UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 40-F

[Check one]o

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934ORý

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For
the fiscal year ended December 31, 2008
Commission file number 001-15214



TRANSALTA CORPORATION(Exact name of Registrant as specified in its charter)

Not applicable(Translation of Registrant's name into English (if applicable))

Canada(Province or other jurisdiction of incorporation or organization)

4911(Primary Standard Industrial Classification Code Number (if applicable))

Not Applicable(I.R.S Employer Identification Number (if applicable))110-12th Avenue S.W., Box 1900, Station "M",
Calgary, Alberta, Canada, T2P 2M1,
(403) 267-7110(Address and telephone number of Registrant's principal executive offices)




CT Corporation System, 111 8th Avenue, 13th Floor,
New York, New York, 10011, (212) 894-8400(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:Title of each class

Name of each exchange
on which registeredCommon Shares, no par value

New York Stock ExchangeCommon Share Purchase Rights

New York Stock Exchange


Securities
registered or to be registered pursuant to Section 12(g) of the Act:None(Title of Class)

Securities
for which there is a reporting obligation pursuant to Section 15(d) of the Act:None(Title of Class)

For
annual reports, indicate by check mark the information filed with this form:

ý  Annual
information form                   ý  Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report:

At
December 31, 2008, 197,622,215 common shares were issued and outstanding.

Indicate
by check mark whether the Registrant by filing 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 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with
such Rule.

Yes  o
82-





                   No  ý

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the
preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past
90 days.

Yes  ý                   No  o

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INCORPORATION BY REFERENCE

The documents (or portions thereof) forming part of this Form 40-F are incorporated by reference into the
following registration statements under the Securities Act of 1933, as amended.

Form

Registration No.S-8


333-72454S-8


333-101470F-10


333-155243


CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS  AND MANAGEMENT'S DISCUSSION & ANALYSIS

A.    Consolidated Audited Annual Financial Statements

For consolidated audited annual financial statements, including the report of independent chartered accountants with respect thereto, see pages 66through 111 of the TransAlta Corporation 2008 Annual Report to shareholders included herein. See Exhibit 13.4 for the related supplementary
note entitled "Reconciliation to United States Generally Accepted Accounting Principles" for a reconciliation of the important differences between Canadian and United States generally
accepted accounting principles.

B.    Management's Discussion & Analysis

For management's discussion & analysis, see pages 19 through 65 of the TransAlta Corporation 2008 Annual Report to shareholders included
herein under the heading "Management's Discussion & Analysis."

For
the purposes of this Form 40-F, only pages 66 through 111 and 19 through 65 of the TransAlta Corporation 2008 Annual Report to shareholders as
referred to above shall be deemed incorporated herein by reference and filed, and the balance of such 2008 Annual Report, except as otherwise specifically incorporated by reference in the TransAlta
Corporation Annual Information Form filed as Exhibit 13.1 hereto, shall not be deemed to be filed under the Exchange Act with the Securities and Exchange Commission as part of this
Form 40-F.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15 under the Securities Exchange Act of 1934, 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 was required to apply its judgment in evaluating and implementing possible controls and procedures. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial
Officer have concluded that, as of December 31, 2008, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

2

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MANAGEMENT'S REPORT ON INTERNAL CONTROL  OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting.

Internal
control over financial reporting refers to a process designed by, or under the supervision of, our chief executive officer and chief financial officer and effected by our board
of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles and includes those policies and procedures that:



Management
evaluated the effectiveness of our internal control over financial reporting as of December 31, 2008 using the framework set forth in the report of the Treadway
Commission's Committee of Sponsoring Organizations (COSO), "Internal Control  Integrated Framework." Management has concluded that our internal control over
financial reporting was effective as of December 31, 2008. Certain matters relating to the scope of Management's evaluation and limitations of management's conclusions are described below. See
"Limitations and Scope of Management's Report on Internal Control over Financial Reporting."

Our
independent registered public accounting firm, Ernst & Young LLP, has issued an attestation report on the effectiveness of our internal control over financial reporting
as of December 31, 2008. For Ernst & Young LLP's report see page 68 of the TransAlta Corporation 2008 Annual Report to shareholders under the heading "Independent Auditors'
Report on Internal Controls Under Standards of the Public Company Accounting Oversight Board (United States)".

There
has been no change in the internal control over financial reporting during the year covered by this report that has materially affected, or is reasonably likely to materially
affect, the Company's internal control over financial reporting.

LIMITATIONS AND SCOPE OF MANAGEMENT'S  REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management
has not evaluated the internal controls of the Sheerness, CE Generation and Genesee 3 joint ventures (collectively, the "Excluded Entities"), in accordance with
Frequently Asked Question No. 1, "Management's Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports," of the Office of the Chief
Accountant of the Division of Corporation Finance of the U.S. Securities and Exchange Commission (revised Oct. 6, 2004). Accordingly, management's evaluation of the Company's internal
control over financial reporting did not include an evaluation of the internal controls

3

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of
any of the Excluded Entities, and management's conclusion regarding the effectiveness of the Company's internal control over financial reporting does not extend to the internal controls of any of
the Excluded Entities.

Proportionate
consolidation of the Excluded Entities contributes to the Company's financial statements in the amount of $1,680 million of the Company's total assets,
$747 million of net assets, $481 million of revenues and $53 million of operating income. The Company's financial statements include the accounts of the Excluded Entities,
accounted for via proportionate consolidation, in accordance with EITF 00-1, but management has been unable to assess the effectiveness of internal control at
the Excluded Entities because the Company does not have the ability to dictate or modify the controls of the Excluded Entities and does not have the ability, in practice, to assess
those controls.

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant's board of directors has determined that it has at least one audit committee financial expert serving on its Audit and
Risk Committee (the "ARC"). Mr. William D. Anderson has been determined to be an audit committee financial expert, within the meaning of Section 407 of the United States
Sarbanes-Oxley Act of 2002 ("Sarbanes-Oxley"), and is independent, as that term is defined by the New York Stock Exchange's ("NYSE") listing standards applicable to the Registrant.
Mr. Gordon S. Lackenbauer has also been determined to be an audit committee financial expert for purposes of Section 407 of Sarbanes-Oxley and independent under the applicable NYSE
listing standards. Under Securities and Exchange Commission rules the designation of persons as audit committee financial experts does not make them "experts" for any other purpose, impose any duties,
obligations or liability on them that are greater than those imposed on members of their committee and the board of directors who do not carry this designation or affect the duties, obligations or
liability of any other member of their committee.

CODE OF ETHICS

The Registrant has adopted a code of ethics as part of its "Corporate Code of Conduct" that applies to all employees and officers which
has been filed with the SEC. In addition, the Registrant has adopted a code of conduct applicable to all directors of the Company and a separate financial code of conduct which applies to all
financial management employees. The Registrant's Corporate Codes of Conduct are available on its Internet website at www.transalta.com. There has been no waiver of the
codes granted during the 2008 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2008 and 2007, Ernst & Young LLP and its affiliates were paid approximately
$3,372,142 and $2,838,740 respectively, as detailed below:

Year-ended December 312008

2007Ernst & Young LLPAudit Fees

$
2,594,183

$
2,624,029Audit-Related Fees

$
432,343

$
168,968Tax Fees

$
345,616

$
45,743All Other Fees

$


$Total

$
3,372,142

$
2,838,740


No
other audit firms provided audit services in 2008 or 2007.

The
nature of each category of fees is described below.

Audit Fees

Audit fees were paid for professional services rendered by the auditors for the audit of the Company's annual financial statements or
services provided in connection with statutory and regulatory filings or engagements, including the translation from English into French of the Company's financial statements and

4

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other
documents. Total audit fees for 2008 include payments related to 2007 in the amount of $1,403,923. Total audit fees for 2007 include payments related to 2006 in the amount of $1,476,300.

Audit-Related Fees

The audit-related fees in 2008 and 2007 were primarily for work performed by Ernst & Young LLP in the provision of
miscellaneous accounting advice provided to the Company.

Tax Fees

The majority of tax fees for 2008 related to the finalization of tax credit recoveries.

Pre-Approval Policies and Procedures

The ARC has considered whether the provision of services other than audit services is compatible with maintaining the auditors'
independence. The ARC has adopted a policy that prohibits the Company from engaging the auditors for "prohibited" categories of non-audit services and requires pre-approval of
the ARC for other permissible categories of non-audit services, such categories as determined under Sarbanes-Oxley.

Percentage of Services Approved by the ARC

For the year ended December 31, 2008, none of the services described above were approved by the ARC pursuant to
paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

OFF-BALANCE SHEET ARRANGEMENTS

See page 47 of Exhibit 13.3.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See page 46 of Exhibit 13.3 under the heading "Liquidity and Capital Resources" and page 101 of
Exhibit 13.2 under the heading "Commitments".

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing ARC. The members of the ARC are:

William
D. Anderson (Chair)
Stephen L. Baum
Timothy W. Faithfull
Michael M. Kanovsky
Gordon S. Lackenbauer
Donna S. Kaufman (ex-officio member)

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FORWARD LOOKING INFORMATION

This document, 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 TransAlta's beliefs as well as assumptions based on information available at the time the assumption was
made. 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 TransAlta's future performance and are subject to
risks, uncertainties and other important factors that could cause TransAlta's actual performance to be materially different from those projected.

Factors
that may adversely impact the Corporation's forward looking statements include risks relating to: (i) fluctuations in market prices and availability of fuel supplies
required to generate electricity and in the price of electricity; (ii) the regulatory and political environments in the jurisdictions in which the Corporation operates;
(iii) environmental requirements and changes in, or liabilities under, these requirements; (iv) changes in general economic conditions including interest rates; (v) operational
risks involving the Corporation's facilities, including unplanned outages at such facilities; (vi) disruptions in the transmission and distribution of electricity; (vii) disruptions in
the source of fuels or water required to operate the Corporation's facilities; (viii) trading risks; (ix) fluctuations in the value of foreign currencies and foreign political risks;
(x) need for additional financing; (xi) liquidity risk; (xii) structural subordination of securities; (xiii) counterparty credit risk; (xiv) insurance risk;
(xv) the Corporation's provision for income taxes; (xvi) legal proceedings involving the Corporation; (xvii) reliance on key personnel; (xviii) labour relations matters;
and (xix) absence of a public market for certain of the securities offered. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" in the
documents filed herewith under Form 40-F and in other documents and filings made with securities regulatory authorities from time to time.

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 the Corporation does 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 or might not occur. The
Corporation cannot assure you that projected results or events will be achieved.

UNDERTAKING

TransAlta Corporation undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the
Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities
in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on
Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

TRANSALTA CORPORATION/s/ BRIAN BURDENBrian Burden
Executive Vice-President and Chief Financial Officer


Dated:
March 16, 2009

6

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EXHIBITS

13.1

TransAlta Corporation Annual Information Form for the year ended December 31, 2008.13.2

Consolidated Audited Financial Statements for the year ended December 31, 2008 (included on pages 66 through 111 of the 2008 TransAlta Annual Report to Shareholders).13.3

Management's Discussion and Analysis (included on pages 19 through 65 of the 2008 TransAlta Annual Report to Shareholders).13.4

Reconciliation to United States Generally Accepted Accounting Principles of the 2008 Consolidated Audited Financial Statements.23.1

Consent of Ernst and Young LLP Chartered Accountants.31.1

Certification of Chief Executive Officer pursuant to Section 302 and Section 404 of the Sarbanes-Oxley Act of 2002.31.2

Certification of Chief Financial Officer pursuant to Section 302 and Section 404 of the Sarbanes-Oxley Act of 2002.32.1

Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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EXHIBIT INDEX

13.1

TransAlta Corporation Annual Information Form for the year ended December 31, 2008.13.2

Consolidated Audited Financial Statements for the year ended December 31, 2008 (included on pages 66 through 111 of the 2008 TransAlta Annual Report to shareholders).13.3

Management's Discussion and Analysis (included on pages 19 through 65 of the 2008 TransAlta Annual Report to shareholders).13.4

Reconciliation to United States Generally Accepted Accounting Principles of the 2008 Consolidated Audited Financial Statements.23.1

Consent of Ernst and Young LLP Chartered Accountants.31.1

Certification of Chief Executive Officer pursuant to Section 302 and Section 404 of the Sarbanes-Oxley Act of 2002.31.2

Certification of Chief Financial Officer pursuant to Section 302 and Section 404 of the Sarbanes-Oxley Act of 2002.32.1

Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


E-1

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TRANSALTA
CORPORATION  2009
RENEWAL ANNUAL INFORMATION FORM  FOR THE
YEAR ENDED DECEMBER 31, 2008    MARCH 16,
2009


-
i -   TABLE OF CONTENTS  PRESENTATION OF INFORMATION
  1SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
  1DOCUMENTS INCORPORATED BY REFERENCE
  1CORPORATE STRUCTURE
  2OVERVIEW
  3GENERAL DEVELOPMENT OF THE BUSINESS
  4BUSINESS OF TRANSALTA
  8Generation Business Segment
  8Commercial Operations and Development
  16ENVIRONMENTAL RISK MANAGEMENT
  19RISK FACTORS
  22EMPLOYEES
  28CAPITAL STRUCTURE
  29CREDIT RATINGS
  30DIVIDENDS
  30MARKET FOR SECURITIES
  31DIRECTORS AND OFFICERS
  31INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  37INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR
  OFFICERS
  37CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS
  37CONFLICTS OF INTEREST
  38LEGAL PROCEEDINGS AND REGULATORY ACTIONS
  38TRANSFER AGENT AND REGISTRAR
  39INTERESTS OF EXPERTS
  39ADDITIONAL INFORMATION
  39AUDIT AND RISK COMMITTEE
  39APPENDIX A
  A-1APPENDIX B
  B-1


- 1 -   PRESENTATION
OF INFORMATION  Unless otherwise noted, the information contained in this annual
information form (Annual Information Form)
is given as at or for the year ended December 31, 2008.  Amounts are expressed in Canadian dollars
unless otherwise indicated.  Financial
information is presented in accordance with Canadian generally accepted
accounting principles.  SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS  This Annual Information
Form, 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 TransAltas beliefs as well as assumptions
based on information available at the time the assumption was made.  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
TransAltas future performance and are subject to risks, uncertainties and
other important factors that could cause TransAltas actual performance to be
materially different from those projected.  Factors that may adversely
impact the Corporations
forward looking statements include risks relating to: (i) fluctuations in
market prices and availability of fuel supplies required to generate
electricity and in the price of electricity; (ii) the regulatory and
political environments in the jurisdictions in which the Corporation operates; (iii) environmental
requirements and changes in, or liabilities under, these requirements; (iv) changes
in general economic conditions including interest rates; (v) operational
risks involving the Corporations facilities, including unplanned outages at
such facilities; (vi) disruptions in the transmission and distribution of
electricity; (vii) disruptions in the source of fuels or water required to
operate the Corporations facilities; (viii) trading risks; (ix) fluctuations
in the value of foreign currencies and foreign political risks; (x) need
for additional financing; (xi) liquidity risk; (xii) structural
subordination of securities; (xiii) counterparty credit risk;
(xiv) insurance risk; (xv) the Corporations provision for income
taxes; (xvi) legal proceedings involving the Corporation;
(xvii) reliance on key personnel and (xviii) labour relations matters
and (xix) absence of a public market for certain of the securities offered.  The foregoing risk factors, among others, are
described in further detail under the heading Risk Factors in this Annual
Information Form and in the documents incorporated by reference in this
Annual Information Form, including the TransAlta Managements Discussion and
Analysis for the year ended December 31, 2008 (the Annual MD&A).  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 the Corporation does 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 or might not
occur.  The Corporation cannot assure you
that projected results or events will be achieved.  DOCUMENTS
INCORPORATED BY REFERENCE  TransAltas Audited Consolidated Financial Statements for the year
ended December 31, 2008 and the Annual MD&A are hereby specifically
incorporated by reference in this Annual Information Form.  Copies of these documents are available on SEDAR
at www.sedar.com.


- 2 -   CORPORATE
STRUCTURE  Name and Incorporation  TransAlta Corporation was formed by Certificate of
Amalgamation issued under the Canada Business
Corporations Act on October 8, 1992.  On December 31, 1992, a Certificate of
Amendment was issued in connection with a plan of arrangement involving the
Corporation and TransAlta Utilities Corporation (TransAlta
Utilities or TAU) under the
Canada Business Corporations Act.  The plan of arrangement, which was approved
by shareholders on November 26, 1992, resulted in common shareholders of
TransAlta Utilities exchanging their common shares for shares of TransAlta on a
one-for-one basis.  Upon completion of
the arrangement, TransAlta Utilities became a wholly-owned subsidiary of
TransAlta.  On January 1, 2009,
TransAlta was issued a Certificate of Amalgamation under the Canada Business Corporations Act in connection with the
amalgamation of TransAlta Corporation, TransAlta Utilities, TransAlta Energy
Corporation (TransAlta Energy or TEC) and Keephills 3 GP Ltd.  The amalgamation was completed as part of a
series of transactions involving TransAlta and certain of its subsidiaries and
affiliates carried out to reorganize (the Reorganization)
TransAltas interest in certain of its assets.  The registered office and principal place of business of TransAlta is
at 110 - 12th Avenue S.W., Calgary,
Alberta, Canada, T2R 0G7.  Intercorporate Relationships  Effective January 1, 2009, the Corporation
completed an internal reorganization whereby the assets and business affairs of
TAU and TEC (with the exception of the wind business) were transferred to
TransAlta Generation Partnership, a new Alberta general partnership, whose
partners are TransAlta Corporation and TransAlta Generation Ltd., a
wholly-owned subsidiary of TransAlta Corporation. TransAlta Generation
Partnership is managed by TransAlta Corporation pursuant to the terms of the
partnership agreement and a management services agreement.  Immediately following the transfer of assets
by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation
amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the Canada Business Corporations Act.  TransAlta remains the holding entity of the
various businesses of the Corporation, some of which are now held directly, in
the case of the wind assets, and some of which are now held indirectly, in the
case of the former generation assets and businesses of TAU and TEC.  As of January 1, 2009, the principal subsidiaries of the
Corporation and their respective jurisdictions of formation are set out below.


- 3 -   Unless the context otherwise requires, all references
to the Corporation and to TransAlta herein refer to TransAlta Corporation
and its subsidiaries on a consolidated basis. 
References to TransAlta Corporation herein refer to TransAlta
Corporation, excluding its subsidiaries.   OVERVIEW  TransAlta and its predecessors have been engaged in the production and
sale of electric energy since 1909.  The
Corporation is among Canadas largest non regulated electricity generation and
energy marketing companies with an aggregate net ownership interest of 7,976
megawatts (MW) of generating capacity1 operating in facilities having approximately 9,697MW of aggregate generating capacity. In addition, the
Corporation has facilities under construction with a net ownership interest of
456 MW, of an aggregate generating capacity of 681 MW.  The Corporation is focused on generating
electricity in Canada, the United States and Australia through its diversified
portfolio of facilities fuelled by coal, gas, hydroelectric, wind and
geothermal resources.  In Canada, the Corporation holds a net ownership interest of 5,661 MW
of electrical generating capacity in thermal, gas-fired, wind-powered and
hydroelectric facilities, including 4,937 MW in Western Canada, 628 MW in
Ontario and 96 MW in New Brunswick.  In the United States, the Corporations principal facilities include a1,376 MW thermal facility and a 248 MW gas-fired facility,
both located in Centralia, Washington, which supply electricity to the Pacific
northwest. The Corporation also holds a 50 per cent interest in CE Generation,
LLC (CE Generation), through which it has
an aggregate net ownership interest of approximately 385 MW of generating
capacity in geothermal facilities in California and gas-fired facilities in
Texas, Arizona and New York. In addition, the Corporation also has 6 MW of
electrical generating capacity through hydroelectric facilities located in
Washington and Hawaii.  In Australia, the Corporation has 300MW
of net electrical generating capacity from gas-fired generation facilities.  The Corporation regularly reviews its operations in order to optimize
its generating assets and evaluates appropriate growth opportunities.  The Corporation has in the past and may in
the future make changes and additions to its fleet of coal, gas, hydro, wind
and geothermal fuelled facilities.  The Corporation is organized into two business segments: Generation and
Commercial Operations and Development. The Generation group is responsible for
constructing, operating and maintaining electricity generation facilities.  The Commercial Operations and Development
group is responsible for managing the sale of production, purchasing natural
gas, transmission capacity and market risks associated with the Corporations
generation assets and for non asset backed trading activities.  Both segments are supported by a corporate
group that provides finance, treasury, legal, regulatory, environmental, health
and safety, sustainable development, corporate communications, government
relations, information technology, human resources, internal audit, and other
administrative support.   
 1TransAlta measures capacity as
the net maximum capacity that a unit can sustain over a period of time, which
is consistent with industry standards. 
All capacity amounts are as of the date of this Annual Information Form and
represent capacity owned and operated by the Corporation unless otherwise
indicated.


- 4 -   GENERAL
DEVELOPMENT OF THE BUSINESS  The significant events and conditions affecting TransAltas business
during the three most recently completed financial years are summarized
below.  Certain of these events and
conditions are discussed in greater detail under the heading Business of
TransAlta in this Annual Information Form.  Recent Developments  ·On February 10, 2009, the
Corporation reported that the 406 MW Sundance 4 facility had experienced an
unplanned outage in December 2008 relating to the failure of an induced
draft fan.  At the time, the unit was
derated to approximately 205 MW.  The
repair of the fan components by the original equipment manufacturer took longer
than planned and, therefore, Unit 4 did not return to full service until February
23, 2009.  As a result of the extended
derate, first quarter production was reduced by 328GWh and net income declined
by $17 million.  The Corporation has
given notice of a High Impact Low Probability Event to the PPA Buyer and the
Balancing Pool which, if successful, will protect the Corporation from the
financial loss and related penalties. 
The available penalties that the Corporation expects to recover in net
income are anticipated to be $14 million.  ·On January 29, 2009, the
Board of Directors of the Corporation declared a quarterly dividend of $0.29
per common share, payable April 1, 2009 to holders of record on March 1,
2009.  This represents a $0.02 per share
increase in the quarterly dividend, yielding on an annualized basis a dividend
of $1.16 per share.  ·On January 29, 2009, the
Corporation announced that it will be proceeding with the addition of two 23 MW
efficiency uprates at its Keephills plant in Alberta. Both Keephills units 1
and 2 will be upgraded to 406 MW and are expected to be operational by the end
of 2011 and 2012, respectively. The total capital cost of the projects is estimated
at $68 million.  ·Effective January 1,
2009, the Corporation completed an internal reorganization whereby the assets
and business affairs of TAU and TEC (with the exception of the wind business)
were transferred to TransAlta Generation Partnership, a new Alberta general partnership,
whose partners are TransAlta and TransAlta Generation Ltd., a wholly-owned
subsidiary of TransAlta. TransAlta Generation Partnership is managed by
TransAlta pursuant to the terms of the partnership agreement and a management
services agreement.  Immediately
following the transfer of assets by TAU and TEC to TransAlta Generation
Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3
GP Ltd. pursuant to the Canada Business
Corporations Act.  TransAlta
remains the holding entity of the various businesses of the Corporation, some
of which are now held directly, in the case of the wind assets, and some of
which are now held indirectly, in the case of the former generation assets and
businesses of TAU and TEC.  Year Ended December 31, 2008  ·On December 31, 2008, the
Corporation announced that the 96 MW, $170 million Kent Hills Wind Farm had
begun commercial operation.  The wind
farm consists of 32 Vestas V90, 3MW wind turbines.  The capacity from this project is sold under
a power purchase agreement with New Brunswick Power Distribution and Customer
Service Corporation (New Brunswick Power).  ·On October 8, 2008, the
Corporation announced the completion of the sale of its Mexican businesses to
Intergen Global Ventures B.V. II for a sale price of US$303.5 million.  The sale included the 252 MW gas/diesel
combined cycle gas plant in Campeche, a 259 MW combined cycle gas plant in
Chihuahua and all associated commercial arrangements.


- 5 -   ·On May 27, 2008, the
Corporation announced that, commencing in 2009, it would be constructing
another 66 MW wind generation facility in southern Alberta, consisting of 22
Vestas V90 3 MW wind turbines.  The total
capital cost for this expansion of the Summerview wind power project is
expected to be $123 million.  The
capacity from this project is expected to be sold on the Alberta Power Pool.  ·On May 5, 2008, the
Corporation announced that it had received regulatory approval from the Toronto
Stock Exchange (TSX) for the continuation of its
normal course issuer bid (NCIB)
program.  Under the NCIB program, the
Corporation has approval to purchase, for cancellation, up to 19.9 million of
its common shares, representing 10 per cent of its public float as of April 23,
2008.  ·On April 21, 2008, the
Corporation announced a 53 MW efficiency uprate at Unit 5 of its Sundance
facility. The total capital cost of the project is estimated at $75 million
with commercial operations expected to commence by the end of 2009.  ·On April 3, 2008,
TransAlta announced a partnership with Alstom LLC to develop a one million
tonne/year carbon capture and storage project at one of TransAltas coal-fired
power stations in Alberta.  This project
has been shortlisted by the Alberta Government for contributory funding as part
of the provinces $2 billion carbon capture and storage (CCS)
program, with a decision expected by June 30, 2009.  ·On February 20, 2008, the
Corporation announced it had signed a purchase and sale agreement with Intergen
Global Ventures B.V. pursuant to which Intergen agreed to pay the Corporation
US$303.5 million in cash for its Mexican assets.  ·On February 13, 2008, the
Corporation announced that, commencing in 2009, it would be constructing a 66
MW wind generation facility in southern Alberta, consisting of 22 Vestas V90 3
MW wind turbines.  The total capital
costs for this Blue Trail wind power project is expected to be $115
million.  The capacity from this project
is expected to be sold on the Alberta Power Pool.  ·On February 1, 2008, the
Board of Directors of the Corporation declared a quarterly dividend of $0.27
per common share, payable April 1, 2008 to holders of record on March 1,
2008.  This represents a $0.02 per share
increase in the quarterly dividend, yielding on an annualized basis a dividend
of $1.08 per share.  Year Ended December 31, 2007  ·During the third quarter, the
Corporation completed an uprate on the Sundance Unit 4 facility.  A final measurement took place in the fourth
quarter of 2007 and the generating capacity added as a result of this uprate
was 53 MW.  ·On September 11, 2007,
the Corporation announced it had received regulatory approval to increase the
number of shares it may purchase under its NCIB program.  As a result, the Corporation was authorized
to purchase for cancellation up to 20.2 million shares or approximately 10 per
cent of the 202 million common shares issued and outstanding as of April 23,
2007.  ·On July 17, 2007, the
Corporation amended the power purchase agreement with New Brunswick Power to
increase capacity at its Kent Hills wind power facility from 75 MW to 96
MW.  As a result, total capital costs for
the Kent Hills project will also increase by $40 million, from $130 million to
$170 million. The Corporation also signed a purchase and sale agreement with
Vector Wind Energy,


- 6 -   a
wholly owned subsidiary of Canadian Hydro Developers Inc., to acquire its
Fairfield Hill wind power site, including an option to develop the site at a
future date.  ·On June 21, 2007,
TransAlta Utilities entered into an agreement with Bucyrus Canada Limited and
Bucyrus International Inc. for the purchase of a dragline to be used primarily
in the supply of coal for the Keephills 3 joint venture project. The total
dragline purchase costs are approximately $150 million, with final payments for
goods and services due by May 2010. The total payments made under this
agreement in 2007 were $18 million.  ·On February 26, 2007, the
Corporation and EPCOR Power Development Corporation (EPCOR)
announced that they were proceeding with building the 450 MW Keephills 3 power
project located approximately 70 kilometres west of Edmonton, Alberta.  The capital cost for the project, including
mine capital, is expected to be approximately $1.6 billion and is expected to
be completed at the end of the first quarter of 2011. Through the Keephills 3
Limited Partnership (K3LP), an
affiliate of the Corporation, TransAlta and EPCOR will be equal partners in the
ownership of Keephills 3, with TransAlta responsible for managing the joint
venture and EPCOR responsible for the construction.  Upon completion, it is expected that
TransAlta will operate the facility and EPCOR and TransAlta will independently
dispatch and market their share of the units electrical output.  The project has received approval from the
Alberta Energy and Utilities Board and from Alberta Environment.  ·On January 19, 2007, the
Corporation announced that it had been awarded a 25-year Power Purchase
Agreement (PPA) to provide 75 MW of wind
power to New Brunswick Power.  Under the
agreement, TransAlta will construct, own and operate a wind power facility in
New Brunswick.  The capital cost of the
project is estimated to be $130 million. 
The project is subject to regulatory and environmental approvals and is
expected to begin commercial operations by the end of 2008.  Natural Forces Technologies Inc., an Atlantic
Canada based wind developer, is TransAltas co-development partner in this
project.  ·On January 2, 2007, the
Corporation redeemed, at par, all of its outstanding 7.75 per cent preferred
securities, with an outstanding principal amount of $175 million.  Year ended December 31, 2006  ·On December 18, 2006,
TransAlta Utilities assigned its rights in the development agreement it held
with EPCOR, governing the joint development of the Keephills 3 power project,
to K3LP.  K3LP subsequently sold a 50 per
cent undivided interest in the Keephills 3 power project to the EPCOR Power
Development (K3) Limited Partnership and has entered into a joint venture
agreement governing the continued development of the Keephills 3 power
project.  In the event the Keephills 3
power project proceeds to operation, it is anticipated that TransAlta will be
the operator of the project pursuant to an operations and maintenance agreement
and coal supply agreement.  ·On November 27, 2006,
TransAlta announced it would immediately stop mining operations at its
Centralia, Washington coal-mine. 
TransAlta also announced that it had entered into agreements to purchase
and transport coal from the Powder River Basin to fuel TransAltas Centralia
thermal facility.  ·On November 17, 2006,
TransAlta Utilities entered into a settlement agreement with Canadian National
Railway Company for a portion of outstanding claims for lost margin and
incremental expenses relating to the train derailment and resulting oil spill
into Lake Wabamun in 2005.  The terms of
the settlement are subject to a confidentiality agreement and cannot be disclosed.


- 7 -   ·On February 17, 2006, a
wholly-owned subsidiary of TransAlta, together with a subsidiary of
Mid-American Energy Company (Mid-American),
entered into an agreement to purchase a 10 MW hydro facility in Hawaii to be
held directly by the Wailuku Holding Company LLC, a company jointly and equally
owned by TransAlta and Mid-American.  ·On February 15, 2006,
TransAlta announced it had signed a five-year agreement with the Ontario Power
Authority (OPA) for the supply of
electricity from TransAltas Sarnia Regional Cogeneration Power Plant.  Under the terms of the agreement, Transalta
will be available to supply an average of 400 MW of electricity to the Ontario
electricity market.  The supply contract
is effective until December 31, 2010.  ·On February 1, 2006,
TransAlta Utilities entered into a development agreement with EPCOR to jointly
pursue the Keephills 3 power project. 
Keephills 3 is a proposed 450 MW facility adjacent to TransAltas existing
Keephills facility, approximately 70 kilometres west of Edmonton, Alberta.


- 8 -   BUSINESS
OF TRANSALTA  Generation
Business Segment  The following table summarizes the Corporations generation facilities
which are operating, under construction or under development, as at January 31,
2009:  Region
  
  Facility
  
  Capacity 
  (MW)
  
  Ownership 
  (%)
  
  Net Capacity 
  Ownership 
  Interest
  
  Fuel
  
  Revenue Source
  
  Contract 
  Expiry DateWestern
  
  Canada 
  (28 Facilities)
  
  Sundance(1)
  
  2,126
  
  100
  
  2,126
  
  Coal
  
  Alberta
  PPA / Merchant(2)
  
  2017,
  2020Keephills(3)
  
  812
  
  100
  
  812
  
  Coal
  
  Alberta
  PPA
  
  2020Sheerness
  
  780
  
  25
  
  195
  
  Coal
  
  Alberta
  PPA
  
  2020Wabamun
  
  279
  
  100
  
  279
  
  Coal
  
  Merchant
  
  -Genesee 3
  
  450
  
  50
  
  225
  
  Coal
  
  Merchant
  
  -Keephills
  3(4)
  
  450
  
  50
  
  225
  
  Coal
  
  Merchant
  
  -Fort Saskatchewan
  
  118
  
  30
  
  35
  
  Gas
  
  Long-term
  contract(LTC)
  
  2019Meridian
  
  220
  
  25
  
  55
  
  Gas
  
  LTC
  
  2024Poplar Creek
  
  356
  
  100
  
  356
  
  Gas
  
  LTC/Merchant
  
  2024Hydro
  assets(5)
  
  801
  
  100
  
  801
  
  Hydro
  
  Alberta
  PPA
  
  2013-2020Castle
  River(6)
  
  44
  
  100
  
  44
  
  Wind
  
  LTC/Merchant
  
  2011McBride Lake
  
  75
  
  50
  
  38
  
  Wind
  
  LTC
  
  2024Summerview
  1(7)
  
  70
  
  100
  
  70
  
  Wind
  
  Merchant
  
  -Blue
  Trail(4)
  
  66
  
  100
  
  66
  
  Wind
  
  Merchant
  
  -Summerview
  2(4)
  
  66
  
  100
  
  66
  
  Wind
  
  Merchant
  
  -Total
  Western Canada
  
  6,713
  
  
  
  5,393Mississauga
  
  108
  
  50
  
  54
  
  Gas
  
  LTC
  
  2017Eastern
  
  Ottawa
  
  68
  
  50
  
  34
  
  Gas
  
  LTC
  
  2012Canada
  
  Windsor
  
  68
  
  50
  
  34
  
  Gas
  
  LTC/Merchant
  
  2016(5 Facilities)
  
  Sarnia(8)
  
  506
  
  100
  
  506
  
  Gas
  
  LTC/Merchant
  
  2022Kent Hills
  
  96
  
  100
  
  96
  
  Wind
  
  PPA
  
  2033Total
  Eastern 
  Canada
  
  846
  
  
  
  724Centralia(9)
  
  1,376
  
  100
  
  1,376
  
  Coal
  
  Merchant
  
  -Centralia Gas
  
  248
  
  100
  
  248
  
  Gas
  
  Merchant
  
  -Power Resource
  
  212
  
  50
  
  106
  
  Gas
  
  Merchant
  
  -Saranac
  
  240
  
  37.5
  
  90
  
  Gas
  
  LTC
  
  2009United States
  
  Yuma
  
  50
  
  50
  
  25
  
  Gas
  
  LTC
  
  2024(17 Facilities)
  
  Imperial
  Valley Geothermal Facilities(10)
  
  327
  
  50
  
  164
  
  Geothermal
  
  LTC/Merchant
  
  2016-2029Skookumchuk
  
  1
  
  100
  
  1
  
  Hydro
  
  -
  
  -Wailuku
  
  10
  
  50
  
  5
  
  Hydro
  
  LTC
  
  2023Total US
  
  2,464
  
  
  
  2,015Australia
  
  Parkeston
  
  110
  
  50
  
  55
  
  Gas
  
  LTC
  
  2016(5 Facilities)
  
  Southern
  Cross(11)
  
  245
  
  100
  
  245
  
  Gas/Diesel
  
  LTC
  
  2013Total Australia
  
  355
  
  
  
  300Total
  
  
  
  10,378
  
  
  
  8,432  Notes: (1)Includes a 53 MW uprate
expected to be commercial in 2009. (2)Merchant capacity refers to 53
MW and 44 MW uprates on units 4 and 6, respectively. (3)Includes two 23 MW uprates on
units 1 and 2 expected to be commercial in 2011, and 2012, respectively. (4)These facilities are currently
under development. (5)Comprised of 13 facilities.


- 9 -   (6)Includes 7 individual turbines
at other locations. (7)Comprised of 2 facilities. (8)Sarnias net maximum capacity
(NMC) has been adjusted from 575 MW due
to decommissioning of equipment at the facility. (9)Centralia Thermals NMC has
been reduced from 1,404 MW to reflect a lower plant output as a result of its
conversion to burning Powder River Basin coal. (10)Comprised of 10 facilities. (11)Comprised of 4 facilities.  Canada:  Alberta  Thermal
facilities  The following table summarizes the Corporations western Canadian
thermal generation facilities:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesWabamun(1)
  
  Wabamun Unit No. 4
  
  279
  
  100
  
  1968Sundance
  
  Sundance Unit No. 1
  
  280
  
  100
  
  1970Sundance Unit No. 2
  
  280
  
  100
  
  1973Sundance Unit No. 3
  
  353
  
  100
  
  1976Sundance Unit No. 4
  
  406
  
  100
  
  1977Sundance Unit No. 5(2)
  
  406
  
  100
  
  1978Sundance Unit No. 6
  
  401
  
  100
  
  1980Keephills
  
  Keephills
  Unit No. 1(3)
  
  406
  
  100
  
  1983Keephills Unit No. 2(3)
  
  406
  
  100
  
  1984Keephills Unit No. 3(4)
  
  450
  
  50
  
  2011Sheerness
  
  Sheerness
  Unit No. 1
  
  390
  
  25
  
  1986Sheerness Unit No. 2
  
  390
  
  25
  
  1990Genesee
  
  Genesee 3
  
  450
  
  50
  
  2005Total
  
  
  
  4,897  Notes: (1)Wabamun unit 4 is expected to
be removed from service upon the expiry of its license in 2010. (2)Includes a 53 MW uprate
expected to be commercial in 2009. (3)Includes two 23 MW uprates on
units 1 and 2 expected to be commercial in 2011, and 2012, respectively. (4)This facility is currently
under development.  The Keephills, Sundance and Wabamun facilities (the Alberta thermal plants) are located approximately 70
kilometres west of Edmonton, Alberta and are owned by TransAlta.  The Sheerness facility is jointly owned by
TransAlta Cogeneration, L.P. (TA Cogen), an
Ontario limited partnership, and ATCO Power (2000) Ltd. (ATCO Power).
The Genesee facility is jointly owned by TransAlta and EPCOR.  TransAltas thermal plants are generally base
load plants, meaning that they are expected to operate for long periods of time
at or near their rated capacity. 
Availability is an important measure of the economic success of a thermal
plant. The weighted equivalent availability factor for the Alberta thermal
plants in 2008 was 82.9 per cent compared with 87.1 per cent in 2007 and 88.7
per cent in 2006.  For the Sheerness
facility, the weighted equivalent availability factor was 94.1 per cent in 2008
compared to 94.4 per cent in 2007 and 92.2 per cent in 2006.  For the Genesee 3 facility, the weighted
equivalent availability factor was 78.2 per cent in 2008 compared to 92.9 per
cent in 2007 and 96.9 per cent in 2006.  Fuel requirements for TransAltas thermal power facilities are supplied
by surface strip coal-mines located in close proximity to the facilities.  TransAlta owns two surface mines in Alberta
that supply coal to its Alberta thermal plants. 
The Whitewood mine supplies the Wabamun plant and the Highvale mine
supplies the Sundance and Keephills facilities. 
TransAlta estimates that the recoverable coal reserves contained in
these mines are expected to be sufficient to supply the anticipated requirements
for the life of these facilities including running post PPA expiry and plant
expansion.  Coal for the Sheerness facility is provided from the adjacent Sheerness
mine.  The coal reserves of the mine are
owned, leased or controlled jointly by TA Cogen, ATCO Power and Prairie Mines &
Royalties Limited (PMRL).


- 10 -   TA Cogen and ATCO Power have entered into coal supply agreements with
PMRL, which operates the mine, to supply coal until 2026.  Coal for the Genesee 3 facility is provided from the adjacent Genesee
mine.  The coal reserves of the mine are
owned, leased or controlled jointly by PMRL and EPCOR.  The Corporation has entered into coal supply
agreements with PMRL, which operates the mine, to supply coal for the life of
the facility.  In February 2001, the Corporation announced a proposal for a 900
MW expansion at its Keephills facility. 
Although the Corporation received regulatory approval to proceed with
the expansion, an application was made, in December 2004, to the AEUB to
amend its 900 MW permit to allow for the construction of a smaller 450 MW
facility using improved technology.  On February 1, 2006, the Corporation entered into a development
agreement with EPCOR to jointly pursue the 450 MW Keephills 3 power
project.  On December 18, 2006, the
Corporation assigned its rights in the development agreement which it held with
EPCOR for the joint development of the Keephills 3 power project to K3LP, an
affiliate of the Corporation.  K3LP
subsequently sold a 50 per cent undivided interest in the Keephills 3 power
project to the EPCOR Power Development (K3) Limited Partnership and has entered
into a joint venture agreement governing the continued development of the
Keephills 3 power project.  The project
received approval from the Alberta Energy and Utilities Board and from Alberta
Environment.  On February 26, 2007, the Corporation and EPCOR commenced
construction of the net 450 MW Keephills 3 power project.  The capital cost for the project, including
mine capital, is expected to be approximately $1.6 billion and is expected to
be completed at the end of the first quarter of 2011.  Through K3LP, TransAlta and EPCOR will be
equal partners in the ownership of Keephills 3, with TransAlta responsible for
managing the joint venture and EPCOR responsible for construction.  Upon completion, it is expected that
TransAlta will operate the facility and EPCOR and TransAlta will independently
dispatch and market their share of the units electrical output.  The Corporation will also provide coal to the
facility through the Highvale mine.  On January 29,
2009, the Corporations estimate of total costs for Keephills 3 increased by
$73 million, due to higher material and labour costs, for a total projected
cost of $1.7 billion.  The Corporation
continues to monitor the costs and will look for opportunities to reduce the
cost increases.  Gas
fired facilities  The following table summarizes the Corporations western Canadian gas
fired generation facilities:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesLloydminster, SK
  
  Meridian
  
  220
  
  25
  
  1999Fort McMurray, AB
  
  Poplar Creek
  
  356
  
  100
  
  2001Fort Saskatchewan, AB
  
  Fort
  Saskatchewan
  
  118
  
  30
  
  1999Total
  
  
  
  694  The Corporations interests in the Meridian and Fort Saskatchewan
facilities are held through TA Cogen. 
See TA Cogen.  The Meridian plant is located in Lloydminster, Saskatchewan and is
owned by TA Cogen and Husky Oil Operations Limited. The Meridian plant sells
electricity to Saskatchewan Power Corporation, a Crown corporation owned by the
Province of Saskatchewan, and steam to a heavy oil upgrader in Lloydminster,
Saskatchewan.  The Poplar Creek plant is located in Fort McMurray, Alberta and is
owned by the Corporation.  This 356 MW
cogeneration plant became fully operational in the first quarter of 2001 and
delivers approximately 200 MW of electricity and steam to Suncor Energy Inc. (Suncor).  Any surplus
power not used by Suncor is available for sale


- 11 -   by the Corporation to other parties, in which case Suncor is entitled
to a share of that revenue, under certain conditions.  The Fort Saskatchewan plant is located in Fort Saskatchewan, Alberta
and is owned by TA Cogen and Air Liquide Canada Inc.  The 118 MW Fort Saskatchewan gas fired
combined cycle cogeneration plant in Alberta provides electricity and steam to
Dow Chemical Canada Inc.  Hydroelectric
facilities  The following table summarizes the Corporations western Canadian
hydroelectric facilities:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning
  DatesBow River System
  
  Horseshoe
  
  14
  
  100
  
  1911Kananaskis
  
  19
  
  100
  
  1913, 1951Ghost
  
  51
  
  100
  
  1929, 1954Cascade
  
  36
  
  100
  
  1942, 1957Barrier
  
  13
  
  100
  
  1947Bearspaw
  
  17
  
  100
  
  1953, 1954Pocaterra
  
  15
  
  100
  
  1955Interlakes
  
  5
  
  100
  
  1955Spray
  
  103
  
  100
  
  1951, 1960Three Sisters
  
  3
  
  100
  
  1951Rundle
  
  50
  
  100
  
  1951, 1960100North Saskatchewan
  River
  System
  
  Brazeau
  
  355
  
  100
  
  1965, 1967Bighorn
  
  120
  
  100
  
  1972Total
  
  
  
  801  The Corporations hydroelectric facilities are primarily peaking
plants, meaning they are generally only operated during times of peak demand.  Wind Generation
Facilities  The following table summarizes the Corporations wind generation
facilities:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesFort MacLeod
  
  McBride Lake
  
  75
  
  50
  
  2003Pincher Creek
  
  Castle River and
  Other
  
  44
  
  100
  
  1997  2001Pincher Creek
  
  Summerview 1
  
  70
  
  100
  
  2004New Brunswick
  
  Kent Hills
  
  96
  
  100
  
  2008Fort Macleod
  
  Blue Trail(1)
  
  66
  
  100
  
  2009Pincher Creek
  
  Summerview 2(1)
  
  66
  
  100
  
  2010Total
  
  
  
  417  Note: (1)Facility under development
reflects expected capacity and commissioning date.  The Corporation owns and operates approximately 248 MW of net capacity
(excluding facilities under development) and operates approximately 285 MW of
capacity primarily in three wind farms in southwestern Alberta and one in New
Brunswick.  Castle River is a 40 MW facility comprised of 59 Vestas V47 (660 kW)
turbines and 1 Vestas V44 (600 kW) turbine located at Pincher Creek,
Alberta.  The facility is 71 per cent
contracted primarily to ENMAX Energy Corp.


- 12 -   (ENMAX) and is the sole Green Energy®
provider to the City of Calgarys Ride the Wind Light Rail Transit
program.  The Corporation also owns and
operates seven additional turbines totalling 4 MW located individually in the
Pincher Creek, Fort Macleod and Hillspring areas of southwestern Alberta.  McBride Lake is a 75 MW facility comprised of 114 Vestas V47 (660 kW)
turbines located at Fort MacLeod, Alberta. 
It was constructed by the Corporation and has been producing electricity
since the third quarter of 2003.  McBride
Lake is operated by the Corporation and is owned by the Corporation and ENMAX
Green Power Inc.  The output from the
facility is 100 per cent contracted in the form of a 20 year PPA with
ENMAX.  The Corporation is also entitled
to receive Wind Power Production Incentive (WPPI)
payments from the federal government at $12/MWh in respect of the McBride Lake
facility until 2013.  On October 13, 2004, TransAlta announced the commencement of
commercial operations at its $100 million Summerview 68 MW wind farm located
approximately 15 kilometres northeast of Pincher Creek, Alberta.  The Summerview facility, which comprises 38
1.8 MW turbines, together with an existing 1.8 MW turbine in the area, brings
the total wind generation capacity at that location to 70 MW.  The Summerview wind farm is a merchant
facility but is entitled to receive WPPI payments from the Federal Government
at $10/MWh until 2014.  On January 19, 2007, the Corporation announced that it had been
awarded a 25 year PPA to deliver 75 MW of wind power to New Brunswick Power. On
July 17, 2007, the Corporation announced it had amended its PPA with New
Brunswick Power from 75 MW to 96 MW bringing the total capital cost for the
project to an estimated $170 million. 
The project was completed by the end of 2008.  Natural Forces Technologies Inc. (Natural Forces), an Atlantic Canada based wind developer,
is TransAltas co-development partner in this project and Natural Forces has an
option to purchase up to 17 per cent of the Kent Hills project within 180 days
of its completion.  On February 13, 2008, the Corporation announced that, commencing
in 2009, it would be constructing a 66 MW wind generation facility in southern
Alberta, consisting of 22 Vestas V90 3 MW wind turbines.  The total capital cost for this Blue Trail
wind power project is expected to be $115 million.  The capacity from this project is expected to
be sold on the Alberta Power Pool.  The
Blue Trail wind farm is entitled to receive payments from Natural Resources
Canada (NRCan), a division of the federal
government, through the eco Energy for Renewable Power (eERP)
program.  On May 27, 2008, the Corporation announced that, commencing in
2009, it would be constructing another 66 MW wind generation facility in
southern Alberta, consisting of 22 Vestas V90 3 MW wind turbines.  The total capital costs for this expansion of
the Summerview 2 wind power project is expected to be $123 million.  The capacity from this project is expected to
be sold on the Alberta Power Pool.  With
this announcement, existing and planned wind generation facilities owned and
operated by the Corporation total 419 MW. 
The Summerview 2 wind farm expansion is entitled to receive payments
from NRCan through the eERP program.  All of the electricity generated and sold by the Corporations wind
division is from generation facilities that are EcoLogo certified.  The Corporation is an EcoLogo certified
distributor of Alternative Source Electricity through Environment Canadas
Environmental Choice program.  EcoLogo
certification is granted to products with environmental performance that meet
or exceed all government, industrial safety and performance standards.  The Corporations wind facilities constructed
after April 2001, also qualify for the Green E and Green Leaf
certifications.  Alberta PPAs  All of the Corporations Alberta thermal and hydroelectric facilities,
other than the Wabamun, Genesee 3 facilities, and uprated capacity, operate
under Alberta PPAs.  The Alberta PPAs
establish committed capacity and electrical energy generation requirements and
availability targets to be achieved by each thermal plant, energy and ancillary
services obligations for the hydroelectric plants, and the price at which
electricity is to be supplied.  The
Corporation bears the risk or retains the benefit of volume variances (except
for those arising from events considered to be force


- 13 -   majeure, in the case of the thermal plants) and any change in costs
(unless due to a change in law) required to maintain and operate the
facilities.  Under the Alberta PPAs, for the formerly regulated thermal facilities,
the Corporation is exposed to electricity price risk if availability declines
below contracted levels (other than as a result of outages caused by an event
of force majeure).  In such
circumstances, the Corporation must pay a penalty for the lost availability
based upon a price equal to the 30 day rolling average of Albertas market
electricity prices.  This rolling average
provision attempts to mitigate price spikes that can occur as a result of
sudden outages.  The Corporation attempts
to further mitigate this exposure by maintaining contracted and uncontracted
capacity in the market, through operating and maintenance practices, and
through hedging activities.  The Corporations hydroelectric facilities are not contracted on a
facility-by-facility basis; rather, facilities are aggregated in a single
Alberta PPA which provides for financial obligations for energy and ancillary
services based on hourly targets.  These
targeted amounts are met by the Corporation through physical delivery or third
party purchases.  The Corporations compensation under the Alberta PPAs is based on a
pricing formula which replaced the cost of service regime that applied
previously under utility regulation.  Key
elements of the pricing formula are the amount of common equity deemed to form
part of the capital structure, the amount of risk premium attributable to
deemed common equity and a recovery of fixed and variable costs.  Common equity is deemed to be 45 per cent of
total capital and the return on equity is set annually at a 4.5 per cent
premium over the rate on a 10-year Government of Canada Bond.  The pricing formula includes a provision for site restoration costs of
the thermal generating plants for the whole term of the PPA.  Until 2017, if the costs recovered are
insufficient, then the Corporation can apply to the Balancing Pool to recover
the incremental portion.  The Alberta
PPAs include, as part of the capacity payment for hydroelectric operations, an
amount for decommissioning.  The expiry dates for the Corporations Alberta PPAs, range from 2013 to
2020.  With the expiry of the PPA at the
Wabamun facility, the Corporation procured an extension of the license to
operate Unit four of the Wabamun facility until March 31, 2010.  The Corporation holds various licenses from
Alberta Environment and the AEUB to operate its other facilities, most of which
are renewed every few years.  The
Corporation is evaluating the economics of running assets post-PPA expiry.  Upon the expiry of the PPAs and subject to
procuring an extension of the licenses, if required, the Corporation will then
be able to sell its electricity to the Alberta Power Pool and to third party
purchasers through direct sales agreements. 
The Corporation is currently selling most of its electricity from the
Wabamun facility on the spot market.  The Alberta PPAs (together with legislation which applies thereto)
permit the Balancing Pool, an entity established by the Government of Alberta,
directly or indirectly as successor to the power purchaser under the Alberta
PPAs, to terminate the Alberta PPAs in certain circumstances.  These termination provisions are similar to
those found in some PPAs entered into by government related power
purchasers.  The Corporation will be
entitled to receive a lump sum payment in connection with any such termination,
other than a termination resulting from the Corporations default and will
thereafter be able to sell the output from any affected facilities for its own
account.  Canada:  Ontario  The Corporations Ontario generating facilities are summarized in the
following table:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesSarnia
  
  Sarnia
  
  506
  
  100
  
  2003Ottawa
  
  Ottawa
  
  68
  
  50
  
  1992Mississauga
  
  Mississauga
  
  108
  
  50
  
  1992


- 14 -   Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesWindsor
  
  Windsor
  
  68
  
  50
  
  1996Total
  
  
  
  750
  The Sarnia facility is a combined cycle cogeneration facility which is
owned by the Corporation.  The
Corporation acquired 135 MW of electric generation capacity in 2002, and in March 2003
the Corporation acquired the remaining 440 MW of capacity.  On January 1, 2009, the Corporation
applied, and subsequently received approval, to decommission a 69 MW turbine at
Sarnia.  The 506 MW facility provides
steam and electricity to nearby facilities owned by Dow Chemical Canada Inc.,
Lanxess (formerly Bayer Inc.), Nova Chemicals (Canada) Ltd. and Suncor Energy
Products Inc.  On February 15, 2006,
TransAlta announced that it had signed a five-year agreement with the OPA for
production at its Sarnia facility.  Under
the terms of the contract, TransAlta will be available to supply an average of
400 MW of electricity to the Ontario electricity market.  The supply contract is effective until December 31,
2010.  On December 24, 2008, the
Minister of Energy and Infrastructure directed the OPA to seek contracts with
certain energy providers in Ontario, namely those listed in a December 14,
2005 Direction which includes Sarnia, for the supply of clean and efficient
electricity generation.  The OPA is not
required to enter a new contract with the energy provider where an agreement
cannot be reached as to what constitutes a reasonable cost to Ontario
electricity consumers and a reasonable balancing of risk and reward.  The Ottawa plant is owned by TA Cogen. 
It is a combined cycle cogeneration facility designed to produce 68 MW
of electrical energy.  This capacity is
sold under a long-term contract with the Ontario Electricity Financial
Corporation (OEFC), an agency of the Province
of Ontario.  This agreement expires in
2012.  The Ottawa plant also provides
thermal energy to the member hospitals and treatment centers of the Ottawa
Health Sciences Centre, National Defence Medical Centre and the Perley and
Rideau Veterans Health Centre.  The Mississauga plant is owned by TA Cogen.  It is a combined cycle cogeneration facility
designed to produce 108 MW of electrical energy.  This capacity is contracted under a long-term
contract with the OEFC which expires in 2017. 
The Mississauga Plant provided cogeneration services to Boeing Canada
Inc. (Boeing) until July 2005 at which
time Boeing exercised its right under the cogeneration services agreement to no
longer take and pay for cogeneration services due to the recent closure of its
manufacturing facility.  Boeing remains
entitled to any steam credits based on the total plant electricity generation
revenue.  On or prior to each of January 1,
2013, 2018 and 2023, Boeing may give notice of its intention to continue to
purchase, or discontinue, cogeneration services.  In addition, on those same dates, Boeing has
the option to require the removal of the Mississauga Plant from the leased
lands or purchase the Mississauga Plant at its net salvage value.  The Windsor plant is owned by TA Cogen. 
It is a combined cycle cogeneration facility designed to produce 68 MW
of electrical energy.  Currently, 50 MW
of the capacity is sold under a long-term contract to the OEFC.  This agreement expires in 2016.  The Windsor plant also provides thermal
energy to Chrysler Canada Inc.s minivan assembly facility in Windsor.  In 2003, an agreement was reached with the
OEFC to sell the remaining 18 MW to the Ontario power market when it is
economic to do so.  United States  The Corporations generation facilities in the United States are
summarized in the following table:  Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesWashington
  
  Centralia Coal No. 1
  
  688
  
  100
  
  1971Centralia Coal No. 2
  
  688
  
  100
  
  1971Centralia Gas
  
  248
  
  100
  
  2002Skookumchuk
  
  1
  
  100
  
  1970


- 15 -   Location
  
  Plant
  
  Capacity
  (MW)
  
  Ownership
  (%)
  
  Commissioning DatesNew York
  
  Saranac
  
  240
  
  37.5
  
  1994California
  
  Vulcan
  
  34
  
  50
  
  1986Del Ranch
  
  38
  
  50
  
  1989Elmore
  
  38
  
  50
  
  1989Leathers
  
  38
  
  50
  
  1990CE Turbo
  
  10
  
  50
  
  2000Salton Sea I
  
  10
  
  50
  
  1987Salton Sea II
  
  20
  
  50
  
  1990Salton Sea III
  
  50
  
  50
  
  1989Salton Sea IV
  
  40
  
  50
  
  1996Salton Sea V
  
  49
  
  50
  
  2000Texas
  
  Power Resources
  
  212
  
  50
  
  1988Arizona
  
  Yuma
  
  50
  
  50
  
  1994Hawaii
  
  Wailuku
  
  10
  
  50
  
  1993Total
  
  
  
  2,464
  Centralia  The Corporation owns a two unit 1,376 MW thermal facility and a 248 MW
gas-fired facility in Centralia, Washington, located south of Seattle.  The Corporation also owns a 1 MW
hydro-electric generating facility and related assets on the Skookumchuk River
near Centralia, which facilities are used to provide reliable water supply to
TransAltas other generation facilities at Centralia.  TransAlta also owns a coal-mine adjacent to
the Centralia facility, however, it stopped all mining operations at the mine
in late 2006.  The Corporation has entered into a number of medium to long-term energy
sales agreements from the Centralia facility. 
The Corporation also sells electricity from the Centralia facility into
the Western Electricity Coordinating Council and, in particular, on the spot
market in the U.S. Pacific Northwest energy market.  The Corporations strategy is to balance
contracted and non contracted sales of electricity to manage production and
price risk.  The Corporation stopped mining operations at its Centralia coal-mine on
November 27, 2006.  Prior to that
date, the Centralia mine produced approximately five to six million tons of
coal annually, or approximately 70 to 85 per cent of the Centralia plants
annual coal requirements.  Although the
Corporation estimates that certain coal reserves remain to be extracted, the
Corporation has not yet received permits for, nor developed the new area, from
which this coal could be produced.  The
Corporation has entered into contracts to purchase and transport coal from the
Powder River Basin in Montana and Wyoming to fuel its facility until such time,
if any, as it is economic to pursue the extraction of coal at its Centralia
mine.  CE
Generation  On January 29, 2003, TransAlta announced the completion of the
acquisition from El Paso Corporation (El Paso) of a
50 per cent interest in CE Generation, for total consideration of approximately
US$240 million, which included approximately US$35 million for working
capital.  The CE Generation acquisition
included the right to a 50 per cent interest in Salton Sea VI, a geothermal
project, in the Imperial Valley, California. 
While there is still future development potential for CE Generation in
the Imperial Valley, the Salton Sea VI project that was being pursued when
TransAlta acquired its interest in CE Generation was never developed.  CE Generation, through its subsidiaries, is primarily engaged in the
development, ownership and operation of independent power production facilities
in the United States using geothermal and natural gas resources.  CE Generation holds a net ownership interest
of approximately 385 MW in 13 facilities, having an aggregate operating


- 16 -   capacity of 829 MW, including 327 MW of geothermal generation in
California and 502 MW of gas fired cogeneration in New York, Texas and Arizona.  CE Generation affiliates currently operate 10 geothermal facilities in
Imperial Valley, California.  Each of the
geothermal facilities sells electricity pursuant to independent, long term
contracts.  CE Generation affiliates currently operate three natural gas fired
facilities in Texas, Arizona and New York State, having an aggregate generation
capacity of 502 MW.  The Arizona facility
sells its output pursuant to long-term contracts while the Texas facility has
contracted a tolling agreement for capacity, which expires at the end of
2009.  The New York facility sells its
output pursuant to long-term contracts until mid-2009, after which point its
capacity will be sold on the spot market. The intent is to re-contract both the
New York facility and the Texas facility under a tolling agreement for
capacity.  Wailuku  On February 17, 2006, a subsidiary of TransAlta, together with a
subsidiary of Mid-American entered into an arrangement to purchase a 10 MW
hydro facility in Hawaii to be held directly by the Wailuku Holding Company
LLC.  Each of TransAlta and Mid American
hold a 50 per cent interest in the facility. 
The facility sells electricity pursuant to the terms of a 30 year
long-term contract with the Hawaii Electricity Light Company.  Australia  The Corporation holds interests in Western Australia consisting of the
110 MW Parkeston generation facility through a 50/50 joint venture with NP
Kalgoorlie Pty Ltd, a subsidiary of Newmont Australia Limited, and the 245 MW
Southern Cross Energy gas and diesel generation facilities.  Most of TransAltas generation supplies two
large mining companies through long-term capacity contracts and the remaining
amount of surplus energy and capacity is sold into Australias Wholesale
Electricity Market which was introduced in Western Australia in late 2006.  TA Cogen  The Corporations interest in the 220 MW Meridian natural gas fired
generation facility in Saskatchewan, the 780 MW Sheerness thermal generation
facility, the 118 MW Fort Saskatchewan gas fired cogeneration facility in
Alberta, and the Mississauga, Ottawa and Windsor Essex facilities in Ontario,
are held through TA Cogen, an Ontario limited partnership owned 50.01 per cent
by subsidiaries of TransAlta and 49.99 per cent by Stanley Power Inc., a
subsidiary of Cheung Kong Infrastructure Holdings Limited.  Commercial
Operations and Development  The Commercial Operations Development group provides a number of
strategic functions to the Corporation, including the following:  ·Gathering and assessing market intelligence, enabling management to
more effectively engage in strategic planning and decision making for the
Corporation.  This includes identifying
and ranking markets which are the most attractive to enter, and developing
strategies and plans to effectively compete in each market where the
Corporation operates;  ·Identifying specific opportunities to develop, acquire, or divest of
generation assets in markets where the Corporation is operating or growing and
completing the business arrangements so the Corporation can either make
investment or divesture decisions;  ·Negotiating and entering into contractual agreements with customers
for the sale of output from the Corporations generating assets, including
electricity, steam or other energy related commodities;


- 17 -   ·Scheduling physical deliveries of natural gas supplies used to
generate electricity and the electrical generation outputs from each asset to
meet contractual obligations while managing the physical and financial risks
associated with the generation and transmission of electrical energy, including
during those periods of unplanned outages;  ·Increasing the value of electricity output and fuel inputs from each
generating asset through a variety of regional portfolio optimization
strategies in both the current year and over the long-term; and  ·Recommending optimum maintenance schedules and operating levels
according to current and anticipated market conditions that will maximize
earnings from each of the generation assets.  Beyond these functions, the Commercial Operations Development group
derives additional revenue and earnings from the wholesale trading of
electricity and other energy related commodities and derivatives.  The group seeks to manage and limit risk exposures from both financial
and physical positions, as well as counterparty risks.  The key risk control activities of the
Commercial Operations Development group, in conjunction with other functions of
the Corporation, include credit review approval and reporting, risk measurement
monitoring and reporting, validation of transactions, and trading portfolio
valuation monitoring and reporting.  The Corporation uses mark-to-market valuation and the application of a
value at risk (VAR) determination for risk
control practices for its trading portfolios. 
This approach is a measure of assessing the potential trading losses
that the Corporation could experience over a given time, due to fluctuations in
energy prices in each market.  The
Corporations policy is to actively manage and limit the groups aggregate VAR
exposure within board approved limits.  Competitive Environment  TransAlta is the largest generator of electricity in Alberta, measured
by capacity, and has a significant portfolio of generation assets in the
Pacific Northwest and western U.S.  The
Corporation also owns and operates generating assets in eastern Canada and
Australia.  The Corporation expects continued long-term growth of electricity
demand in its core markets although short-term growth rates may be
significantly reduced in the current economic environment.  In addition to increased demand, many of the
markets in which TransAlta participates have established renewable portfolio
targets or standards that require new renewable power investments.  As part of its balanced approach to capital allocation which includes
returning capital to shareholders through dividends and share buybacks,
TransAlta also has plans for investing in new capacity in its core markets
where opportunities exist for renewable and cogeneration assets.  Alberta is Canadas fourth largest province by population with
approximately 3.6 million residents representing approximately 11 per cent of
Canadas total population.  Alberta
consumed approximately 70,000 GWh of electricity in 2008.  As at December 31, 2008, the aggregate
installed capacity of generating facilities in Alberta was approximately 12,300
MW.  Electrical utilities in the U.S. Pacific Northwest are organized into
the Western Electricity Coordinating Council (WECC).  The WECC is the largest geographically of the
ten regions in the North American Electric Reliability Council and is divided
into four sub regions, of which Region 1 includes British Columbia, Alberta,
Washington, Oregon, Idaho, Montana, Utah, Western Wyoming and Northern
Nevada.  This sub region is referred to
as the Northwest Power Pool (NWPP). 
The WECC estimates that approximately 369,000 GWh of electricity was
consumed in the NWPP in 2008.  The WECC
also reported an estimated aggregate electrical generating capacity of
approximately 85,000 MW in the NWPP for the year ending 2008.


- 18 -   Ontario is Canadas largest province with approximately 12.9 million
residents representing approximately 39 per cent of Canadas total
population.  Ontario consumed
approximately 148,700 GWh of electricity in 2008.  Ontario Power Generation Inc., the successor
to the generation business of Ontarios former integrated electric utility,
controls two thirds of Ontarios approximately 32,000 MW of installed capacity,
the balance of which is owned by municipal electric utilities and private
independent power producers or industrial consumers.  In October 2004, the provincial government of New Brunswick
officially opened the electricity market to partial competition and corporate
reorganization. The Electricity Act (2004) allows
wholesale and industrial consumers to purchase power from either New Brunswick
Power or a competing supplier. The new competitive market does not extend to
retail customers, businesses or small industries.  In 2007, New Brunswick announced the Charter
for Change requiring ten per cent of electricity purchases to be from renewable
sources commencing in 2016.  The Corporation expects that the demand for electricity will continue
to grow in its target markets over the long-term.  In addition to increased demand, the market
for electricity in some of these regions has undergone deregulation.  Legislation in Alberta and Ontario and many
states in the United States have mandated the unbundling of generation,
transmission and distribution services which were traditionally provided by
vertically integrated utilities to promote competition in the market for
generation, which caused some integrated utilities to sell all or parts of
their generation assets.  While the pace
of this process has changed, the Corporation believes that the combination of
increased demand for electricity, deregulation and the increased availability
of generation assets may provide an opportunity to increase its generation
capacity and leverage its Commercial Operations Development capabilities,
provided that in doing so, the financial position of the Corporation is not
compromised.  Australia is heavily dependent on coal for electricity, more so than
any other developed country except Denmark and Greece.  About 80 per cent of power produced is
derived from coal.  Natural gas is
increasingly used for electricity, especially in South Australia and Western
Australia.  The Australian Bureau of
Agriculture and Resource Economics (ABARE) estimated total production of
272,000 GWh for 2008 with a growth rate of approximately 2.4 per cent per annum
from 2009 to 2012.  The major reform in
the Australian electricity industry involved the establishment in southern and
eastern Australia of the National Electricity Market (NEM).  In Western Australia, where TransAltas power
assets are located, a new Wholesale Electricity Market (WEM) was introduced
in late 2006. Total installed capacity in the WEM is about 4,500 MW, while
TransAltas capacity in the region is approximately 345 MW.  TransAlta enjoys a solid competitive
advantage in power supply to mining operations, especially remote mining
operations, and has built up significant knowledge and expertise in this field.  Competitive Strengths  The Corporation believes it is well positioned to achieve its business
strategy due to its competitive strengths, which include the following:  Financial
strength - The Corporation has investment
grade ratings from Moodys Investor Services, Inc. (Moodys),
Standard & Poors, a division of the McGraw Hill Companies, Inc.
(S&P) and Dominion Bond Rating
Service Limited (DBRS).  Stable
cash flow base  Approximately 70 per cent
of the Corporations generating capacity is contracted through PPAs or LTCs
for the next five years.  Revenues
received under contractual arrangements are not subject to short-term
fluctuations in the spot price for electricity.  Fuel
diversity - The Corporation has a diverse
mix of fuels used for the generation of electricity, including coal, natural
gas, hydro, geothermal and wind.  The
Corporation believes that this mix reduces the impact on corporate performance
in the event of external events affecting one fuel source.  Management
team - The Corporations management team has
substantial industry, international and local market experience.


- 19 -   Commercial
Operations Development expertise - The
Corporation believes that its Commercial Operations Development group has
enhanced returns from the Corporations existing generation base and has
allowed the Corporation to obtain more favourable pricing for uncommitted
electricity, secure fuel supply on a cost-effective basis and fulfill
electricity delivery obligations in the event of an outage.  Ownership
or control of coal supply - The Corporation
owns, controls or leases extensive coal reserves in Alberta that provide a long-term
and stable source of fuel for all of its thermal generation capacity in
Alberta.  The Corporations mines in
Alberta contain some of the lowest sulphur coal in North America, averaging
0.25 per cent sulphur at the Whitewood mine and 0.25 per cent at the Highvale
mine.  Coal with lower sulphur content
emits less sulphur dioxide when it is burned.  Wind
Generation - The Corporation is one of the
largest owners and operators of wind generation in Canada.  The Wind management team has developed key
relationships with customers, suppliers and policy makers that provide a
competitive advantage in the development, operations and marketing of wind
generation.  Environment  The Corporation is a recognized leader in Sustainable Development
and has taken early preventative action on a number of environmental fronts in
advance of regulation.  Capital Expenditures  Capital expenditures for property and investments (including acquisitions)
by TransAlta for the past five years were:  2008
  
  $1,006.4 million
  
  2005
  
  $325.5 million2007
  
  $599.7 million
  
  2004
  
  $345.7 million2006
  
  $224.9 million
   ENVIRONMENTAL
RISK MANAGEMENT  TransAlta is subject to federal, provincial, state and local
environmental laws, regulations and guidelines concerning the generation and
transmission of electrical and thermal energy and surface mining.  TransAlta is committed to complying with
legislative and regulatory requirements and to minimizing the environmental
impact of its operations.  TransAlta
works with governments and the public to develop appropriate frameworks to
protect the environment and to promote sustainable development.  TransAltas approach to managing its environmental, health and safety (EHS) risks has three elements:  ·              Compliance based activities, such as permitting and
reporting;  ·              ISO based EHS Management systems and programs, such as
safety programs and auditing; and  ·              Longer term strategic initiatives, including climate
change and government policy development.  These elements are integrated into TransAltas corporate wide
operations and management systems.  They
are designed to mitigate risks of TransAltas activities to employees, the
public and the environment, and to address potential competitive risks from future
changes in environmental policy.  They
are also supportive of TransAltas corporate commitment to sustainability.  To meet regulatory requirements and improve environmental performance,
TransAlta made environmental operating and capital expenditures in fiscal year
2008 of approximately $47 million. 
Environmental expenditures are generally defined as expenditures
incurred to comply with Canadian or international environmental regulations,
conventions or voluntary agreements.


- 20 -   All TransAltas facilities are in material compliance with existing
regulatory requirements.  Environmental
risk at the plants operated by TransAlta has been reduced by actions in several
areas:  ·
  
  Continued investment in mercury control
  technology evaluation leading to expected installation of mercury capture
  equipment at our Alberta coal plants in 2010, and at our Centralia,
  Washington coal plant by 2012;·
  
  Uprate improvements delivering higher
  efficiency generation at the Sundance plant;·
  
  Continued program of compliance and
  management system audits at all facilities;·
  
  The planned decommissioning of the older
  Wabamun thermal plant in 2010;·
  
  Acquisition of carbon offsets;·
  
  Continued expansion of the wind energy
  business, with minimal emissions footprint; and·
  
  Development of a carbon capture and
  storage demonstration project in Alberta.  On a longer time horizon, TransAlta anticipates future environmental regulatory
developments in areas such as climate change, air quality and water.  Regulatory changes and policy developments
are tracked in all relevant jurisdictions. 
Relevant regulatory developments are discussed below.  Canada  On January 24, 2008, the Government of Alberta announced its
long-term intention to cut greenhouse gas emissions to 14 per cent below 2005
levels by 2050 through developing and implementing carbon capture and storage
technologies, developing conservation and energy efficiency programs, and
through increased investment in clean energy technologies.  We are assessing the impact of this proposal
upon our operations and our own investment in environmental technologies and
programs.  Alberta continues to maintain its greenhouse gas (GHG)
regulatory regime which was implemented in July 1, 2007, under the Climate Change and Emissions Management Amendment Act.  Under the legislation, baselines and targets
for GHG intensity are set on a facility-by-facility basis.  The legislation and subsequent regulations
require a 12 per cent reduction in GHG emission intensity from a baseline of
the average of 2003 to 2005 emission levels. 
New facilities or those in operation for less than three years are
exempt; however, upon the fourth year of operations, the facility baseline is
established and reduction requirements gradually increase until the eighth year
by which time emissions must be 12 per cent below the established
baseline.  Emissions over the baseline must
be mitigated either through contributions to an Alberta Technology Fund at $15
per tonne, or through the purchase and retirement of Alberta-based offsets from
non-regulated sectors.  The PPAs for our
Alberta-based coal facilities contain change-in-law provisions that allow us to
recover compliance costs from the PPA customers.  After flow-through, the annual net compliance
costs for 2008 are estimated to be $1.2 million.  Mercury reduction requirements in Alberta are established at a 70 per
cent reduction by 2010.  We submitted our
mercury control plan in March 2007. 
Detailed mercury technology testing was conducted in 2008 and further is
expected in 2009.  Engineering work is
underway to have mercury controls fully implemented in 2010.  On April 26, 2007, the Canadian government released details of its
proposed environmental legislation in its Turning the Corner policy paper. The
federal plan calls for an 18 per cent reduction in GHG emission intensity
starting in 2010, increasing to a 20 per cent absolute reduction requirement by
2020. The plan also calls for a reduction in air pollutants such as sulphur
dioxide, nitrous oxide, mercury, and particulates starting in the 2012 - 2015
period. Proposed reduction caps range from 45 per cent to 60 per cent of
current levels.  A number of material details
in the


- 21 -   federal plan are still to be determined, including its interaction with
provincial programs, which would allow a reasonable determination of future
compliance costs.  The Canadian government indicated in January 2009 that it intends to
develop an integrated cap and trade program for greenhouse gas emissions, in
cooperation with its North American trading partners.  There are few details of this new approach
and it is therefore not possible to determine what compliance costs would be or
how it might affect the previous approach.  In August 2007, the Government of Ontario announced its climate change
action plan which included a target to reduce GHG emissions by 6 per cent below
1990 level by 2014.  Subsequently the
government has indicated its intention to implement a cap and trade system for
greenhouse gases by 2010, although no additional legislation or details have
been developed.  United
States  In the United States, the Washington State Climate Bill 6001 was
enacted and came into effect on July 22, 2007.  Our operations will not be impacted by the
bills performance standards at the current time, provided the facilities do
not change ownership or enter into power sales contracts longer than five
years.  On December 12, 2008, Washington State introduced draft
legislation to enable a cap and trade system to be implemented by 2012.  Specific details of caps and allocations will
be developed in 2009.  In parallel,
Washington State is engaged with other western states in the Western Climate
Initiative (WCI) to examine a regional cap
and trade system for carbon.  On September 23,
2008, the WCI released its design for a regional greenhouse gas cap and trade
system, which will be influential in individual state regulation
development.  At this point, there are no
indications as to how these initiatives will impact our fossil-fired assets in
Washington.  The United States Federal Government continues to contemplate a number
of proposed GHG related bills, but to date no clear outcome or schedule is
evident.  In February 2009, the
Administration provided a budget plan for implementing an economy-wide federal
cap & trade system to reduce greenhouse gases to 14 per cent below
2005 levels by 2020.  The budget includes
a plan to auction 100 per cent of the required allowances, with approximately
$150B of the revenue raised from auctioning to be allocated to clean energy
investments over 10 years.  TransAlta is an active participant in the Canadian Clean Power
Coalition, which is committed to developing clean coal technology in
Canada.  The coalition has several
engineering initiatives underway which will provide important guidance on
ultimate clean coal solutions for TransAltas facilities.  The Corporation is also exploring the
possibilities for a CO2 network pipeline through the ICON industry consortium.  In April 2008, TransAlta announced a partnership with Alstom LLC
to develop a one million tonne/year carbon capture and storage project at one
of TransAltas coal-fired power stations in Alberta.  This project has been shortlisted by the
Alberta Government for contributory funding as part of the provinces $2
billion CCS program, with a decision expected by June 30, 2009.  Environmental issues concerning water use are managed within the ISO
14001 framework.  TransAlta continues to
work with regulators in each jurisdiction in which it operates, to ensure water
is used wisely on site and that all regulations pertaining to water and
wetlands management, both on and off site, are met at all times.  TransAltas environmental efforts have been recognized by the Dow Jones
North American Sustainability Index for four years in a row.  The Index represents the best environmental
performance leaders in North America.  In
2008, TransAlta also participated in the global Carbon Disclosure Project which
requires detailed assessments of corporate climate change plans and actions.


- 22 -   To date, TransAlta does not believe that its competitive position in
the wholesale generation business has been adversely affected by environmental
concerns.  TransAlta continues to make
operational improvements and investments to its existing generating facilities
to reduce the environmental impact of generating electricity.  RISK
FACTORS  Readers should consider carefully the risk factors set forth below as
well as the other information contained and incorporated by reference in this
Annual Information Form. For a further discussion of risk factors affecting
TransAlta, please refer to Risk Factors in the Annual MD&A, which is
incorporated by reference herein.  A reference herein to a material adverse effect on the Corporation
means such an effect on the Corporation on its business, financial condition,
results of operations, or its cash flows, as the context requires.  Changes in the prices and availability of fuel
supplies required to generate electricity, and in the price of electricity, may
materially adversely affect the Corporation.  A significant portion of the Corporations revenues are tied, either
directly or indirectly, to the market price for electricity in the markets in
which the Corporation operates.  Market
electricity prices are impacted by a number of factors, including: the price of
fuel that is used to generate other sources of electricity (and, accordingly,
certain of the factors that affect the price of fuel described below); the
management of generation and the amount of excess generating capacity relative
to load in a particular market; the cost of controlling emissions of pollution,
including potentially the cost of carbon; the structure of the particular
market; and weather conditions that impact electrical load.  As a result, the Corporation cannot
accurately predict future electricity prices and electricity price volatility
could have a material adverse effect on the Corporation.  The Corporation buys natural gas and some of its coal to supply the
fuel needed to generate electricity. The Corporation could be materially
adversely affected if the cost of fuel that it must buy to generate electricity
increases to a greater degree than the price that it can obtain for the
electricity that it sells.  Several
factors affect the price of fuel, many of which are beyond the Corporations
control, including:  ·              prevailing market prices for fuel, including any
associated transportation costs;  ·              demand for energy products;  ·              increases in the supply of energy products in the
wholesale power markets; and  ·              the extent of fuel transportation capacity or cost of
fuel transportation service into the Corporations markets.  Changes in any of these factors may increase the Corporations cost of
producing power or decrease the amount of revenue it receives from the sale of
power, which could materially adversely affect the Corporation.  The rules and regulations in the various markets in
which the Corporation operates are subject to change, which may materially
adversely affect the Corporation.  Certain of the markets in which the Corporation operates and intends to
operate are subject to significant regulatory oversight and control.  The Corporation is not able to predict
whether there will be any further changes in the regulatory environment, including
potential regulation of the rates allowed to be charged and the capital
structure of wholesale generating companies such as the Corporation, or what
the ultimate effect of a changing regulatory environment will have on its
business.  Existing market rules and
regulations may be revised or reinterpreted and new laws and regulations may be
adopted or become applicable to the Corporation or its facilities which could
have a material adverse effect on the Corporation.  The Corporation cannot guarantee that it will
be able to adapt its business


- 23 -   in a timely manner in response to any changes in the regulatory regimes
in which it operates, and such failure to adapt could have a material adverse
effect on the Corporation.  Regulatory authorities may also from time to time investigate the
Corporations activities in the markets in which it operates or pursues
trading.  Such investigations may result
in sanctions or penalties which may materially affect the Corporations future
activities or financial status.  The Corporations facilities are also subject to various licensing and
permitting requirements in the jurisdictions in which they operate, many of
which licenses and permits need to be renewed from time to time.  If the Corporation is unsuccessful in
renewing such licenses or permits, or the terms of such licenses or permits are
changed in a manner that is adverse to the Corporation, the Corporation could
be materially adversely affected.  Any changes in the rules and regulations of provincial or state
public utility commissions or other regulatory bodies in the other markets in
which the Corporation competes or may compete in the future may materially
adversely affect the Corporation.  Many of the Corporations activities and properties
are subject to environmental requirements and changes in, or liabilities under,
these requirements may materially adversely affect the Corporation.  The Corporations operations are subject to extensive Canadian, United
States and other federal, provincial, state and local environmental laws,
regulations and guidelines, relating to the generation and transmission of
electrical and thermal energy and surface mining, pertaining to pollution and
protection of the environment, health and safety and governing among other
things, air emissions, water usage and discharges, storage, treatment and
disposal of waste and other materials and remediation of sites and land use
responsibility (collectively, environmental regulation).  These laws can impose liability for costs to
investigate and remediate contamination without regard to fault and under
certain circumstances liability may be joint and several resulting in one
responsible party being held responsible for the entire obligation.  Environmental regulation can also impose,
among other things, restrictions, liabilities and obligations in connection
with the generation, handling, use, storage, transport, treatment and disposal
of hazardous substances and waste and can impose clean-up, disclosure or other
responsibilities with respect to spills, releases and emissions of various
substances to the environment. 
Environmental regulation can also require that facilities and other
properties associated with the Corporations operations be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable
regulatory authorities.  In addition,
there is an increasing level of environmental regulation regarding the use,
treatment and discharge of water and increasing anticipation of new or
additional emission regulations at a national level in Canada and the United
States which may impose different compliance requirements standards on the
Corporation.  These various compliance
standards may result in duplicate compliance and costs requirements for the
Corporation or may impact our ability to operate our facilities.  To comply with environmental regulation, the Corporation must incur
material capital and operating expenditures relating to environmental
monitoring, emissions and effluent control equipment and processes, emissions
measurement, verification and reporting, emissions fees and other compliance
activities or obligations.  The
Corporation expects to continue to have environmental expenditures in the
future.  Stricter standards, new or
greater regulation, increased enforcement by regulatory authorities, more
extensive permitting requirements, an increase in the number and types of
assets operated by the Corporation subject to environmental regulation and the
implementation of provincial, state and national GHG emissions, mercury
emissions or other air emissions regulation in a jurisdiction in which we
operate could increase the amount of these expenditures. To the extent these
expenditures cannot be passed through to our customers under our power purchase
agreements, including Alberta PPAs (as defined herein) or otherwise, the costs
to the Corporation could be material.  In
addition, compliance with environmental regulation might result in restrictions
on some of the Corporations operations. 
If the Corporation does not comply with environmental regulation,
regulatory agencies could seek to impose statutory, administrative and/or
criminal liabilities on the Corporation or to curtail its operations and
significant expenditures on compliance, new equipment or technology, reporting
obligations and research and development. 
In addition to environmental regulation, the Corporation could also face
civil liability in the event that private parties seek to impose liability on
the Corporation


- 24 -   for property damage, personal injury or other costs and losses.  The Corporation cannot guarantee that
lawsuits or administrative or investigative actions will not be commenced
against it otherwise affect its operations and assets.  If an action is filed against the Corporation
or which may otherwise affect its operations and assets, the Corporation could
be required to make substantial expenditures to defend or evidence its
activities or to bring the Corporation, its operations and assets into
compliance, which could have a material adverse effect on the Corporation.  A number of recent federal, provincial, state and local regulatory
efforts continue to focus on potential climate change or GHG emissions
regulation.  GHG legislation is in early
stages of evolution in Canada and the United States, and it is relatively early
to determine the impact of potential GHG reduction requirements.  For example, the issues of jurisdiction to
regulate GHG emissions, as between the federal and provincial governments, and
whether both levels of government will be able to agree on harmonization of
desired GHG emissions reduction requirements, also remains outstanding in
Canada.  In addition, Washington is part
of a group of states in the Western Climate Initiative, which have announced
the intention to implement a cap and trade program for GHGs by 2012.  Mandatory GHG emissions reductions
requirements are expected to impose increased costs on the Corporation, as is
expected to be the case generally for thermal power producers in North
America.  The Corporation is subject to
other air quality regulation including mercury regulation.  At this time, the Corporation cannot assess the
potential impact of future mercury regulation at its United States facilities.  To the extent new or additional GHG, mercury
or other air emission regulations may require the Corporation to incur costs
that cannot be passed through to our customers under our power purchase
agreements, including Alberta PPAs or otherwise, the costs could be material
and have a material adverse effect on the Corporation.  The Corporations surface mining operations are subject to laws and
regulations establishing mining, environmental protection and reclamation
standards for all aspect of surface mining. 
As a mine owner or operator the Corporation must obtain permits from the
applicable regulatory body providing for the authorization of certain mining
operations that result in a disturbance of the surface.  These requirements seek to limit the adverse
impacts of coal mining and more restrictive requirements may be adopted from
time to time.  TransAlta as a mine owner
or operator may also be required to submit a bond or otherwise secure payment
of certain long-term obligations including mine closure or reclamations
costs.  Surety bond costs have increased
in recent years while the market terms of such bonds have generally become more
unfavourable.  In addition, the number of
companies willing to issue surety bonds has decreased.  TransAlta could be required to self fund
these obligations should it be unable to renew or secure the required surety
bonds for its mining operations.  Changes in general economic conditions may have a
material adverse effect on the Corporation.  Adverse changes in general economic and market conditions could
negatively impact product demand, revenue, operating costs, timing and extent
of capital expenditures, the net recoverable value of plant, property and
equipment, results of financing efforts, credit risk, and counterparty risk,
which could have a material adverse effect on the Corporation. Changes in
interest rates can impact the Corporations borrowing costs and the capacity
revenues the Corporation receives pursuant to the Alberta government mandated
power purchase arrangements (the Alberta PPAs).  Under the government mandated power purchase arrangements pursuant to
which the Corporation operates most of its facilities in Alberta, the
Corporation is subject to certain risks, including the possibilities of
penalties for unplanned outages and the burden of increased costs required to
maintain and operate its generation facilities.  The majority of the Corporations Alberta coal fired and hydroelectric
generating plants operate under the Alberta PPAs which established committed
capacity and electrical energy generation requirements and availability targets
to be achieved by each coal fired plant, energy and ancillary services
obligations for the hydroelectric plants, and the price at which power will be
supplied.  Under the Alberta PPAs
applicable to coal fired plants, in the event of an unplanned outage, other
than an outage determined to be caused by force majeure, the Corporation must
pay a penalty for the lost production based upon a price equal to the 30 day
trailing average of Alberta market electricity prices.  Consequently, an unplanned outage could have
a material adverse effect on the Corporation.


- 25 -   The Corporation bears some of the impact of increases in its operating
costs (other than increases arising as a result of a change of law as such
term is defined in the Alberta PPAs) because the price at which the Corporation
is able to sell its generation under the Alberta PPAs is based on a schedule of
forecast fixed costs.  Many of the
forecast costs will be determined by indices, formulae or other means for the
entire term of the Alberta PPA.  The
Corporations actual results will vary and depend on performance compared to
the forecasts on which the Alberta PPAs are based. Operating costs could
increase as a result of a number of factors which are beyond the Corporations
control. A significant increase in the Corporations operating costs could have
a material adverse effect on the Corporation.  From time to time during the term of the Alberta PPAs, issues may arise
regarding the intended operation of the Alberta PPAs which may require certain
provisions of the Alberta PPAs to be interpreted, and the interpretations given
may not be favourable to the Corporation. 
In such circumstances, the Corporation could be materially adversely
affected.  The operation and maintenance of the Corporations
facilities involves risks that may materially adversely affect the Corporation.  The operation, maintenance, refurbishment, construction and expansion
of power generation facilities involve risks, including breakdown or failure of
equipment or processes, fuel interruption and performance below expected levels
of output or efficiency.  Certain of the
Corporations generation facilities, particularly in Alberta, were constructed
many years ago and may require significant capital expenditures to maintain
peak efficiency or to maintain operations at all.  In addition, weather related interference,
work stoppages and other unforeseen problems may disrupt the operation and
maintenance of the Corporations facilities and may materially adversely affect
the Corporation.  The Corporation has entered into on going maintenance and service
agreements with the manufacturers of certain critical equipment.  If a manufacturer is unable or unwilling to
provide satisfactory maintenance or warranty support, the Corporation may have
to enter into alternative arrangements with other providers if it cannot perform
the maintenance itself.  These arrangements
could be more expensive to the Corporation than its current arrangements and
this increased expense could have a material adverse effect on the
Corporation.  If the Corporation is
unable to enter into satisfactory alternative arrangements, the inability of
the Corporation to access technical expertise or parts could have a material
adverse effect on the Corporation.  While the Corporation maintains an inventory, or otherwise makes
arrangements to obtain, spare parts to replace critical equipment and maintains
insurance for property damage to protect against operating risks, these
protections may not be adequate to cover lost revenues or increased expenses
and penalties which could result if the Corporation is unable to operate its
generation facilities at a level necessary to comply with sales contracts
(including Alberta PPAs).  The Corporation may be subject to the risk that it is necessary to
operate a plant at a capacity level beyond that which the Corporation has
contracted to provide steam in order to fulfill a contract.  In such circumstances the costs to produce
the steam being sold may exceed the revenues derived therefrom.  The Corporation relies on transmission lines that
it does not own or control, which may hinder its ability to deliver electricity.  The Corporation depends on transmission and distribution facilities
that are owned and operated by utilities and other power companies to deliver
the electricity the Corporation generates. 
An extended disruption in transmission would impact the Corporations
ability to sell and deliver electricity, which could have a material adverse
effect on the Corporation.  The Corporation may be adversely affected if its
supply of water is materially reduced.  Hydroelectric, natural gas, and coal-fired plants require continuous
water flow for their operation. Shifts in weather or climate patterns,
seasonable precipitation, the timing and rate of melting, run off, and other
factors beyond the control


- 26 -   of the Corporation, may reduce the water flow to the Corporations
facilities.  Any material reduction in
the water flow to the Corporations facilities would limit the Corporations
ability to produce and market electricity from these facilities and could have
a material adverse effect on the Corporation. 
There is an increasing level of regulation respecting the use, treatment
and discharge of water, and respecting the licensing of water rights in
Alberta.  Any such change in regulations
could have a material adverse effect on the Corporation.  Trading risks may have a material adverse affect on
the Corporation.  The Corporations trading and marketing business frequently involves
the establishment of trading positions in the wholesale energy markets on both
a long term and short term basis.  To the
extent that the Corporation has long positions in the energy markets, a
downturn in the markets is likely to result in losses from a decline in the
value of such long positions. 
Conversely, to the extent that the Corporation enters into forward sales
contracts to deliver energy the Corporation does not own, or take short
positions in the energy markets, an upturn in the energy markets is likely to
expose the Corporation to losses as it attempts to cover any short positions by
acquiring energy in a rising market.  In addition, from time to time the Corporation may have a trading
strategy consisting of simultaneously holding a long position and a short
position, from which the Corporation expects to earn a profit based on changes
in the relative value of the two positions. 
If, however, the relative value of the two positions changes in a
direction or manner the Corporation did not anticipate, it could realize losses
from such a paired position.  If the strategy the Corporation uses to hedge its exposures to these
various risks is not effective, it could incur significant losses.  The Corporations trading positions are
subject to the level of volatility in the energy markets that, in turn, depend
on various factors, including weather in various geographical areas and short
term supply and demand imbalances, which cannot be predicted with any
certainty.  A shift in the energy markets
could adversely affect the Corporations positions which could also have a
material adverse effect on the Corporation.  While the Corporation uses a number of risk management controls to
limit its exposure to risks arising from its trading activities, including
value-at-risk, volumetric and term limits and restrictions on authorized instruments,
the Corporation cannot guarantee that losses will not occur and such losses, if
material, could have a material adverse effect on the Corporation.  Because of the Corporations multinational
operations, the Corporation is subject to currency rate risk and regulatory and
political risk.  A significant part of the Corporations revenues and expenditures are
in U.S. and other currencies. 
Fluctuations in the exchange rate between these currencies and the
Canadian dollar could have a negative effect on the Corporation. While the
Corporation attempts to manage this risk through its use of hedging
instruments, including cross currency swaps, forward exchange contracts and by
matching revenues and expenses by currency at the Corporate level, fluctuations
in these exchange rates may have a material adverse effect on the Corporation.  In addition to currency rate risk, the Corporations foreign operations
may be subject to regulatory and political risk.  Any change to the regulations governing power
generation or the political climate in countries where the Corporation has
operations could impose additional costs and have a material adverse effect on
the Corporation.  The Corporation may have difficulty raising needed
capital in the future, which could significantly harm its business.  To the extent that the Corporations sources of cash and cash flow from
operations are insufficient to fund the Corporations activities, it may need
to raise additional funds.  Additional
financing may not be available when needed and, if such financing is available,
it may not be available on terms favourable to the Corporation.


- 27 -   The Corporations debt securities will be
structurally subordinated to any debt of its subsidiaries that is currently
outstanding or may be incurred in the future.  The Corporation operates its business through, and a majority of its
assets are held by, its subsidiaries, including partnerships.  The Corporations results of operations and
ability to service indebtedness are dependent upon the results of operations of
its subsidiaries and the payment of funds by these subsidiaries to it in the
form of loans, dividends or otherwise. 
The Corporations subsidiaries will not have an obligation to pay amounts
due pursuant to any debt securities issued by the Corporation or make any funds
available for payment of debt securities issued by the Corporation, whether by
dividends, interests, loans, advances or other payments.  In addition, the payment of dividends and the
making of loans, advances and other payments to the Corporation by its
subsidiaries may be subject to statutory or contractual restrictions.  In the event of the liquidation of any subsidiary, the assets of the
subsidiary would be used first to repay the indebtedness of the subsidiary,
including trade payables or obligations under any guarantees, prior to being
used to pay the Corporations indebtedness, including any debt securities
issued by the Corporation.  Such
indebtedness and any other future indebtedness of such subsidiaries would be
structurally senior to any debt securities issued by the Corporation.  The Corporations subsidiaries have financed some investments using non
recourse project financing.  Each non
recourse project loan is structured to be repaid out of cash flow provided by
the investment.  In the event of a
default under a financing agreement which is not cured, the lenders would
generally have rights to the related assets. 
In the event of foreclosure after a default, the Corporations
subsidiary may lose its equity in the asset or may not be entitled to any cash
that the asset may generate.  Although a
default under a project loan will not cause a default with respect to any debt
securities issued by the Corporation, it may materially affect the Corporations
ability to service its outstanding indebtedness.  Certain of the contracts to which the Corporation
is a party require the Corporation to provide collateral against its
obligations.  The Corporation is exposed to risk under certain electricity and
natural gas purchase and sale contracts entered into for the purposes of hedges
and proprietary trading. The terms and conditions of these contracts require
the Corporation to provide collateral when the fair value of these contracts is
in excess of any credit limits granted by the Corporations counterparties and
the contract obliges the Corporation to provide the collateral.  The change in fair value of these contracts
occurs due to changes in commodity prices. 
These contracts include: (i) purchase agreements, when forward
commodity prices are less than contracted prices; and (ii) sales
agreements, when forward commodity prices exceed contracted prices. Downgrades
in the Corporations creditworthiness by certain credit rating agencies may
decrease the credit limits granted by the Corporations counterparties and
accordingly increase the amount of collateral the Corporation may have to
provide.  If counterparties to the Corporations contracts
are unable to meet their obligations, the Corporation may be materially
adversely affected.  If purchasers of the Corporations electricity, steam or other
contractual counterparties of the Corporation default on their obligations, the
Corporation may be materially adversely affected. While the Corporation seeks
to control its exposure to credit risk by considering the ability of
counterparties to fulfill their obligations under the related contracts prior
to entering into such contracts, the Corporation cannot guarantee that it will
be successful in identifying credit worthy customers.  Moreover, while the Corporation seeks to
monitor trading activities to ensure that the credit limits for counterparties
are not exceeded, it cannot guarantee that it will be successful in doing
so.  If counterparties to the Corporations
contracts are unable to meet their obligations, the Corporation could suffer a
reduction in revenue which could have a material adverse effect on the
Corporation.


- 28 -   Insurance coverage may not be sufficient.  The Corporation has insurance for its facilities, including all risk
property insurance, commercial general public liability insurance, boiler and
machinery coverage, replacement power and business interruption insurance, in
amounts and with deductibles that the Corporation considers appropriate.  The Corporations insurance coverage may not
be available in the future on commercially reasonable terms or adequate
insurance limits may not be available in the market.  In addition, the insurance proceeds received
for any loss of or any damage to any of its generation facilities may not be
sufficient to permit it to continue to make payments on its debt.  Provision for income taxes may not be sufficient.  The Corporations operations are complex, and the computation of the
provision for income taxes involves tax interpretations, regulations, and
legislation that are continually changing. 
In addition, the Corporations tax filings are subject to audit by
taxation authorities.  While the
Corporation believes that its tax filings have been made in accordance with all
such tax interpretations, regulations, and legislation, the Corporation cannot
guarantee that it will not have disagreements with the Canada Revenue Agency or
other taxation authorities with respect to the Corporations tax filings.  The Corporation may be unsuccessful in the defence
of legal actions.  The Corporation is occasionally named as a defendant in various claims
and legal actions.  There can be no
assurance that the Corporation will be successful in the defence of each of
these claims and legal actions or that any claim or legal action that is
decided adverse to the Corporation will not materially adversely affect the
Corporation.  If the Corporation fails to attract and retain key
personnel, it could be materially adversely affected.  The loss of any of the Corporations key personnel or its inability to
attract, train, retain and motivate additional qualified management and other
personnel could have a material adverse effect on the Corporation.  Competition for these personnel is intense
and there can be no assurance that the Corporation will be successful in this
regard.  If the Corporation is unable to successfully
negotiate new collective bargaining agreements with its unionized workforce, as
required from time to time, it will be adversely affected.  While the Corporation believes it has a good relationship with its
unionized employees, the Corporation cannot guarantee that it will be able to
successfully negotiate or renegotiate its collective bargaining agreements on
terms agreeable to the Corporation.  Any
problems in negotiating these collective bargaining agreements could lead to
higher employee costs and a work stoppage or strike, which could have a
material adverse effect on the Corporation.  EMPLOYEES  As of December 31, 2008, the Corporation had 2,110 full and
part-time employees, of which 1,529 were employed in TransAltas generation
business and 147 were employed in TransAltas energy marketing business.  Approximately 46 per cent of the Corporations
employees are represented by labour unions. 
The Corporation is currently a party to 11 different collective
bargaining agreements.  Overall in 2008,
the Corporation renewed three of the agreements, an additional five agreements
are expected to be re-negotiated in 2009, and the remaining three agreements
are expected to be re-negotiated in 2010.


- 29 -   CAPITAL
STRUCTURE  General  The Corporations authorized share capital consists of an unlimited
number of common shares and an unlimited number of first preferred shares,
issuable in series.  As at March 12,
2009, there were 197,849,306common shares outstanding and no first
preferred shares were outstanding.  Common Shares  Each common share of the Corporation entitles the holder thereof to one
vote for each common share held at all meetings of shareholders of the
Corporation, except meetings at which only holders of another specified class
or series of shares are entitled to vote, to receive dividends if, as and when
declared by the Board of Directors, subject to prior satisfaction of preferential
dividends applicable to any first preferred shares, and to participate rateably
in any distribution of the assets of the Corporation upon a liquidation,
dissolution or winding up and subject to prior rights and privileges attaching
to first preferred shares.  The common
shares are not convertible and are not entitled to any pre-emptive rights.  The common shares are not entitled to
cumulative voting.  First Preferred Shares  The Corporation is authorized to issue an unlimited number of first
preferred shares, issuable in series and, with respect to each series, the
Board of Directors is authorized to fix the number of shares comprising the
series and determine the designation, rights, privileges, restrictions and
conditions attaching to such shares, subject to certain limitations.  The first preferred shares of all series rank senior to all other
shares of the Corporation with respect to priority in payment of dividends and
with respect to distribution of assets in the event of liquidation, dissolution
or winding up of the Corporation, or a reduction of stated capital.  Holders of first preferred shares are
entitled to receive cumulative quarterly dividends on the subscription price
thereof as and when declared by the Board of Directors at the rate established
by the Board of Directors at the time of issue of shares of a series.  No dividends may be declared or paid on any
other shares of the Corporation unless all cumulative dividends accrued upon
all outstanding first preferred shares have been paid or declared and set
apart.  In the event of the liquidation,
dissolution or winding up of the Corporation, or a reduction of stated capital,
no sum shall be paid or assets distributed to holders of other shares of the
Corporation until the holders of first preferred shares shall have been paid
the subscription price of the shares, plus a sum equal to the premium payable
on a redemption, plus a sum equal to the arrears of dividends accumulated on
the first preferred shares to the date of such liquidation, dissolution,
winding up, or reduction of stated capital, as applicable.  After payment of such amount, the holders of
first preferred shares shall not be entitled to share further in the
distribution of the assets of the Corporation.  The Corporations Board of Directors may include, in the share
conditions attaching to a particular series of first preferred shares, certain
voting rights effective upon the Corporation failing to make payment of six
quarterly dividend payments, whether or not consecutive.  These voting rights continue for so long as
any dividends remain in arrears.  These
voting rights are the right to one vote for each $25 of subscription price on
all matters in respect of which shareholders vote, and additionally, the right
of all series of first preferred shares, voting as a combined class, to elect
two directors of the Corporation if the Board of Directors then consists of
less than 16 directors, or three directors if the Board of Directors consists
of 16 or more directors.  Otherwise,
except as required by law, the holders of first preferred shares shall not be
entitled to vote or to receive notice of or attend any meeting of the
shareholders of the Corporation.  Subject to the share conditions attaching to any particular series
providing to the contrary, the Corporation may redeem first preferred shares of
a series, in whole or from time to time in part, at the redemption price
applicable to each series and the Corporation has the right to acquire any of
the first preferred shares of one or more series by


- 30 -   purchase for cancellation in the open market or by invitation for
tenders at a price not to exceed the redemption price applicable to the series.  CREDIT RATINGS  Issuer Rating  As of December 31, 2008, the Corporations issuer rating from
S&P was BBB (stable), from Moodys was Baa2 (stable), and from DBRS was BBB
(stable).  Senior Unsecured Long Term Debt  As of December 31, 2008, the Corporations senior unsecured long-term
debt is rated BBB (stable) by DBRS, BBB (stable) by S&P and Baa2 (stable)
by Moodys.  The ratings for debt
instruments range from a high of AAA to a low of D in the case of both DBRS and
S&P and from a high of Aaa to a low of C in the case of Moodys.  According to the DBRS rating system, debt securities rated BBB are of
adequate credit quality.  Protection of
interest and principal is considered acceptable, but the entity is more
susceptible to adverse changes in financial and economic conditions, or there
may be other adverse conditions present which reduce the strength of the entity
and its rated securities.  High or Low
grades indicate the relative standing within a rating category.  DBRS also assigns rating trends to each of
its ratings to give investors an understanding of DBRS opinion regarding the
outlook for the rating in question.  According to the S&P rating system, debt securities rated BBB
exhibit adequate protection parameters. 
However, adverse economic conditions or changing circumstances are more
likely to lead to a weakened capacity of the obligor to meet its financial
commitment on such obligations than on obligations in the higher rating
categories.  The ratings from AA to B may
be modified by the addition of a plus (+) or minus () sign to show relative
standing within the major rating categories.  According to the Moodys rating system, debt securities rated Baa are
subject to moderate credit risk.  They
are considered medium grade and as such may possess certain speculative
characteristics.  Numerical modifiers 1,
2 and 3 are applied to each rating category, with 1 indicating that the
obligation ranks in the higher end of the category, 2 indicating a mid range
ranking and 3 indicating a ranking in the lower end of the category.  Note Regarding Credit Ratings  Credit ratings are intended to provide investors with an independent
measure of credit quality of an issue of securities.  The credit ratings accorded to the
Corporations outstanding securities by S&P, Moodys and DBRS, as
applicable, are not recommendations to purchase, hold or sell such securities
inasmuch as such ratings do not comment as to market price or suitability for a
particular investor.  There is no
assurance that the ratings will remain in effect for any given period or that a
rating will not be revised or withdrawn entirely by S&P, Moodys or DBRS in
the future if, in its judgement, circumstances so warrant.  DIVIDENDS  In setting its dividend, TransAltas Board of Directors considers the
Corporations financial performance and balances liquidity requirements,
capital reinvestment and returning capital to shareholders, with a policy of
paying annual dividends to its shareholders in the range of 60 to 70 per cent
of comparable earnings.  The payment and
level of future dividends on the common shares are determined by the Board of
Directors of TransAlta upon consideration of such factors.  TransAlta has declared and paid the following
dividends per share on its outstanding common shares for the past three years:


- 31 -   Period
  
  
  
  Dividend per Common Share2006
  
  First Quarter
  
  $0.25Second Quarter
  
  $0.25Third Quarter
  
  $0.25Fourth Quarter
  
  $0.252007
  
  First Quarter
  
  $0.25Second Quarter
  
  $0.25Third Quarter
  
  $0.25Fourth Quarter
  
  $0.252008
  
  First Quarter
  
  $0.27Second Quarter
  
  $0.27Third Quarter
  
  $0.27Fourth Quarter
  
  $0.27
  On January 29,
2009, the Corporations Board of Directors declared a cash dividend of $0.29
per common share, payable on April 1, 2009 to shareholders of record on March 1,
2009.  MARKET FOR
SECURITIES  TransAltas
common shares are listed on the TSX under the symbol TA and the New York
Stock Exchange under the symbol TAC. 
The following table sets forth the reported high and low trading prices
and trading volumes of the Corporations common shares as reported by the TSX
for the periods indicated:  Price ($)Month
  
  High
  
  Low
  
  Volume2008January
  
  34.00
  
  29.85
  
  15,201,560February
  
  35.80
  
  32.01
  
  27,280,079March
  
  35.73
  
  30.03
  
  31,739,588April
  
  34.27
  
  30.83
  
  16,237,231May
  
  36.16
  
  33.24
  
  16,671,590June
  
  37.30
  
  34.65
  
  17,308,802July
  
  38.10
  
  30.71
  
  42,637,530August
  
  37.73
  
  34.59
  
  20,057,372September
  
  36.88
  
  26.53
  
  28,180,867October
  
  29.85
  
  20.00
  
  24,458,282November
  
  24.59
  
  21.00
  
  14,517,240December
  
  24.45
  
  20.77
  
  11,835,5712009January
  
  26.60
  
  21.13
  
  10,881,392February
  
  22.96
  
  18.50
  
  16,191,905March 1 to 12
  
  21.05
  
  17.96
  
  5,609,514  DIRECTORS AND
OFFICERS  The name,
province or state and country of residence of each of the directors and
officers of TransAlta as at March 12, 2009, their respective position and
office and their respective principal occupation during the five preceding
years, are set out below.  The year in
which each director was appointed to serve to the Board is also set out
below.  Each director is appointed to
serve until the next annual meeting of TransAlta or until his or her successor
is elected or appointed.


- 32 -   Name, Province (State) and
  Country of Residence
  
  Year first
  became
  Director
  
  Principal OccupationWilliam D. Anderson
  Ontario, Canada
  
  2003
  
  Corporate Director. Mr. Anderson was President
  of BCE Ventures (a subsidiary of BCE Inc.) from 2001 to 2005
  (telecommunications) and prior to that Chief Financial Officer (CFO) of BCE
  Inc., Bell Canada Inc. and Bell Cablemedia plc (telecommunications). As
  President of BCE Ventures, he was responsible for a number of significant
  operating companies as well as being Chief Executive Officer (CEO) of Bell
  Canada International Inc. In his CFO roles, Mr. Anderson was responsible
  for all financial operations of the respective companies and executed
  numerous debt and equity financings, corporate acquisition and disposition
  transactions as well as corporate and operational restructurings.Mr. Anderson is a director of Gildan Activewear Inc. and of MDS
  Inc. He is a past director at BCE Emergis Inc., Bell Cablemedia plc, Bell
  Canada International Inc., CGI Group Inc., Four Seasons Hotels Inc., Sears
  Canada Inc., and Videotron Holdings plc.At TransAlta, Mr. Anderson is Chair of the Audit and Risk
  Committee of the Board.Mr. Anderson holds a bachelor degree in business administration
  from the University of Western Ontario (London, ON) and is a Chartered
  Accountant.Stephen L. Baum
  New Hampshire, U.S.A.
  
  2008
  
  Corporate Director. Mr. Baum was Chairman and
  CEO of Sempra Energy from December 1996 to February 2006, a San
  Diego-based Fortune 500 energy services holding company formerly known as
  Enova Corporation. Previous to that, Mr. Baum was President, CEO and
  Vice-Chairman of Sempra Energy. Prior to that he was Chairman, CEO and a
  member of the board of directors of Enova Corporation, the parent company of
  San Diego Gas & Electric (SDG&E) where he served in various
  officer positions including General Counsel. Before joining SDG&E, he was
  Senior Vice President and General Counsel of the New York Power Authority. He
  has also held various legal positions, including General Attorney at
  Orange & Rockland Utilities, and as an associate with the law firm
  of Curtis, Mallet-Prevost, Colt & Mosle in New York City.Mr. Baum is a member of the
  board of directors of Computer Science Corporation and is Chair of its Audit
  Committee. He is also a Senior Advisor to SkyFuel Inc., a solar company.At TransAlta, Mr. Baum is a
  member of the Audit and Risk Committee and the Human Resources Committee of
  the Board.Mr. Baum is a graduate of
  Harvard University and the University of Virginia Law School. He has also
  served as a Captain in the U.S. Marine Corps.Stanley J. Bright(1)
  Maryland, U.S.A.
  
  1999
  
  Corporate Director. Mr. Bright was President,
  CEO and Chairman of MidAmerican Energy Company (MidAmerican) from 1997 to
  1999 (electric and gas utility). He was also Chairman, President, and CEO,
  and CEO of predecessor companies, including the Iowa-Illinois Gas &
  Electric Company (IIG&E) from 1991 to 1997. As the CEO of IIG&E,
  Mr. Bright was successful with the consolidation of IIG&E and other
  Iowa based utilities in anticipation of emerging market competition, giving
  rise to the creation of MidAmerican. As the Chairman, President and CEO of
  the new entity, Mr. Bright led the realization of significant synergies
  while working through the post-merger transition. The Company also structured
  a long-term rate plan with the Iowa Public Service Commission. He retired as
  CEO of MidAmerican in 1999 but continued as a director until 2006.At TransAlta, Mr. Bright is Chair of the Human Resources
  Committee of the Board.Mr. Bright holds an undergraduate degree in accounting from The
  George Washington University (Washington, DC) and is a Certified Public
  Accountant.


- 33 -   Name, Province (State) and
  Country of Residence
  
  Year first
  became
  Director
  
  Principal OccupationTimothy W. Faithfull
  England, U.K.
  
  2003
  
  Corporate Director. Mr. Faithfull is a 36-year
  veteran of Royal Dutch/Shell plc (energy), where he filled diverse
  international roles principally in oil products and LNG project development.
  As President and CEO of Shell Canada Limited, he was responsible for bringing
  the $6 billion Athabasca Oil Sands Project on line, the first fully
  integrated oil sands venture in 25 years. Mr. Faithfull has extensive
  experience with commodity exposure and risk management, the result of his time
  directing the global crude oil trading operations of Shell International
  Trading and Shipping Company from 1993 to 1996. He was Chairman and CEO of
  Shell Eastern Petroleum in Singapore from 1996 to 1999, including Shells
  main refinery and oil products trading for Asia Pacific.During his time in Singapore he was a director of DBS Bank, and the
  Port of Singapore Authority. He was a trustee of the main Singapore
  Arts/Theatre complex. In Calgary, he served on the board of the Calgary
  Health Trust and the Epcor Arts Centre.Mr. Faithfull is a director of Canadian Pacific Railway Limited,
  Shell Pension Trust Limited, AMEC plc and Enerflex Systems Income Fund.At TransAlta,
  Mr. Faithfull is a member of the Audit and Risk Committee and the Human
  Resources Committee of the Board.Mr. Faithfull holds a master of arts degree in philosophy,
  politics and economics from the University of Oxford, U.K.Ambassador Gordon D. Giffin
  Georgia, U.S.A
  
  2002
  
  Lawyer and Senior Partner, McKenna, Long &
  Aldridge LLP(attorneys). From 1997 to 2001, Mr. Giffin served as the United States
  Ambassador to Canada with responsibility for managing Canada/U.S. bilateral
  relations, including energy and environmental policy. Prior to this appointment,
  he practised law for 18 years as a senior partner in Atlanta, Georgia and
  Washington, D.C. His practice focused on energy regulatory work at the state
  and federal levels. Prior to that, he served as Chief Counsel and Legislative
  Director to United States Senator Sam Nunn, with responsibility for the legal
  and legislative operations of the office. In 2001, Mr. Giffin returned
  to private practice where he specialized in state and federal regulatory
  matters, including those related to trade, energy and trans-border commerce.Mr. Giffin is a director of Canadian Imperial Bank of Commerce,
  Canadian National Railway Company, Canadian Natural Resources Limited, and
  Ontario Energy Savings Ltd.At TransAlta, Mr. Giffin is Chair of the Governance and
  Environment Committee of the Board.Mr. Giffin holds a bachelor of arts from Duke University (Durham,
  NC) and a juris doctorate from Emory University School of Law (Atlanta, GA).


- 34 -   Name, Province (State) and
  Country of Residence
  Year first became Director
  Principal OccupationC. Kent Jespersen
  Alberta, Canada
  2004
  Corporate Director. 
  Mr. Jespersen has been Chair and CEO of La Jolla Resources
  International Ltd. since 1998 (advisory and investments).  He has also held senior executive positions
  with NOVA Corporation of Alberta, Foothills Pipe Lines Ltd., and Husky Oil
  Limited before assuming the presidency of Foothills Pipe Lines Ltd. and
  later, NOVA Gas International Ltd. (NOVA). 
  At NOVA, he led the non-regulated energy services business (including
  energy trading and marketing) and all international activities.Mr. Jespersen is Chairman and a director of Orvana Minerals Ltd.
  and CCR Technologies Ltd. and a director of Matrikon Inc., Axia NetMedia
  Corporation and CanElson Drilling Ltd.At TransAlta,
  Mr. Jespersen is a member of the Governance and Environment Committee
  and the Human Resources Committee of the Board.Mr. Jespersen holds a bachelor of science in education and a
  master of science in education from the University of Oregon (Eugene, OR).Michael M. Kanovsky
  Alberta, Canada
  2004
  Corporate
  Director and Independent Businessman.  Mr. Kanovsky co-founded Northstar
  Energy Corporation (Northstar) with initial capital of $400,000 and helped
  build this entity into an oil and gas producer that was sold to Devon Energy
  Corporation for approximately $600 million in 1998.  During this period, Mr. Kanovsky was
  responsible for strategy and finance as well as merger and acquisition
  activity.  He initiated Northstars
  entry into electrical cogeneration through its wholly-owned power subsidiary,
  Powerlink Corporation (Powerlink). 
  Powerlink developed one of the first independent power producer (IPP)
  gas-fired co-generation plants in Ontario and also internationally.  In 1997, he founded Bonavista Energy Trust,
  which has grown to a present day market capitalization of approximately $2
  billion.Mr. Kanovsky is a director of Argosy Energy Corporation, ARC
  Energy Trust, Bonavista Energy Trust, Devon Energy Corporation, and Pure
  Technologies Ltd.At TransAlta, Mr. Kanovsky is a member of the Audit and Risk
  Committee and the Governance and Environment Committee of the Board.Mr. Kanovsky, a Professional Engineer, holds a bachelor of
  science in mechanical engineering from Queens University (Kingston, ON) as
  well as a master of business administration from the Richard Ivey School of
  Business at the University of Western Ontario (London, ON).Donna Soble Kaufman
  Ontario, Canada
  1989
  Lawyer and Corporate Director.  Mrs. Kaufman is a former partner with
  Stikeman Elliott LLP, an international law firm, where she practised
  antitrust law.  She has served on a
  number of boards since 1987, when she became a director of Selkirk
  Communications Limited, a diversified communications company.  A year later she was appointed Chair of the
  Board, President and CEO.  Several
  other directorships followed.  In
  addition to TransAlta, Mrs. Kaufman currently serves on the boards of
  BCE Inc. and Bell Canada.  She is also
  a director of HISTORICA, a private-sector education initiative, of the
  Institute of Corporate Directors, and a member of the Canadian Advisory Board
  of Catalyst, a non-profit organization working to advance women in
  business.  In 2001, she was named a
  Fellow of the Institute of Corporate Directors.At TransAlta, Mrs. Kaufman is Chair of the Board and an
  ex-officio member of all committees of the Board.Mrs. Kaufman holds a bachelor of civil law degree from McGill
  University (Montréal, QC) and a master of laws degree from the Université de
  Montréal (Montréal, QC).


- 35 -   Name, Province (State) and
  Country of Residence
  Year first
  became
  Director
  Principal OccupationGordon S. Lackenbauer(1)
  Alberta, Canada
  2005
  Corporate Director. 
  Mr. Lackenbauer was Deputy Chairman of BMO Nesbitt Burns Inc.
  (investment banking) from 1990 to 2004. 
  Prior to this, he was responsible for the principal activities of the
  firm, which included fixed income sales and trading, new issue underwriting,
  syndication and merger and acquisition advisory mandates.  Mr. Lackenbauer has worked with many
  of Canadas leading utilities and has frequently acted as an expert financial
  witness testifying on the cost of capital, appropriate capital structure, and
  the fair rate of return, principally before the Alberta Utilities Commission,
  the National Energy Board, and the Ontario Energy Board.Mr. Lackenbauer is a director of NAL Oil & Gas Trust and
  CTV Globemedia Inc.At TransAlta, Mr. Lackenbauer is a member of the Governance and
  Environment Committee and the Audit and Risk Committee of the Board.Mr. Lackenbauer holds a bachelor of arts in economics from Loyola
  College (Montréal, QC), as well as a master of business administration from
  the University of Western Ontario (London, ON).  He is also a chartered financial analyst.Martha C. Piper
  British Columbia, Canada
  2006
  Corporate Director.  Dr. Piper was President and
  Vice-Chancellor of the University of British Columbia from 1997 to 2006
  (education).  Prior to her appointment
  at UBC, she served as Vice-President, Research at the University of
  Alberta.  She served on the boards of
  the Alberta Research Council, the Conference Board of Canada and the Centre
  of Frontier Engineering Research. 
  Dr. Piper was also appointed by the Prime Minister of Canada to
  the Advisory Council on Science and Technology and currently Chairs the Board
  of the National Institute for Nanotechnology.Dr. Piper is a director of the Bank of Montreal, Shoppers Drug
  Mart Corporation and a member of the Canadian delegation to the Trilateral
  Commission, an organization fostering closer cooperation among the core democratic
  industrialized areas of the world.At TransAlta, Dr. Piper is a member of the Human Resources
  Committee and the Governance and Environment Committee of the Board.Dr. Piper holds a bachelor of science in physical therapy from
  the University of Michigan (Ann Arbor, MI), a master of arts in child
  development from the University of Connecticut (Storrs, CT), and a doctorate
  of philosophy in epidemiology and biostatistics from McGill University
  (Montréal, QC).  She has also received
  honorary degrees from 16 international universities.  Dr. Piper is an Officer of the Order
  of Canada and a recipient of the Order of British Columbia.Luis Vázquez Senties
  Mexico
  2001
  Corporate Director and Independent Businessman. 
  Mr. Vázquez is founder, President, CEO and Chairman of Grupo
  Diavaz, an international constructor of offshore oil and gas platforms,
  developer of oil and gas fields, and a distributor of natural gas in Mexico
  (oil and gas).  Grupo Diavaz began as a
  Mexican underwater diving operation that grew to become the worlds second
  largest firm of its kind, servicing the offshore oil and gas industry in both
  exploration and production efforts.Mr. Vázquez is Chairman of the Mexican Gas Association and
  Vice-President of the Mexico Chapter of the World Energy Council.  He is a past director of the American Gas
  Association.At TransAlta, Mr. Vázquez is a member of the Human Resources
  Committee of the Board.


- 36 -   Name,
  Province (State) and Country of Residence
  
  Year
  first
  became
  Director
  
  Principal OccupationStephen
  G. SnyderAlberta, Canada
  
  1996
  
  President
  and Chief Executive Officer of TransAlta Corporation since 1996.Previously Mr. Snyder
  was President & CEO, Noma Industries Ltd., President & CEO,
  GE Canada Inc., and President & CEO, Camco, Inc.Mr. Snyder
  is a director of the Canadian Imperial Bank of Commerce, Chair of the Calgary
  Stampede Foundation, and Chair of the Alberta Secretariat for Action on Homelessness.
  He is past-chair of the Calgary Committee to End Homelessness, the
  Canada-Alberta ecoEnergy Carbon Capture & Storage Task Force, the
  Conference Board of Canada, the Canadian Electricity Association, the Calgary
  Zoological Society, the University of Calgary Management Advisory Council,
  the Calgary Zoo Destination Africa Campaign and the Calgary United Way
  Campaign.Mr. Snyder
  holds a bachelor of science in chemical engineering from Queens University
  (Kingston, ON) as well as a master of business administration from the
  University of Western Ontario (London, ON).He has
  honourary degrees from the University of Calgary (LLD), and the Southern
  Alberta Institute of Technology (Bachelor of Applied Technology). He was
  awarded the Alberta Centennial Medal in 2005, and the Conference Board
  Honorary Associate Award for 2008.  Notes:(1)
  Mr. Bright
  served as a director of Access Air Inc. (Access Air) for the period of
  December 4, 1997 to January 31, 2000, a privately held start-up
  airline company.  The company
  Mr. Bright was employed by, and whom he represented on the Access Air
  board, supported Access Air in the hope that it would improve air service to
  the state of Iowa.  Access Air filed
  for bankruptcy protection on November 29, 1999.(2)
  Mr. Lackenbauer
  resigned from the Board of Directors of Tembec Inc. (Tembec) on
  August 2, 2007.  On
  December 19, 2007, Tembec announced its proposed recapitalization
  transaction providing a consensual solution to both noteholders and shareholders.  On February 22, 2008, Tembec announced
  that it had received the approval of the majority of shareholders and the
  requisite majority of noteholders of Tembec Industries Inc.  On February 27, 2008, Tembec announced
  that it had received approval from the Ontario Superior Court of Justice
  (Commercial List) with respect to their plan of arrangement relating to the
  proposed recapitalization transaction. 
  On October 31, 2008, Tembec announced that it had successfully
  obtained a final American court order recognizing its Canadian plan of
  arrangement as a foreign proceeding in the United States.  OfficersName
  
  Principal
  Occupation
  
  ResidenceStephen G. Snyder
  
  President and Chief Executive Officer
  
  Alberta, CanadaBrian Burden
  
  Executive Vice-President and Chief Financial Officer
  
  Alberta, CanadaWilliam D.A. Bridge
  
  Executive Vice-President, Generation Technology and
  PMM
  
  Alberta, CanadaDawn L. Farrell
  
  Executive Vice-President, Commercial Operations and
  Development
  
  Alberta, CanadaRichard P. Langhammer
  
  Executive Vice-President, Generation Operations
  
  Alberta, CanadaKenneth S. Stickland
  
  Executive Vice-President, Legal, SD and EH&S
  
  Alberta, CanadaMichael Williams
  
  Executive Vice-President, Human Resources, IT and Communications
  
  Alberta, CanadaFrank Hawkins
  
  Vice-President and Treasurer
  
  Alberta, CanadaMaryse C. St.-Laurent
  
  Corporate Secretary
  
  Alberta, CanadaAll of the officers of TransAlta
  have held their present principal occupation or position for the past five
  years, except for the following:


- 37 -   ·Prior to December 2005, Brian Burden was Executive
Vice-President and Chief Financial Officer of Molson Inc.  Prior to 2002, he was Senior Vice-President,
Seagram Corporate/Venture Transition of Diageo PLC.  ·Prior to July 2007, William Bridge was Vice-President, Western
Canada Operations.  Prior to October 2005,
Mr. Bridge was Vice-President, Customer and Asset Management; prior to September 2003,
he was Vice-President, Development & Acquisition; and prior to September 2001
he was Director, Commercial Operations, Eastern Canada.  ·Prior to July 2007, Dawn Farrell served as Executive
Vice-President, Corporate Development, Executive Vice-President, Independent
Power Projects and Vice-President, Energy Marketing and IPP Development at
TransAlta Corporation.  From 2003 to 2006,
she served as Executive Vice-President Generation and in June 2006 she was
appointed Executive Vice-President Engineering, Aboriginal Relations and
Generation at B.C. Hydro.  ·Prior to October 2005, Richard Langhammer was President,
TransAlta Centralia Generation LLC and TransAlta Centralia Mining LLC,
subsidiaries of the Corporation; and prior to December 2003, he was
Vice-President, Plant Operations of TransAlta.  ·Prior to April, 2007, Kenneth Stickland was Executive
Vice-President, Legal.  ·Prior to July 2007, Michael Williams was Executive
Vice-President, HR & Communications.  ·Prior to June 2007, Frank Hawkins was Assistant Treasurer.  ·Prior to June 2005, Maryse St.-Laurent was Secretary of TC
PipeLines, LP since September 2003 and Recording Secretary since January 2001,
and Senior Legal Counsel TransCanada Corporation since June 1997.  As of March 11, 2009, the directors and executive officers of
TransAlta, as a group, beneficially owned, directly or indirectly, or exercised
control or direction over an aggregate of 676,330 common shares of
TransAlta.  This constitutes less than
one per cent of TransAltas outstanding common shares.  INTERESTS OF
MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS  No director or executive officer of the Corporation, no person or
company that is the direct or indirect beneficial owner of, or who exercises
control or direction over more than 10 per cent of the common shares of the
Corporation, and no associate or affiliate of any of them, has or has had any
material interest, direct or indirect, in any transaction involving the
Corporation within the three most recently completed financial years or to date
in 2009 or in any proposed transactions that has materially affected or will
materially affect the Corporation.  INDEBTEDNESS
OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS  Since January 1, 2008, there has been no indebtedness, other than
routine indebtedness, outstanding to TransAlta from any of TransAltas
directors, nominees for election as directors, executive officers, senior
officers or associates of any such directors, nominees or officers.  CORPORATE
CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS  Corporate
Cease Trade Orders


- 38 -   Except as otherwise disclosed herein, no director, executive officer or
controlling security holder of TransAlta Corporation is, as at the date of this
Annual Information Form, or has been, within the past ten years before the date
hereof, a director or executive officer of any other issuer that, while that
person was acting in that capacity:  (i)was the subject of a cease trade or similar order or an order that
denied the relevant company access to any exemption under securities
legislation for a period of more than 30 consecutive days; or  (ii)was subject to an event that resulted, after the person ceased to be
a director or executive officer, in the company being the subject of a cease
trade or similar order or an order that denied the relevant company access to
any exemption under securities legislation for a period of more than 30
consecutive days; or  (iii)within a year of that person ceasing to act in that capacity, became
bankrupt, made a proposal under any legislation relating to bankruptcy or
insolvency or was subject to or instituted any proceedings, arrangement or
compromise with creditors or had a receiver, receiver manager or trustee
appointed to hold its assets.  Personal
Bankruptcies  No director, executive officer or controlling security holder of
TransAlta Corporation has, within the 10 years before the date hereof, become
bankrupt, made a proposal under any legislation relating to bankruptcy or
insolvency, or became subject to or instituted any proceedings, arrangement or
compromise with creditors, or had a receiver, receiver manager or trustee
appointed to hold such persons assets.  Penalties
or Sanctions  No director, executive officer or controlling security holder of
TransAlta Corporation has:  (iv)been subject to any penalties or sanctions imposed by a court relating
to securities legislation or by a securities regulatory authority or has
entered into a settlement agreement with a securities regulatory authority,
other than penalties for late filing of insider reports; or  (v)been subject to any other penalties or sanctions imposed by a court
or regulatory body that would likely be considered important to a reasonable
investor in making an investment decision.  CONFLICTS OF INTEREST  Circumstances
may arise where members of the Board of Directors serve as directors or
officers of corporations which are in competition to the interests of the
Corporation. No assurances can be given that opportunities identified by such
board members will be provided to the Corporation.  LEGAL PROCEEDINGS
AND REGULATORY ACTIONS  TransAlta is occasionally named as a party in various claims and legal
proceedings which arise during the normal course of its business.  TransAlta reviews each of these claims,
including the nature of the claim, the amount in dispute or claimed and the
availability of insurance coverage. 
Although there can be no assurance that any particular claim will be
resolved in the Corporations favour, the Corporation does not believe that the
outcome of any claims or potential claims of which it is currently aware will
have a material adverse effect on the Corporation, taken as a whole, after
taking into account amounts reserved by the Corporation.  For further information, please refer to Notes
29 and 31 of the Corporations audited consolidated financial statements for
the year ended December 31, 2008, which financial statements are
incorporated by reference herein.  See Documents
Incorporated by Reference herein.


- 39 -   TRANSFER AGENT AND REGISTRAR  The transfer
agent and registrar for TransAltas common shares is CIBC Mellon Trust Company
in Vancouver, Calgary, Winnipeg, Toronto and Montreal.  The transfer agent and registrar for the
common shares in the United States is Mellon Investor Services LLC at its
principal office in New York, New York.  INTERESTS OF EXPERTS  Ernst &
Young LLP, Chartered Accountants, 1000, 440 - 2nd Avenue, S.W., Calgary,
Alberta, T2P 5E9 are the auditors of the Corporation.  TransAltas
auditors, Ernst & Young LLP, are independent in accordance with the
Rules of Professional Conduct of the Institute of Chartered Accountants of
Alberta and have complied with the SECs rules on auditor independence.  ADDITIONAL INFORMATION  Additional
information in relation to TransAlta may be found under TransAltas profile on
SEDAR at www.sedar.com.  Additional
information including directors and officers remuneration and indebtedness,
principal holders of TransAltas securities and securities authorized for
issuance under equity compensation plans (all where applicable), is contained
in TransAltas Management Proxy Circular for its most recent annual meeting of
shareholders that involved the election of directors and can be obtained upon
request from the Corporate Secretary of TransAlta Corporation.  Additional
financial information is provided in TransAltas audited consolidated financial
statements as at and for the year ended December 31, 2008 and in the
Annual MD&A, each of which is incorporated by reference in this Annual
Information Form.  See Documents
Incorporated by Reference herein.  AUDIT AND RISK COMMITTEE  General  The members of
TransAltas Audit and Risk Committee (ARC) satisfy
the requirements for independence under the provisions of Canadian Securities
Regulators, Multilateral Instrument 52-110 Audit Committees,
Section 303A of the New York Stock Exchange Rules and Rule 10A-3
under the U.S. Securities and Exchange Act of 1934.  The ARCs Charter requires that it be
comprised of a minimum of three independent directors.  It currently has six independent members,
William D. Anderson (Chair), Stephen L. Baum, Timothy W. Faithfull, Michael M.
Kanovsky, Gordon S. Lackenbauer and Donna S. Kaufman as an ex-officio
member.  All members of the committee are
financially literate pursuant to both Canadian and U.S. securities requirements
and each of Mr. William D. Anderson and Mr. Gordon S. Lackenbauer
have been determined by the Board to be an audit
committee financial expert, within the meaning of Section 407
of the United States Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley Act).  Mandate of the Audit and Risk Committee  The mandate of
the ARC is to assist the Board in its oversight responsibility to the
shareholders of the Corporation, the investment community and others relating
to the integrity of the Corporations financial statements, the quality of its
financial reporting processes, the systems of internal accounting and financial
controls, the risk identification assessments conducted by management and the
programs established in response to such risks, the internal audit function,
the external auditors qualifications, independence, performance and reports
and to provide oversight with respect to legal compliance programs established
by management which may have a material effect on the financial statements of
the Corporation.  The ARC also reviews
the Corporations compliance with the Corporations code of


- 40 -   conduct,
financial code of conduct and the Corporations policy with respect to the
hiring of employees of the external auditors.  The ARCs
function is oversight.  Management is
responsible for the preparation, presentation and integrity of the financial
statements of the Corporation. 
Management and the internal audit group of the Corporation are
responsible for maintaining appropriate accounting and financial reporting
principles and policy and internal controls and procedures for compliance with
accounting standards and applicable laws and regulations.  While the ARC
has the responsibilities and powers set forth herein, it is not the duty of the
ARC to plan or conduct audits or to determine that the Corporations financial
statements are complete and accurate and in accordance with generally accepted
accounting principles.  This is the
responsibility of management and the external auditors.  Management is
responsible for preparing the interim and annual financial statements and financial
disclosure of the Corporation and for maintaining a system of internal controls
to provide reasonable assurance that assets are safeguarded and that
transactions are authorized, executed, recorded and reported properly.  The ARCs role is to provide direct,
meaningful and effective oversight of the Corporations financial reporting and
counsel to management without assuming responsibility for managements day to
day duties.  Audit and Risk Committee Charter  The Charter of
the Audit and Risk Committee is attached as Appendix A.  Relevant Education and Experience of Audit and Risk Committee Members  The following
is a brief summary of the education or experience of each member of the ARC
that is relevant to the performance of their responsibilities as a member of
the ARC, including any education or experience that has provided the member
with an understanding of the accounting principles used by TransAlta to prepare
its annual and interim financial statements.  Name of ARC Member
  
  Relevant Education and ExperienceW. D. Anderson
  
  Mr. Anderson
  is a Chartered Accountant. Mr. Anderson has served as Chief Executive Officer
  of a public company and as Chief Financial Officer of several public
  companies. In such capacities, Mr. Anderson actively supervised persons
  engaged in preparing, auditing, analyzing or evaluating financial statements.
  Mr. Anderson has also served as a principal financial officer and accounting
  officer and as a director and audit committee member of several public companies.Stephen L. Baum
  
  Mr. Baum has over 25 years of financial, legal and
  industry experience gained working as a senior officer, director and Chairman
  of energy companies.  During his tenure
  as CEO of Sempra Energy, Mr. Baum had financial officers reporting directly
  to him.  Mr. Baum also serves as
  Chairman of the Audit Committee of Computer Sciences Corporation, a NYSE
  listed company. Mr. Baum holds a law degree from the University of Virginia.T. W. Faithfull
  
  Mr. Faithfull
  holds a Bachelor of Arts degree in Economics and has acquired significant
  financial experience and exposure to accounting and financial issues as Chief
  Executive Officer of Shell Canada Limited and in his other capacities during
  his 36 years with the Royal Dutch/Shell group of companies.M. M. Kanovsky
  
  Mr. Kanovsky
  has over 30 years of financial and industry experience gained through working
  in the investment banking business as well as a director, officer and audit
  committee member of several public companies and trusts. Mr. Kanovsky is a
  graduate of the MBA program from the Richard Ivey School of Business at the
  University of Western Ontario.


- 41 -   Name of ARC Member
  
  Relevant Education and ExperienceG. S. Lackenbauer
  
  Mr.
  Lackenbauer has over 35 years of experience in the investment banking
  industry. Mr. Lackenbauer has also appeared as an expert financial witness
  with respect to financial markets, capital structure, cost of capital and
  fair return on common equity, in over 40 regulatory proceedings. Mr.
  Lackenbauer also has extensive experience as a director or governor of public
  companies and not-for-profit organizations. Mr. Lackenbauer holds a Bachelor
  of Arts in Economics, a MBA degree from the University of Western Ontario and
  is a Chartered Financial Analyst.D. S. Kaufman (ex-officio)
  
  Mrs. Kaufman has over 25 years of legal, professional
  and financial management experience gained in the practice of law, as a
  director of several public companies and as Chair, President and CEO of
  Selkirk Communications.  Mrs. Kaufman
  has served on several audit committees. 
  Mrs. Kaufman holds a civil law degree from McGill University and a
  master of laws from the University of Montreal.   Other Board Committees  In addition to
the Audit and Risk Committee, TransAlta has two other standing committees: the
Governance and Environment Committee and the Human Resources Committee.  Mrs. Kaufman, the Chair of the Board, is a
non-voting ex-officio member of all committees. 
The members of these committees as of December 31, 2008 are:  Governance and Environment Committee
  
  Human Resources CommitteeChair: Ambassador Gordon D. Giffin
  
  Chair: Stanley J. BrightC. Kent Jespersen
  
  Stephen L. BaumMichael M. Kanovsky
  
  Timothy W. FaithfullGordon S. Lackenbauer
  
  C. Kent JespersenDr. Martha C. Piper
  
  Dr. Martha C. PiperDonna Soble Kaufman (ex-officio)
  
  Luis Vázquez SentiesDonna Soble Kaufman (ex-officio)  The Charters of the Governance and Environment Committee
and the Human Resources Committee may be found on TransAltas website under
Corporate Responsibility - Governance at www.transalta.com.  Further information about the Board and the
Corporations corporate governance may also be found on our website or in the
Corporations Management Proxy Circular which is filed on Sedar at www.sedar.com.  Fees Paid to Ernst & Young LLP  For the years
ended December 31, 2008 and December 31, 2007, Ernst & Young
LLP and its affiliates were paid $3,372,142 and $2,838,740 respectively, as
detailed below:  Year ended Dec. 31Ernst & Young LLP
  
  2008
  
  2007Audit fees
  
  $
  2,594,183
  
  $
  2,624,029Audit related fees
  
  432,343
  
  168,968Tax fees
  
  
  345,616
  
  45,743Total
  
  $
  3,372,142
  
  $
  2,838,740
  No other audit
firms provided audit services in 2008 or 2007.  The nature of
each category of fees is described below:


- 42 -   Audit Fees  Audit fees
were paid for professional services rendered by the auditors for the audit of
the Corporations annual financial statements or services provided in
connection with statutory and regulatory filings or engagements, including the
translation from English to French of the Corporations financial statements
and other documents.  Total audit fees
for 2008 include payments related to 2007 in the amount of $1,403,923.  Total audit fees for 2007 include payments
related to 2006 in the amount of $1,476,300.  Audit-Related Fees  The
audit-related fees in 2008 were primarily for work performed by Ernst &
Young LLP in relation to miscellaneous accounting advice provided to the
Corporation.  Tax Fees  Majority of
tax fees for 2008 relate to the finalization of tax credit recoveries.  Pre-Approval Policies and Procedures  The ARC has
considered whether the provision of services other than audit services is
compatible with maintaining the auditors independence. In May 2002, the ARC
adopted a policy that prohibits TransAlta from engaging the auditors for
prohibited categories of non-audit services and requires pre-approval of the
ARC for other permissible categories of non-audit services, such categories
being determined under the Sarbanes-Oxley Act.  Representatives
of Ernst & Young LLP will be in attendance at the Meeting, will have
the opportunity to make a statement if they so wish and will be available to
respond to questions.


A-1   APPENDIX A  TRANSALTA CORPORATION (the Corporation)  AUDIT AND RISK COMMITTEE CHARTER   A.Establishment of Committee and Procedures  1.Composition of
Committee  The Audit and
Risk Committee (the Committee) of the Board of Directors (the Board) of
TransAlta Corporation (the Corporation) shall consist of not less than three
Directors.  All members of the Committee
shall be determined by the Board to be independent as required under the
provisions of Canadian Securities Regulators Multilateral Instrument 52-110
Audit Committees, Section 303A of the New York Stock Exchange rules and
Rule 10A-3 of the U.S. Securities and Exchange Act of 1934, as such
rules apply to audit committee members. 
All members of the Committee must be financially literate pursuant to
both Canadian and U.S. securities requirements and at least one member must be
determined by the Board to be an audit committee financial expert within the
meaning of Section 407 of the United States Sarbanes-Oxley Act of 2002
(the Sarbanes Oxley Act). 
Determinations as to whether a particular director satisfies the requirements
for membership on the Committee shall be made by the Board of Directors (the
Board) at the recommendation of the Committee.  2.Appointment of Committee Members  Members of the
Committee shall be appointed from time to time by the Board, on  the recommendation of the Governance and
Environment Committee, and shall hold office until the next annual meeting of
shareholders, or until their successors are earlier appointed, or until they
cease to be Directors of the Corporation.  3.Vacancies  Where a
vacancy occurs at any time in the membership of the Committee, it may be filled
by the Board.  The Board shall fill any
vacancy if the membership of the Committee is less than three directors.  4.Committee Chair  The Board
shall appoint a Chair for the Committee on the recommendation of the Governance
and Environment Committee.  5.Absence of Committee Chair  If the Chair
of the Committee is not present at any meeting of the Committee, one of the
members of the Committee who is present at the meeting shall be chosen by the
Committee to preside at the meeting.


A-2   6.Secretary of Committee  The Committee
shall appoint a Secretary who need not be a director of the Corporation.  7.Meetings  The
Chair of the Committee or any of its members may call a meeting of the
Committee.  The Committee shall meet at
least quarterly and at such other time during each year as it deems
appropriate.  In addition, the Chair of
the Committee or any of its members may call a special meeting of the Committee
at any time. Although the Corporations Chief Executive Officer may attend
meetings of the Committee, the Committee shall also meet in separate executive
sessions.  8.Quorum  A majority of
the members of the Committee present in person or by telephone or other
telecommunication device that permits all persons participating in the meeting
to speak to each other, shall constitute a quorum.  9.Notice of Meetings  Notice of the
time and place of every meeting shall be given in writing (including by way of
written facsimile communication or email) to each member of the Committee at
least 48 hours prior to the time fixed for such meeting, provided, however,
that a member may in any manner waive 
notice of a meeting; and attendance of a member at a meeting constitutes
a waiver of notice of the meeting, except where a member attends for the
express purpose of objecting to the transaction of any business on the ground
that the meeting is not lawfully called. 
Notice of every meeting shall also be provided to the external and
internal auditors.  10.Attendance at Meetings  At the
invitation of the Chair of the Committee, other Board members, officers or
employees of the Corporation, the external auditors, and other experts or
consultants may attend a meeting of the Committee.  11.Procedure, Records and Reporting  Subject to any
statute or the articles and by-laws of the Corporation, the Committee shall fix
its own procedures at meetings, keep records of its proceedings and report to
the Board generally not later than the next scheduled meeting of the Board.  12.Review of Charter  The Committee
shall evaluate its performance and review and reassess the adequacy of its
Charter at least annually or otherwise, as it deems appropriate, and if necessary
propose changes to the Governance and Environment Committee and the Board for
review and approval.  13.Outside
Experts and Advisors  The Committee Chair, on behalf of the Committee, or any of its
members is authorized, at the expense of the Corporation, when deemed necessary
or desirable, to retain independent counsel, outside experts and other advisors
to advise the Committee independently on any matter.


A-3   B.Mandate of the Committee  The Committee
provides assistance to the Board in fulfilling its oversight responsibility to
the shareholders, the investment community and others, relating to the
integrity of the Corporations financial statements, the financial reporting
process, the systems of internal accounting and financial controls, the risk
identification assessment conducted by management and the programs established
by management and the Board in response to such assessment, the internal audit
function and the external auditors qualifications, independence, performance
and reports to the Corporation.  In so
doing, it is the Committees responsibility to maintain an open avenue of
communication between the Committee, the external auditors, the internal
auditors and management of the Corporation.  The function
of the Committee is oversight. 
Management is responsible for the preparation, presentation and
integrity of the interim and annual financial statements and related disclosure
documents.  Management of the Corporation
is also responsible for maintaining appropriate accounting and financial
reporting policies and systems of internal controls and procedures that are in
compliance with accounting standards, applicable laws and regulations and that
provide reasonable assurances that assets are safeguarded and that transactions
are authorized, executed, recorded and reported properly.  While the
Committee has the responsibilities and powers set forth herein, it is not the
duty of the Committee to plan or conduct audits or to determine that the
Corporations financial statements are complete and accurate and in accordance
with generally accepted accounting principles. 
This is the responsibility of management and the external auditors.  The designation of a member or members as an
audit committee financial expert is based on that individuals education and
experience, which the individual will bring to bear in carrying out his or her
duties on the Committee.  Designation as
an audit committee financial expert
does not impose on such person any duties, obligations and liability that are
greater than the duties, obligations and liability imposed on a member of the
Committee and Board in the absence of such designation.  Management is
also responsible for the identification and management of the Corporations
risks and the development and implementation of policies and procedures to
mitigate such risks.  The Committees
role is to provide oversight in order to ensure that the Corporations assets
are protected and safeguarded within reasonable business limits.  C.Duties and Responsibilities of the Committee  The Committee
shall have the following specific duties and responsibilities:  1.Audit and Financial
Matters  The Committee
shall:  (a)have
direct responsibility for the compensation and oversight of the external
auditors including nominating the external auditors to the Board for
appointment by the shareholders at the Corporations general annual
meeting.  In performing its function, the
Committee shall:  (i)review the experience and qualifications of the external auditors
senior personnel who are providing audit services to the Corporation and the
quality control procedures of the external auditors, including obtaining
confirmation that the external auditors are in compliance with Canadian and
U.S. regulatory registration requirements;  (ii)review and approve annually the external auditors audit plan;


A-4   (iii)review and approve the basis and amount of the external auditors
fees and ensure the Corporation has provided appropriate funding for payment of
compensation to the external auditors;  (iv)review and discuss with the external auditors all relationships that
the external auditors and their affiliates have with the Corporation and its
affiliates in order to determine the external auditors independence,
including, without limitation, (i) requesting, receiving and reviewing, at
least annually, a formal written statement from the external auditors
delineating all relationships that may reasonably be thought to bear on the
independence of the external auditors with respect to the Corporation,
(ii) discussing with the external auditors any disclosed relationships or
services that the external auditors believe may affect the objectivity and
independence of the external auditors, and (iii) recommending that the
Board take appropriate action in response to the external auditors report to
satisfy itself of the external auditors independence;  (v)resolve disagreements
between management and the external auditors regarding financial reporting;  (vi)pre-approve all audit related services including all non-prohibited
non-audit services provided by the external auditors; the Chair of the
Committee, is authorized to approve all audit related services including
non-prohibited non-audit services provided by the external auditors, and shall
report all such approvals to the Committee at its next scheduled meeting;  (vii)inform the external auditors and management that the external
auditors shall have direct access to the Committee at all times, as well as the
Committee to the external auditors; and  (viii)instruct the external auditors that they are ultimately accountable
to the Committee as representatives of the shareholders of the Corporation;  (b)review
with management and the Corporations external auditors the   Corporations financial reporting in
connection with the annual audit and the preparation of the financial
statements, including, without limitation, the annual audit plan of the external
auditors, the judgment of the external auditors as to the quality, not just the
acceptability, of and the appropriateness of the Corporations accounting
principles as applied in its financial reporting and the degree of
aggressiveness or conservatism of the Corporations accounting principles and
underlying estimates;  (c)review
with management and the external auditors all financial statements and
financial disclosure;  (i)recommend to the Board for approval the Corporations audited annual
financial statements including the notes thereto and, Managements Discussion
and Analysis;  (ii)review any report or opinion to be rendered in connection therewith;  (iii)review with the external auditors the cooperation they received
during the course of their review and their access to all records, data and
information requested;


A-5   (iv)discuss with management and the external auditors all significant
transactions which were not a normal part of the Corporations business;  (v)review the management processes for formulating sensitive accounting
estimates and the reasonableness of the estimates;  (vi)review with management and the external auditors any changes in
accounting principles and their applicability to the business;  (vii)review with management and the external auditors alternative
treatments of financial information within generally accepted accounting
principles that have been discussed with management, ramifications of the use
of such alternative disclosures and treatments and the treatment preferred by
the external auditors;  (viii)satisfy itself that there are no unresolved issues between
management and the external auditors that could reasonably be expected to
materially affect the financial statements;  (d)review
with management and the external auditors the Corporations interim financial
statements, including the notes thereto, Managements Discussion and Analysis
and earnings release, and approve the release thereof by management to the
public;  (e)review
and discuss with management and external auditors the use of pro forma or
adjusted non-GAAP information and the applicable reconciliation;  (f)on
behalf of the Committee, the Chair shall review all public disclosure of
material financial information extracted or derived from the Corporations
financial statements;  (g)review
with management at least annually the approach and nature of financial
information and earnings guidance to be disclosed to analysts and rating
agencies;  (h)review
and recommend to the Board for approval the Corporations issuance and
redemption of securities, financial commitments and limits, and any material
changes underlying any of these commitments;  (i)at
least annually, obtain and review the external auditors report with respect to
the auditing firms internal quality-control procedures, any material issues
raised by the most recent internal quality-control review or peer review of the
auditing firm, any inquiry or investigation by governmental or professional
authorities within the preceding five years undertaken respecting one or more
independent audits carried out by the external auditors, and any steps taken to
deal with any such issues;  (j)review
quarterly with senior management, the chief legal officer and, as necessary,
outside legal advisors, and the Corporations internal and external auditors,
the effectiveness of the Corporations internal controls to ensure the
Corporation is in compliance with legal and regulatory requirements and with the
Corporations policies;  (k)review quarterly with the
chief legal officer, and, if necessary, outside legal advisors, significant
legal, compliance or regulatory matters that may have a material effect on the
financial statements of the business;


A-6   (l)review
and consider, as appropriate, any significant reports and recommendations made
by internal audit relating to internal audit issues, together with managements
response thereto;  (m)review
changes in accounting practices or policies and the financial impact these may
have on the Corporation;  (n)discuss
with the external auditors their perception of the Corporations financial and
accounting personnel, any recommendations which the external auditors may have,
including those contained in the management letter, with respect to improving
internal financial controls, choice of accounting principles or management
reporting systems, and review all management letters from the external auditors
together with managements written responses thereto;  (o)review
with management, the external auditors and, as necessary, internal and external
legal counsel, any litigation, claim or contingency, including tax assessments,
that could have a material effect upon the financial position of the
Corporation, and the manner in which these matters may be, or have been,
disclosed in the financial statements;  (p)review
annually the Annual Pension Report and financial statements of the
Corporations pension plans including the actuarial valuation, asset/liability
forecast, asset allocation, manager performance and plan operating costs;  (q)together
with the Human Resources Committee of the Board, review annually and as
required the overall governance of the Corporations Pension Plans, approve the
broad objectives of the plans and report to the Board annually;  (r)review
annually the internal audit departments charter, the scope and plans for the
work of the internal audit group the adequacy of the groups resources, the
internal auditors access to all functions, records, property and personnel of
the Corporation and inform the internal auditors and management that the
internal auditors shall have unfettered access to the Committee, as well as the
Committee to the internal auditors;  (s)meet
separately with management, the external auditors and internal auditors to
review issues and matters of concern respecting audits and financial reporting;  (t)review
the annual audit of expense accounts and perquisites of the Directors, the CEO
and his direct reports, including the use of the Corporations assets, as well
as the Corporations annual sponsorship, donations and political contributions;  (u)review
managements processes relating to the assessment of potential fraud, programs
and controls to mitigate the risk of fraud and the process put in place for
monitoring the risks within targeted areas;  (v)review
with the Corporations senior financial management and the Vice-President
Internal Audit the adequacy of the Corporations systems of internal control
and procedures;  (w)review
disclosures made to the Committee by the CEO and Chief Financial Officer (the
CFO) during their certification process for the relevant periodic reports
filed with securities regulators to ensure that information required to be
disclosed is recorded, processed, summarized and reported within the time
periods specified for the reporting period. 
Obtain assurances from the CEO and CFO as to the adequacy and effectiveness
of the Corporations disclosure controls and procedures and systems of internal
control over financial reporting and that any fraud involving management or
other employees who have a significant role in the Companys internal controls
was reported to the Committee;


A-7   (x)ensure
that the Corporations business practices and ethical behaviours are
communicated to employees and contractors on an annual basis, to review at
least annually the Corporate Code of Conduct and the policies and practices in
place to ensure compliance.  Inquire of
the internal and external auditors as to any instances of deviation from the
Corporate Code of Conduct which has come to their attention and the action
taken as a result of same;  (y)establish
procedures for the receipt, retention and treatment of complaints received by
the Corporation regarding accounting, internal accounting controls or auditing
matters and the confidential, anonymous submission by employees of concerns
regarding accounting or auditing matters;  (z)review
all incidents, complaints or information reported through the  Ethics Help Line and/or management;  (aa)review
disclosure made to the Committee by the chief executive officer, chief
financial officer and/or chief legal officer of a material violation of
applicable securities laws, a material breach of a fiduciary duty under
applicable laws or a similar material violation by the Corporation or by any
officer, director, employee or agent of the Corporation, which has been
reported to the Committee, determine whether an investigation is necessary
regarding any such report and report to the board;  (bb)discuss with
management and the external auditors any correspondence from or with regulators
or governmental agencies, any employee complaints or any published reports that
raise material issues regarding the Corporations financial statements or
accounting policies;  (cc)report
annually to shareholders or on the work of the Committee during the year;  (dd)review and approve
the Corporations hiring policies for employees or former employees of the
external auditors and monitor the Corporations adherence to the policy;  (ee)recommend
to the Human Resources Committee the appointment and termination or transfer of
the Vice-President, Internal Audit.  2.Risk Management  The Committee provides oversight of
managements establishment of an overall risk culture for the Corporation.  The Committee shall oversee and approve the
processes established and developed by management for the identification of the
Corporations principal risks, the evaluation of potential impact and the
implementation of appropriate systems to mitigate and manage the risks.  The Committee shall:  (a)review
annually with the Board managements assessment of the significant risks to
which the Corporation is exposed; discuss with management the Corporations
policies and procedures for identifying and managing the principal risks of its
business in order to ensure that management:


A-8   (i)has identified
appropriate business strategies taking into account the principal risks
identified, and  (ii)is maintaining
systems and procedures to manage or mitigate those risks, including programs of
loss prevention, insurance and risk reduction and disaster response and
recovery programs;  (b)receive
and review managements quarterly risk assessment update including an update on
residual risks, emergent risks and next steps;  (c)review
the Corporations enterprise risk management framework and reporting
methodology;  (d)review
annually the Corporations Financial and Commodity Exposure Management Policies
and approve changes to such policies; review and authorize strategic hedging
program guidelines and risk tolerance; review and monitor quarterly results of
financial and commodity exposure management activities, including foreign
currency and interest rate risk strategies, counterparty credit exposure and
the use of derivative instruments;  (e)review
the Corporations annual insurance program, including the risk retention
philosophy and resulting uninsured exposure and corporate liability protection
programs for directors and officers including directors and officers
insurance coverage;  (f)periodically
consider the respective roles and responsibilities of the external auditor, the
internal audit department, internal and external counsel concerning risk
management of the Corporation and review their performance in relation to such
roles and responsibilities; and  (g)annually,
together with management report to the Board on:  (i)the
Corporations strategies in light of the overall risk profile of the
Corporation;  (ii)the
nature and magnitude of all significant risks;  (iii)the
processes, policies, procedures and controls in place to manage or mitigate the
significant risks; and  (iv)the
overall effectiveness of risk management processes including highlighting risk
management problems and the actions that have been or will be taken to address
them.  D.Compliance
and Powers of the Committee  (a)The
responsibilities of the Committee complies with applicable Canadian laws and
regulations, such as the rules of the Canadian Securities Administrators,
and with the disclosure and listing requirements of the Toronto Stock Exchange,
as they exist on the date hereof.  In
addition this Charter complies with the applicable US laws, such as the
Sarbanes-Oxley Act, and the rules and regulations adopted thereunder, and
with the New York Stock Exchanges corporate governance standards, as they
exist on the date hereof.  This Charter
is reviewed from time to time by the Corporate Secretary together with the
Chair of the Committee in order to ensure on going compliance with such
standards.  (b)The
Committee may, at the request of the Board or on its own initiative,
investigate such other matters as are considered necessary or appropriate in
carrying out its mandate.


B-1   APPENDIX B  GLOSSARY OF TERMS  This Annual
Information Form includes the following defined terms:  AEUB means the Alberta Energy and
Utilities Board;  Alberta PPA means an Alberta government
mandated power purchase arrangement;  availability means the weighted average
equivalent availability factor, which is a term used to calculate availability
for a pool or fleet of units of varying sizes. 
It is a measure of time and energy expressed in percentage of continuous
operation, 24 hours a day, 365 days a year, that a generating unit is capable
of generating electricity, whether or not it is actually generating
electricity;  capacity means net maximum capacity that a
unit can sustain over a period of time;  gigawatt hour or GWh means one million kilowatt hours of
electrical power;  kilowatt or kW means 1,000 watts of electrical power;  kilowatt hour or kWh means one hour during which one
kilowatt of electrical power has been continuously produced;  megawatt or MW means 1,000 kilowatts or one million watts of electrical
power;  megawatt hour or MWh means 1,000 kilowatt hours;  PPA means a power purchase agreement
having an initial term of five years or greater;  watt means the scientific unit of
electrical power, being the rate of energy use that gives rise to the
production of energy at a rate of one joule per second;  watt hour is a measure of energy
production or consumption equal to one watt produced or consumed for one hour;
and  WPPI means the Government of Canadas Wind
Power Production Incentive available to approved wind generation facilities
commissioned between April 1, 2002 and March 31, 2007.


TransAlta 2008
  Annual Report powering on


[LOGO]


TransAlta has
  been powering on for almost 100 years Let us show you how our five Value
  Drivers act as the foundation of our success. Join us on a journey through a
  day in the life of reliably delivering the energy you need today... To be
  successful for close to a century requires the ability to adapt and embrace
  new ideas and strategies. With our sustainable business model, highly
  motivated team and financial strength, TransAlta is well-positioned for
  todays volatile commodity markets, rising economic pressures and a
  carbon-constrained world.


This power
  curve is from the Alberta market. It is illustrative of demand curves in our
  other markets. 24 HOURS in the life of millions of consumers, and 2,200
  TransAlta employees. The things they do, the power they need and how its
  delivered. 1 VALUE DRIVER Were always on. That means reducing unplanned
  outages and maintaining the life of our plants while spending the optimal
  amount of money and downtime for maintenance. The timing and nature of our
  maintenance schedules ensure efficiency that generates more profitable and
  steady growth in earnings and cash flow. Reliable Supply People need reliable
  power 24 hours a day, 7 days a week, 365 days a year. So we make sure they
  have it. 4 am 7,127 MW 3 am 7,092 MW 7,160 MW 1 am 7,276 MW 2 am An essential
  for life, power is always needed, so TransAlta never sleeps. Employees are on
  duty around the clock at over 50 generating stations capable of producing nearly
  8,000 megawatts of power  enough to power over 7 million homes.


7:03 am 7:30 am
  Breakfasts are cooked, businesses open and the daily migration begins. In
  Calgary, 280,000 commuters pack the LRT every weekday, energized by wind
  power generated by TransAlta. 7:03 am and demand begins to climb as people
  head to work, school and play. In TransAltas core markets, electricity
  demand is split between consumers, commercial operations and industrial use.
  While industrial use can decline in a downturn, consumer and commercial use
  usually remains stable. TransAlta is well positioned to respond to demand in
  our core markets. 7,740 MW Meeting Demand Long-term demand growth and
  renewable portfolio standards will require incremental capacity. 2 VALUE
  DRIVER 5:26 am Demand begins to stir as millions of people wake to a new day.
  Hundreds of hockey arenas come to life across Canada as men, women and
  children take to the ice. 8 am 8,264 MW 5 am 7,125 MW 7,310 MW 6 am


3 VALUE DRIVER
  10:24 am The children are just settling down for their nap at a daycare in
  Seattle. Meanwhile, TransAlta employees carefully monitor availability and
  generation capacity. TransAlta is a leader in sustainable development. We are
  a founder of the World Business Council for Sustainable Development, one of
  Canadas largest producers of wind power and one of only two Canadian
  companies in the utility sector named to the Dow Jones Sustainability North
  America Index. In addition, TransAlta has announced plans to build Canadas
  first fully integrated carbon capture and storage (CCS) facility.
  Environmental Leadership Renewable energy accounts for 16 per cent of
  TransAltas generation capability. 9 am 8,361 MW 10 am 8,365 MW 11 am 8,388
  MW 12 pm 8,358 MW


2:53 pm
  TransAltas renewable generating facilities, from hydro and geothermal to
  wind power, are hard at work keeping the world humming, including hundreds of
  care facilities. In 2008, we produced nearly 3,500 gigawatt hours of
  renewable energy. Our plan is to increase our renewable capabilities
  significantly in the future. Investing in Communities We believe in
  strengthening the communities where our employees live and work. 2:53 pm
  8,328 MW 4 Value Driver 3:48 pm Hungry students arrive home from school. TVs,
  computers and stoves get turned on as TransAlta prepares to meet evening
  demand. 1 pm 8,329 MW 2 pm 8,327 MW 4 pm 8,372 MW


5 Value Driver
  6:00 pm Night falls, and people are sitting down to supper as the days power
  demand has been fulfilled. TransAlta remains on the job. We believe in
  financial strength, supported by a strong balance sheet and investment grade
  credit ratios and secured by highly contracted cash flows. Our financial
  strategy is based on a well-balanced capital allocation plan that both
  reinvests in the business and returns capital to shareholders. We remain
  focused on achieving greater than a 10 per cent return on three key financial
  measuresInternal Rate of Return on a project basis, portfolio Return on
  Capital Employed and Total Shareholder Value. Financial Security TransAltas
  strong balance sheet and financial flexibility create consistent shareholder
  value. 4:51 pm Commuters eye the clock as rush hour on the streets, and on
  the power grid, begins. Power usage at businesses and homes converge as we
  approach the peak. 5 pm 8,670 MW 6 pm 9,013 MW 7 pm 8,921 MW 8 pm 8,828 MW


In the previous
  24 HOURS, TransAlta generated thousands of megawatts of electricity, powering
  the lives of millions. Shortly, it will begin again. TransAlta remains alert
  and watchful, as we have for a century. 8,018 MW 10:37 pm 10:37 pm and people
  are turning in, but TransAlta powers on. Despite any upheaval in todays
  capital and commodity markets, TransAltas value proposition and outlook for
  the next several years remain strong, and will continue to deliver
  shareholder value for our investorsand our future investors. 9:20 pm Demand
  has tapered, dishes are done and bedtime stories have been told. TransAlta
  reduces generation to ensure system stability. 9 pm 8,699 MW 7,673 MW 8,432
  MW 10 pm 12 am


Financial
  Highlights In Millions of Canadian Dollars except per common share data and
  ratios Year ended Dec. 31 2008 2007 2006 Revenues $ 3,110 $ 2,775 $ 2,677 Net
  earnings $ 235 $ 309 $ 45 Comparable earnings $ 290 $ 264 $ 234 Cash flow from
  operations $ 1,038 $ 847 $ 490 Free cash flow $ 121 $ 111 $ 230 Per common
  share data Net earnings $ 1.18 $ 1.53 $ 0.22 Comparable earnings $ 1.46 $ 1.31 $ 1.16 Dividends $ 1.08 $ 1.00 $ 1.00 Ratios Cash flow to interest
  coverage (times) 7.2 6.6 5.5 Cash flow to total debt (%) 31.1 30.7 26.2 Debt
  to invested capital (%) 48.1 46.8 44.5 Comparable return on capital employed
  (%) 9.8 9.7 9.0 08 Comparable Earnings per Share $ 07 06 1.16 1.46 1.31 Cash
  Flow from Operations 08 07 06 490 1,038 847 $ millions 08 07 06 9.0 9.8 9.7
  Comparable Return on Capital Employed %


2008 Annual
  Report TransAlta has been in business almost 100 years. Powering on into the
  future, and continuing to deliver shareholder value, requires us to adapt and
  invest in new techniques and technologies  while maintaining our
  low-to-moderate risk strategy and financial strength. The Key to
  Sustainability 2 Message to Shareowners 8 Performance Metrics 10 Our
  Commitment to Powering Generations 12 Message from the Chair 14 Board of
  Directors 17 Corporate Governance 18 Plant Summary 19 Managements Discussion
  and Analysis 66 Consolidated Financial Statements 74 Notes to Consolidated
  Financial Statements 112 Eleven-Year Financial and Statistical Summary 114
  Shareholder Information 115 Shareholder Highlights 116 Corporate Information


2 AR 08 Thats
  what TransAlta delivered in 2008. Im sure most annual report commentaries
  this year will start instead with words like tumultuous, worst ever,
  unprecedented. They would all be true when it comes to our economy and credit
  markets. And TransAlta was not and will not be immune from them. However, our
  long-term strategy has been to manage our business for all cycles, including
  unexpected and negative downturns. Those efforts paid off for our shareowners
  last year. And will continue to do so. Weve always recognized the
  electricity business has a very long cycle. Capital investment decisions we
  make today wont come to fruition for years and well live with them for
  generations. Success in this industry requires tremendous discipline, a
  powerful focus on cash flow and a strong balance sheet. These have been among
  our key operating drivers for decades. There were times when short-term
  perspectives could have easily got us off track, such as the period not long
  ago when debt was cheap and plentiful. Today debt is once again expensive. A
  strategy in our business built on the flavour of the day is almost destined
  to fail. This belief in the fundamentals of our business runs deep at
  TransAlta. We work hard every day to reduce volatility and maintain a low-to-moderate
  risk profile. There are four other keys to our success: One, we stay focused
  on costs. Since 2006 our overall operations, maintenance and administration
  costs (OM&A) have remained low, increasing on average approximately two
  per cent per year despite powerful inflationary forces over the years,
  especially in our main market of Alberta. That focus will continue. Two, we
  maintain our plants on the basis that we want them to run as long as they physically
  can while generating a profitable economic return. Most of our capital is
  invested in our equipment. We make money by running our plants as much as
  possible each day for as many years as possible (40-plus years is common).
  Market prices effectively determine the life of our plants, not age or use.
  Every plant has a sweet spot Comparable earnings per share up 11 per cent.
  Cash flow over $1 billion. Investment grade credit rating. Successfully added
  96 MW Steve Snyder President & CEO Message to Shareowners of wind
  generation. Safety record improved by 27 per cent. A record Energy Trading
  year. Dividend up 8 per cent. Comparable Return on Capital Employed increased
  to 9.8 per cent.


3 AR 08 for
  availability versus the capital costs needed to keep it there. We spend a
  significant amount of time and research to find those spots and then run our
  plants there as efficiently as possible. The most availability for the least
  amount of capitalthats what our Technology teams strive for. Three, we
  design and operate our plants to meet all potential permitting requirements.
  In our industry, that requires a continued focus on environmental leadership.
  That is why TransAlta has maintained its listing on the Dow Jones
  Sustainability North America Index (DJSI NA) for three straight years. Its
  why you see us taking a leadership role in climate change. We have been
  leaders in offsets and carbon trading for years. Now you see us taking a
  world leadership position in carbon capture and storage (CCS)a technology desperately
  needed if the world is to break the back of the carbon dioxide (CO2)
  challenges. Four, we make sure that safety is always, always front and centre
  at TransAlta. Our Target Zero program continues to gain momentum. It is being
  driven into every operation of our company. And that focus will persist.
  While achieving an absolute target of zero incidents across our company may
  be a goal that cannot ultimately be achieved, we will drive to be as close as
  possible as soon as possible. These are the key operating principles that
  guide us day in and day out:  A strong balance sheet  A focus on cash flow
   Cost discipline  Long-term maintenance planning  Environmental leadership
   Safety, safety, safety We are proud of our accomplishments, but 2008 was not
  without challenges for us. Our key disappointment was the unexpected poor
  availability performance of our Alberta Thermal fleet. Our teams may have
  pushed the envelope one step too far in our efforts to find the sweet spot
  between reinvestment, short-term availability and long-term life cycles. The
  result was a higher number of unplanned outages than our historical average,
  and that made for a very tough year for our Alberta Thermal teams. Unplanned
  outages take a lot of extra work and are costly. But our teams responded to
  this challenge. They swarmed all over our records, reviewed all their
  assumptions, checked their quality control processes and brought in
  third-party experts to double-check our plans and expenditures. As a result,
  theyve modified our ongoing major maintenance plans to get our Alberta units
  back on track in 2009 and beyond. I know our Generation Operations Alberta
  Thermal teams are keenly aware of their performance in the year. It held us
  back, despite strong performance from our other plants, from having an even
  more successful year than We work hard every day to reduce volatility and
  maintain a low-to-moderate risk profile. Generation Gross Margin 08 07 06
  1,426 65 1,512 105 1,489 55 Generation gross margin Commercial Operations
  & Development gross margin $ millions


4 AR 08 we
  delivered. That all said, I am confident that their expertise and
  determination to succeed will deliver a big performance improvement in 2009.
  One of the major offsets to these challenges was the outstanding performance
  of our Energy Trading team. They saw the warning signs early in the year. The
  markets were starting to show cracks and signs of volatility. In the first
  quarter, they made the decision to adjust their strategies and tightened up
  on all of their risk controls and measurements. And while I am sure none of
  them predicted just how volatile and bad markets would get by year-end, they
  were directionally correct, and their timing was superb. They kept this
  discipline up all year. The result: our first ever $100 million Energy
  Trading margin year. This tremendous performance was not achieved because of
  one or two trading calls that won for us big time. That would go against our
  disciplines and operating philosophy. Instead, it was the product of steady slugging
  and adherence to a strict strategy consistently over time. Our daily, weekly
  and monthly earnings consistency for the Energy Trading business were all way
  up in 2008. The disciplined approach executed by our Energy Trading team
  could be seen right across our company in 2008. It was a year when it would
  have been easy to get off track and off target. We had external
  distractionsa proxy dispute, a potential takeover and, of course, the now
  infamous worldwide economic flame-out. We had internal distractionsthe
  Keephills lagoon dyke failure, the unexpected Genesee 3 turbine blade failure
  and the effort required to sell our Mexican assets just as credit markets
  essentially stopped cold. Through all of this, the internal disciplines weve
  built up over the years paid off for us. In 2008, we delivered on our key
  financial goals of:  Low double-digit comparable earnings growth  Strong
  cash flow  A strong balance sheet with excellent liquidity  Improved
  comparable Return on Capital Employed (ROCE) We maintained capital allocation
  discipline:  Increased our dividend  Divested our Mexican assets  Bought
  back shares  Invested in growth for the future  Commissioned our Kent Hills
  wind farm and kept other growth projects on track We advanced our environmental
  initiatives:  Named again to the DJSI NA  Announced Project Pioneer and
  related partnerships (our CCS project) These are all important
  accomplishments. Yes, they should be recognized. But now we need to look
  forwardpowering on in 2009 and beyond. So, what are our plans? First,
  TransAlta is well-positioned to succeed despite the uncertainty in the
  marketplace. Our balance sheet and liquidity are strong and all of our
  financings In 2008, we delivered on key financial goals. AUSTRALIA 300 MW
  UNITED STATES 2,015 MW HAWAI I CANADA 6,117 MW GENERATION CAPACITY FACILITIES
  OWNED Coal-fired plants 4,914 MW Coal-fired plant 324 MW (IN DEVELOPMENT)
  Hydro plants 807 MW Gas-fired plants 1,843 MW Wind-powered plants 248 MW
  Wind-powered plant 132 MW (IN DEVELOPMENT) Geothermal plants 164 MW Corporate
  offices Energy Marketing offices


5 AR 08 over
  the next few years can be managed. Our markets may need less electricity
  growth than was forecast a year ago but overall supply is not where it needs
  to be in order to ensure good reliability in our key markets. More capacity
  will ultimately be needed. Another source of strength and predictability: our
  plants are significantly contracted for 2009 and 2010. This protects our cash
  flow, downside risks and our balance sheet. Our long-term fuel needs and
  related costs are also largely secured. We remain committed to our dividend,
  and our strong cash flow secures it. We can also afford to be patient and
  disciplined when it comes to making the right capital allocation decisions to
  position TransAlta even better for the future. Asset values are dropping.
  Equipment costs are coming down. Labour availability is improving. We are
  entering a truly unique period in which strongly positioned power generation
  companies will have the opportunity to add long-term, low-cost assets to
  their portfolios. Yes, uncertainty in the markets remains. But the marginal
  cost of new power remains much higher than current prices and, consequently,
  power prices are expected to rise over time. Adding low-cost assets today,
  whether through acquisitions or organic growth, should yield excellent
  rewards well into the future. Good companies with strong finances should be
  able to prosper with these conditions. We intend to be one of them. TransAlta
  has excellent internal organic growth opportunities in renewable generation.
  We are very competitive here. And the timing for any growth is largely in our
  control. In Alberta, we have access to superb wind reserves. Our expertise
  and experience allow us to develop these at lower capital costs than any
  competitor. In California, we have access through our CE Gen partnership to
  an approximate 1,000 MW of additional geothermal resources. This generation
  can be backed by long-term contracts. And across Canada and the Western
  United States the enforcement of renewable portfolio standards creates
  opportunities for growth supported again by long-term contracts. Our
  advantage is that all of this growth can be paced to suit market conditions,
  our economic strengths and our competitive advantages. Since 1998, we have
  focused on positioning your company to succeed financially, strategically and
  organizationally in all market conditions. The benefits of that work have
  never been greater than in 2008. We could not have predicted, nor did we, the
  extent of the changes in financial and credit markets during the year. But we
  are nonetheless prepared to prosper when others may not be. We certainly
  wont get carried away. Discipline and a commitment to the core guiding
  principles Growth can be paced to suit market conditions, our economic
  strengths, and our competitive advantages. The 96 MW Kent Hills wind farm
  began commercial operations on time and on budget on December 31, 2008.


6 AR 08 I
  talked about earlier have brought us to a position of strength, and we are
  determined to keep it that way. But we also wont leave behind opportunities
  that are consistent with our strategy and risk profile. I would like to end
  my note to you with some words on the most pressing issue facing our industry
  today the environment. You know we take our responsibilities here seriously.
  Youve seen our track record. Weve been leaders in nitrogen oxide (NOx),
  sulphur dioxide (SOx), mercury and particulate reductions. Weve diversified
  from essentially an all-coal asset base to one that includes natural gas,
  hydro, wind and geothermal. Now we are taking on the challenge of CO2. This
  is an issue that goes way beyond TransAlta or even Canada. Over 80 per cent
  of the worlds energy is hydrocarbon based. That reality wont change
  quickly. And it has resulted in what I call the triple E equation: Economic
  growth = demand energy growth = environmental impact. We need to break this
  equation if we are going to raise world living standards while reducing our
  environmental impact. We could take a sledgehammer approach. Simply put,
  Canada could stop all of its CO2 production tomorrow (no cars, no trains, no
  planes, no manufacturing plants, little electricity supply) and the result
  would be essentially no impact on the worlds climate change challenge. We
  produce only two per cent of the worlds CO298 per cent of the problem
  remains. Not surprisingly, there are few advocates to this approach. We
  cannot, however, sit idly by and ignore the problem. We must take on the challenge
  of keeping our economy prosperous and still reduce our environmental
  footprint. That means that we have to be very focused on what we as a country
  and as an industry can do. We need to play to our strengths. Through
  technology and changed living habits, we have a fantastic opportunity to make
  the triple E work in our favourand for our planet. That is why TransAlta
  is such a strong advocate for CCS. Our world has a huge installed base of
  hydrocarbondriven economic engines. Replacing them all from scratch with
  alternatives is financially and technically impossible for decades. By
  2050possible. By 2025hopefully excellent progress. But what about today? We
  need to find a way to economically eliminate the waste CO2 from all these
  existing facilities. That will allow the world to much more quickly achieve
  the CO2 targets it is setting for itself. This is where Canada, and
  especially Alberta, can play a leading role on a global scale in advancing
  this technology. Our unique combinations of large single-source CO2 emitters,
  outstanding deep sequestration capacity, world-class pipeline expertise, a
  sophisticated regulatory system and experienced and energy-based research
  universities are attracting scientific and engineering leaders from around
  the world to Canada to test emerging technologies. Senior Management (left to
  right) Mike Williams Executive Vice-President, Human Resources, Information
  Technology & Communications; Dawn Farrell Executive Vice-President,
  Commercial Operations & Development; Richard Langhammer Executive
  Vice-President, Generation Operations; Steve Snyder President & Chief
  Executive Officer; Will Bridge Executive Vice-President, Generation
  Technology & Procurement & Material Management; Ken Stickland
  Executive Vice-President, Legal, Sustainable Development & Environment,
  Health & Safety; Brian Burden Executive Vice-President & Chief
  Financial Officer We have to be very focused on what we as a country and as
  an industry can do.


7 AR 08 Canada
  can lead the way, and help the world, in real CO2 reductions. We can bring
  financing, location, opportunity and technology together faster and better
  than any other jurisdiction in the world. Green carbon truly is technically
  possible, and achieving that goal is a worthy objective for all of us. That
  is why we are so proud of Project Pioneer. This project would provide
  Alberta, Canada and the world with the largest integrated post-combustion CCS
  facility. Unfortunately, electricity markets today will not financially
  support these early technology applications. They are simply too expensive
  until scale brings down the costs. But a partnership of government,
  researchers and industry can fund these seed projects and start the process
  to green coal. I believe strongly that they should. Where else can Canada
  play such a productive role that will help solve the worlds CO2 issues and
  not just our own? There is much work to do yet on sequestration. Hopefully we
  will make real advancements in 2009. The strong performance you have seen
  from your company over the last five years is a result of the dedicated work
  of all of our employees. Each of them has demonstrated their focus to deliver
  reliable shareowner value growth. Theyve become battle hardened and are
  ready to deliver excellent performance despite the gloomy market conditions
  in front of us. Our employees are backed by a very strong Board that has been
  consistently recognized for governance excellence by third-party evaluators.
  Our Board has clearly shown it understands shareowner value and takes its
  responsibilities seriously. It is engaged. It is proactive. It understands
  our industry. It helps ensure our strategy is on-the-mark. And it carefully
  monitors our progress to achieve success. Looking ahead, your company will
  continue to benefit from:  A dedicated and well-trained employee team  A
  strong, experienced Board  A clear-cut, disciplined strategy  Strong
  pay-for-performance links  A dedication to financial strength  Adaptability
   A long-term perspective All of these attributes have served shareowners
  well and will continue to do so as we go forward to 2009 and beyond. Our
  Board and our employees thank you for your ongoing support and confidence.
  Sincerely, Steve Snyder President and Chief Executive Officer March 4, 2009
  We are ready to deliver excellent performance despite the market conditions.
  Carbon Capture and Storage Refinery Power Plant Coal Beds Oil and Gas
  Reservoir Saline Aquifier Salt Cavern CO2 returned Energy input (oil/gas)
  Energy input (coal) CCS captures CO2 from large industrial facilities and
  stores it deeply and safely underground, where it cannot contribute to
  climate change.


8 AR 08
  Availability and Production Our goal is to achieve top decile availability in
  the industry of 90 to 92 per cent and optimize production. Availability is a
  key factor in determining revenue in many of our contracts. Availability is
  the percentage of time a generating unit is capable of running, regardless of
  whether or not it is generating electricity. As plants need maintenance and occasionally
  break down, 100 per cent availability over an extended period of time is not
  achievable. Production is the amount of electricity generated and is measured
  in gigawatt hours (GWh). It is a significant driver of revenue in certain
  contracts. 06 07 08 Target 09/10 Availability (%) 89.0 87.2 85.8 9092
  Production (GWh) 48,213 50,395 48,891 Optimize Availability and production
  decreased in 2008 due to:  Higher unplanned outages at Alberta Thermal 
  Higher unplanned outages at Genesee 3  Higher planned outages at Centralia
  Thermal as a result of equipment modifications  Lower market heat rates at
  Sarnia  Economic dispatching at Centralia Thermal Productivity Our goal is
  to offset the impact of inflation on OM&A. Managing our maintenance and
  administration costs is essential to improving the bottom line. Productivity
  is measured as operations, maintenance and administration (OM&A) expense
  per installed megawatt hour (MWh). Target 06 07 08 09/10 OM&A Offset
  ($/installed MWh) 7.93 7.81 8.61 Inflation In 2008, a 10 per cent
  year-over-year increase in OM&A expenses exceeded inflation. Higher costs
  resulted from:  Increased maintenance and compensation expenses 
  Unfavourable exchange rates  Cost escalations Sustaining Capital
  Expenditures Our goal is to make sustaining capital expenditures more
  predictable and in line with our long-range plans. Sustaining capital
  expenditures are investments made to maintain our current operations. They
  include routine and major maintenance on our plants, equipment for our mines
  and investment in our information systems and productivity. 06 07 08 Target
  09/10 Sustaining Capex ($ millions) 207 371 465 270390 The sustaining capex
  in 2008 was higher than the target of $290 to $325 million. This was
  primarily due to:  Centralia fuel transition  Higher planned maintenance
  and higher unplanned outages at Alberta Thermal Performance Metrics
  Availability and Production 08 07 06 48,213 48,891 50,395 Production (GWh)
  Availability (%) 89.0 87.2 85.8 Our long-term strategy has been to manage
  business for all cycles. Steve Snyder President & CEO


9 AR 08
  Earnings Per Share Our target is to generate low double-digit EPS growth on a
  comparable basis annually. Comparable earnings per share (EPS) is frequently
  used to measure a companys ongoing profitability. 06 07 08 Earnings/share
  ($) 1.16 1.31 1.46 (comparable basis) Target 09/10 Increase > 10%/yr
  Comparable EPS increased 11 per cent in 2008. Improved results were driven
  by:  Higher contracted electricity prices in Alberta and the Pacific
  Northwest  Greater merchant production  An increase of $50 million in
  Energy Trading gross margins Cash Flow Our goal is to generate significant
  cash flow from operations. Cash flow generated from operations is used to
  maintain our equipment, meet our debt repayment obligations, return capital
  to shareholders through dividends and share buybacks and invest in new
  capacity. 06 07 08 Cash flow from 490 847 1,038 operations ($ millions)
  Target 09/10 800900 An increase of $191 million in cash flows in 2008 was
  driven by:  Higher cash earnings  Favourable movements in working capital
  Safety Our ultimate goal is to achieve zero injury incidents; targeting a 10
  per cent IFR reduction year-over-year. Safety is a core value at TransAlta.
  We take it very seriously and measure ourselves against industry-wide
  standards. Injury Frequency Rate (IFR) measures all fatal, lost time and
  medical aid injuries. 06 07 08 Injury Frequency Rate 1.96 1.76 1.28 Target
  09/10 Reduce > 10%/yr Our overall employee and contractor IFR for 2008
  surpassed our goal of 1.41 resulting in a 27 per cent improvement compared to
  2007. This significant improvement is a result of the collected efforts of
  all asset teams from across the fleet decreasing their individual IFR.
  Investment Ratios Our goal is to maintain investment grade credit ratings and
  operate the business within established financial ratio ranges. Financial
  strength and flexibility are critical to the companys ability to create
  value, capitalize on opportunities and manage industry cyclicality. The
  ratios used to measure our performance include: cash flow to interest, cash
  flow to total debt and debt to invested capital. Credit rating agencies also
  use these ratios when evaluating the financial strength of the company. 06 07
  08 Cash flow to interest (times) 5.5 6.6 7.2 Target 09/10 Min. of 4x Cash
  flow to total debt (%) 26.2 30.7 31.1 Target 09/10 Min. of 25% Debt to
  invested capital (%) 44.5 46.8 48.1 Target 09/10 Max. of 55% In 2008, we
  maintained a strong balance sheet, financial ratios, ample liquidity and
  stable investment grade credit ratings. Sustainable Long-Term Shareholder
  Value Our goal is to achieve greater than 10 per cent for both ROCE and TSR.
  We measure returns to our shareholders and investors two ways: return on
  capital employed (ROCE) and total shareholder return (TSR). ROCE is a measure
  of the efficiency and profitability of capital investments. TSR is the total
  amount returned to investors over a specific holding period and includes
  capital gains and dividends. We continue to create economic value from
  capital investments. 06 07 08 Comparable ROCE (%) 9.0 9.7 9.8 Target 09/10
  > 10% TSR (%) 9.2 29.0 -23.9 Target 09/10 > 10% A strong ROCE was held
  in 2008. Although the annual TSR was lower than 2007, we were able to
  maintain the cumulative five-year TSR of 65 per cent. Comparable Earnings Per
  Share 08 07 06 1.16 1.46 1.31 $ 08 07 06 9.0 9.8 9.7 Comparable Return on
  Capital Employed % Cash Flow from Operations 08 07 06 490 1,038 847 $ millions


10 AR 08 We
  balance our responsibility to communities, employees and shareholders with
  our commitment to minimize our environmental impact. A commitment to the
  environment Our environmental strategy includes chemical management, employee
  programs, heat rate improvements, water management, land reclamation, waste
  management as well as emissions reduction programs. These are a focal point
  of our environmental efforts. Coal-fired power generation is and will
  continue to be a significant part of our business as a low-cost and reliable
  fuel source. We recognize that we have a significant role to play in
  determining the best solutions for emissions management. Careful research and
  consultation have determined that Carbon Capture and Storage (CCS) is our
  long-term strategy. In 2008, we launched Project Pioneer, a pre-commercial
  pilot CCS project, at our Wabuman-area operations. The project is expected to
  be online in 2013 with results shared across all industry. Through 2008 we
  established the academic, industry and technology partnerships needed for the
  project. In 2009, we will pursue the government partnerships that are
  required if the pilot is to be financially achievable. Our medium-term
  strategy for emissions management is steady growth of our portfolio of
  renewable sources of power generation. In 2008, we announced two wind
  generation projects in Alberta: the 66 MW Blue Trail wind farm and the 66 MW
  expansion of our Summerview operations. We also completed the 96 MW Kent
  Hills wind farm, New Brunswicks first wind project. Our short-term strategy
  leverages our years of expertise in offsets trading. TransAlta is a
  recognized leader in offsets and in 2008 we completed a transaction that
  ensures that we meet our emissions reductions commitments through to the end
  of 2009. We are currently investigating the viability of our wind operations
  and by-product sales as offset mechanisms; both significantly offset carbon
  dioxide emissions. TransAlta has established a pattern of adopting action and
  testing solutions ahead of regulation. By proactively researching and testing
  solutions, we can share what we learn with policy-makers and work
  collaboratively with industry, typically resulting in more workable and
  practical solutions. TransAlta has continually decreased our greenhouse gas
  emissions intensity since 2000, and has been leading a major mercury emission
  reduction project for the purpose of decreasing our mercury emissions in
  Alberta by 70 per cent by 2010. TransAltas sulphur dioxide and nitrogen
  dioxide emission intensities have also decreased steadily since 2000. In
  2008, we decreased our environmental incidents to 35 from 41 in 2007. Our
  Commitment to Powering Generations generator and marketer of energy, it is
  our responsibility to provide reasonably priced electricity that allows Were
  proud of our progress to date and confident in our ability to find the right
  answers for a sustainable future. TransAlta provides an essential service. As
  a wholesale the quality of life we all enjoy.


11 AR 08 A
  commitment to safety Safety is a core value at TransAlta and in 2008 we
  sharpened our focus. Through 2007 we recognized a trend toward more safety
  incidents, despite best efforts to ensure safety was top of mind for all
  staff and contractors. TransAlta has a comprehensive safety program called
  Target Zero. The premise is that zero incidents can be achieved. In 2008 we
  enhanced our program with more employee education, more safety personnel on
  operations teams and an enterprise-wide system for tracking and following up
  on potential safety issues. Employee safety programs were enhanced with
  regular communications and training. A safety registry was also introduced,
  documenting all performance and offering the opportunity for follow-up or
  recognition, as appropriate. A contractor safety management process was
  introduced in 2007 and took shape through 2008 with an enhanced contractor
  prequalification process. The new system allows the company to provide better
  oversight where needed, according to the results of a prequalification process.
  The vendor system also allows TransAlta access to a databank of prequalified,
  safety-conscious contractors. TransAlta launched the Presidents Awards for
  Safety in 2008, to recognize excellence in safety practices and performance.
  The first awards were presented in early 2009; they will be presented
  annually. Target Zero is a way of working that is integrated into all that we
  do. By ensuring that safety continues to be seen as a core value, we improved
  our safety performance in 2008 by 27 per cent. Our employee injury frequency
  rate was 0.95 compared to 1.04 in 2007 and our contractor injury frequency
  rate was 1.74 compared to 2.88 in 2007. We aim to further improve our safety
  performance by 10 per cent per year until we achieve our goal of zero
  mishaps. A commitment to communities TransAltas corporate community
  investment focuses in the areas of environment, education, arts and culture,
  and health and human services. We invest where we can have a meaningful
  impact over the long term, and where we can enhance communities where our
  employees work and live. In 2008, our investment in the University of
  Calgarys Institute for Sustainable Energy, Environment and Economy (ISEEE)
  shared the spotlight when Dr. Robert Page, TransAlta Professor of
  Environmental Management and Sustainability, was appointed, for a three-year
  renewable term, as chair of the National Round Table on the Environment and
  the Economy (NRTEE) in an open competition. In a separate appointment, Dr.
  Page was confirmed as chair of the management committee for the International
  Organization for Standardization 14000 series of international environmental
  standards, which develops standards for adoption by industry and government.
  Both these high-level appointments raised the profile and policy-related work
  of ISEEE before national and international communities and stakeholders. The
  main focus of a U.S.$500,000 contribution from TransAlta to Centralia College
  was building a better future for students and improving community resources
  in Lewis County, Washington, home to our Centralia operations. Groundbreaking
  on the TransAlta College Commons building will take place in 2011; the
  facility will open in 2013. This 70,000 square foot building will bring
  together under one roof the admissions centre, student support services,
  computer labs, meeting rooms and an expanded cafeteria. Since 2002, we have
  supported the state-of-the-art TransAlta Tri Leisure Centre, an example of a
  leading-edge community partnership between three municipalities, industry and
  the provincial government that focuses on the health and wellness of all
  community residents. In 2008, over 300 of our employees, retirees and their
  families who live near our Alberta Thermal operations made use of the
  facility TransAlta is a long-time supporter of the Calgary Stampede.
  TransAlta supports the TransAlta Stage for the events grandstand show,
  TransAlta Lights Up the Night, and, through the Calgary Stampede Foundation,
  the Young Canadians School of Performing Arts. In 2008, we provided the Foundation
  $500,000, which represents the second year of a five-year pledge. In 2008,
  TransAlta was a recipient of the United Way-Centraide national Thanks a
  Million award. This award is dedicated to organizations that sustain
  contributions of $1 million or more to United Way-Centraide through employee
  and retiree leadership. Our 2008 campaign, co-led by one of our retirees,
  achieved a record high, raising $1.5 million through employee and retiree
  contributions, and a dollar-for-dollar corporate match. TransAlta has
  sustained the $1 million level since 2001. TransAltas 2008 Report on
  Sustainability will be published to www.transalta.com/2008rs in June 2009. A
  summary of the report is available by mail; to be added to the mailing list,
  please contact sustainable_development@transalta.com. Safety is a core value
  at TransAlta.


12 AR 08 Never
  have we seen this belief validated more strongly than by the recent financial
  crisis. Although we are in the midst of unprecedented economic challenges,
  TransAltas financial condition remains healthy, our ability to meet the
  needs of our customers is as strong as ever and our commitment to pursue a
  disciplined growth strategy is intact. Reflecting on the theme of this years
  annual report, while others are powering down, TransAlta is powering on. At
  TransAlta, we work to create sustainable shareholder value by investing in
  our people, pursuing growth with a low-to-moderate risk profile and
  maintaining a strong balance sheet. It has also meant continually enhancing
  the effectiveness of our governance practices. All of this contributes to the
  results we have been able to achieve for our shareholders, employees,
  customers and communities. This approach serves us well. It allows us to
  deliver consistent value to our shareholders through the highs and lows of
  the market. And, it positions us to do well going forward. In 2008,
  TransAltas Board of Directors continued its work to build a strong and
  sustainable company. We focused on three key areas: our strategic plan, our
  sustainable business practices and corporate governance. Delivering on our
  Strategy During the past year, TransAlta took a hard look at its capital
  allocation plans and priorities and devoted significant attention to
  assessing and addressing risk factors associated with our business and growth
  plans. In terms of capital allocation, we put everything on the table and
  came back to where we have long been, reaffirming our long-term, phased
  approach to investing in growth projects while returning capital to our
  shareholders. We also strengthened our enterprise risk management practice
  and tied it directly into our governance process. The dividend is an
  important component of how we return value to our shareholders. We were
  pleased to adopt a dividend policy in 2008 and a dividend Donna Soble Kaufman
  Chair of the Board Message from the Chair I have been a TransAlta shareholder
  and director for many years. During that time, I have learned power
  generation is a long-cycle business that requires a disciplined focus on
  basic strategic priorities and a strong commitment to good corporate
  governance.


13 AR 08
  increase of $0.08 per share. As earnings increase, we are committed to
  providing consistent and sustainable dividend growth for our shareholders.
  This policy reflects your Boards intention to maintain a balanced approach
  to capital allocation. Recognition for Leadership We were especially pleased
  that TransAltas investor relations program was selected this year as the
  best in the utility and pipeline sector by IR Magazine (Canada). IR Magazine
  commissions an annual independent research survey covering a broad
  cross-section of the Canadian investment community. Last year, more than 250
  buy-side analysts, sell-side analysts and portfolio managers from a sample
  supplied by Thomson Financial and Equicom were interviewed to identify the
  award winners. Last year we were named to the Dow Jones Sustainability North
  America Index (DJSI NA) for a third consecutive year. TransAlta is one of 22
  Canadian companies on the index, and one of only two Canadian companies in
  the utility sector. Inclusion in the DJSI NA is granted to companies that
  lead their industries toward sustainability by setting standards for best
  practices and demonstrating superior environmental, social and economic performance.
  As a company with significant environmental opportunities in renewable power
  and carbon capture and storage, we believe our position as a recognized
  leader in sustainable business practices is an important competitive
  advantage. An Innovative Approach to Governance Our commitment to an ethical
  culture and strong corporate governance provides us with a solid foundation
  from which to operate. This is critically important in view of increasing
  change and industry-wide instability. We are not merely following North
  Americas changing governance standardswe are leading the way. For the
  seventh consecutive year, the Globe and Mail recognized TransAlta as one of
  the best-governed corporations in Canada, and the number one company in the
  utility sector for corporate governance. We were also recognized as a leader
  for the Conference Board of Canadas Spencer Stuart 2008 National Awards in
  Governancespecifically for our approach to enterprise risk management. The
  advisory board cited TransAlta as an example of a board that has been
  innovative and has worked smart on issues that go to the core of its
  businesss success and sustainability. Our Board In 2008 we made a strong
  Board even stronger with the addition of Stephen L. Baum. Mr. Baum was
  Chairman and Chief Executive Officer of Sempra Energy, a San Diegobased
  Fortune 500 energy services holding company. He brings a wealth of experience
  to TransAlta and is a member of the Audit and Risk Committee and Human
  Resources Committee of our Board. This year, Luis Vázquez Senties has decided
  not to seek re-election to the Board of Directors. I would like to thank Mr.
  Vázquez for his eight years of very valuable service to our Board. His
  contributions to TransAlta were numerous and he will be missed by all his colleagues.
  We know we must work to earn your trust every day and every year, and we
  consider strong corporate governance a key priority. Our efforts in this area
  reflect our great respect and appreciation for our stakeholders. It is
  gratifying for us, as we hope it is for you, to see TransAlta ranked, year
  after year, as one of the best-governed companies in Canada, particularly as
  we also achieve double-digit comparable earnings growth and strong cash flow.
  As we move forward, the Board will continue our proven approach to overseeing
  the business from economic, environmental and social perspectives. We have a
  strong balance sheet, sound environmental practices and excellent
  governancea winning combination that positions us well for profitable
  growth. I would like to thank my fellow Board members for their diligence and
  commitment. And, on their behalf, I would like to thank our management team
  and all of TransAltas 2,200 employees for their efforts. The TransAlta team
  is highly capable, energized, motivated and committed to the objectives and
  priorities of the Company. We have first-rate people, a proven and
  sustainable strategy and a strong balance sheet. I cannot think of a better
  formula for long-term success. Finally, to our shareholders, thank you for your
  confidence and continued support. Donna Soble Kaufman Chair of the Board
  March 4, 2009 We know we must work to earn your trust.


14 AR 08
  William D. Anderson Corporate Director Mr. Anderson was President of BCE
  Ventures (a subsidiary of BCE Inc.) from 2001 to 2005 (telecommunications)
  and, prior to that, Chief Financial Officer (CFO) of BCE Inc., Bell Canada
  Inc. and of Bell Cablemedia plc (telecommunications). As President of BCE
  Ventures, he was responsible for a number of significant operating companies
  as well as being Chief Executive Officer (CEO) of Bell Canada International
  Inc. In his CFO roles, Mr. Anderson was responsible for all financial
  operations of the respective companies and executed numerous debt and equity
  financings, corporate acquisition and disposition transactions as well as
  corporate and operational restructurings. Mr. Anderson is a director of
  Gildan Activewear Inc. and of MDS Inc. He is a past director at BCE Emergis
  Inc., Bell Cablemedia plc, Bell Canada International Inc., CGI Group Inc.,
  Four Seasons Hotels Inc., Sears Canada Inc. and Videotron Holdings plc. At
  TransAlta, Mr. Anderson is Chair of the Audit and Risk Committee of the
  Board. Mr. Anderson holds a bachelor degree in business administration from
  the University of Western Ontario (London, ON) and is a Chartered Accountant.
  Stephen L. Baum Corporate Director Mr. Baum was Chairman and CEO of Sempra
  Energy from December 1996 to February 2006, a San Diegobased Fortune 500
  energy services holding company formerly known as Enova Corporation. Previous
  to that, Mr. Baum was Vice Chairman, President and CEO of Sempra Energy.
  Prior to that he was Chairman, CEO and a member of the Board of Directors of
  Enova Corporation, the parent company of San Diego Gas & Electric (SDG&E)
  where he served in various officer positions including General Counsel.
  Before joining SDG&E, he was Senior Vice President and General Counsel of
  the New York Power Authority. He has also held various legal positions,
  including General Attorney at Orange & Rockland Utilities, and as an
  associate with the law firm of Curtis, Mallet Prevost, Colt & Mosle in
  New York City. Mr. Baum is a member of the Board of Directors of Computer
  Science Corporation and is Chairman of its Audit Committee. He is also a
  Senior Advisor to SkyFuel, Inc., a solar company. At TransAlta, Mr. Baum is a
  member of the Audit and Risk Committee and Human Resources Committee of the
  Board. Mr. Baum is a graduate of Harvard University (Boston, MA) and the
  University of Virginia Law School (Charlottesville, VA). He has also served
  as a Captain in the U.S. Marine Corps. Stanley J. Bright Corporate Director
  Mr. Bright was Chairman, President and CEO of MidAmerican Energy Company from
  1997 to 1999 (electric and gas utility). He was also Chairman, President and
  CEO, and CEO of predecessor companies, including the Iowa Illinois Gas &
  Electric Company (IIG&E), from 1991 to 1997. As the CEO of IIG&E, Mr.
  Bright was successful with the consolidation of IIG&E and other
  Iowa-based utilities in anticipation of emerging market competition, giving
  rise to the creation of MidAmerican Energy. As the Chairman, President and
  CEO of the new entity, Mr. Bright led the realization of significant
  merger-related synergies while working through the post-merger transition.
  The company also structured a long-term rate plan with the Iowa Public
  Service Commission. He retired as CEO of MidAmerican in 1999 but continued as
  a director until 2006. At TransAlta, Mr. Bright is Chair of the Human
  Resources Committee of the Board. Mr. Bright holds an undergraduate degree in
  accounting from the George Washington University (Washington, DC) and is a
  Certified Public Accountant. Timothy W. Faithfull Corporate Director Mr.
  Faithfull is a 36-year veteran of Royal Dutch/Shell plc (energy), where he
  filled diverse international roles principally in oil products and LNG
  project development. As President and CEO of Shell Canada Limited, he was
  responsible for bringing the $6 billion Athabasca Oil Sands Project on line,
  the first fully integrated oil sands venture in 25 years. Mr. Faithfull has
  extensive experience with commodity exposure and risk management, the result
  of his time directing the global crude oil trading operations of Shell In
  2008 we made a strong Board even stronger. Donna Soble Kaufman Chair of the
  Board Board of Directors


15 AR 08 Board
  of Directors (left to right) Gordon Giffin, Tim Faithfull, Bill Anderson,
  Gordon Lackenbauer, Stephen Baum, Steve Snyder, Donna Soble Kaufman, Luis
  Vázquez Senties, Stanley Bright, Kent Jespersen, Michael Kanovsky, Martha
  Piper International Trading and Shipping Company from 1993 to 1996. He was
  Chairman and CEO of Shell Eastern Petroleum in Singapore from 1996 to 1999,
  including Shells main refinery and oil products trading for Asia Pacific.
  During his time in Singapore he was a director of DBS Bank and the Port of
  Singapore Authority. He was a trustee of the main Singapore Arts/Theatre
  complex. In Calgary, he served on the board of the Calgary Health Trust and
  the Epcor Arts Centre. Mr. Faithfull is a director of Canadian Pacific
  Railway Limited, Shell Pension Trust Limited and AMEC plc. At TransAlta, Mr.
  Faithfull is a member of the Audit and Risk Committee and the Human Resources
  Committee of the Board. Mr. Faithfull holds a master of arts degree in
  philosophy, politics and economics from the University of Oxford, U.K. Gordon
  D. Giffin Lawyer and Senior Partner, McKenna, Long & Aldridge LLP
  (attorneys) From 1997 to 2001, Mr. Giffin served as the United States
  Ambassador to Canada with responsibility for managing Canada/ U.S. bilateral
  relations, including energy and environmental policy. Prior to this
  appointment, he practiced law for 18 years as a senior partner in Atlanta,
  Georgia and Washington, D.C. His practice focused on energy regulatory work
  at the state and federal levels. Prior to that, he served as Chief Counsel
  and Legislative Director to United States Senator Sam Nunn, with
  responsibility for the legal and legislative operations of the office. In
  2001, Mr. Giffin returned to private practice, where he specializes in state
  and federal regulatory matters, including those related to trade, energy and
  trans-border commerce. Mr. Giffin is a director of Canadian Imperial Bank of
  Commerce, Canadian National Railway Company, Canadian Natural Resources
  Limited and Ontario Energy Savings Ltd. At TransAlta, Mr. Giffin is Chair of
  the Governance and Environment Committee of the Board. Mr. Giffin holds a
  bachelor of arts from Duke University (Durham, NC) and a juris doctorate from
  Emory University School of Law (Atlanta, GA). C. Kent Jespersen Corporate
  Director Mr. Jespersen has been Chair and CEO of La Jolla Resources
  International Ltd. since 1998 (advisory and investments). He also held senior
  executive positions with NOVA Corporation of Alberta, Foothills Pipe Lines
  Ltd. and Husky Oil Limited before assuming the presidency of Foothills Pipe
  Lines Ltd. and, later, NOVA Gas International Ltd. At NOVA, he led the
  non-regulated energy services business (including energy trading and marketing)
  and all international activities. Mr. Jespersen is Chairman and a director of
  Orvana Minerals Ltd. and CCR Technologies Ltd. and a director of Matrikon
  Inc. and of Axia NetMedia Corporation. At TransAlta, Mr. Jespersen is a
  member of the Governance and Environment Committee and the Human Resources
  Committee of the Board. Mr. Jespersen holds a bachelor of science in
  education and a master of science in education from the University of Oregon
  (Eugene, OR). Michael M. Kanovsky Corporate Director and Independent
  Businessman Mr. Kanovsky co-founded Northstar Energy Corporation with initial
  capital of $400,000 and helped build this entity into an oil and gas producer
  that was sold to Devon Energy Corporation for approximately $600 million in
  1998. During this period, Mr. Kanovsky was responsible for strategy and
  finance as well as merger and acquisition activity. He initiated Northstars
  entry into electrical cogeneration through its wholly owned power subsidiary,
  Powerlink Corporation. Powerlink developed one of the first independent power
  producer (IPP) gas-fired cogeneration plants in Ontario and also
  internationally. In 1997, he founded Bonavista Energy Trust, which has grown
  to a present-day market capitalization of approximately $2 billion. Mr.
  Kanovsky is a director of Argosy Energy Corporation, ARC Energy Trust,
  Bonavista Energy Trust, Devon Energy Corporation and Pure Technologies Ltd.


16 AR 08 At
  TransAlta, Mr. Kanovsky is a member of the Audit and Risk Committee and the
  Governance and Environment Committee of the Board. Mr. Kanovsky, a
  Professional Engineer, holds a bachelor of science in mechanical engineering
  from Queens University (Kingston, ON) as well as a master of business
  administration from the Richard Ivey School of Business at the University of
  Western Ontario (London, ON). Donna Soble Kaufman Lawyer and Corporate
  Director Mrs. Kaufman is a former partner with Stikeman Elliott, an
  international law firm, where she practiced antitrust law. She has served on
  a number of boards since 1987, when she became a director of Selkirk
  Communications Limited, a diversified communications company. A year later
  she was appointed Chair of the Board, President and CEO. Several other
  directorships followed. In addition to TransAlta, Mrs. Kaufman currently
  serves on the boards of BCE Inc. and Bell Canada. She is also a director of
  HISTORICA, a private sector education initiative, and the Institute of
  Corporate Directors and a member of the Canadian Advisory Board of Catalyst,
  a non-profit organization working to advance women in business. In 2001, she
  was named a Fellow of the Institute of Corporate Directors. At TransAlta,
  Mrs. Kaufman is Chair of the Board and an ex officio member of all committees
  of the Board. Mrs. Kaufman holds a bachelor of civil law degree from McGill
  University (Montréal, QC) and a master of laws degree from the Université de
  Montréal. Gordon S. Lackenbauer Corporate Director Mr. Lackenbauer was Deputy
  Chairman of BMO Nesbitt Burns Inc. (investment banking) from 1990 to 2004. Prior
  to this, he was responsible for the principal activities of the firm, which
  included fixed income sales and trading, new issue underwriting, syndication
  and merger and acquisition advisory mandates. Mr. Lackenbauer has worked with
  many of Canadas leading utilities and has frequently acted as an expert
  financial witness testifying on the cost of capital, appropriate capital
  structure and the fair rate of return, principally before the Alberta
  Utilities Commission, the National Energy Board and the Ontario Energy Board.
  Mr. Lackenbauer is a director of NAL Oil & Gas Trust and CTV Globemedia
  Inc. At TransAlta, Mr. Lackenbauer is a member of the Governance and
  Environment Committee and the Audit and Risk Committee of the Board. Mr.
  Lackenbauer holds a bachelor of arts in economics from Loyola College
  (Montréal, QC), as well as a master of business administration from the
  University of Western Ontario (London, ON). He is also a chartered financial
  analyst. Martha C. Piper Corporate Director Dr. Piper was President and Vice
  Chancellor of the University of British Columbia from 1997 to 2006
  (education). Prior to her appointment at UBC, she served as Vice President,
  Research at the University of Alberta. She served on the boards of the
  Alberta Research Council, the Conference Board of Canada and the Centre of
  Frontier Engineering Research. Dr. Piper was also appointed by the Prime
  Minister of Canada to the Advisory Council on Science and Technology and
  currently chairs the Board of the National Institute for Nanotechnology. Dr.
  Piper is a director of the Bank of Montreal, Shoppers Drug Mart Corporation
  and a member of the Canadian delegation to the Trilateral Commission, an
  organization fostering closer cooperation among the core democratic
  industrialized areas of the world. At TransAlta, Dr. Piper is a member of the
  Human Resources Committee and the Governance and Environment Committee of the
  Board. Dr. Piper holds a bachelor of science in physical therapy from the
  University of Michigan (Ann Arbor, MI), a master of arts in child development
  from the University of Connecticut (Storrs, CT) and a doctorate of philosophy
  in epidemiology and biostatistics from McGill University (Montréal, QC). She
  has also received honorary degrees from 16 international universities. Dr. Piper
  is an Officer of the Order of Canada and a recipient of the Order of British
  Columbia. Luis Vázquez Senties Corporate Director and Independent Businessman
  Mr. Vázquez is founder, Chairman, President and CEO of Group Diavaz, an
  international constructor of offshore oil and gas platforms, developer of oil
  and gas fields and a distributor of natural gas in Mexico. Grupo Diavaz began
  as a Mexican underwater diving operation that grew to become the worlds
  second largest firm of its kind, servicing the offshore oil and gas industry
  in both exploration and production efforts. Mr. Vázquez is Chairman of the
  Mexican Gas Association and Vice President of the Mexico Chapter of the World
  Energy Council. He is a past director of the American Gas Association. At TransAlta,
  Mr. Vázquez is a member of the Human Resources Committee of the Board.
  Stephen G. Snyder President and Chief Executive Officer of TransAlta
  Corporation since 1996 Mr. Snyder is a director of the Canadian Imperial Bank
  of Commerce, Chair of the Calgary Stampede Foundation and Chair of the
  Alberta Secretariat for Action on Homelessness. He is past-chair of the
  Calgary Committee to End Homelessness, the Canada-Alberta ecoEnergy Carbon
  Capture & Storage Task Force, the Conference Board of Canada, the Canadian
  Electricity Association, the Calgary Zoological Society, the University of
  Calgary Management Advisory Council, the Calgary Zoo Destination Africa
  Campaign and the Calgary United Way Campaign. Mr. Snyder holds a bachelor of
  science in chemical engineering from Queens University (Kingston, ON) as
  well as a master of business administration from the University of Western
  Ontario (London, ON). He has honorary degrees from the University of Calgary
  (Doctor of Laws) and the Southern Alberta Institute of Technology (bachelor
  of applied technology). He was awarded the Alberta Centennial Medal in 2005
  and the Conference Board Honorary Associate Award for 2008.


17 AR 08
  TransAltas directors are experienced senior business leaders bringing a
  broad mix of skills in the electricity sector, finance, law, government,
  regulatory and corporate governance. On behalf of TransAltas shareholders,
  the Board of Directors is responsible for the stewardship of the Corporation,
  establishing overall policies and standards and reviewing strategic plans. In
  2008, the directors met on 22 occasions, including one special meeting
  devoted exclusively to TransAltas corporate strategy and direction. After a
  detailed examination of the relationships between each of the directors and
  TransAlta, the Board determined that 11 of the 12 board members are
  independent, excluding only Stephen Snyder, President and CEO of the Company.
  All of the members of each of the committees of the Board are independent. In
  2008, the Board had three standing committees, which are briefly described
  below. In 2008, the Board also convened a special committee to address
  matters raised by LS Power Energy Partners and affiliated shareholders.
  Further detailed information with respect to TransAltas approach to
  corporate governance is contained in the 2009 Management Proxy Circular.
  Audit and Risk Committee The Committee provides oversight relating to the
  integrity of the Corporations financial statements, the financial reporting
  process, the systems of internal accounting and financial controls, the risk
  identification assessment conducted by management and the programs
  established by management and the Board in response to such assessment, the
  internal audit function and the external auditors qualifications,
  independence, performance and reports. This committee met 10 times in 2008.
  Committee chair: William D. Anderson. Members: Stephen L. Baum, Timothy W.
  Faithfull, Michael M. Kanovsky, Gordon S. Lackenbauer and Donna Soble Kaufman
  (as an ex officio member). Governance and Environment Committee The Committee
  is responsible for identifying and recommending individuals to the Board for
  nomination to the Board, developing and recommending to the Board a set of
  corporate governance principles applicable to the Corporation and monitoring
  compliance therewith. The Committee also assists the Board in its oversight
  responsibilities with respect to environmental, health and safety practices,
  procedures and policies as established by management in relation to legal/regulatory
  and industry standards or best practices. This com mittee met five times in
  2008. Committee chair: Ambassador Gordon D. Giffin. Members: C. Kent
  Jespersen, Michael M. Kanovsky, Gordon S. Lackenbauer, Dr. Martha C. Piper
  and Donna Soble Kaufman (as an ex officio member). Human Resources Committee
  The Committee is responsible for reviewing and approving key compensation and
  human resource policies for the Corporation. Specifically, the Committee is
  responsible for reviewing the Companys key human resources strategies and
  equity-based and other compensation programs, and for recommending to the
  Board the compensation of the Corporations executives. The Committee also
  reviews and approves the succession management and development plan for key
  employees. This committee met eight times in 2008. Committee chair: Stanley
  J. Bright. Members: Stephen L. Baum, Timothy W. Faithfull, C. Kent Jespersen,
  Dr. Martha C. Piper, Luis Vázquez Senties and Donna Soble Kaufman (as an ex
  officio member). Corporate Governance Our commitment to an ethical culture
  and strong corporate governance provides us with a solid foundation from
  which to operate. Donna Soble Kaufman Chair of the Board


18 AR 08 As of
  January 31, 2009 Facility Capacity (MW) Ownership (%) Net capacity ownership
  interest (MW) Fuel Revenue source Contract expiry date Western Canada 28
  facilities Sundance (1) 2,126 100 2,126 Coal Alberta PPA / Merchant (2) 2017,
  2020 Keephills (3) 812 100 812 Coal Alberta PPA 2020 Sheerness 780 25 195
  Coal Alberta PPA 2020 Wabamun 279 100 279 Coal Merchant  Genesee 3 450 50
  225 Coal Merchant  Keephills 3 (4) 450 50 225 Coal Merchant  Fort
  Saskatchewan 118 30 35 Gas Long term contract (LTC) 2019 Meridian 220 25 55
  Gas LTC 2024 Poplar Creek 356 100 356 Gas LTC/Merchant 2024 Hydro assets (5)
  801 100 801 Hydro Alberta PPA 2013-2020 Castle River (6) 44 100 44 Wind
  LTC/Merchant 2011 McBride Lake 75 50 38 Wind LTC 2024 Summerview 1 (7) 70 100
  70 Wind Merchant  Blue Trail (4) 66 100 66 Wind Merchant  Summerview 2 (4)
  66 100 66 Wind Merchant  Total Western Canada 6,713 5,393 Eastern Canada 5
  facilities Mississauga 108 50 54 Gas LTC 2017 Ottawa 68 50 34 Gas LTC 2012
  Windsor 68 50 34 Gas LTC/Merchant 2016 Sarnia (8) 506 100 506 Gas
  LTC/Merchant 2022 Kent Hills 96 100 96 Wind PPA 2033 Total Eastern Canada 846
  724 United States 17 facilities Centralia (9) 1,376 100 1,376 Coal Merchant 
  Centralia Gas 248 100 248 Gas Merchant  Power Resource 212 50 106 Gas
  Merchant  Saranac 240 37.5 90 Gas LTC 2009 Yuma 50 50 25 Gas LTC 2024 Imperial
  Valley Geothermal Facilities (10) 327 50 164 Geothermal LTC/Merchant
  2016-2029 Skookumchuk 1 100 1 Hydro   Wailuku 10 50 5 Hydro LTC 2023 Total
  US 2,464 2,015 Australia 5 facilities Parkeston 110 50 55 Gas LTC 2016
  Southern Cross (11) 245 100 245 Gas/Diesel LTC 2013 Total Australia 355 300
  TOTAl 10,378 8,432 Plant Summary (1) Includes a 53 MW uprate on unit 5
  expected to be commercial in 2009. (2) Merchant capacity refers to 53 MW and
  44 MW uprates on units 4 and 6, respectively. (3) Includes two 23 MW uprates
  on units 1 and 2 expected to be commercial in 2011 and 2012, respectively.
  (4) These facilities are currently under development. (5) Comprises 13
  facilities. (6) Includes 7 individual turbines at other locations. (7)
  Comprises 2 facilities. (8) Sarnias net maximum capacity (NMC) has been
  adjusted from 575 MW due to decommissioning of equipment at the facility. (9)
  Centralia Thermals NMC has been reduced from 1,404 MW to reflect a lower
  plant output as a result of its conversion to burning Powder River Basin
  coal. (10) Comprises 10 facilities. (11) Comprises 4 facilities.




Management's Discussion and Analysis



20 Business Environment    22 Strategy    23 Capability to Deliver
Results    24 Performance Metrics    27 Results of Operations    28 Reported Earnings 29 Significant
Events    34 Subsequent Events    35 Discussion of Segmented Results    41 Financial Position    41 Financial
Instruments    45 Statements of Cash Flows    46 Liquidity and Capital Resources    47 Climate Change and Air Emissions    49 2009
Outlook    51 Risk Management    58 Critical Accounting Policies and Estimates    62 Future Accounting Changes    63 Non-GAAP
Measures



GRAPHIC

.................................................................................................................................................................
...........................................................

This management's discussion and analysis ("MD&A") should be read in conjunction with the audited 2008 consolidated financial statements. The
consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All dollar amounts in the following discussion including the
tables are in millions of Canadian dollars unless otherwise noted. This MD&A is dated March 4, 2009. Additional information respecting TransAlta Corporation ("TransAlta", "we", "our", "us",
or "the Corporation"), including its annual information form, is available on SEDAR at www.sedar.com and on our website at www.transalta.com.

2008 Management's Discussion and Analysis19

---





Business Environment

We are a wholesale power generator and marketer with operations in Canada, the United States and Australia. We own,
operate, and
manage a highly contracted and geographically diversified portfolio of assets and have expertise in generation fuels including coal, natural gas, hydro, and
renewable energy.

We operate in a variety of markets to generate electricity, find buyers for the power we generate, and arrange for its
transmission. Our key markets are Western Canada, the Pacific Northwest, and Eastern Canada. The key characteristics of these markets are described below.

Demand

Demand for electricity is a fundamental driver of prices in all of our markets. Economic growth is the key driver of longer-term changes in the
demand for electricity. Demand for electricity in all three of our major markets has been growing at an average rate of one to three per cent per year; however, the current weak economic
environment is potentially threatening growth in demand. Alberta has seen the highest rate of growth in demand in recent years, driven by a strong economy. However, development of the oil sands is
starting to slowdown as oil sands developers delay and cancel projects. Since a significant portion of Alberta's electricity load is industrial, a slowdown in the oil sands development sector will
likely affect overall demand growth. While declines in demand growth over the next few years are not expected to impact us significantly as a result of our highly contracted capability, a more
significant decline in the rate of demand growth could occur between 2013 and 2018, when the majority of the delayed and cancelled oil sands projects were scheduled to begin operations. In the
Pacific Northwest, demand has grown at a moderate but steady pace but may be threatened due to a recessionary environment in the nearer-term. Demand in Ontario is expected to remain relatively weak,
due to reduced manufacturing activity and conservation.

Supply

In all markets in which we operate, the cost of building new generating capacity has increased due to a shortage of component parts and the
increased cost of raw materials. We are seeing indications that many North American power companies are postponing the construction of projects or cutting 2009 capital spending. We believe that
reserve margins, which are the amount of generating capacity available in excess of the capacity needed to meet normal demand levels, will continue to contract and, as a result, prices are expected
to remain fairly strong over the longer-term. In the nearer-term, reserve margins are expected to increase due to weaker economic conditions and new supply coming on stream. Overall, significant
changes in investment patterns are expected to increase the volatility in the price of both natural gas and electricity.

In
Alberta, the existing thermal fleet is aging, resulting in more outages. As a result of strong economic growth over the past few years, new generation is needed to meet
the increased demand, but is limited by transmission connections both within the province and to other markets. In the Pacific Northwest, sufficient generating supply exists in the nearer-term. In
Ontario, the anticipated retirement of thermal generation is placing demand on new nuclear, natural gas-fired, and wind generation, although transmission capacity constraints may affect
how much new generation can be added to the market.

Transmission

Transmission refers to the bulk delivery system of power and energy between a generating unit and the distribution system that links to wholesale
and/or retail customers. Transmission lines themselves serve as the physical path, transporting electricity from the generating unit to the individual distribution systems. Transmission systems are
designed with sufficient reserve capacity to allow for "real time" fluctuations in both supply and demand caused by generation plants or loads coming on and off the transmission network.

Transmission
capacity refers to the ability of the transmission line, or lines, to transport this bulk supply of electricity, in an amount that balances the demand needs
to the generating supply, allows for an amount of power required for system integrity and security, and for reserve capacity to respond to contingency situations on the system. In the past, adequate
transmission capacity, tightly correlated to demand growth, served as a buffer to maintaining adequate transmission capacity during periods of new generation builds. Most transmission businesses in
North America are still regulated.

In
many markets, including Alberta, investment in transmission capacity has not kept pace with growth in the demand for electricity. Lead times in new transmission
infrastructure projects are significant and are subject to extensive consultation processes with landowners and ever-changing regulatory requirements. As a result, additions of generating capacity,
specifically renewable projects, such as wind, may not have ready access to markets until key transmission upgrades and additions are completed.

Environmental Legislation and Technologies

Environmental issues and related legislation have, and will continue to have, an impact upon our business. In 2007, we began to incur costs as a
result of greenhouse gas ("GHG") legislation in Alberta. Legislation in other jurisdictions and at different levels of government is in various stages. Our exposure to increased costs as a result of
environmental legislation in Alberta is minimized through change-in-law provisions in our Power Purchase Arrangements ("PPAs").

Both
the Canadian and U.S. federal governments are considering cap and trade policies to manage greenhouse gas emissions. However, economic uncertainty fueled by financial
market volatility, a developing recession, and Canada's political environment may delay the adoption of such systems. For these reasons, the government in Canada may not implement new environmental
legislation until 2010 or later. In the U.S. the Western Climate Initiative ("WCI"), a group of eleven U.S. western states and Canadian provinces unveiled its final version of a cap
and trade plan in 2008. Washington State, where our Centralia Thermal plant ("Centralia Thermal") is located, is a member of this group. The regional goal from this initiative is to reduce GHG
emissions by 15 per cent below 2005 levels by 2020. Separately, Washington State is also considering its own climate change legislation that could be implemented independently or in
coordination with the WCI program.

20TransAlta Corporation    Annual Report 2008

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GRAPHIC

These initiatives will impact any decision to construct new coal-fired facilities in the region because growth will increase overall emissions and compliance costs. Additional growth would result in a need for alternative
energy resources and carbon offsets to be investigated, and those investments could lead to an overall increase in compliance environmental spending. Refer to the Climate Change and Air Emissions section of this MD&A for further details.
While carbon capture and storage ("CCS") technologies are being developed, these technologies are not sufficiently advanced at this time. Consequently, we are expecting environmental compliance costs to increase the cost of generating
electricity so long as they are in place and/or the cost of low carbon generation technologies are higher than high carbon generation technologies. Economic EnvironmentAs a result of the current economic environment, commodity prices, other than electricity, are decreasing. In the short-term, lower commodity prices, specifically natural gas and coal, will not significantly alter our operating costs because those
input costs have been contracted. The decrease in commodity prices could result in lower operating costs for us in the future if commodity prices remain low and we can contract at those lower prices. In addition, decreasing commodity prices have
begun to lower the price of assets owned by others, which could result in cost-efficient acquisitions to further diversify our portfolio of assets.
A number of financial and industrial counterparties have experienced credit rating downgrades and we expect 2009 will continue to be a challenging year for some of our counterparties as a result of the recent financial crisis and current economic
environment. While we had no counterparty losses in 2008, we continue to monitor counterparty credit risk and act in accordance with our established risk management policies. We do not anticipate any material change to our existing credit practices
and continue to deal primarily with investment grade


counterparties in our trading and hedging activities.

We
expect continued strict lending conditions, which could reduce the amount of capital available and/or increase our cost of borrowing. Our strong financial position,
available committed lines of credit, and relatively low debt maturity profile allow us to be selective about when we need to go to the market for financing. We see support in the market for
successful projects with high returns, so we will continue to evaluate potential projects using the risk management policies that have been developed and take action when appropriate.

Electricity Prices

Spot electricity prices are important to our business as our merchant natural gas, wind, hydro, and thermal facilities are exposed to these prices.
Changes in these prices will affect our profitability as well as any contracting strategy. Our Alberta plants operating under PPAs pay penalties or receive payments based upon a rolling
30-day average of spot prices. Longer-term contracts at Centralia Thermal and Sarnia and our shorter-term contracts at Genesee 3 and Wabamun minimize the impact of spot
price changes.

Spot
electricity prices in our markets are driven by customer demand, generator supply, and the other business environment dynamics discussed above. We monitor these
trends in prices and schedule maintenance, where possible, during times of lower prices.

The
average spot electricity prices in each of the past three years in our three main markets are shown in the graph above.

For
the year ended Dec. 31, 2008, spot prices increased in Alberta and the Pacific Northwest and were essentially flat in Ontario compared to the same period in
2007. Alberta spot prices increased due to higher natural gas prices during the first three quarters of 2008, higher production losses due to higher than normal forced and planned outages, and lost
production as a result of transmission system upgrades. The Pacific Northwest spot prices increased primarily due to higher natural gas prices during the first three quarters of 2008. Ontario spot
prices were relatively unchanged, with higher natural gas prices being offset by increased hydro generation.

Fuel Costs

Our generating facilities use either renewable fuel sources such as water, wind, or geothermal or use combustible fuels such as coal and natural
gas. The costs of these fuels, including the cost to supply them to our generating facilities, affect our financial results. With the current market conditions, we are generally seeing falling
commodity prices, but coal costs are expected to continue to increase due to higher contract and transportation costs. As a result, coal costs at Centralia Thermal are expected to increase 10 to
15 per cent in 2009.

Mining
coal in Alberta is subject to cost increases due to increased overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal
mining are minimized through the application of standard costing. Coal costs for 2009, on a standard cost basis, are expected to increase five per cent from the prior year primarily due to
increased capital expenditures.

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
previously announced construction of numerous liquefied natural gas ("LNG") terminals throughout North America was expected to significantly impact the natural gas
market by allowing for large amounts of natural gas shipments to occur between continents. These terminals would have created an international market of supply and demand, which could have
significantly impacted natural gas prices. However, with the recent economic environment, decreasing commodity prices and the supply of natural gas that currently exists in North America, the
construction of the majority of the planned LNG terminals has been delayed or cancelled due to higher than anticipated construction costs and insufficient returns. Accordingly, this technology is
not expected to have a significant impact on natural gas prices in the near future.

In
2008, the amount of natural gas production in North America from unconventional sources, such as shale gas, has increased. If shale gas production is sustainable and
economically viable over the long-term, this increased production from unconventional sources could potentially reduce the price of natural gas over the longer-term.

We
closely monitor the risks associated with changes in electricity and natural gas 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 risk.

2008 Management's Discussion and Analysis21

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Spark SpreadsSpark spreads measure the potential profit from generating electricity at current market rates.
A spark spread is calculated as the difference between the market price of electricity and its cost of production. The cost of production is comprised of the total cost of fuel and the efficiency, or heat rate, with which the plant converts natural
gas to electricity. For most markets, a standardized heat rate is assumed to be 7,000 British Thermal Units (Btu) per Kilowatt hour (KWh).
Using this standardized measure, the average spark spreads in each of the past three years in our three main markets are shown in the adjacent graph.
Spark spreads will also vary between different plants due to their design, the region of the world in which they operate, and the requirements of the customer and/or market the plant serves. The change in the prices of electricity and natural gas and
resulting spark spreads in our three major markets affect our Generation and Commercial Operations & Development ("COD") business segments.
For the year ended Dec. 31, 2008, spark spreads increased in Alberta and decreased in the Pacific Northwest and Ontario compared to the same period in 2007. Alberta spark spreads were higher due to increased planned and unplanned outages. Spark
spreads in the Pacific Northwest were lower due to increased hydro generation during the second quarter of 2008. In Ontario, spot spark spreads were lower due to increased hydro generation, partially offset by higher natural gas prices.
The effect of these prices upon the margins from our generating facilities and our trading activities are described in further detail below.

GRAPHIC 1    For a 7,000 Btu/KWh heat rate plant.


Strategy

Our strategic position is to deliver shareholder value by maintaining a low-to-moderate risk profile, which is centered
around long-term comparable earnings per share ("EPS") growth driven by geographically focusing our operations and expanding our portfolio in the western regions of Canada and the U.S.
We are focusing on this geographic area because of market dynamics, such as deregulation, demand growth and potential green energy growth, and our expertise, scale, and access to numerous fuel
resources, including coal, wind, geothermal, hydro and natural gas.

Financial Strategy

Our financial strategy is to maintain a strong balance sheet and investment grade credit ratios in our long-cycle, capital intensive,
and commodity-sensitive business. A strong balance sheet and investment grade credit ratios improves our competitiveness by providing greater access to capital markets, lowering our cost of capital
compared to that of non-investment grade companies and enabling us to contract our assets with customers on more favourable commercial terms. We value financial flexibility, which allows
us to selectively access the capital markets when conditions are favourable.

Contracting Cash Flows

In Alberta, demand was almost flat in 2008 compared to the growth experienced in 2007, primarily due to the delayed start-up of several large
industrial projects. In 2009, while we do expect some growth in demand in Alberta due to these delayed projects coming online, we expect that demand growth will be softer than initially forecasted.
While we will not be immune to softening power prices, the impact is significantly mitigated because across our fleet approximately 90 per cent of 2009 and approximately
85 per cent of 2010 expected capacity is contracted. It is this low-to-moderate risk contracting strategy that helps protect our cash flow and our balance sheet through economic cycles
and will ultimately help us through the current downturn in the market.

Growth Strategy

The time frame for delivering on the growth component of our strategy is outlined below.

Short-Term: 2009  2012

During this period, the focus will be on efficiency uprates at our Keephills and Sundance facilities and growing
renewable energy capacity, such as wind and geothermal. We will continue our research related to various emission reduction technologies and projects, such as CCS technology and carbon dioxide
("CO2") offsets. Our focus will be on renewable energy during this time frame until we determine if CCS technology will be economically viable prior to building more
coal-fired facilities.

Medium-Term: 2013  2015

During this period, the focus of our strategy will shift to the construction of CCS technologies and investment in the
life cycle of our Alberta Thermal plants ("Alberta Thermal") to improve the longer-term efficiency and availability of our facilities. Potential investments in alternative energy sources that have
not been traditional growth areas for us, such as hydro, will be investigated along with continued investment in CO2 offsets.

Longer-Term: Beyond 2016

During this period, our strategy will be to increase overall capacity without increasing our emissions profile.
Construction of current growth and emission reduction projects will be completed and in full
production, potentially including coal-fired plants with CCS technology. We anticipate having generating assets using alternative energy to be compliant with the expected increase in environmental
regulations. This growth could be achieved by partnering with a large hydro operation, potentially obtaining an equity share in alternate energy projects, and/or uprating the capacity of existing
facilities.

22TransAlta Corporation    Annual Report 2008

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Capability to Deliver Results

We have numerous core competencies and non-capital resources that will enable us to achieve our corporate
objectives,
which are discussed below. Refer to the Liquidity and Capital Resources section of this MD&A for further discussion of the capital resources available that will assist in enabling us to achieve
our objectives.

Portfolio Optimization

We seek to optimize our generating portfolio by owning and managing a mix of assets aimed at providing the highest return for a relatively low
level of risk. This optimization requires that we divest or improve returns from our non-core and underperforming assets. Most recently, we sold our Mexico operations and we are
currently pursuing an improved long-term contract at Sarnia. In 2009, we will perform upgrades on the gas turbine engines at our Ottawa, Mississauga and Windsor facilities to improve
productivity and enhance returns.

Financial Strength

We carefully manage our balance sheet in order to maintain financial strength and flexibility throughout all economic cycles. This discipline is
important in the current economic environment. We currently maintain financial ratios that exceed our minimum targets. We continue to maintain $2.2 billion available in committed credit
facilities, and as of Dec. 31, 2008, $1.4 billion was available to us. These strong ratios, available credit, and continued positive cash flow from operations provide us with ample
financial flexibility and as a result, we can be selective about if and when we go to the capital markets for funding.

Environmental Leadership

We are committed to being industry leaders in environmental stewardship. In the past, we have been involved in various projects directed toward
researching and implementing more environmentally friendly technologies at our plants. In April 2008, we announced Project Pioneer that will pilot Alstom Canada's chilled ammonia CCS
technology at one of our Alberta Thermal units. This technology has the potential to remove up to 90 per cent of CO2 emissions. This CCS project will be the largest of its
kind and the first project in the world to have an integrated underground storage system. TransCanada PipeLines Limited is participating in the development of Project Pioneer and we are working to
secure additional industry partners. Securing industry partners and funding initiatives from the federal and provincial governments are key to accelerating CCS projects across Alberta.

In
2007, we voluntarily installed continuous emissions monitoring systems at Centralia Thermal. In 2008, we reached an agreement with the Department of Ecology in
Washington State to voluntarily cut emissions of mercury and visibility-limiting nitrogen oxide. Testing and certification of these new technologies occurred throughout 2008 and will continue into
the future. We continue to work with regulators to determine appropriate reduction targets and compliance timelines and to develop future environmental policy. We remain dedicated to being involved
in discussions with policy-makers and regulators regarding future environmental legislation and implementation.

Disciplined Capital Allocation

We are committed to optimizing the balance between dividend growth, liquidity requirements, base business investment, growth opportunities, and
share buybacks. We have a proven track record of long-term financial stability and are committed to paying dividends to shareholders based on between 60 and 70 per cent of
comparable earnings.1

.....................................................................................................................................................................
.......................................................

We continue to grow our diversified generating fleet in order to increase production and meet future demand requirements, with all
growth projects having to exceed corporate hurdles for returns. We currently have 456 megawatts ("MW") of capacity under construction and due to be commissioned in the 2009-2012
period, which is comprised of 225 MW of coal-fired generation, 99 MW of uprates to our thermal coal fleet, and 132 MW of wind power. We are a leading generator of wind power in
Canada and these growth projects will increase our total renewable energy capacity.

In
addition to our greenfield growth plans, we continue our uprates of existing facilities. These uprates add capability to our existing fleet and provide opportunities
for high rates of return.

Lifecycle Planning

Managing the operation and maintenance of our fleet is important to ensure reliable generation and revenues. Ensuring the consistent reliability of
our facilities is achieved by understanding current technologies and monitoring new developments in technology for their potential application. Lifecycle planning also involves making decisions as
to when changes should be made to our existing facilities and when maintenance should occur on components at those facilities. Our success in providing reliable generation is a result of carefully
planned and closely monitored maintenance schedules, as well as efficient response and correction of unplanned outages at our facilities. We expect to see increases in production over time as we
continue to optimize our current major and routine maintenance programs.

Operational Excellence

We achieve operational excellence by closely planning and monitoring the routine maintenance requirements of our assets. Over the last five years,
our average availability has been 88.1 per cent, which is below our corporate target of 90 to 92 per cent. This decrease in our average availability has been
primarily impacted by the declines in availability in 2007 and 2008 due to higher than normal unplanned outages at our plants. A significant portion of these unplanned outages were a result
of boiler leaks at our Alberta Thermal facilities.

2008 Management's Discussion and Analysis23

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While Alberta Thermal faced challenges in 2008, we have a solid plan to drive our fleet to 90 to 92 per cent availability. We realize that there is always going to be a trade-off between costs and availability
and that there are always going to be operational risks that cannot be entirely eliminated economically. We acknowledge the challenges that were faced in 2008 and have refined our understanding of the business risks and the relationship to
maintenance work related to these challenges. Part of our plan to address the boiler leaks at our Alberta Thermal facilities includes a heavy maintenance schedule for 2009, for which the majority of the work is scheduled to take place in the first
and second quarters.
In addition, part of our plan to improve availability was implementing the Operations Diagnostic Centre ("ODC"), which came online on Dec. 1, 2008. The ODC is a real-time monitoring centre staffed by highly trained engineers and operators. It
uses state-of-the-art technology to enable us to optimize our preventive maintenance work by allowing us to continuously monitor and improve our operation. The ODC is instrumental to improving the efficiency of our generating fleet by enabling us to
monitor the entire fleet in one location and to plan and act on a fleet-wide basis, instead of on a

GRAPHIC

GRAPHIC


somewhat isolated plant-level scale. We believe the investment in the ODC will pay for itself in two years.

We
have performed significant planned maintenance work to improve availability and efficiency at Centralia Thermal by modifying the boilers to burn Powder River Basin
("PRB") coal. We completed the Unit 2 boiler modifications, a 500,000-man-hour turnaround, on time and with an excellent safety record. Unit 2 is operating to all performance targets.
Unit 1 boiler modifications are scheduled to begin in the spring of 2009.

We
will continuously monitor and revise our plans, as necessary, to improve availability and to meet our corporate targets.

Organizational Leadership

Our experienced leadership team is comprised of senior business leaders who bring a broad mix of skills in the electricity sector, finance, law,
government, regulation, and corporate governance. The leadership team's experience and expertise, combined with our employees' knowledge and dedication to superior operations, has resulted in a
long-term proven track record of financial stability and increasing shareholder value.

Performance Metrics

We have key measures that, in our opinion, are critical to evaluating how we are progressing towards meeting our goals. These
measures, which include a mix of operational, risk management, and financial metrics, are discussed below.

Availability

Our plants must be available throughout the year at all times to meet demand. However, this ability to meet demand is limited by the requirement to
shut down for planned maintenance and unplanned outages, and reduced production as a result of derates. Our goal is to minimize these events through regular assessments of our equipment and a
comprehensive review of our maintenance plans. Over the past three years we have achieved an average availability of
87.3 per cent, which is below our long-term target of 90 to 92 per cent. Our availability in 2008 was 85.8 per cent. The graph above shows our
availability results for the past three years.

Availability
for the year ended Dec. 31, 2008 decreased to 85.8 per cent from 87.2 per cent compared to the same period in 2007 due to
higher unplanned outages at Alberta Thermal and Genesee 3, and higher planned outages as a result of equipment modifications at Centralia Thermal, partially offset by lower derates at
Centralia Thermal as in 2007 we conducted test burns of PRB coal.

In
2007, availability decreased to 87.2 per cent from 89.0 per cent in 2006 as a result of derating at Centralia Thermal due to test-burning
PRB coal in 2007 and higher unplanned outages in Western Canada. The underlying availability, after adjusting for Centralia Thermal derates, was 90.5 per cent for the year ended
Dec. 31, 2007.

Production

Production is a significant driver of revenue in some of our contracts and in our ability to capture market opportunities. Our goal is to optimize
production through planned maintenance programs and the use of monitoring programs to minimize unplanned outages and derates. We combine these programs with our monitoring of market prices to
optimize our results under both our contracted and merchant facilities. The graph above shows our production results for the past three years.

For
the year ended Dec. 31, 2008, production decreased 1,504 gigawatt hours ("GWh") compared to the same period in 2007 due to higher unplanned outages at
Alberta Thermal and Genesee 3, higher planned outages at Centralia Thermal, lower market heat rates at Sarnia, and economic dispatching at Centralia Thermal, partially offset by lower unplanned
outages at Centralia Thermal, higher merchant volumes due to the uprate on Unit 4 at our Sundance facility, and lower derates at Centralia Thermal resulting from test burns of PRB coal
in 2007.

24TransAlta Corporation    Annual Report 2008

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GRAPHIC

GRAPHIC

In 2007, production increased 2,182 GWh compared to the same period in 2006 due to higher production at Centralia Thermal and lower planned outages and increased demand at Sarnia partially offset by higher
unplanned outages at Alberta Thermal. ProductivityOur operations, maintenance, and administration ("OM&A") costs reflect the operating cost of our facilities. These costs can fluctuate due to the timing and nature of planned maintenance activities. The remainder of
OM&A costs reflect the cost of day-to-day operations. Our target is to absorb the impact of inflation in our recurring operating costs as much as possible through cost control and targeted productivity initiatives. We measure our ability to
maintain productivity on OM&A based on the cost per installed megawatt-hour ("MWh") of capacity.
OM&A costs per installed MWh have increased compared to the same period in 2007 due to cost escalations, higher planned maintenance costs, and increased compensation costs.


Safety

Safety is a top priority with all of our staff, contractors and visitors. Our goal is to improve safety by reducing the rate of injuries by
10 per cent each year and our ultimate target is for no incidents to occur.

2006


2007


2008

Target 09/10Injury Frequency Rate ("IFR")


1.96


1.76


1.28

Reduce >10% annually


The IFR has consistently decreased over the past three years as a direct result of our continuous efforts to improve safety.

Sustaining Capital Expenditures

We are in a long-cycle capital-intensive business that requires consistent and stable capital expenditures. Our sustaining capital
comprises two components: (1) routine and mine capital, and (2) planned maintenance.

In
2008, we spent $340 million on routine and mine capital and $125 million on planned maintenance. In 2007, we spent $293 million on routine and mine
capital and $78 million on planned maintenance. The increase in both routine and mine capital and planned maintenance in 2008 compared to the same period in 2007 was due to higher unplanned
outages at Alberta Thermal and Genesee 3, equipment modifications at Centralia Thermal, and higher planned maintenance activities across the fleet.

Our
annual target for sustaining capital expenditures is expected to decrease for 2009 to approximately $340 to $390 million, primarily due to lower unplanned
outages. We expect to return to normal sustaining capital expenditure levels of $270 to $315 million in 2010 as a result of lower productivity spending, reduced capital spending at CE
Generation, LLC ("CE Gen"), and the elimination of capital spending related to Centralia Fuel Blend.

Earnings and Cash Flow From Operating Activities

We focus our base business on delivering strong earnings and cash flow growth. Comparable earnings per share1 are targeted to
increase in the low double-digit range per year with operating cash flows targeted between approximately $800 and $900 million.

2006


2007


2008

Target 09/10Earnings per share (comparable basis)

$
1.16

$
1.31

$
1.46

>10% annuallyCash flow from operating activities ($ millions)


490


847


1,038

800-900


In 2008, earnings per share on a comparable basis increased 11 per cent to $1.46 due to favourable pricing in our
core markets, higher merchant volumes due to the uprate on Unit 4 at our Sundance facility, and strong Energy Trading results across all markets, partially offset by higher unplanned outages
at Alberta Thermal.

In
2007, earnings per share on a comparable basis increased 13 per cent to $1.31 due to favourable pricing, higher production and lower coal costs at
Centralia Thermal, partially offset by higher unplanned outages at Alberta Thermal.

.....................................................................................................................................................................
.......................................................

2008 Management's Discussion and Analysis25

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In 2008, cash flow from operating activities increased 23 per cent to $1,038 million due to an increase in cash earnings and
favourable changes in working capital including the timing of PPA receipts in 2008.

In
2007, cash flow from operating activities increased 73 per cent to $847 million mainly due to higher cash earnings, and receiving 12 months
of contractually scheduled payments in 2007 compared to 11 in 2006.

Investment Ratios

Investment grade ratings support contracting activities and provide better access to capital markets through commodity and credit cycles. We are
focused on maintaining a strong balance sheet and stable investment grade credit
ratings. Our objective is to maintain a cash flow to interest ratio of at least four times, a cash flow to debt ratio of at least 25 per cent, and a debt to invested capital
ratio of not more than 55 per cent.

Cash
flow to interest increased to 7.2 times from 6.6 times in 2007 and 5.5 times in 2006. Cash flow to interest increased in 2008 compared to the same period in
2007 as a result of increased cash from operating activities and lower interest expense.

Cash
flow to total debt increased to 31.1 per cent from 30.7 per cent in 2007 and 26.2 per cent in 2006. Cash flow to total debt increased in 2008 compared
to the same period in 2007 due to an increase in cash flows from operating activities, which offset the increase in debt balances.

At
Dec. 31, 2008, our total debt (including non-recourse debt) to invested capital was 48.1 per cent (45.6 per cent
excluding non-recourse debt) compared to the Dec. 31, 2007 ratio of 46.8 per cent and Dec. 31, 2006 ratio of 44.5 per cent. Total debt to
invested capital increased in 2008 compared to the same period in 2007 as a result of the issuance of senior notes in the amount of U.S.$500 million.

2006


2007


2008

Target 09/10Cash flow to interest (times)


5.5


6.6


7.2

Minimum 4Cash flow to total debt (%)


26.2


30.7


31.1

Minimum 25Debt to invested capital (%)


44.5


46.8


48.1

Maximum 55


We seek to maintain financial flexibility by using multiple sources of capital to finance capital allocation plans effectively,
while maintaining sufficient liquidity in our investments to support contracting and trading activities. Further, this allows our commercial team to contract our portfolio with a variety of
counterparties on terms and prices that are beneficial to our financial results.

Shareholder Value

Our business model is designed to deliver low-to-moderate risk-adjusted sustainable returns and maintain financial strength and
flexibility, which enhances shareholder value in a capital intensive,
long-cycle, commodity-based business. Our goal is to achieve consistent comparable return on capital employed ("ROCE")2 greater than 10 per cent and total
shareholder return ("TSR")1 of 10 per cent or more per year.

The
table below shows our historical performance on these measures:

2006


2007


2008

Target 09/10Comparable ROCE (%)


9.0


9.7


9.8

> 10% annuallyTSR (%)


9.2


29.0


(23.9
)
> 10% annually


Comparable ROCE in 2008 was consistent with the prior year. The decrease in TSR for 2008 was due to a decrease in share
price during 2008 as a result of the weakening economic environment. The Standard & Poor's ("S&P")/Toronto Stock Exchange ("TSX") Composite Index decreased 35 per cent during
the same period.

.....................................................................................................................................................................
.......................................................

26TransAlta Corporation    Annual Report 2008

---



Results of Operations

The results of operations are presented on a consolidated basis and by business segment. We have two business segments:
Generation and Commercial Operations & Development ("COD"). Our 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.

Some of our accounting policies require management to make estimates or assumptions that in some cases may relate to matters
that are inherently uncertain. Critical accounting policies and estimates include: revenue recognition, valuation and useful life of property, plant and equipment ("PP&E"), financial instruments,
asset retirement obligations ("ARO"), valuation of goodwill, income taxes, and employee future benefits. Refer to the Critical Accounting Policies and Estimates section of this MD&A for
further discussion.

In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is
discussed with the relevant income statement and balance sheet items. While individual balance sheet line items will be impacted by foreign exchange fluctuations, the net impact of the translation
of individual items is reflected in the equity section of the consolidated balance sheets.

Highlights and Summary of Results

During 2008, we:

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

Year ended Dec. 31


2008


2007


2006Availability (%)


85.8


87.2


89.0Production (GWh)


48,891


50,395


48,213Revenue

$
3,110

$
2,775

$
2,677Gross margin1

$
1,617

$
1,544

$
1,491Operating income before mine closure and asset impairment charges1

$
533

$
541

$
479Mine closure charges








(192
)Asset impairment charges








(130
)Operating income1

$
533

$
541

$
157Net earnings

$
235

$
309

$
45Basic and diluted earnings per common share

$
1.18

$
1.53

$
0.22Comparable earnings per share1

$
1.46

$
1.31

$
1.16Cash flow from operating activities

$
1,038

$
847

$
490Free cash flow2

$
121

$
111

$
230Cash dividends declared per share

$
1.08

$
1.00

$
1.00




As at Dec. 31


2008


2007


2006Total assets

$
7,815

$
7,157

$
7,460Total long-term financial liabilities

$
3,193

$
2,858

$
3,094


.........................................................................................................................................................................................................................................
.....................................

2008 Management's Discussion and Analysis27

---



Reported Earnings

In 2008, reported earnings decreased to $235 million, compared to $309 million in 2007 and $45 million in
2006, as shown below:

Net earnings for the year ended Dec. 31, 2006

$
45Increase in Generation gross margins


83Mark-to-market movements  Generation


(64
)Writedown of coal inventory to lower of cost and market in 2006


44Decrease in COD margins


(10
)Decrease in operations, maintenance and administration costs


4Decrease in depreciation expense


4Centralia coal mine closure charges in 2006


192Asset impairment charges in 2006


130Gain on sale of mining equipment


16Decrease in net interest expense


35Increase in equity loss


(33
)Decrease in non-controlling interest


4Increase in income tax expense


(146
)Other


5Net earnings for the year ended Dec. 31, 2007

$
309Increase in Generation gross margins


7Mark-to-market movements  Generation


16Increase in COD gross margins


50Increase in operations, maintenance, and administration costs


(60
)Increase in depreciation expense


(22
)Gain on sale of mining equipment in 2007


(11
)Decrease in net interest expense


23Increase in equity loss


(47
)Increase in non-controlling interest


(13
)Increase in income tax expense


(3
)Other


(14
)Net earnings, 2008

$
235


Generation gross margins1, net of mark-to-market movements, increased by $7 million
for the year ended Dec. 31, 2008 due to favourable pricing, lower derates at Centralia Thermal, and higher merchant volumes as a result of the uprate on Unit 4 at our Sundance
facility, partially offset by higher unplanned outages at Alberta Thermal and Genesee 3.

In
2007, generation gross margins, net of mark-to-market movements, increased $83 million as a result of lower planned outages in Western
Canada combined with favourable pricing, higher production, and lower fuel costs at Centralia Thermal, partially offset by higher coal costs and higher unplanned outages in Western Canada and the
strengthening of the Canadian dollar relative to the U.S. dollar.

For
the year ended Dec. 31, 2008, COD gross margins increased $50 million primarily due to strong results in all markets. As at Dec. 31, 2008,
substantially all of these positions had been settled. In 2007, COD gross margins decreased $10 million compared to the same period in 2006 due to decreased gas and eastern region trading
margins in 2007 as a result of natural gas market volatility and the strengthening of the Canadian dollar relative to the U.S. dollar.

OM&A
costs for the year ended Dec. 31, 2008 increased $60 million compared to the same period in 2007 due to cost escalations, higher planned maintenance
costs, and increased compensation costs. In 2007, OM&A decreased $4 million compared to the same period in 2006 primarily due to reduced operational spending across the Generation fleet,
partially offset by the impact of the economic dispatch at Centralia Thermal in the second quarter of 2006, increased investment in our technological infrastructure, and higher stock compensation
costs.

For
the year ended Dec. 31, 2008, depreciation expense increased $22 million compared to the same period in 2007 due to increased capital spending, the
retirement of assets that were not fully depreciated as a result of planned maintenance activities, and the early retirement of certain components as a result of equipment modifications made at
Centralia Thermal. In 2007, depreciation decreased $4 million due to the impairment recorded in 2006 on turbines held in inventory and by lower depreciation as a result of the impairment of
the Centralia Gas-fired facility ("Centralia Gas") recorded in 2006.

For
the year ended Dec. 31, 2008, net interest expense decreased $23 million compared to the same period in 2007 primarily due to interest received on the
settlement of a tax issue and higher capitalized interest, partially offset by lower interest income from cash deposits. In 2007, net interest expense decreased $35 million mainly due to
lower long-term debt levels, higher interest income on cash deposits, and the strengthening of the Canadian dollar relative to the U.S. dollar.

For
the year ended Dec. 31, 2008, equity loss increased $47 million compared to the same period in 2007 due to the writedown of our Mexican investment in the
first quarter of 2008, partially offset by a tax expense recorded in 2007 as a result of changes in tax law in Mexico. In 2007, equity loss increased $33 million as a result
of changes in Mexican tax laws, lower margins, and higher interest expense as a result of refinancing these subsidiaries, partially offset by the recognition of deferred financing fees
in 2006.

.....................................................................................................................................................................
.......................................................

28TransAlta Corporation    Annual Report 2008

---



Income tax expense for the year ended Dec. 31, 2008 was comparable to the same period in 2007. In 2007, income taxes
increased $146 million compared to the same period in 2006 due to higher pre-tax earnings in 2007, lower benefits from tax rate reductions relating to prior periods, and tax
recoveries on the 2006 asset impairment and mine closure charges, partially offset by the recovery from resolution of uncertain tax positions in 2007. Adjusting for these items, the effective tax
rate for the year ended Dec. 31, 2008 was 21 per cent compared to 23 per cent in 2007, and 20 per cent in 2006.

Significant Events

Our consolidated financial results include the following significant events:

2008

Kent Hills Wind Farm

On Dec. 31, 2008, our 96 MW Kent Hills Wind Farm, which is located 30 kilometres southwest of Moncton, New Brunswick,
began commercial operations. This project was delivered on time and on budget.

Carbon Capture and Storage

On April 3, 2008, we announced an agreement with Alstom Canada to pilot chilled ammonia carbon capture technology at one of our Alberta
Thermal units, contingent on acquiring adequate industry and government support.

On
April 4, 2008, the Government of Canada announced a $125 million fund to support the development of CCS technologies from the oil sands and from
coal-fired electricity plants, and on July 8, 2008, the Alberta government announced its commitment to provide $2 billion in funding for the development of CCS technology.
These funding initiatives are key to accelerating CCS projects across Alberta and in particular, our chilled ammonia CCS pilot project with Alstom Canada. We have applied for funding support under
both of these programs.

On
Dec. 18, 2008, we announced the participation of TransCanada PipeLines Limited in our proposed development of Canada's first fully-integrated carbon capture and
storage project. When complete, the plant will be one of the largest CCS facilities in the world and the first to have an integrated underground storage system. The project will pilot Alstom
Canada's proprietary chilled ammonia carbon capture technology and will be designed to capture one megatonne of CO2 at one of our Alberta Thermal units. The CO2 will be used
for enhanced oil recovery as well as injected into a permanent geological storage site.

Debentures

On July 31, 2008, $100 million of debentures issued by TransAlta Utilities Corporation ("TAU") were redeemed by the holder of the
debentures at a price of $98.45 per $100 of notional amount. The debentures had been issued at a fixed interest rate of 5.49 per cent, maturing in 2023, and redeemable at the option of
the holder in 2008.

On
Oct. 10, 2008, $50 million of debentures issued by TAU were redeemed at a negotiated price. The debentures were originally issued at a fixed interest rate
of 5.66 per cent and were to mature in 2033.

As
of Dec. 12, 2008, TAU is no longer a reporting issuer.

Contract Negotiations with the International Brotherhood of Electrical Workers ("IBEW")

On July 18, 2008, being unable to reach an agreement with the IBEW representing our Alberta Thermal and Hydro employees, the Government of
Alberta approved our application to have the matter referred to a Disputes Inquiry Board. As part of this process, the ability of the IBEW to strike or for us to exercise a lockout was suspended.
Contract negotiations continued during this process with the assistance of a government-appointed mediator.

On
Sept. 19, 2008, the Disputes Inquiry Board concluded that union members at three of our facilities were required to vote in accordance with the original terms of
the Memorandum of Settlement. Discussions were held with the Labour Relations Board and the IBEW to determine a voting process and on Oct. 17, 2008, the IBEW membership at our Alberta Thermal
and Hydro facilities reached a settlement and voted to accept our revised offer and ratify the Memorandum of Settlement.

Genesee 3

On Oct. 10, 2008, the Genesee 3 plant, a 450 MW joint venture with EPCOR Utilities Inc. ("EPCOR") (225 MW net
ownership interest), experienced an unplanned outage as a result of a turbine blade failure. EPCOR, the plant operator, returned the unit to service on Nov. 18, 2008. As a result of the
event, fourth quarter total production was reduced by 210 GWh and gross margin decreased by $15 million.

2008 Management's Discussion and Analysis29

---



Mexican Business

On Oct. 8, 2008, we successfully completed the sale of our Mexican business to InterGen Global Ventures B.V. ("InterGen") for gross
proceeds of $334 million (U.S.$303.5 million). The sale included the plants at both facilities and all associated commercial arrangements.

The
actual net loss as a result of the sale was $62 million, which is calculated below:

Contractual proceeds




$
334Less: closing costs





(3
)Net proceeds excluding cash on hand of $1 million





331Book value of investment





420Loss before deferred foreign exchange losses





89Deferred foreign exchange losses on the net assets of the Mexican operations

$
147Deferred gains on financial instruments designated as hedges of the net assets
of the Mexican operations


(148
)Income tax expense on financial instruments


9Deferred foreign exchange losses





8Loss before income taxes




$
97Income tax recovery





35Net loss




$
62


The difference between the $65 million estimated loss on the sale of our Mexican business and the actual net loss of
$62 million is due to an increase in earnings of our Mexican assets between the first quarter and the completion of the sale. The gross charge of $97 million is recorded in
equity loss.

LS Power and Global Infrastructure

On July 18, 2008, we received a non-binding letter from LS Power Equity Partners, an entity associated with Luminus
Management LLC, and Global Infrastructure Partners regarding engaging in a dialogue about a possible acquisition of TransAlta.

On
Aug. 6, 2008, the Board of Directors unanimously concluded that the proposal undervalued the company and was not in the best interest of TransAlta and its
shareholders. The Board made its determination following a detailed and comprehensive review by a special committee of independent directors and based on advice from financial and
legal advisors.

On
Oct. 7, 2008, LS Power Equity Partners and Global Infrastructure Partners announced that their proposal set out in the letter on July 18, 2008 had
been withdrawn.

Potential Breach of Keephills Ash Lagoon

On July 26, 2008, we detected a crack in the dyke wall at our Keephills ash lagoon. We immediately notified Alberta Environment and the
local authorities, and began taking measures to control and mitigate the effects of any potential breach and release of water from the lagoon. A series of dykes were constructed at the Keephills ash
lagoon site and the risk associated with the potential breach was successfully mitigated.

Expansion at Summerview

On May 27, 2008, we announced a 66 MW expansion at our Summerview wind farm located in southern Alberta near Pincher Creek. The total
capital cost of the project is estimated at $123 million with commercial operations expected to commence by the first quarter of 2010.

Bond Offering

On May 9, 2008, we completed an offering of U.S.$500 million of 6.65 per cent senior notes due in 2018. The net
proceeds from the offering were used for debt repayment, financing of our long-term investment plan, and for general corporate purposes.

Normal Course Issuer Bid ("NCIB") Program

On May 5, 2008, we announced plans to renew our NCIB program until May 5, 2009. We received the approval to purchase, for
cancellation, up to 19.9 million of our common shares representing 10 per cent of our 199 million common shares issued and outstanding as at April 23, 2008. Any
purchases undertaken will be made on the open market through the TSX at the market price of such shares at the time of acquisition.

30TransAlta Corporation    Annual Report 2008

---



For
the year ended Dec. 31, 2008, we purchased 3,886,400 shares (2007  2,371,800 shares) at an average price of
$33.46 per share (2007  $31.59 per share). The shares were purchased for an amount higher than their weighted average book value of $8.95 per share
(2007  $8.92 per share) resulting in a reduction of retained earnings of $95 million (2007  $54 million).

Year ended Dec. 31


2008


2007Total shares purchased


3,886,400


2,371,800Average purchase price per share

$
33.46

$
31.59Total cost

$
130

$
75Weighted average book value of shares cancelled


35


21Reduction to retained earnings

$
95

$
54


Given the current unprecedented level of volatility in the financial markets, we have decided to suspend purchases under our NCIB
program at this time in order to maintain maximum financial flexibility. We will re-evaluate financial market conditions throughout 2009 to determine the best use of cash resources
going forward.

Uprate at Sundance Facility

On April 21, 2008, we announced a 53 MW efficiency uprate at Unit 5 of our Sundance facility. The total capital cost of the project
is estimated at $75 million with commercial operations expected to commence by the end of 2009.

Greenhouse Gas Emissions

March 31, 2008 marked the deadline for the first compliance year with Alberta's Specified Gas Emitters Regulations for GHG reductions.
Compliance was required for GHGs emitted from the implementation date of July 1, 2007 to Dec. 31, 2007. Affected firms were required to reduce their emissions intensity by
12 per cent annually from an emissions baseline averaged over 2003-2005. For our operations not covered under PPAs, we complied through the delivery to government of
purchased emissions offsets, acquired at a competitive cost below the $15 per tonne cap. For Alberta plants having PPAs, we were also responsible for compliance, and the approach was coordinated
with PPA Buyers such that a mix of Buyer-supplied offsets and contributions to the Alberta Technology Fund at $15 per tonne were used. The PPAs contain change-in-law
provisions that allow us to recover compliance costs from the PPA customers.

Dividend Policy and Dividend Increase

On Feb. 1, 2008, the Board of Directors declared a quarterly dividend of $0.27 per share on common shares. This represented an increase of
$0.02 per share to the quarterly dividend which on an annual basis yielded $1.08 per share versus $1.00.

On
March 25, 2008, the Board of Directors announced the adoption of a formal dividend policy that targets to pay shareholders an annual dividend in the range of 60
to 70 per cent of comparable earnings.1

Blue Trail Wind Power Project

On Feb. 13, 2008, we announced plans to design, build, and operate Blue Trail, a 66 MW wind power project in southern Alberta. The
capital cost of the project is estimated at $115 million. Commercial operations are expected to commence in the fourth quarter of 2009.

2007

Tax Rate Change

On Dec. 14, 2007, Bill C-28 received Royal Assent, lowering the federal corporate income tax rate to
15 per cent by 2012. These are further rate reductions from the ones included in Bill C-52, which received Royal Assent on June 22, 2007. A total of
$48 million of future income tax benefit was recorded in 2007.

TransAlta Power, L.P.

On Dec. 6, 2007, Stanley Power, an indirect wholly owned subsidiary of Cheung Kong Infrastructure Holdings Limited, announced that it had
paid for and acquired all of the limited partnership units of TransAlta Power, L.P. at the price of $8.38 in cash per unit. The transaction was valued at approximately $629 million.
This transaction had no material impact on us.

Ottawa Power Purchase Agreement

On Oct. 12, 2007, we signed an agreement amending our original PPA with the Ontario Electricity Financial Corporation ("OEFC") for the
Ottawa Cogeneration Power Plant. The agreement was entered into to ensure continued plant operations following the expiry of long-term natural gas supply contracts. The agreement will be
in effect from Nov. 1, 2007 until Dec. 31, 2012.

Mexico Tax Reform

On Oct. 1, 2007, the Mexican government enacted law replacing the existing asset tax with a new flat tax starting Jan. 1, 2008. The
flat tax is a minimum tax whereby the greater of income tax or flat tax is paid. In computing the flat tax, only 50 per cent of the undepreciated tax balance of certain capital assets
acquired before Sept. 1, 2007 is deductible over 10 years. In addition, no deduction or credit is permitted in respect of interest expense, and net operating losses for income taxes as
at Dec. 31, 2007 cannot be carried forward to shelter flat tax. We recorded a $28 million charge in equity losses as a result of this change.

.....................................................................................................................................................................
.......................................................

2008 Management's Discussion and Analysis31

---





NCIB Program

On Sept. 11, 2007, we announced an expansion of our NCIB program under which we could purchase, for cancellation, up to 20.2 million
of our common shares or approximately 10 per cent of the 202.0 million common shares issued and outstanding as at April 23, 2007. The 2007 NCIB program started on
May 3, 2007 and continued until May 2, 2008. Purchases were made on the open market through the TSX at the market price of such shares at the time of acquisition.

For
the year ended Dec. 31, 2007, we purchased 2,371,800 shares at an average price of $31.59 per share. This purchase price was in excess of the weighted
average book value of $8.92 per share, resulting in a reduction to retained earnings of $54 million.

New Brunswick Power Purchase Agreement

On Jan. 19, 2007, we announced a 25-year contract with New Brunswick Power Distribution and Customer Service Corporation
("New Brunswick Power") to provide 96 MW of wind power in New Brunswick ("Kent Hills"). We constructed, own and operate the Kent Hills facility for which commercial operations
began on December 31, 2008. Total capital costs for the construction of Kent Hills were approximately $170 million. On July 17, 2007, we signed a purchase and sale
agreement with Vector Wind Energy, a wholly owned subsidiary of Canadian Hydro Developers Inc., for its Fairfield Hill wind power site.

Natural
Forces Technologies Inc. has an option to purchase up to 17 per cent of the Kent Hills project within 180 days from Dec. 31,
2008, the commencement of commercial operations.

Sundance Unit 4 Uprate

During 2007, we completed an uprate on Unit 4 of our Sundance facility that added 53 MW of capacity to this facility.

Greenhouse Gas Emissions Standards

Effective July 1, 2007, theClimate Change and Emissions Management Amendment Actwas
enacted into law in Alberta. Under the legislation, baselines and targets for GHG emissions intensity are set on a facility-by-facility basis. The legislation requires a
12 per cent reduction in carbon emission intensity over a baseline for the period 2003 to 2005, established as at Dec. 31, 2007. New facilities or those in operation for less
than three years are exempt; however, upon the fourth year of operations, the facility baseline is established and gradually reduces by year of operation until the eighth year, by which emissions
must be 12 per cent below the established baseline. Emissions over the baseline are subject to a charge that must be paid annually. The PPAs for our Alberta-based coal facilities
contain change-in-law provisions that allow us to recover most compliance costs from the PPA customers. After flow-through, the net compliance costs are estimated
to be approximately $5 million per year until we are able to meet the targets for GHG emissions under the Act.

Dragline Deposit

On June 21, 2007, TAU entered into an agreement with Bucyrus Canada Limited and Bucyrus International Inc. for the purchase of a
dragline to be used primarily in the supply of coal for the Keephills 3 joint venture project. The total dragline purchase costs are approximately $150 million, with final payments for
goods and services due by May 2010. The total payments made under this agreement in 2007 were $18 million.

Keephills 3 Power Plant

On Feb. 26, 2007, we announced that we would be building the 450 MW Keephills 3 coal-fired power plant. The plant
is being developed jointly by EPCOR and by us. The capital cost of the project is expected to be approximately $1.7 billion, including associated mine capital, and is anticipated to begin
commercial operations in the first quarter of 2011. We own a 50 per cent interest in this unit.

2006

Centralia Coal Mine

On Nov. 27, 2006, we ceased mining activities at our Centralia coal mine as a result of increased costs and unfavourable geological
conditions. Inventory extracted up to the date on which we ceased operations was mostly consumed throughout 2007. Coal requirements for the foreseeable future are expected to be sourced from coal
imported from the PRB. In 2007, we reduced production at the plant by approximately 2,500 GWh. We completed the Unit 2 boiler modifications at Centralia Thermal in the second quarter
of 2008 and Unit 1 boiler modifications are scheduled to begin in the spring of 2009.

We
incurred an after-tax charge of $154 million ($0.76 per share) due to asset and inventory writedowns, reclamation liabilities, severance costs and
other charges.

32TransAlta Corporation    Annual Report 2008

---



As
required by GAAP, the restructuring charges appear on their appropriate lines on the Statements of Earnings. These have been summarized in the following table and are
described below:

Writedown of coal inventory

$
44Impact on gross margin


(44
)Mine closure chargesMine equipment and infrastructure writedown

$
72ARO writedown


81Severance costs and other


39Total mine closure charges


192Loss before income taxes

$
(236
)Income tax recovery


82Net loss impact of event

$
(154
)


Writedown of Coal Inventory

Since all coal requirements are now being sourced from an external source, the existing internally produced coal
inventory was written down to fair market value, which was the current PRB cost at the time of cessation of mining activities.

Mine Equipment and Infrastructure Writedown

Mine equipment was valued at the lower of current net book value and fair value. The majority of this equipment was
anticipated to be sold in 2007. Mining infrastructure, which includes processing facilities, was also written down to its expected fair values.

ARO Writedown

The unamortized cost of future reclamation expenses was recognized immediately.

Severance Costs and Other

This includes salaries payable to employees, estimated benefit obligations, other transition payments as a result of the
closure, amounts accrued for estimated contract termination penalties, and writedown of materials and supplies. These costs were paid in 2007 for a total of $24 million with the difference
between this amount and the amount above of $39 million due to the strengthening of the Canadian dollar relative to the U.S. dollar.

Further,
since Centralia Thermal was not operating at full capacity in 2007 and 2008, certain contracts were no longer backed by physical production at the plant and
therefore no longer qualified for hedge accounting. Therefore, under GAAP, we recorded these contracts at fair value and as a result of differences between market prices at that time and those of
the contracts, recognized mark-to-market gains on these contracts. As well, we entered into additional contracts to offset some of this exposure and recorded these contracts
at fair market value. As a result, on a net basis, based on current forward price estimates at that time, we recorded mark-to-market gains of $35 million. These
mark-to-market adjustments, which are not included in the table above, had no cash impact on the 2006 financial statements, although the fair market value will continue to
change as market prices change until settlement occurs in future periods.

Centralia Gas Impairment

During our annual impairment review, we concluded that the full book value of our Centralia Gas facility was unlikely to be recovered from future
cash flows due to changes in our outlook for the plant's profitability based on market dispatch rates and trading values. As a result, we recorded an $84 million after-tax ($0.42
per share) impairment charge to write the plant down to fair value.

Notice of Preferred Securities Redemption

On Nov. 22, 2006, we announced our intention to redeem all of our 7.75 per cent Preferred Securities, which had an aggregate
principal of $175 million. We redeemed these securities on Jan. 2, 2007.

Designation of Eligible Dividends

Under the 2007 legislation enacted by the Department of Finance, Canadian residents are entitled to a higher gross-up and dividend tax
credit in 2006 and subsequent years if they receive eligible dividends. The dividends paid by us during 2006, 2007 and 2008 are eligible dividends.

Amendment to Dividend Reinvestment and Share Purchase ("DRASP") Plan

On Oct. 20, 2006, we announced that effective Jan. 1, 2007, we were amending and thereby removing the five per cent discount
on the price of shares purchased through the DRASP plan and suspending the issuance of shares from treasury. Instead, shares purchased under the DRASP plan are acquired in the open market at
100 per cent of the average purchase price of common shares acquired on the TSX on the investment dates. Shares issuable under the DRASP plan have not been registered under any
U.S. Federal or State Securities laws and U.S. persons or residents are not eligible to participate in the DRASP plan.

Wabamun Outage

In 2005, an oil spill at Lake Wabamun, Alberta forced us to shut down unit four of our Wabamun coal-fired plant for 39 days. In
the fourth quarter of 2006, we settled a portion of our outstanding claim for lost margin and incremental expenses. The terms of the settlement are subject to a confidentiality agreement. The
settlement is included in merchant revenues.

Sarnia Power Plant

On Feb. 15, 2006, we signed a five-year contract with the Ontario Power Authority for our Sarnia Regional Cogeneration Power
Plant to supply an average of 400 MW of electricity to the Ontario electricity market. The contract was effective Jan. 1, 2006.

2008 Management's Discussion and Analysis33

---



Centralia Thermal Reduced Production and Economic Dispatch

Due to heavy rainfall in the Pacific Northwest in the first quarter of 2006, we derated Centralia Thermal and started rebuilding our coal
inventory. The impact of derating the plant during this time was partially offset by increasing coal imports and purchasing replacement power. We experienced 875 GWh of lower production
during the first quarter of 2006 compared to the same period of 2005.

During
the second quarter of 2006, lower market prices allowed us to purchase power at a price lower than our variable cost of production. As a result, Centralia Thermal
did not operate for the majority of the second quarter. We experienced 1,936 GWh of lower production during the second quarter compared to the same period of 2005.

In
the third quarter of 2006, the 702 MW unit 2 experienced a turbine blade failure. As a result of the event, total production was reduced by
727 GWh. Also, in the third quarter of 2006, higher unplanned outages resulted in 232 GWh of lower production.

In
the fourth quarter of 2006, 358 GWh of production at Centralia Thermal was lost as a result of PRB coal test burns at the plant.

For
the year ended Dec. 31, 2006, as a result of the above-mentioned events, total production at Centralia was 4,128 GWh lower than in 2005.

Purchase of Wailuku River Hydroelectric L.P.

On Feb. 17, 2006, we purchased a 50 per cent interest in Wailuku River Hydroelectric L.P. through Wailuku Holding
Company, LLC ("Wailuku") for cash of U.S.$1 million (CDN$1.2 million). Wailuku had debt of U.S.$19 million (CDN$22 million) at the time of acquisition. Wailuku
owns a run-of-river hydro facility in Hawaii with an operating capacity of 10 MW. MidAmerican Energy Holdings Company ("MidAmerican") owns the other
50 per cent interest in Wailuku.

Change in Depreciation Rate

In the first quarter of 2006, we changed the depreciation method of the Windsor-Essex, Mississauga, Ottawa, Meridian, and Fort Saskatchewan plants.
Previously, these plants were amortized on a unit-of-production method over the life of the plants. After reviewing the estimated useful life and considering the uncertainty
for the plants' operations beyond the terms of the current sales contracts, we determined that it was more reasonable to allocate the remaining net book value of the plants on a
straight-line basis over the remaining term of the respective contracts. This increase in depreciation is offset by a reduction in earnings attributable to the
non-controlling interests in our consolidated statement of earnings.

Keephills 3 Project

On March 14, 2006, we signed a development agreement with EPCOR to jointly examine the development of the Keephills 3 power project,
a proposed 450 MW supercritical coal-fired plant adjacent to our existing Keephills facility.

2006 Federal and Alberta Budgets

On May 24, 2006, the Alberta budget received Royal Assent. As a result, the general corporate income tax rate for Alberta was reduced from
11.5 per cent to 10 per cent effective April 1, 2006. The federal budget received Royal Assent on June 22, 2006. As a result, the general corporate federal
tax rate is to be reduced from 21 per cent to 19 per cent by Jan. 1, 2010. The corporate surtax was eliminated for taxation years ended after Dec. 31, 2007
and the federal capital tax has been eliminated effective Jan. 1, 2006. The carry-forward period for non-capital losses and investment tax credits earned after 2005 was extended
from 10 to 20 years. As a result of these changes, we reduced income tax expense by $55 million.

Subsequent Events

Sundance Unit 4 Derate

On Feb. 10, 2009, we reported the first quarter financial impact of an extended derate at Unit 4 of our Sundance thermal plant ("Unit 4").
The facility experienced an unplanned outage in December 2008 related to the failure of an induced draft ("ID") fan. At that time, Unit 4, which has a capacity of 406 MW, had
been derated to approximately 205 MW. The repair of the ID fan components by the original equipment manufacturer took longer than planned, and therefore, Unit 4 did not return to full
service until Feb. 23, 2009. As a result of the extended derate, first quarter production was reduced by 328 GWh and net income declined by $17 million.

We
have given notice of a High Impact Low Probability Event to the PPA Buyer and the Balancing Pool, which if successful, will protect us from the financial loss and
related penalties. The available penalties that we would expect to recover in net income are anticipated to be $14 million.

Keephills Units 1 and 2 Uprates

On Jan. 29, 2009, we announced a 46 MW (23 MW per unit) efficiency uprate at Unit 1 and Unit 2 of our Keephills facility. The
total capital cost of the project is estimated at $68 million with commercial operations expected to commence by the end of 2011 and 2012, respectively.

Dividend Increase

On Jan. 28, 2009, our Board of Directors declared a quarterly dividend of $0.29 per share on common shares, an increase of $0.02 per share,
which on an annual basis will yield $1.16 per share versus $1.08.

Carbon Capture and Storage

On Jan. 27, 2009, the Government of Canada announced in the 2009 federal budget an additional $850 million of funding that has been
earmarked to support the development of CCS technologies. The impact of this announcement on us cannot be reasonably determined at this time because specific information regarding the use,
distribution timelines, and recipients of the funding have not been clarified by the government.

34TransAlta Corporation    Annual Report 2008

---



Discussion of Segmented Results

GENERATION:Owns and operates hydro, wind, geothermal, natural gas- and coal-fired plants and related mining operations in
Canada, the U.S., and Australia. Generation's revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support. At
Dec. 31, 2008, Generation had 8,482 MW of gross generating capacity1 in operation (8,073 MW net ownership interest) and 456 MW net under construction. For a
full listing of all of our generating assets and the regions in which they operate, refer to page 18 of this Annual Report.

During 2008, we completed the Kent Hills wind farm in New Brunswick that added 96 MW of generating capacity.
Kent Hills operates under a PPA with New Brunswick Power.

We
have strategic alliances with EPCOR, ENMAX Corporation ("ENMAX"), and MidAmerican. The EPCOR alliance provided the opportunity for us to acquire a
50 per cent ownership in the 450 MW Genesee 3 project and to build the Keephills 3 project. ENMAX and our Company each own 50 per cent of the
partnership in the McBride Lake wind project. MidAmerican owns the other 50 per cent interest in CE Gen and Wailuku.

Our
results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are usually 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. Margins are also typically impacted in the second quarter due
to the volume of hydro production resulting from spring runoff and rainfall in the Canadian and U.S. markets.

The
results of the Generation segment are as follows:

2008


2007


2006Year ended Dec. 31


Total


Per installed
MWh
2

Total


Per installed
MWh
2

Total


Per installed
MWh
2Revenues

$
3,005

$
40.63

$
2,720

$
37.03

$
2,612

$
35.64Fuel and purchased power


(1,493
)

(20.18
)

(1,231
)

(16.76
)

(1,186
)

(16.19
)Gross margin


1,512


20.45


1,489


20.27


1,426


19.45Operations, maintenance and administration


487


6.58


447


6.08


458


6.25Depreciation and amortization


409


5.53


391


5.33


397


5.42Taxes, other than income taxes


19


0.26


20


0.27


21


0.29Intersegment cost allocation


30


0.41


27


0.37


28


0.38Operating expenses


945


12.78


885


12.05


904


12.34Operating income before mine closure and asset impairment charges3


567


7.67


604


8.22


522


7.11Mine closure charges














192


2.62Asset impairment charges














130


1.77Operating income

$
567

$
7.67

$
604

$
8.22

$
200

$
2.72Installed capacity (GWh)


73,969





73,447





73,287Production (GWh)


48,891





50,395





48,213Availability (%)


85.8





87.2





89.0


.........................................................................................................................................................................................................................................
.....................................

2008 Management's Discussion and Analysis35

---





Generation Production and Gross Margins

Generation's production volumes, electricity and steam production revenues, and fuel and purchased power costs are presented below, based on
geographical regions.

Year ended Dec. 31, 2008


Production
(GWh
)

Installed
(GWh
)

Revenue


Fuel &
purchased
power


Gross
margin


Revenue
per
installed
MWh
1

Fuel &
purchased
power per
installed
MWh
1

Gross
margin per
installed
MWh
1Western Canada


32,364


46,096

$
1,314

$
525

$
789

$
28.51

$
11.39

$
17.12Eastern Canada


3,290


7,194


501


351


150


69.64


48.79


20.85International


13,237


20,679


1,190


617


573


57.55


29.84


27.7148,891


73,969

$
3,005

$
1,493

$
1,512

$
40.63

$
20.18

$
20.45




Year ended Dec. 31, 2007


Production
(GWh
)

Installed
(GWh
)

Revenue


Fuel &
purchased
power


Gross
margin


Revenue
per
installed
MWh
1

Fuel &
purchased
power per
installed
MWh
1

Gross
margin per
installed
MWh
1Western Canada


33,398


45,385

$
1,302

$
449

$
853

$
28.69

$
9.90

$
18.79Eastern Canada


3,775


7,173


443


303


140


61.75


42.19


19.56International


13,222


20,889


975


479


496


46.66


22.92


23.7450,395


73,447

$
2,720

$
1,231

$
1,489

$
37.03

$
16.76

$
20.27




Year ended Dec. 31, 2006


Production
(GWh
)

Installed
(GWh
)

Revenue


Fuel &
purchased
power


Gross
margin


Revenue
per
installed
MWh
1

Fuel &
purchased
power per
installed
MWh
1

Gross
margin per
installed
MWh
1Western Canada


33,501


45,238

$
1,291

$
403

$
888

$
28.55

$
8.90

$
19.65Eastern Canada


3,353


7,174


454


300


154


63.23


41.87


21.36International


11,359


20,875


867


483


384


41.53


23.14


18.3948,213


73,287

$
2,612

$
1,186

$
1,426

$
35.64

$
16.19

$
19.45


Western Canada

Our Western Canada assets consist of five coal facilities, three natural gas-fired facilities, 13 hydro facilities, and three
wind farms with a total gross generating capacity of 5,224 MW (4,937 MW net ownership interest). We are currently constructing a 450 MW (225 MW net ownership interest)
merchant thermal plant at our Keephills facility under a joint venture with EPCOR, which is scheduled to enter commercial production in 2011. We are also currently constructing two wind
farms, Summerview 2 and Blue Trail, in southern Alberta. Each farm will have a generating capacity of 66 MW. Blue Trail is scheduled to enter commercial production in 2009 and Summerview
2 is scheduled to enter commercial production in 2010.

Our
Sundance, Keephills, and Sheerness plants and hydro facilities operate under PPAs with a gross generating capacity of 4,030 MW (3,835 MW net ownership
interest). Under the PPAs, we earn monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for our plants and mines. We also earn energy payments for the
recovery of predetermined variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability, and an excess energy payment for power production above
committed capacity. Additional capacity added to these units that is not included in capacity covered by the PPAs is sold on the merchant market.

Our
Wabamun, Genesee 3, Summerview, and a portion of our Poplar Creek facilities sell their production on the merchant spot market. In order to manage our exposure
to changes in spot electricity prices as well as capture value, we contract a portion of this production to guarantee cash flows.

Due
to their close physical proximity, three of our coal-fired plants, Sundance, Keephills, and Wabamun, are operated and managed collectively and are referred to as
"Alberta Thermal."

Our
Castle River, McBride Lake, Meridian, Fort Saskatchewan, and a significant portion of our Poplar Creek assets earn revenues under long-term contracts for
which revenues are derived from payments for capacity and/or the production of electrical energy and steam as well as for ancillary services. These contracts are for an original term of at least ten
years and payments do not fluctuate significantly with changes in levels of production.

For
the year ended Dec. 31, 2008, production decreased 1,034 GWh compared to 2007 due to higher unplanned outages at Alberta Thermal and Genesee 3,
partially offset by increased merchant production resulting from the Unit 4 uprate at our Sundance facility.

In
2007, production decreased 103 GWh compared to 2006 due to higher unplanned outages at Alberta Thermal, partially offset by increased customer demand at Fort
Saskatchewan, increased hydro production, and lower planned outages at Alberta Thermal.

.....................................................................................................................................................................
.......................................................

36TransAlta Corporation    Annual Report 2008

---



Gross margin for the year ended Dec. 31, 2008 decreased $64 million ($1.67 per installed MWh) compared to the same
period in 2007 due to higher unplanned outages at Alberta Thermal and Genesee 3, and higher coal costs, partially offset by favourable pricing and higher merchant volumes due to the uprate on
Unit 4 of our Sundance facility.

In
2007, gross margin decreased $35 million ($0.86 per installed MWh) compared to 2006 due to higher coal costs, higher unplanned outages at Alberta Thermal, and
lower prices, partially offset by lower planned outages at Alberta Thermal and higher excess energy due to the uprate on Unit 4 of our Sundance facility.

Eastern Canada

Our Eastern Canada assets consist of four natural gas-fired facilities and one wind farm with a total gross generating capacity of
915 MW (793 MW net ownership interest). All four natural gas-fired facilities earn revenue under long-term contracts for which revenues are derived from
payments for capacity and/or the production of electrical energy and steam. Kent Hills, a 96 MW wind farm located in New Brunswick, began commercial operations on
Dec. 31, 2008.

For
the year ended Dec. 31, 2008, production decreased 485 GWh compared to the same period in 2007, primarily due to higher planned outages and lower market
heat rates at Sarnia.

In
2007, production increased 422 GWh compared to 2006 primarily as a result of favourable market conditions, higher customer demand and lower planned maintenance
at Sarnia and increased production at Ottawa due to natural gas sales in the first quarter of 2006.

For
the year ended Dec. 31, 2008, gross margins were comparable to the same period in 2007. In 2007, gross margins decreased $14 million ($1.80 per installed
MWh) compared to 2006 as a result of lower gas sales at Ottawa.

International

Our international assets consist of natural gas, coal, hydro, and geothermal assets in various locations in the United States with a
generating capacity of 2,043 MW and natural gas- and diesel-fired assets in Australia with a generating capacity of 300 MW. 385 MW of our United States assets
are operated by CE Gen, a joint venture owned 50 per cent by us.

Our
Centralia Thermal, Centralia Gas, Power Resources, Skookumchuck, and one unit of our Imperial Valley assets are merchant facilities. To reduce the volatility and risk
in merchant markets, we use a variety of physical and financial hedges to secure prices received for electrical production. The remainder of our international facilities operate under
long-term contracts.

For
the year ended Dec. 31, 2008, production increased 15 GWh compared to the same period in 2007 due to lower unplanned outages and lower derates at
Centralia Thermal (in 2007 we conducted test burns of PRB coal), partially offset by higher planned outages as a result of equipment modifications made at Centralia Thermal and economic dispatching
at Centralia Thermal in the second quarter.

In
2007, production increased 1,863 GWh compared to 2006 due to lower unplanned outages combined with higher production at Centralia Thermal due to the facility
being economically dispatched in the second quarter of 2006, partially offset by lower production at Centralia Gas.

For
the year ended Dec. 31, 2008, gross margins increased $77 million ($3.97 per installed MWh) compared to the same period in 2007 primarily due to
favourable pricing and mark-to-market movements.

In
2007, gross margins increased $112 million ($5.35 per installed MWh) due to favourable market and contractual pricing and increased production at Centralia
Thermal, the writedown of inventory related to the cessation of mining activities of the Centralia coal mine in 2006, and lower coal costs at Centralia Thermal, partially offset by
mark-to-market losses in 2007 versus mark-to-market gains in 2006 and the strengthening of the Canadian dollar compared to the U.S. dollar.

Operations, Maintenance, and Administration

For the year ended Dec. 31, 2008, OM&A expenses increased $40 million compared to the same period in 2007 due to cost escalations and
higher planned maintenance costs.

In
2007, OM&A expense decreased by $11 million primarily due to lower operational spending and planned maintenance expenditures, partially offset by savings
realized from the economic dispatch at Centralia Thermal in the second quarter of 2006.

Planned Maintenance

The table below shows the amount of planned maintenance capitalized and expensed, excluding CE Gen:

Year ended Dec. 31


2008


2007


2006Capitalized

$
125

$
78

$
84Expensed


68


54


56$
193

$
132

$
140GWh lost


3,478


2,056


2,325


Production lost as a result of planned maintenance in the year ended Dec. 31, 2008 increased by 1,422 GWh primarily
due to the Unit 2 boiler modifications at Centralia Thermal. Production lost in 2007 decreased by 269 GWh from 2006 due to reduced planned outages across the fleet.

For
the year ended Dec. 31, 2008, total capitalized and expensed maintenance costs increased compared to 2007 due to the Unit 2 boiler modifications at
Centralia Thermal, higher planned outages across the fleet and cost escalations. Total capital and expensed maintenance

2008 Management's Discussion and Analysis37

---



costs
decreased in 2007 compared to the same period in 2006 primarily due to lower planned maintenance activity at our gas-fired facilities.

Depreciation Expense

For the year ended Dec. 31, 2008, depreciation expense increased $18 million compared to the same period in 2007 due to increased
capital spending, the retirement of assets that were not fully depreciated as a result of planned maintenance activities, and the early retirement of certain components as a result of equipment
modifications made at Centralia Thermal.

In
2007, depreciation expense decreased $6 million compared to 2006 due to the impairment recorded in 2006 on turbines held in inventory, lower depreciation at
Centralia Gas, and the strengthening of the Canadian dollar versus the U.S. dollar, partially offset by the recording of ARO accretion at the Centralia coal mine, increased depreciation as a
result of capital spending in 2006, and reduced life of certain parts at Centralia Thermal.

For
active mines, accretion expense related to ARO is included in cost of sales. However, the Centralia coal mine is currently considered to be inactive and accretion
expense is therefore now recorded in depreciation expense. Accretion expense of $9 million and $10 million related to the Centralia coal mine was recorded in depreciation for the years
ended Dec. 31, 2008 and 2007, respectively. Accretion expense of $9 million was recorded in cost of sales for the year ended Dec. 31, 2006.

COMMERCIAL OPERATIONS & DEVELOPMENT ("COD"):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 COD's trading activities.

COD is responsible for the management of commercial activities for our current generating assets. COD also manages available
generating capacity as well as the fuel and transmission needs of the Generation business by utilizing contracts of various durations for the forward sales of electricity and for the purchase of
natural gas, coal, and transmission capacity. Further, COD is responsible for developing or acquiring new cogeneration, wind, geothermal, and hydro generating assets and making portfolio
optimization decisions. The results of all of these activities are included in the Generation segment.

Our
trading activities utilize a variety of instruments to manage risk, earn trading revenue, and gain market information. Our trading strategies consist of
shorter-term physical and financial trades in regions where we have assets and the markets that interconnect with those regions. The portfolio primarily consists of physical and
financial derivative instruments including forwards, swaps, futures, and options in various commodities. These contracts meet the definition of trading activities and have been accounted for at fair
value under Canadian GAAP. Changes in the fair value of the portfolio are recognized in income in the period they occur.

While
trading products are generally consistent between periods, positions held and resulting earnings impacts will vary due to current and forecasted external market
conditions. Positions for each region are established based on the market conditions and the risk/reward ratio established for each trade at the time it is transacted. Results will therefore vary
regionally or by strategy from one reported period to the next.

A
portion of OM&A costs incurred within COD is allocated to the Generation segment based on an estimate of operating expenses and an estimated percentage of resources
dedicated to providing support and analysis. This fixed fee intersegment allocation is represented as a cost recovery in COD and an operating expense within Generation.

The
results of the COD segment, with all trading results presented net, are as follows:

Year ended Dec. 31


2008


2007


2006Gross margin

$
105

$
55

$
65Operations, maintenance and administration


53


34


37Depreciation and amortization


3


1


1Intersegment cost allocation


(30
)

(27
)

(28
)Operating expenses


26


8


10Operating income

$
79

$
47

$
55


For the year ended Dec. 31, 2008, gross margins increased $50 million compared to the same period in 2007 due to
increased margins across all markets. As at Dec. 31, 2008, substantially all of these positions had been settled.

For
the year ended Dec. 31, 2007, gross margins decreased $10 million compared to the same period in 2006 due to decreased natural gas and eastern region
trading margins as a result of natural gas market volatility and the strengthening of the Canadian dollar relative to the U.S. dollar.

For
the year ended Dec. 31, 2008, OM&A costs increased $19 million compared to the same period in 2007, from additional trading compensation as a result of
increased gross margins.

OM&A
costs for 2007 decreased $3 million due to lower incentive costs as a result of decreased margins as well as lower project consulting expenses.

The
inter-segment cost allocations increased slightly in 2008 due to an increase in the work performed on behalf of the Generation segment. The inter-segment cost
allocations in 2007 and 2006 were comparable.

38TransAlta Corporation    Annual Report 2008

---



Net Interest Expense

Year ended Dec. 31


2008


2007


2006Interest on long-term debt

$
147

$
145

$
154Interest on short-term debt


30


26


13Interest income from tax settlement


(30
)




Interest on preferred securities








14Interest income


(16
)

(32
)

(13
)Capitalized interest


(21
)

(6
)

Net interest expense

$
110

$
133

$
168


$30 million of reported interest income relates to refund interest received or due from taxation authorities for the
settlement of outstanding tax issues related to prior periods.

For
the year ended Dec. 31, 2008, net interest expense decreased $23 million compared to the same period in 2007 primarily due to interest income received on
the settlement of the tax issue discussed above, and higher capitalized interest, partially offset by lower interest income from cash deposits.

In
2007, net interest expense decreased $35 million compared to 2006 due to lower long-term debt balances, the strengthening of the Canadian dollar
relative to the U.S. dollar, the redemption of preferred securities, higher interest on cash deposits and interest capitalized related to assets under construction, partially offset by higher
short-term debt balances.

Gain on Sale of Assets

As a result of the decision to cease mining activities at the Centralia coal mine in 2006, all associated mining and
reclamation equipment was classified as being held for sale. All equipment was recorded at the lower of net book value or anticipated realized proceeds. These assets were included in the Generation
segment. In 2007, some of this equipment had been retained for reclamation activities and some was transferred to the Highvale mine for use in production of coal inventory. The equipment retained
was reclassified to property, plant, and equipment in 2008. The decision to retain equipment for use in reclamation activities at the Centralia coal mine and in operations at the Highvale mine, was
arrived at as the economics of retaining these assets was greater than the potential cash proceeds from their disposal.

During
2008, mining equipment with a net book value of $2 million related to the cessation of mining activities at the Centralia coal mine was sold for proceeds of
$7 million. For the year ended Dec. 31, 2007, we sold equipment with a recorded value of $31 million, received proceeds of $47 million, and recorded a pre-tax
gain of $16 million.

Non-Controlling Interests

We own 50.01 per cent of TA Cogeneration, L.P. ("TA Cogen"), which owns, operates, or has
an interest in five natural gas-fired and one coal-fired generating facility with a total gross generating capacity of 814 MW. A private investor owns the minority
interest in TA Cogen. Our CE Gen joint venture investment includes a 75 per cent ownership of Saranac, a 320 MW natural gas-fired cogeneration facility in
New York. Since we own a controlling interest in TA Cogen and Saranac, under Canadian GAAP, we consolidate the entire earnings, assets, and liabilities in relation to TA Cogen's
ownership of those assets. Non-controlling interests on the income statement and balance sheet relate to the earnings and net assets attributable to TA Cogen and Saranac that are
not owned by us. On the statement of cash flow, cash paid to the minority shareholders of TA Cogen and Saranac is shown as 'Distributions to subsidiaries' non-controlling
interests' in the financing section.

The
earnings attributable to non-controlling interests for the year ended Dec. 31, 2008 increased $13 million due to higher earnings at
TA Cogen and CE Gen.

In
2007, earnings attributable to non-controlling interests decreased $4 million due to lower margins at Sheerness and Ottawa, partially offset by
higher margins at Meridian.

Equity Loss

As required under Accounting Guideline 15, Consolidation of Variable Interest Entities, of the Canadian Institute of
Chartered Accountants ("CICA"), our Mexican operations were accounted for as equity subsidiaries. On Oct. 8, 2008, we successfully completed the sale of our Mexican operations to InterGen for
a sale price of $334 million. The sale included the plants at both facilities and all associated commercial arrangements. Refer to the Significant Events section for further
details.

The
table below summarizes key information from these operations.

Year ended Dec. 31


2008


2007


2006Availability (%)


97.5


92.7


90.8Production (GWh)


2,646


3,084


2,918Equity loss

$
(97
)
$
(50
)
$
(17
)Capital expenditures

$


$
1

$
10Operating cash flow

$
2

$
(3
)
$
(7
)Interest expense

$
13

$
27

$
32


2008 Management's Discussion and Analysis39

---





As at Dec. 31


2008


2007Total assets

$


$
451Total liabilities

$


$
369


For the year ended Dec. 31, 2008, availability increased due to lower planned and unplanned outages at Chihuahua and lower
unplanned outages at Campeche. In 2007, availability increased primarily due to lower planned outages at Campeche and Chihuahua and unplanned outages at Chihuahua.

As
a result of the sale of our Mexican business in 2008, total production decreased by 438 GWh compared to 2007. In 2007, production increased 166 GWh due to
higher customer demand at Chihuahua and lower planned outages at Campeche and Chihuahua.

For
the year ended Dec. 31, 2008, equity loss increased $47 million due to the writedown of our Mexican investment in the first quarter of 2008, partially
offset by a tax expense recorded in 2007 as a result of changes in tax law in Mexico.

As
described in the Significant Events section of this MD&A, on Oct. 1, 2007, the Mexican government enacted law introducing a flat tax system starting
Jan. 1, 2008, and as a result, we recorded a $28 million charge to equity losses and a corresponding reduction in investments reflecting the expected impact of this change in law
in 2007.

For
the year ended Dec. 31, 2007, equity loss increased $33 million due to the income tax expense described above, lower margins, and increased interest
costs as a result of refinancing these subsidiaries in 2006, partially offset by the recognition of deferred financing fees and the loss incurred on unwinding a cross-currency swap in 2006 related
to the refinancing.

Income Taxes

Income tax expense under GAAP is based on the earnings of the period, the jurisdiction in which the income is earned, and if
there are any differences between how pre-tax income is calculated under GAAP versus income tax law. Income tax rates and amounts differ based upon these factors. When calculating income
tax expense, if there is a difference from when an expense or revenue is recognized under either accounting or income tax rules, we make an estimate of when in the future this difference will no
longer be in effect and the anticipated income tax rate at that time. These items are deductible or taxable temporary differences. We base these tax rates upon the rates the government expects to be
in effect when these temporary differences reverse.

Therefore, when a government announces a change in future income tax rates, it will affect the anticipated income tax asset
or liability that will appear in our financial statements. We have seen several large reductions in future tax expense as a result of the Canadian government reducing future
tax rates.

A
reconciliation of income tax expense and effective tax rates is presented below:

Year ended Dec. 31


2008


2007


2006Earnings (loss) before income taxes per statement of earnings

$
258

$
329

$
(81
)Equity loss


(97
)

(50
)

(17
)Adjustments:Coal inventory writedown








44Mine closure charges








192Asset impairment charges








130Turbine impairment








10Earnings before income taxes, equity loss and other items

$
355

$
379

$
312Income tax expense excluding equity loss and other items


73


86


61Income tax recovery on one-time adjustments








(132
)Income tax recovery recorded on sale of equity investment


(35
)




Income tax recovery from settlement of tax positions


(15
)

(18
)

Change in tax rate related to prior periods





(48
)

(55
)Income tax expense (recovery) per financial statements

$
23

$
20

$
(126
)Effective tax rate (%)1


21


23


20


In 2008, we recorded a tax recovery of $35 million related to the sale of our Mexican business.

During
2008 and 2007, we settled certain taxation issues with the associated taxation authorities. As a result, we recorded a future income tax recovery of
$15 million and $18 million, respectively, related to these items.

As
a result of a reduction in Canadian corporate income tax rates expected to apply to future tax liabilities, income tax expense was reduced by $48 million for the
year ended Dec. 31, 2007. In 2006, this change in tax rates reduced income tax expense by $55 million.

Adjusting
for the items mentioned above, income tax expense decreased for the year ended Dec. 31, 2008 compared to the same period in 2007 due to lower
pre-tax income. In 2007, tax expense increased from the same period in 2006 due to an increase in pre-tax income earnings and the effect of the change in the mix of
jurisdictions in which pre-tax income is earned.

.....................................................................................................................................................................
.......................................................

40TransAlta Corporation    Annual Report 2008

---





Financial Position

The following chart outlines significant changes in the consolidated balance sheets from Dec. 31, 2007 to
Dec. 31, 2008:

Increase/
(Decrease)

Explanation of changeIncome taxes receivable

12

Tax recovery from current year provision offset by use of tax prepaymentsInventory

21

Higher inventory balances as a result of lower production and an increase in exchange ratesRestricted cash

(242
)
Return of fundsInvestments

(125
)
Disposal of equity investmentRisk management assets (current and long-term)

206

Price movementsProperty, plant, and equipment, net

904

Capital additions and the weakening of the Canadian dollar relative to the U.S. dollar, partially offset by depreciation expenseGoodwill

17

Weakening of the Canadian dollar compared to the U.S. dollarAssets held for sale, net

(29
)
Assets previously held for sale have been reclassified to property, plant, and equipmentOther assets

(18
)
Amortization and reclassification of certain costs to property, plant, and equipmentShort-term debt

(208
)
Net decrease in short-term debtAccounts payable and accrued liabilities

209

Timing of operational commitments and the weakening of the Canadian dollar compared to the U.S. dollarRecourse long-term debt (including current portion)

504

Issuance of long-term debt of U.S.$500 millionNon-recourse long-term debt (including current portion)

24

Weakening of the Canadian dollar compared to the U.S. dollar, partially offset by scheduled debt paymentsRisk management liabilities (current and long-term)

(59
)
Price movementsAsset retirement obligation (including current portion)

21

Increase in estimate and the weakening of the Canadian dollar compared to the U.S. dollar, partially offset by costs settledDeferred credits and other long-term liabilities

21

Receipt of funding from joint venture partnerNet future income tax liabilities (including current portions)

53

Tax effect on the decrease in net risk management liabilitiesNon-controlling interests

(27
)
Distributions in excess of earnings from TA CogenShareholders' equity

211

Net earnings and movements in AOCI, partially offset by shares redeemed under the NCIB and dividends declared


Financial Instruments

Financial instruments are used to manage our exposure to interest rates, commodity prices, currency fluctuations, as well as credit
and other market risks. We currently use physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps and options to achieve
our risk management objectives, which are described below. Financial instruments are accounted for using the fair value method of accounting. The initial recognition of fair value and subsequent
changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is not elected. Otherwise, these changes in fair value will not affect earnings until the
financial instrument is settled. The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as risk
management assets and liabilities.

We
have two types of financial instruments: (1) those that are used in the COD and Generation segments in relation to Energy Trading activities, commodity hedging
activities, and other contracting activities and (2) those used in the hedging of debt, projects, expenditures, and the net investment in self-sustaining foreign subsidiaries. The
majority of the Corporation's derivatives have quoted market prices on active exchanges or over-the-counter quotes available from brokers. However, some derivatives are not
traded on an active exchange or have contracts that extend beyond the time period for which market-based quotes are available, requiring us to use internal valuation techniques or models.

The
majority of our financial instruments and physical commodity contracts are recorded under normal purchase/normal sale accounting or qualify for, and are recorded
under, hedge accounting rules. As a result, for those contracts for which we have elected hedge accounting, no gains or losses are recorded through the statement of earnings as a result of
differences between the contract price and the current forecast of future prices until the period of settlement. We record the changes in value of these contracts through the

2008 Management's Discussion and Analysis41

---



Statement
of Other Comprehensive Income ("OCI"). When these contracts are settled, the value previously recorded in OCI is reversed and we receive the contracted cash amount for those contracts.

Under
hedge accounting rules we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting
can still be applied. For commodity contracts, this testing ensures that the amount of electricity we have contracted to supply or natural gas contracted to buy is still likely to be provided. For
financial instruments related to debt and projects, this testing ensures that the amount we have contracted to pay for long-term financing and capital projects has remained consistent in
terms of timing and amounts. All financial instruments are designed to ensure that future cash inflows and outflows are predictable. Where hedges are effective, that is, it is reasonable that we will
fulfill that contract without having to purchase commodities in the market, we continue the
accounting treatment described above. Where hedges areineffective, that is, we will be required to fulfill that contract with commodities purchased
in the market, these hedges, in total or in part, are considered ineffective. The ineffective portion is no longer recorded as a hedge and the changes in fair value are recorded in income and no
longer through OCI.

As
well, there are certain contracts in our portfolio that at their inception do not qualify for, or we have chosen not to elect, hedge accounting. For these contracts we
recognize mark-to-market gains and losses in the statement of earnings resulting from changes in forward prices compared to the price at which these contracts were
transacted. These changes in price alter the timing of earnings recognition, but do not affect the final settlement amount received. The fair value of future contracts will continue to fluctuate as
market prices change.

Our
financial instruments are categorized as fair value hedges, cash flow hedges, net investment hedges or non-hedges. These categories and their associated
accounting treatments are explained in further detail below.

Fair Value Hedges

Fair value hedges are used to offset the impact of fluctuations in the foreign currency and interest rates on various assets and liabilities.
Interest rate swaps are used to hedge exposures in the fair value of long-term debt caused by variations in market interest rates by fixing interest rates. Foreign exchange contracts are
used to hedge certain foreign currency denominated assets and liabilities. Based on the fair value of risk management assets and liabilities at Dec. 31, 2008, approximately
5 per cent of our financial instruments are fair value hedges.

All
gains or losses related to fair value hedges are recorded on the statement of earnings, which, in turn, are completely offset by the value of the gains or losses on
the fair value of the related debt instruments on the foreign currency denominated assets and liabilities. A summary of how fair value hedges are recorded in our financial statements is
as follows:

Event


Statement of
Earnings


OCI


Balance
Sheet


Cash
FlowEnter into contract1











Reporting date (marked-to-market)











Settle contract














Cash Flow Hedges

Cash flow hedges are categorized as project or commodity hedges and are used to offset foreign exchange and commodity price exposures on long-term
projects as a result of market fluctuations. These contracts have a
maximum duration of five years. Based on the fair value of risk management assets and liabilities at Dec. 31, 2008, approximately 94 per cent of our financial instruments are
cash flow hedges.

Project Hedges

Foreign currency forward contracts are used to hedge foreign exchange exposures resulting from anticipated contracts and firm commitments
denominated in foreign currencies. When project hedges qualify for, and we have elected to use hedge accounting, the gains or losses related to these contracts in the periods prior to settlement are
recorded in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. Upon settlement of the financial instruments, any gain or loss on the contracts is
included in the cost of the related asset and depreciated over the asset's estimated useful life.

A
summary of how project hedges are recorded in our financial statements is as follows:

Event


Statement of
Earnings


OCI


Balance
Sheet


Cash
FlowEnter into contract











Reporting date (marked-to-market)1











Roll-over into new contract











Settle contract














Commodity Hedges

Physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, and options are used primarily to
offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. When commodity hedges qualify for, and we have elected to use hedge accounting, the fair
value of the hedges is recorded in risk management assets or liabilities with changes in value being reported in OCI, up until the date of settlement. The fair value of the majority of our commodity
hedges are

42TransAlta Corporation    Annual Report 2008

---



calculated
using adjusted quoted prices from an active market and/or the input is validated by broker quotes. Upon settlement of these financial instruments, the amounts previously recognized in OCI
are reclassified to net earnings.

These
commodity contracts are designated as all-in-one hedges. However, unlike a typical financial instrument used in a hedging relationship that
results in a net settlement with the counterparty, these contracts will not likely result in a net cash outflow despite their fair value currently resulting in a liability on our balance sheet. For
contracts settled by physical delivery, we will physically deliver the electricity at the price fixed under the contract, and receive cash payment for that physical delivery. Any related cash flow
hedge after-tax losses will be offset by the notional fair value of the contract. If the all-in-one hedge contracts cannot be settled by physical delivery of the
underlying commodity they will be settled financially.

A
summary of how commodity hedges are recorded in our financial statements is as follows:

Event


Statement of
Earnings


OCI


Balance
Sheet


Cash
FlowEnter into contract1











Reporting date (marked-to-market)2











Settle contract














During the year, the change in the position of financial instruments to a net asset position is primarily a result of changes in
future prices on contracts in our Generation segment. Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding fair valuation techniques. Our risk
management profile and practices have not changed materially from Dec. 31, 2007.

In
limited circumstances, we may enter into commodity transactions involving non-standard features for which market-observable data is not available. These
transactions are defined under GAAP as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, therefore fair value is determined using
valuation models or upon internally developed assumptions or inputs. Our Level III fair values are determined using valuation techniques with inputs that are based on historical data such as
unit availability, transmission congestion, or demand profiles. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material
differences are disclosed in the notes to the financial statements. At Dec. 31, 2008, Level III instruments had a net carrying value of nil.

For
both project and commodity cash flow hedges, when we do not elect for hedge accounting, or the hedge is no longer effective and does not qualify for hedge accounting,
the gains or losses as a result of changes in prices or exchange rates related to these financial instruments are recorded through the statement of earnings in the period the gain or
loss occurs.

Net Investment Hedges

Cross-currency interest rate swaps, foreign currency forward contracts, and foreign currency debts are used to hedge exposure to changes in the
carrying values of our net investments in foreign operations having functional currencies other than the Canadian dollar. Foreign denominated expenses are also used to assist in managing foreign
currency exposures on earnings from self-sustaining foreign operations. Based on the fair value of risk management assets and liabilities at Dec. 31, 2008, approximately
one per cent of our financial instruments are net investment hedges.

Since
net investment hedges qualify for hedge accounting, gains or losses related to net investment hedges are recorded in OCI until there is a reduction in the net
investment of the foreign operation. Net investment hedges are short-term in nature related to the underlying investment, therefore contracts must be routinely renewed. As each of the
short-term contracts mature or is settled, cash inflows or outflows result that are recorded in investing activities on the statement of cash flow to reconcile the difference between
contracted rates and market rates at the date of settlement. If there is a reduction in the net investment of the foreign operation, the gains or losses previously recorded in OCI are transferred to
net earnings in that period.

A
summary of how net investment hedges are recorded in our financial statements is as follows:

Event


Statement of
Earnings


OCI


Balance
Sheet


Cash
FlowEnter into contract











Reporting date (marked-to-market)











Roll-over into new contract











Settle contract











Reduction of net investment of foreign operation














Non-Hedges

We use natural hedges as much as possible, such as U.S. interest rates on our U.S.-denominated long-term debt, to offset any
exposures related to changes in foreign exchange rates. Financial instruments not designated as hedges are used to reduce currency risk on the results of our foreign operations due to the
fluctuation of exchange rates beyond what is naturally hedged. All gains or losses related to non-hedges are recorded in the statement of earnings as they do not qualify for, nor have
they been designated for, hedge accounting. The fair value of risk management assets and liabilities related to non-hedges at Dec. 31, 2008 had a net value of $nil.

2008 Management's Discussion and Analysis43

---



A
summary of how non-hedges are recorded in our financial statements is as follows:

Event


Statement of
Earnings


OCI


Balance
Sheet


Cash
FlowEnter into contract1











Reporting date (marked-to-market)











Roll-over into new contract











Settle contract











Divest contract














Employee Share Ownership

We employ a variety of stock-based compensation plans to align employee and corporate objectives. On Feb. 1, 2008,
one million stock options were granted at an exercise price of $31.97, being the last sale price of board lots of the shares on the TSX the day prior to the day the options were granted for
Canadian employees, and U.S.$31.83, being the closing sale price on the New York Stock Exchange on the same date for U.S. employees. These options will vest in equal installments over
four years starting Feb. 1, 2009 and expire on Feb.1, 2019. At Dec. 31, 2008, 1.7 million options to purchase our common shares were outstanding, with 0.6 million
exercisable at the reporting date. At Dec. 31, 2007, 1.2 million options to purchase our common shares were outstanding, with 0.8 million exercisable at the reporting date.
There is no impact on diluted EPS as a result of these options.

On
March 2, 2009, we had 1.6 million outstanding employee stock options with a weighted average exercise price of $23.03. For the year ended Dec. 31,
2008, 0.3 million options with a weighted average exercise price of $20.52 were exercised resulting in 0.3 million shares issued, and 0.2 million options were cancelled with a
weighted average exercise price of $27.96.

Under
the terms of the Performance Share Ownership Plan ("PSOP"), certain employees receive grants which, after three years, make them eligible to receive a set number of
common shares or the equivalent value in cash plus dividends based upon our performance relative to companies comprising the S&P/TSX Composite Index. After three years, once PSOP eligibility has
been determined, 50 per cent of the common shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year. At
Dec. 31, 2008, there were 0.9 million PSOP awards outstanding (2007  1.0 million). There is no impact on diluted EPS as a result of this
program.

Under
the terms of the Employee Share Purchase Plan, we extend an interest-free loan to our employees below executive level for up to 30 per cent
of the employee's base salary for the purchase of our common shares from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless
the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2008, 0.8 million shares had been purchased by employees under this program
(2007  0.7 million). This program is not available to officers and senior management.

Employee Future Benefits

We have registered pension plans in Canada and the U.S. covering substantially all employees of the corporation, its
domestic subsidiaries, and specific named employees working internationally. These plans have defined benefit and defined contribution options. In Canada, there is a supplemental defined benefit
plan for Canadian-based defined contribution members whose annual earnings exceed the Canadian income tax limit. The defined benefit option of the registered pension plan ceased for new employees on
June 30, 1998. The latest actuarial valuations of the registered and supplemental pension plans were as at Dec. 31, 2008.

We
provide other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other
post-retirement benefits). The last actuarial valuation of these plans was conducted at Dec. 31, 2007.

The
supplemental pension plan is an obligation of the corporation. We are not obligated to fund the supplemental plan but are obligated to pay benefits under the terms of
the plan as they come due. We have posted a letter of credit in the amount of $52 million to secure the obligations under the supplemental plan.

44TransAlta Corporation    Annual Report 2008

---





Statements of Cash Flows

Year ended Dec. 31


2008


2007

Explanation of changeCash and cash equivalents, beginning of period

$
51

$
66Provided by (used in):Operating activities


1,038


847

Increase in cash earnings of $47 million and favourable changes in working capital of $144 million primarily due to the timing of PPA receipts in 2008.Investing activities


(581
)

(410
)
Additional capital spending of $407 million, and a decrease in realized gains on financial instruments of $55 million, partially offset by proceeds from the sale of an equity investment of
$332 million.Financing activities


(467
)

(444
)
Increase in repayments of short-term debt of $532 million and long-term debt of $56 million, and a $55 million increase to repurchase common shares under the NCIB program, partially offset
by the issuance of $500 million of long-term debt in 2008 and the redemption of preferred shares of $175 million in 2007.Translation of foreign currency cash


9


(8
)Cash and cash equivalents, end of period

$
50

$
51




Year ended Dec. 31


2007


2006

Explanation of changeCash and cash equivalents, beginning of year

$
66

$
79Provided by (used in):Operating activities


847


490

Increase in cash earnings of $102 million and favourable changes in working capital due to the collection of 2006 PPA revenues in 2007.Investing activities


(410
)

(261
)
Additional capital spending of $375 million due to equipment modifications at Centralia Coal, the Sundance Unit 4 uprate, and Keephills 3, combined with a $245 million loan to our equity
investment, partially offset by a $390 million return of restricted cash.Financing activities


(444
)

(243
)
$75 million used to repurchase common shares under the NCIB program, the redemption of preferred shares of $175 million in 2007, and an increase in cash dividends paid on common shares of
$71 million due to the cessation of dividends being reinvested in the DRASP Plan in 2007.Translation of foreign currency cash


(8
)

1Cash and cash equivalents, end of period

$
51

$
66


2008 Management's Discussion and Analysis45

---





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, short-term borrowings against our credit facilities, and
long-term debt issued under our U.S. shelf registrations and Canadian medium-term note program. 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.

We
have a total of $2.2 billion of committed credit facilities of which $1.4 billion is not drawn and is available as of Dec. 31, 2008, subject to
customary borrowing conditions. At Dec. 31, 2008, credit utilized under these facilities is $0.8 billion, which is comprised of short-term debt of $443 million, less
cash on hand of $50 million, and letters of credit of $430 million.

Our
ability to generate adequate cash flow from operations in the short-term and the long-term to maintain financial capacity and flexibility and
to provide for planned growth remains substantially unchanged since Dec. 31, 2007. In the first quarter of 2008 we received $116 million worth of PPA revenue from 2007 due to the
timing of contractually scheduled payments. Consequently, the effect of the timing of these payments is that we have received 13 months of revenue in 2008.

On
March 2, 2009, we had approximately 198 million common shares outstanding.

Guarantee Contracts

We have obligations to issue letters of credit to secure potential liabilities to certain parties including those related to potential
environmental obligations, trading activities, hedging activities, and purchase obligations. At Dec. 31, 2008, we had issued letters of credit totalling $430 million compared to
$550 million at Dec. 31, 2007. This decrease in letters of credit is due primarily to lower forward electricity prices in the Pacific Northwest. These letters of credit secure certain
amounts included on our balance sheet under "Risk Management Liabilities" and "Asset Retirement Obligations."

Working Capital

For the year ended Dec. 31, 2008, the excess of current liabilities over current assets of $730 million is mainly a result of higher
accounts payable and accrued liabilities, combined with a higher current portion of long-term recourse debt, partially offset by an increase in net risk management assets and lower
short-term debt balances.

For
the year ended Dec. 31, 2007, the excess of current liabilities over current assets of $686 million is mainly due to higher short-term debt
balances, and lower accounts receivable balances, partially offset by receiving November 2006 revenues, as contractually scheduled, on Jan. 2, 2007.

Capital Structure

CICA Handbook Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital;
(ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the
consequences of such non-compliance.

Our
capital structure consisted of the following components as shown below:

As at Dec. 31


2008


2007Debt, net of cash and cash equivalents

$
2,758


48%

$
2,437


47%Non-controlling interests


469


8%


496


9%Common shareholders' equity


2,510


44%


2,299


44%$
5,737


100%

$
5,232


100%


Contractual repayments of long-term debt, commitments under operating leases, fixed price purchase contracts, growth
project commitments, and commitments under mining agreements are as follows:

Fixed price
gas purchase
contracts


Operating
leases


Coal supply
and mining
agreements


Long-term
debt


Interest on
long-term
debt
1

Growth
project
commitments


Total2009

$
9

$
17

$
51

$
244

$
158

$
292

$
7712010


7


19


47


32


145


74


3242011


7


19


47


254


133


4


4642012


7


19


47


397


112





5822013


8


18


51


396


98





5712014 and thereafter


37


73


317


1,033


564





2,024Total

$
75

$
165

$
560

$
2,356

$
1,210

$
370

$
4,736


.........................................................................................................................................................................................................................................
.....................................

46TransAlta Corporation    Annual Report 2008

---



Off-Balance Sheet Arrangements

Disclosure is required of all off-balance sheet arrangements such as transactions, agreements or contractual
arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities that are reasonably likely to materially affect liquidity or the
availability of, or requirements for, capital resources. We currently have no such off-balance sheet arrangements.

Climate Change and Air Emissions

The variety of combustible fuels used to generate electricity all have some impact on the environment. While we are pursuing
a climate change strategy that includes, among other elements, investing in renewable energy resources such as wind and hydro, we believe that coal and natural gas as fuels will continue to play an
important role in meeting the energy needs of the future. We place significant importance on environmental compliance to ensure we are able to continuously deliver low
cost electricity.

Ongoing and Recently Passed Environmental Legislation

While we continue to pursue clean coal and other technologies to reduce the impact of our power generating activities upon the environment, changes
in current environmental legislation do have, and will continue to have, an impact upon our business.

Canada

In Canada, the Conservative Government has indicated its intention to coordinate its climate change policies more
closely with those of the U.S., and to seek alignment on a continental cap and trade system. To date there has been no detail as to when this alignment would occur or how Canada's system might be
designed. Furthermore, there has been no announcement as to the fate of the prior intensity-based program proposed by the previous Conservative Government. Consequently, at this time it is not
possible to fully assess how these broad directional objectives will affect us.

On
Jan. 24, 2008, the Government of Alberta announced its long-term intention to cut greenhouse gas emissions to 14 per cent below 2005
levels by 2050 through developing and implementing CCS technologies, developing conservation and energy efficiency programs, and increasing investment in clean energy technologies. We continue to
assess the impact of this proposal upon our operations and our own investment in environmental technologies and programs.

Alberta
continues to maintain its GHG regulatory regime that was implemented on July 1, 2007, under theClimate Change and Emissions
Management Amendment Act.Under the legislation, baselines and targets for GHG intensity are set on a facility-by-facility basis. The legislation and
subsequent regulations require a 12 per cent reduction in GHG emission intensity from a baseline set as the average level of emissions during 2003 to 2005. New facilities are exempt
for three years and subsequently are subject to a slowly increasing reduction requirement. Emissions over the baseline must be mitigated either through contributions to an Alberta Technology Fund at
$15 per tonne, or through the purchase and retirement of Alberta-based offsets from non-regulated sectors. The PPAs for our Alberta-based coal facilities contain
change-in-law provisions that allow us to recover these compliance costs from the PPA customers. For 2008, after flow-through, our annual net greenhouse gas
compliance costs will be less than $2 million (2007  less than $1 million). We have measures in place to meet the anticipated reduction targets
for 2008 and 2009, and continue to examine compliance options, including additions to our offsets portfolio to minimize our compliance risk beyond that period.

In
August 2007, the Government of Ontario announced its climate change action plan which included a target to reduce GHG emissions by six per cent below 1990
levels by 2014. Subsequently, the Government of Ontario has indicated its intention to implement a cap and trade system for greenhouse gases by 2010, although no additional legislation or details
have been developed at this time.

United States

In the United States, the Washington State Climate Bill 6001 was enacted and came into effect on
July 22, 2007. Our operations will not be impacted by the bill's performance standards at the current time, provided the facilities do not change ownership or enter into power sales contracts
longer than five years.

Washington
State is developing the conceptual design for a cap and trade mechanism to manage greenhouse gases. On Dec. 12, 2008, the State introduced draft
legislation to enable a cap and trade system to be implemented by 2012. Specific details of caps and allocations will be developed in 2009. In parallel, Washington State is engaged with other
western states and some Canadian provinces in the WCI to examine a regional cap and trade system for CO2 emissions. On Sept. 23, 2008, the WCI released its design for a regional
greenhouse gas cap and trade system, which will be influential in individual state regulation development. At this point there are no indications as to how these initiatives will impact our
fossil-fired assets in Washington.

Federally
in the U.S., President Obama has indicated his intentions to push forward legislation on GHGs in 2009. While some form of cap and trade legislation is
anticipated, it is still premature to assess when the legislation might become law and what the specific impacts would be on our U.S. assets.

Legal Implications

There are currently no ongoing legal actions as a result of environmental legislation.

TransAlta Activities

We believe that climate change has the potential to impact the business environment in which we operate. We continuously act to reduce the
environmental impact of our operating activities because severe changes in weather, such as drought and temperature changes, could hinder our operating abilities and ultimately, our profits.
Reducing the environmental impact of our activities has a benefit

2008 Management's Discussion and Analysis47

---



not
only to our operations and financial results, but also to the communities in which we operate. We believe that increased scrutiny will be placed on environmental emissions and compliance, and we
therefore have a proactive approach to minimizing risks to our results.

Our
environment management programs encompass several elements:

Renewable Power

Our investment in renewable power sources continues through the building of renewable power resources such as the Kent Hills, Summerview 2
and Blue Trail wind farms.

Policy Discussions

We are active in policy discussions at a variety of levels of government. These stakeholder negotiations have allowed us to engage in proactive
discussions with governments to meet environmental requirements over the longer-term.

As
one of the founders, and active members, of the Clean Coal Power Coalition, we aim to secure a future for coal-fired electricity generation, within the
context of Canada's multi-fuelled electricity industry, by proactively addressing environmental issues in cooperation with government and our stakeholders. We are also part of a group of companies
participating in the Integrated CO2 Network to work with the Albertan and Canadian governments to develop carbon capture and storage systems for Canada.

CCS Development

On July 8, 2008, the Alberta government announced its plan to provide funding of $2 billion for new CCS projects operational before
2015. On Nov. 12, 2008, we announced that the CCS pilot project was accepted to the short list of projects for funding under this program. On Dec. 18, 2008, we announced the
participation of TransCanada PipeLines Limited in our proposed development of Canada's first fully integrated carbon capture and storage project. When complete, the plant will be one of the largest
CCS facilities in the world and the first to have an integrated underground storage system. The project will pilot Alstom Canada's proprietary chilled ammonia carbon capture technology and will be
designed to capture one megatonne of CO2 at one of our Alberta Thermal units. The CO2 will be used for enhanced oil recovery as well as injected into a permanent geological
storage site. A full project proposal is now being prepared and will be submitted to the Alberta government by March 31, 2009. The government will select the successful projects for
funding by June 30, 2009.

We
continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We are
continuing with detailed technology testing and engineering design in preparation for installing mercury control equipment at our Alberta Thermal operations by 2010 in order to meet the province's
70 per cent reduction objectives and are on track to meet that deadline. We submitted our mercury control plan in March 2007. In prior years we have invested in other capture
technologies such as those for sulfur dioxide.

The
PPAs for our Alberta-based coal facilities contain change-in-law provisions that allow us the opportunity to recover compliance costs from the
PPA customers.

Offsets Portfolio

We continue to pursue emission offset opportunities that also allow us to meet emission targets at a competitive cost. We ensure that any
investments in offsets will meet certification criteria in the market in which they are to be used.

Future Growth

In 2008, we estimate that 38.5 million tonnes of GHGs with an intensity of 0.893 tonnes/MWh
(2007  39.3 million tonnes of GHGs with an intensity of 0.880 tonnes/MWh) were emitted as a result of normal operating activities.1
Total GHG emissions decreased in 2008 due to lower availability and production. Our planned growth over the next four years, as discussed in the Capability to Deliver Results section of this MD&A,
will result in 456 MW of capacity being added to our generation fleet. This growth and the related increase in emissions will be partially offset by the decommissioning of Unit 4 at
our Wabamun plant. We estimate that approximately 0.3 million tonnes of additional GHGs will be emitted each year as a result of these projects being completed. The various activities
discussed above, including our investment in renewable power and CCS technology, are designed to minimize the environmental and financial impacts of the expected increase in emissions.

Our
Board of Directors continues to monitor the results of our reduction efforts and future reduction plans to ensure we are compliant with existing environmental
regulations and to ensure that we will be compliant with future legislation.

.....................................................................................................................................................................
.......................................................

48TransAlta Corporation    Annual Report 2008

---



2009 Outlook

Business Environment

Power Prices

For 2009, lower natural gas prices and slowing year-over-year demand growth due to the current weak economic environment
could result in reduced power prices compared to prior periods in some of our markets. The potential change in power prices as a result of the current economic environment is not expected to
materially affect our results as we currently have approximately 90 percent of our expected 2009 capability contracted.

In
2009, approximately 16 per cent of production at our natural gas-fired facilities and seven per cent of production at our
coal-fired facilities is exposed to market fluctuations in energy commodity prices. We closely monitor the risks associated with these commodity price changes 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 risk.

Environmental Legislation

For 2009, we anticipate increasing regulatory clarity on future GHG requirements as both the Canadian and U.S. governments develop their
programs. Given recent announcements, we now expect environmental regulations to move in the direction of a cap and trade system.

In
Alberta, current regulations on greenhouse gases and air pollutants are clear, but it is uncertain how federal regulations will affect Alberta firms once federal
regulations are implemented. We expect discussions to take place in 2009 between the Federal Government and the provinces about what rules are to be applied and their administration. In Washington
State, we expect to see details of the State's cap and trade legislation by the end of 2009.

We
are active participants in consultations leading up to the formation of these legislative and regulatory mechanisms.

Economic Environment

As a result of the current economic environment, commodity prices are decreasing, which could result in lower input costs for us in the future.
Although we have contracted the price of the majority of our inputs in the short-term, in the long-term we may see the benefit of lower operating costs.

A
number of financial and industrial counterparties have experienced credit rating downgrades and we expect 2009 will continue to be a challenging year for some of our
counterparties as a result of the recent financial crisis and current economic environment. While we had no counterparty losses in 2008, we continue to monitor counterparty credit risk and act in
accordance with our established risk management policies. We do not anticipate any material change to our existing credit practices and continue to deal primarily with investment grade
counterparties in our trading and hedging activities.

We
expect continued strict lending conditions, which could reduce the amount of capital available. Our strong financial position, available committed lines of credit, and
relatively low debt maturity profile allow us to be selective about when we need to go to the market for financing. We see support in the market for successful projects with high returns, so we will
continue to evaluate potential projects using the risk management policies that have been developed and take action when appropriate.

We
do not expect our results from operations in 2009 to be significantly impacted by the current economic environment because production amounts and prices are mainly
contracted through our PPAs.

Operations

Production, Availability, and Capacity

Generating capacity is expected to increase late in 2009 due to the completion of Blue Trail and the uprate at Sundance Unit 5. Production and
availability are expected to increase in the second half of 2009 primarily due to lower unplanned outages at Alberta Thermal. Overall production for 2009 is expected to increase compared to 2008
primarily due to lower unplanned outages at Alberta Thermal and higher expected production at Centralia Thermal.

Fuel Costs

Coal mining in Alberta is subject to cost increases related to mining such as increased overburden removal, inflation, and increases in commodity
prices such as diesel. Seasonal variations in coal costs at our Alberta mines are minimized through the application of standard costing. Coal costs for 2009, on a standard cost basis, are expected
to increase five per cent from the prior year primarily due to increased capital expenditures.

Fuel
at Centralia Thermal is purchased from external suppliers in the PRB and delivered by rail. The delivered cost of fuel is expected to increase between 10 and
15 percent from the prior year due to rail and transportation contract escalations.

Our
natural gas-fired facilities have minimal exposure to market fluctuations in energy commodity prices. Exposure to natural gas costs for facilities under
long-term sales contracts are minimized to the extent possible through long-term natural gas purchase contracts. Merchant natural gas facilities are exposed to the changes in
spark spreads, as discussed in the Business Environment section, as the majority of the natural gas is purchased on a spot basis. The input costs that are purchased on a spot basis are
expected to decrease in 2009 due to lower prices resulting from the current economic environment.

2008 Management's Discussion and Analysis49

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In
addition, the decreasing commodity prices have the potential to lower the price of existing assets available for sale, which could result in more
cost-efficient acquisitions to further diversify our portfolio of assets.

Operations, Maintenance, and Administration Costs

OM&A costs per MWh of installed capacity fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per
installed MWh in 2009 are expected to increase due to higher planned maintenance activities in Alberta and cost escalations, partially offset by productivity initiatives. The increase in planned
maintenance activities is expected to improve our availability at Alberta Thermal.

Energy Trading

Earnings from our COD segment are affected by prices in the market, the positions taken, and the duration of those positions. We continuously
monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2009 objective is for Energy Trading to contribute between $65 million
and $85 million in gross margin.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar by offsetting foreign denominated
assets with foreign denominated liabilities and foreign exchange contracts. We also have foreign currency expenses, including interest charges, which are also used to mostly offset foreign currency
revenues.

Net Interest Expense

Net interest expense for 2009 is expected to be higher mainly due to higher debt balances and lower interest income. However, changes in interest
rates and in the value of the Canadian dollar to the U.S. dollar will 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, there may be the need for additional
liquidity. To mitigate this liquidity risk, we maintain and monitor $2.2 billion of committed credit facilities and monitor exposures to determine any expected liquidity requirements. We have
taken steps in order to maintain maximum financial flexibility, such as suspending purchases under our NCIB program, until we gain a better understanding of where markets may settle.

Accounting Estimates

Although we do not expect significant changes in our accounting estimates as a result of the current economic environment, some fluctuation could
be seen on the fair valuation of our risk management assets and liabilities due to large variation in future commodity prices and foreign exchange and interest rate forward curves. Any significant
changes in forward prices and rates could result in material differences in the amount of unrealized gains or losses and risk management assets and liabilities recorded at each reporting date due to
the fair valuation performed at that time. However, any such change in fair value will not impact cash flow as we will receive our contracted prices.

Capital Expenditures

Projects and Growth

Our major projects are comprised of spending on sustaining our current operations and for growth activities. Six significant growth capital
projects are currently in progress: Keephills 3, Blue Trail, Sundance Unit 5 uprate, Summerview 2, and Keephills Units 1 and 2 uprates. A summary of each of these projects is
outlined below:

Project


Total
spend
(millions
)

Expected
2009 spend
(millions
)

Expected
completion
date

DetailsKeephills 3

$
888

$
235255


Q1 2011

A 450 MW (225 MW net ownership interest) coal-fired supercritical plant and associated mine capital in a partnership with EPCORBlue Trail


115


8590


Q4 2009

A 66 MW wind farm in southern AlbertaSundance Unit 5 uprate


75


5060


Q4 2009

A 53 MW efficiency uprate at our Sundance facilitySummerview 2


123


8090


Q1 2010

A 66 MW expansion of our Summerview wind farm in southern AlbertaKeephills Unit 1 uprate


34


510


Q4 2011

A 23 MW efficiency uprate at our Keephills facilityKeephills Unit 2 uprate


34


510


Q4 2012

A 23 MW efficiency uprate at our Keephills facilityTotal growth

$
1,269

$
460515


Our estimate of total costs for Keephills 3 has increased by $73 million compared to previous estimates due to higher
material and labour costs. We continue to monitor these costs and look for opportunities to reduce these increases.

50TransAlta Corporation    Annual Report 2008

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Sustaining Expenditures

Sustaining expenditures include planned maintenance, regular expenditures on plant equipment, systems and related infrastructures, as well as
investments in our mines. For 2009, our estimate for total sustaining capital expenditures is between $340 million and $390 million net of any contributions received, allocated among:

Coal


Gas and
Hydro


TotalCapitalized

$
8590

$
4550

$
130140Expensed


8590


05


8595$
170180

$
4555

$
215235GWh lost


2,6002,700


250275


2,8502,975


In 2009, we expect to lose approximately 2,850 to 2,975 GWh of production due to planned maintenance.

Included
in our estimate for routine capital expenditures is productivity capital, which is used for various initiatives that are designed to improve the productivity of
existing facilities. The overall increase in sustaining capital expenditures for 2009 is related to a productivity initiative at our Ontario cogeneration plants. In 2009, we will perform upgrades on
the natural gas turbine engines at our Ottawa, Mississauga, and Windsor facilities. This new productivity investment, along with other investments, brings our total productivity spend in 2009 to
$50 million. We expect these investments in productivity to provide returns in excess of 20 per cent.

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities and from existing
borrowing capacity. The funds required for committed growth and sustaining projects are not expected to be impacted by the current economic environment due to the highly contracted nature of
our cash flow and amount of credit available at Dec. 31, 2008.

Related Party Transactions

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

On
Dec. 16, 2006, TAU, a wholly owned subsidiary, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the
coal-fired plant. The joint venture project is held in a partnership with EPCOR Power Development Corporation. TAU will supply coal until the earlier of the permanent closure of the
Keephills 3 facility or from early termination of the agreement by TAU and the partners of the joint venture. As at Dec. 31, 2008, TAU had received $27 million from Keephills
3 Limited Partnership, a wholly owned subsidiary, for the right to coal. Commercial operation of the Keephills plant is scheduled to commence in the first quarter of 2011. Payments
received prior to that date for the right to coal are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply agreement when operations commence.

In
August 2006, we entered into an agreement with CE Gen, a corporation jointly controlled by us and MidAmerican, a subsidiary of Berkshire Hathaway, whereby
we buy available power from certain CE Gen subsidiaries at a fixed price. As this available power is from plants that are already contracted, the value of this agreement is immaterial. In
addition, CE Gen has entered into contracts with related parties to provide administrative and maintenance services.

For
the period November 2002 to November 2012, one of our subsidiaries, TA Cogen, entered into various transportation swap transactions with TEC. TEC
operates and maintains TA Cogen's three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan, Alberta. TEC also provides management services to the Sheerness thermal plant,
which is operated by Canadian Utilities Limited. The business purpose of these transportation swaps is to provide TA Cogen with the delivery of fixed price gas without being exposed to
escalating costs of pipeline transportation for three of its plants over the period of the swap. The notional gas volume in the transaction was the total delivered fuel for each of the facilities.
Exchange amounts are based on the market value of the contract. We entered into an offsetting contract and therefore we have no risk other than counterparty risk.

Risk Management

Our business activities expose us to a wide variety of risks. Our goal in managing these risks is to protect the Corporation
from an unacceptable level of earnings or financial exposure while still enabling business processes and opportunities. We use a multi-level risk management oversight structure to manage these
objectives by ensuring that the risks arising from our business activities, the markets in which we operate, and the political environments in which we operate is mitigated. As evidence of our
dedication to excellent risk management and corporate governance, we were awarded the Private Sector Conference Board of Canada/Spencer Stuart 2009 National Award in Governance on
Feb. 10, 2009.

The
responsibilities of the various stakeholders of our risk management oversight structure are described below:

The Board of Directorsprovides stewardship of the Corporation, establishes policies and procedures, defines risk tolerance
as established under the TSX corporate governance guidelines, and receives the annual comprehensive Enterprise Risk Management

2008 Management's Discussion and Analysis51

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("ERM)"
review. The ERM reviews consist of a holistic view of the company's inherent risks, how we mitigate these risks, and residual risks. It defines these risks, discusses who is responsible to
manage the risks, how the risks are inter-related with each other, and what the risk metrics are. The Board of Directors examines the ERM review in order to fulfill its requirement to
understand the key risks of the company and directs management to address any risk levels with which it is uncomfortable.

Audit and Risk ("A&R") Committee,established by the Board of Directors, provides assistance to the Board of Directors in
fulfilling its oversight responsibility relating to the integrity of our financial statements and the financial reporting process; the systems of internal accounting and financial controls; the
internal audit function; the external auditors' qualifications, terms and conditions of appointment, including remuneration, independence, performance and reports; and the legal and risk compliance
programs as established by management and the Board of Directors. The A&R Committee approves our Commodity Risk and Financial Exposure Management policies and reviews quarterly ERM reporting.

Exposure Management Committee ("EMC")is chaired by our Executive VP and Chief Financial Officer and is comprised of
the Executive Vice-President of Commercial Operations and Development, Executive Vice-President of Generation Operations, Vice-President of Commercial Operations,
Managing Director of Trading, Vice-President and Treasurer, Vice-President of Financial Operations, Vice-President and Comptroller, and the Director of Risk
Management. The EMC is responsible for reviewing, monitoring, and reporting on our compliance with approved financial and commodity risk exposure management policies.

Corporate Treasuryis responsible for the management, oversight, and reporting of financial risks, including: interest
rate, foreign exchange, credit, liquidity, and insurable risks. The objectives are to maintain a low cost of capital by mitigating earnings volatility, maintain access to capital markets, and avoid
losses. Our risk management policy requires that there be sufficient resources and training available to fulfill these objectives, including maintaining segregation of duties, all in accordance with
risk management best practices.

Risk Managementis staffed by experienced risk professionals who are responsible for enterprise risk reporting to the Board
and A&R Committee, analyzing commercial and environmental risk exposures in our assets and trading operations, as well as ensuring our daily market price exposure is kept within VaR limits. The Risk
Management group uses a variety of processes and models to perform this analysis.

Our
risk management practices address key risk factors. These are described in greater detail as follows.

Risk Controls

Our management of these risks is also described in the respective sections. Our risk controls have several key components:

Enterprise Tone

Our corporate values are clearly articulated throughout the organization. Employees sign agreements outlining their commitment to our corporate
code of conduct.

Policies

We maintain a set of enterprise-wide policies that have been established to address key risks. These policies establish delegated
authorities and limits for business transactions, as well as allow for an exceptional approval process. We perform periodic reviews and audits to ensure compliance with these policies.

Reporting

We regularly report risk exposures to key decision makers including the Board of Directors, senior management, and the EMC. This reporting includes
analysis of risks being assumed, existing risk exposures, and recommendations for any suggested course of action. This frequent reporting provides for effective and timely risk management
and oversight.

Whistleblower System

We have a system in place where employees may report any potential ethical concerns. These concerns are directed to the Vice-President
Internal Audit who engages Corporate Security, Legal and Human Resources in determining the appropriate course of action. These concerns and any actions taken are discussed with the Audit and
Risk Committee.

Value at Risk and Trading Positions

VaR is the most commonly used metric employed to track the risk of trading positions. A VaR measure gives, for a specific confidence level, an
estimated maximum loss over a specified period of time.

VaR
is the primary measure used to manage COD's exposure to market risk resulting from trading activities. VaR is monitored on a daily basis, and is used to determine the
potential change in the value of our marketing portfolio over a three-day period within a 95 per cent confidence level resulting from normal market fluctuations. Stress
tests are performed weekly on both earnings and VaR to measure the potential effects of various market events that could impact financial results, including fluctuations in market prices,
volatilities of those prices and the relationships between those prices. The 3-day average VaR for the year ending Dec. 31, 2008 was $6 million compared to
$4 million for the same period in 2007.

We
estimate VaR using the historical variance/covariance approach. Currently, there is no uniform energy industry methodology for estimating VaR. An inherent limitation of
historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. See additional discussion under commodity price risk in the Risk
Management section.

52TransAlta Corporation    Annual Report 2008

---



Risk Factors

Risk is inherent in all business activities and cannot be entirely eliminated. However, shareholder value can be maintained and
enhanced by identifying, mitigating, and where possible, insuring against these risks.

The
following section addresses some, but not all, risk factors that could affect our future results and our activities in mitigating those risks. These risks do not occur
in isolation, but must be considered in conjunction with each other.

Certain
sections will show the after-tax effect on net earnings and/or cash flows of changes in certain key variables. The analysis is based on business
conditions and production volumes in 2008. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and
magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of changes.

Volume Risk

Volume risk relates to the variances from our expected production. Where we are unable to produce sufficient quantities of output in relation to
contractually specified volumes, we may be required to pay penalties or purchase replacement power in the market.

Our
hydro operations' financial performance is partially dependent upon the availability of water in a given year. The availability of water is difficult to forecast as it
is primarily driven by weather. Such water availability introduces a degree of volatility in revenues earned by our hydro operations from year to year. This risk is complicated by obligations
imposed within the PPA applicable to our Alberta hydro facilities. A monthly financial obligation must be paid to the PPA Buyer, based on a predetermined quantity of energy and ancillary services at
market prices, regardless of our ability to generate such quantities. We carefully balance all of these factors together to achieve optimal productivity with the water resources available.

Our
wind and geothermal operations are dependant upon the availability of wind and geothermal resources.

We
manage these risks by:

The
sensitivities of volumes to our net income are described below:

Factor


Increase or
decrease


Approximate impact on
earnings and cash flow
(after-tax
)Availability/production


1%


$     21


Generation Equipment and Technology Risk

Our plants are exposed to operational risks such as fatigue cracks in boilers, corrosion in boiler tubing, turbine failures, and other issues that
can lead to outages and increased volume risk. If plants do not meet availability or production targets specified in their PPA or other long-term contracts, we must either compensate the
purchaser for the loss in the availability of production or record reduced electrical or capacity payments. For merchant facilities, an outage can result in lost merchant opportunities. Therefore,
an extended outage could have a material adverse effect on our business, financial condition, results of operations, or our cash flows.

As
well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure these parts when they are needed for
maintenance activities, we could face an extended period with our equipment unavailable to produce electricity.

We
manage our generation equipment and technology risk by:

2008 Management's Discussion and Analysis53

---





Commodity Price Risk

We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both
our electricity generation and proprietary trading businesses.

We
manage electricity price risk by:

In
2008, we had approximately 97 per cent of production under short-term and long-term contracts and hedges
(2007  96 per cent). In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in
electricity prices on purchases of electricity from the market to fulfill our supply obligations under these short- and long-term contracts.

We
manage fuel price commodity risk by:

We
are exposed to increases in the cost of fuels used in production to the extent such increases are greater than the increases in the price that we can obtain for the
electricity we produce. In 2008, 82 per cent (2007  81 per cent) of our cost of gas used in generating electricity was
contractually fixed or passed through to our customers and 100 per cent (2007  100 per cent) of our purchased coal costs were
contractually fixed.

We
monitor the market for opportunities to enter into favourably priced long-term gas contracts.

The
sensitivities of price changes to our net income are described below:

Factor


Increase or
decrease


Approximate impact on
earnings and cash flow
(after-tax
)Electricity price

$
1.00/MWh


$       9Natural gas price

$
0.10/GJ


$       1Coal price

$
1.00/tonne


$     15


Fuel Supply Risk

We buy natural gas and some of our coal to supply the fuel needed to operate our facilities. The ability to have sufficient fuel available when
required for generation could have an impact upon our ability to produce electricity under contracts and for merchant sale opportunities.

At
Alberta Thermal, higher input costs, such as diesel, tires, the price of mining equipment, increased amounts of overburden being removed to access coal reserves, and
mining operations moving further away from the power plants are all contributing to increased mining costs. Additionally, the ability of the mines to deliver coal to the power plants can be impacted
by weather conditions and labour relations. At Centralia Thermal, interruptions at our suppliers' mines and the availability of trains to deliver coal could affect our ability to generate
electricity.

We
manage fuel supply risk by:

We
believe adequate supplies of natural gas at reasonable prices will be available for plants when existing supply contracts expire.

Environmental Risk

Environmental risks are risks to our business associated with changes in environmental regulations or exposures. New emission reduction objectives
for the power sector are being established by governments in Canada and the United States. We anticipate continued and growing scrutiny by investors relating to sustainability performance.
These changes to regulations may affect our earnings by imposing additional costs on the generation of electricity, such as emission caps, requiring additional capital investments in emission
capture technology, or requiring us to invest in offset credits. It is anticipated that these costs will increase due to increased political and public attention to environmental concerns.

54TransAlta Corporation    Annual Report 2008

---



We
manage environmental risk by:

We
strive to maintain compliance with all environmental regulations relating to operations and facilities. Compliance with both regulatory requirements and management
system standards is regularly audited through our performance assurance policy and results are reported quarterly to our Board of Directors.

In
2008, we spent approximately $47 million (2007  $46 million) on environmental management activities, systems
and processes.

We
are a founder of the Canadian Clean Power Coalition, which is an industry consortium developed to build Canada's first clean coal power plant. In March 2008, the
Alberta government announced its plan to provide funding of $2 billion for new CCS projects operational before 2015. We have submitted a proposal for funding of our Project Pioneer CCS
project and has been short-listed. The Alberta government will announce its funding allocation in July 2009.

Credit Risk

Credit risk is the risk to our business associated with changes in creditworthiness of entities with which we have commercial exposures. This risk
is in the ability of a counterparty to either fulfill their financial obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect
cash due to us or to receive products or services may have an adverse impact upon our cash flows.

We
manage our exposure to credit risk by:

If
established credit exposure limits are exceeded, we take steps to reduce this exposure such as requesting collateral, if applicable, or by halting commercial activities
with the affected counterparty. However, there can be no assurances that we will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.

We
took steps throughout 2008 to reduce our counterparty risk by proactively assessing the effect of the potential changes in the financial markets on counterparty risk
and acting on these assessments. While we had no counterparty losses in 2008, we are continuing to keep a close watch on changes and trends in the market and the impact these changes could have on
our trading business and hedging activities, and will take appropriate actions as required although no assurance can be given that we will always be successful.

We
are exposed to minimal credit risk for Alberta PPAs because under the terms of these arrangements, receivables are substantially all secured by letters of credit. Our
credit risk management profile and practices have not changed materially from Dec. 31, 2007.

A
summary of our credit exposure for commodity trading operations and hedging at Dec. 31, 2008 is provided below:

Counterparty credit rating


Net
exposureInvestment grade

$
350Non-investment grade

$
47No external rating, internally rated as investment grade

$
39No external rating, internally rated as non-investment grade

$
6


The maximum credit exposure to any one customer for commodity trading operations, excluding the California Independent System
Operator and California Power Exchange, and including the fair value of open trading positions, is $105 million (2007  $6 million).

Currency Rate Risk

We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations,
and the acquisition of equipment and services from foreign suppliers. We have exposures primarily to the U.S and Australian currencies. Changes in the values of these currencies in relation to the
Canadian dollar may affect our earnings or the value of our foreign investments to the extent that these positions or cash flows are not hedged.

2008 Management's Discussion and Analysis55

---



We
manage our currency rate risk by:

Translation
gains and losses related to the carrying value of our foreign operations are included in accumulated OCI in shareholders' equity. At Dec. 31, 2008, the
balance in this account was a $61 million gain (2007  $245 million loss).

The
sensitivity of changes in foreign exchange rates upon our earnings is shown below:

Factor


Increase or decrease
(foreign currency
)

Approximate impact on
earnings and cash flow
(after-tax
)Exchange rate


$     0.10


$     10


Liquidity Risk

Liquidity risk relates to our ability to access capital to be used in proprietary trading activities, commodity contracting, and in debt and equity
markets. Investment grade ratings support contracting activities and provide better access to capital markets through commodity and credit cycles. We are focused on maintaining a strong balance
sheet and stable investment grade credit ratings.

We
are exposed to liquidity risk under certain electricity and natural gas purchase and sale contracts entered into for the purposes of asset-backed sales and proprietary
trading. The terms and conditions of these contracts require us to provide collateral when the fair value of these contracts is in excess of any credit limits granted by our counterparties and the
contract obliges us to provide the collateral. Downgrades in our creditworthiness by certain credit rating agencies may decrease the credit limits granted by our counterparties and accordingly
increase the amount of collateral we may have to provide.

We
manage liquidity risk by:

Interest Rate Risk

Changes in interest rates can impact our borrowing costs and the capacity revenues we receive from our Alberta PPA plants. Changes in our cost of
capital may also affect the feasibility of new growth initiatives.

We
manage interest rate risk by:

At
Dec. 31, 2008, approximately 24 per cent (2007  35 per cent) of our total debt portfolio was
subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.

The
sensitivity of changes in interest rates upon our earnings is shown below:

Factor


Increase or
decrease


Approximate impact on
earnings and cash flow
(after-tax
)Interest rate


1%


$     5


Project Management Risk

As we are currently building six generating projects, we face risks associated with cost-overruns, delays, and performance.

We
attempt to minimize these project risks by:

56TransAlta Corporation    Annual Report 2008

---





Human Resource Risk

Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human resource risk can occur
in several ways:

We
manage this risk by:

Of
our labour force, 46 per cent (2007  46 per cent) is covered by
11 (2007  13) collective bargaining agreements. In 2008, three (2007  eight) agreements were renegotiated.
We anticipate negotiating five agreements in 2009. We do not anticipate any significant issues in the renewal of these agreements.

Regulatory and Political Risk

Regulatory and political risk describes the risk to our business associated with existing regulatory structures and the political influence upon
those structures. The generation of electricity is under increased political scrutiny due to decreasing reserve margins, increased demand, and a lack of new generating capacity. This risk can come
from market re-regulation, increased oversight and control, or other unforeseen influences. We are not able to predict whether there will be any changes in the regulatory environment or
the ultimate effect of changes in the regulatory environment on our business.

We
manage these risks by working with governments, regulators, and other stakeholders to resolve issues. We are active in policy discussions at a variety of levels. These
stakeholder negotiations have allowed us to engage in proactive discussions with governments over the longer-term.

International
investments are subject to unique risks and uncertainties relating to the political, social, and economic structures of the respective country and such
country's regulatory regime. We mitigate this risk through the use of non-recourse financing and political risk insurance.

Transmission Risk

Access to transmission lines and sufficient capacity in those transmission lines are key in our ability to deliver power to our customers. However,
with the continued growth in demand for electricity coupled with very little transmission capacity being added to existing infrastructures, the reliability and capacity on the existing transmission
facilities, the risk associated with the existing transmission infrastructure in Alberta, Ontario, and the Pacific Northwest continues to develop.

Transmission
risks are mitigated through:

Reputation Risk

Our reputation is one of our most valued assets. Reputation risk relates to the risk associated with our business because of changes in opinion
from the general public, private stakeholders, governments, and other entities.

We
manage reputation risk by:

We
are dedicated to operating a safe and ethical organization. We have a system in place where employees may report any potential ethical concerns. These concerns are
directed to the Vice-President Internal Audit who engages Corporate Security, Legal, and Human

2008 Management's Discussion and Analysis57

---



Resources
in determining the appropriate course of action. These concerns and any actions taken are discussed with the Audit and Risk Committee. All employees and directors are required to sign a
corporate code of conduct on an annual basis.

Corporate Structure Risk

We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent
upon the results of operations of our subsidiaries and the payment of funds by our subsidiaries in the form of distributions, loans, dividends, or otherwise. In addition, our subsidiaries may be
subject to statutory or contractual restrictions that limit their ability to distribute cash to us.

General Economic Conditions

Changes in general economic conditions impact product demand, revenue, operating costs, timing and extent of capital expenditures, the net
recoverable value of PP&E, results of financing efforts, credit risk, and counterparty risk.

Income Taxes

Our operations are complex, and located in different countries. The computation of the provision for income taxes involves tax interpretations,
regulations, and legislation that are continually changing. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as
required by GAAP, based on all information currently available.

The
sensitivity of changes in income tax rates upon our earnings is shown below:

Factor


Increase or
decrease


Approximate impact on
earnings and cash flow
(after-tax
)Tax rate


1%


$     4


The effective income tax rate can change depending on the mix of earnings from various countries. Increased operating income will
incur income tax expense at a rate of approximately 29 per cent compared to the forecasted overall range of 20 to 25 per cent.

Legal Contingencies

We are occasionally named as a party in various claims and legal proceedings which arise during the normal course of our business. We review each
of these claims, including the nature of the claim, the amount in dispute or claimed, and the availability of insurance coverage. Although there can be no assurance that any particular claim will be
resolved in our favour, we do not believe that the outcome of any claims or potential claims of which we are currently aware will have a material adverse effect on us, taken as
a whole.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during
2008. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that insurance proceeds received by the Corporation for any loss or damage
will be fully adequate to compensate for potential losses incurred.

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities
have evolved and
as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the
use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date, and we believe the proper
implementation and consistent application of accounting rules is critical.

However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is
used to adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines governing them, consider foreign accounting standards, and consult
with our independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of
judgment either in the application and interpretation of existing literature or in the development of estimates that impact our consolidated financial statements.

Our
significant accounting policies are described in Note 1 to the consolidated financial statements. The most critical of these policies are those related
to revenue recognition, PP&E, goodwill, asset retirement obligations, income taxes, employee future benefits, and financial instruments (Notes 1(D), (F), (G), (I), (K), (L), and (N)
respectively). Each policy involves a number of estimates and assumptions to be made about matters that are highly uncertain at the time the estimate is made. Different estimates, with respect to
key variables used for the calculations, or changes to estimates, could potentially have a material impact on our financial position or results of operations.

We
have discussed the development and selection of these critical accounting estimates with our A&R Committee and our independent auditors. The A&R Committee has reviewed
and approved our disclosure relating to critical accounting estimates in this MD&A.

Tables
are provided in the following discussion to reflect the sensitivities associated with changes in key assumptions used in the estimates. The tables reflect an
increase or decrease in the percentage or other factor for each assumption. The inverse of each change is generally expected to have a similar opposite impact. Each separate item in the sensitivity
assumes all other factors remain constant.

These
critical accounting estimates are described below.

58TransAlta Corporation    Annual Report 2008

---



Revenue Recognition

The majority of our revenues are derived from the sale of physical power and from energy marketing and trading activities. Revenues under
long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for being available, energy payments for generation
of electricity, availability incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services.
Each of these components is recognized upon output, delivery, or satisfaction of contractually specific targets. Revenues from non-contracted capacity are comprised of energy payments
for each MWh produced at market prices and are recognized upon delivery.

Trading
activities use derivatives such as physical and financial swaps, forward sales contracts and futures contracts and options, which are used to earn trading revenues
and to gain market information. These derivatives are accounted for using fair value accounting and are presented on a net basis in the statements of earnings. The initial recognition of fair value
and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized
gains or losses and are presented on the balance sheets as risk management assets or liabilities. The fair value of derivative contracts receiving hedge accounting treatment open at the balance
sheet date are deferred in OCI and are presented on the balance sheets as risk management assets or liabilities.

The
determination of the fair value of Energy Trading contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility, and
liquidity, among other factors. The majority of derivatives traded by us have quoted market prices or over-the-counter quotes available from brokers. However, some
derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives have been determined using
valuation techniques or models.

Financial Instruments

The fair value of financial instruments are determined and classified within three categories, which are defined below. The fair value measurement
of a financial instrument is included in only one of the three levels, the determination of which is based upon the lowest level input that is significant to the derivation of the fair value.

Level I

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

Level II

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

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

In
determining Level II fair values of Other Risk Management Assets and Liabilities, the Corporation uses inputs other than unadjusted quoted prices that are
observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the
Corporation relies on similar interest or currency rate inputs and other third party information such as credit spreads. In 2008, the majority of our Level I financial instruments were
reclassified as Level II, which is consistent with industry practice for similar valuation techniques.

Level III

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

In
limited circumstances, Energy Trading may enter into commodity transactions involving non-standard features for which market-observable data is not
available. In these cases, Level III fair values are determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion,
demand profiles, and/or volatilities and correlations between products derived from historical prices.

The
effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III fair values are determined would not
result in materially different fair values.

Valuation of PP&E

As at Dec. 31, 2008, PP&E makes up 77 per cent of our assets, of which 99 per cent relates to the Generation
segment. On an annual basis, and when indicators of impairment exist, we determine whether the net carrying amount of PP&E is recoverable from future undiscounted cash flows. Factors which could
indicate that impairment exists include significant underperformance relative to historical or projected operating results, significant changes in the manner or use of the assets, the strategy for
our overall business, and significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment
does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in
situations where we are not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

2008 Management's Discussion and Analysis59

---



Our
businesses, the markets, and the business environment are continually monitored, and judgments and assessments are made to determine whether an event has occurred that
indicates possible impairment. If such an event has occurred, an estimate is made of the future undiscounted cash flows from the asset. If the total of the undiscounted future cash flows (excluding
financing charges, with the exception of plants that have specifically dedicated debt), is less than the carrying amount of the asset, an asset impairment charge must be recognized in our financial
statements. The amount of the impairment recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset. Fair value is the amount at which an item could be
bought or sold in a current transaction between willing parties, and is best estimated by calculating the net
present value of future expected cash flows related to the asset. Both the identification of events that may trigger an impairment and the estimates of future cash flows and the fair value of the
asset require considerable judgment.

The
assessment of asset impairment requires management to make significant assumptions about future sales prices, cost of sales, production and fuel consumed over the life
of the plants (up to 30 years), retirement costs, and discount rates. In addition, when impairment tests are performed, the estimated useful lives of the plants are reassessed, with
any change accounted for prospectively.

In
estimating future cash flows of the plants, we use estimates of contracted and future market prices based on expected market supply and demand in the region in which
the plant operates, anticipated production levels, planned and unplanned outages, and transmission capacity or constraints for the remaining life of the plant. Actual results can, and often do,
differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.

On
an annual basis, or as events indicate, we perform an impairment review of our plants. As a result of this review, in 2008, there were no material changes. In 2006, we
recorded an impairment charge for the Centralia Gas plant as the full book value of this plant was unlikely to be recovered from future cash flows due to changes in outlook for dispatch rates and
trading values and their impact on plant profitability. Refer to the Significant Events section of this MD&A for further details.

As
a result of the decision to cease mining activities at the Centralia coal mine, we wrote down mining and reclamation equipment as well as mining infrastructure to the
lower of net book value and fair value. Refer to the Significant Events section of this MD&A for further details.

In
2005, we determined that the Ottawa plant was impaired in the accounts of TA Cogen. A fundamental shift in the gas markets and forecast increases in the cost of
natural gas lowered expected margins from the Ottawa plant as TA Cogen does not have a gas supply contract in place for the period 2008-2012 to match the contract to provide
electricity under predetermined prices to the OEFC. Based upon the current view of gas costs and market conditions for that period and the likelihood that the plant will not operate as extensively
beyond 2012, a reduction in the carrying value was required and a charge of $36 million was recognized in 2005.

Asset Retirement Obligations

We recognize ARO for PP&E in the period in which they are incurred if there is a legal obligation for us to reclaim the plant and/or site and if a
reasonable estimate of a fair value can be determined. The fair value of the liability is described as the amount at which the liability could be settled in a current transaction between willing
parties. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many ARO. Expected values are discounted at the
risk-free interest rate adjusted to reflect the market's evaluation of our credit standing.

At
Dec. 31, 2008, the ARO recorded on the consolidated balance sheets were $297 million. We estimate the undiscounted amount of cash flow required to settle
the ARO is approximately $0.8 billion, which will be incurred between 2009 and 2072. The majority of the costs will be incurred between 2020 and 2030. A discount rate of eight per cent
was used to calculate the carrying value of the ARO.

Sensitivities
for the major assumptions are as follows:

Factor


Increase or
decrease


Approximate impact on
earnings and cash flow
(after-tax
)Discount rate


1%


$     2Undiscounted ARO


1%


$     


Useful Life of PP&E

PP&E is depreciated over its estimated useful life. Estimated useful lives were determined based on current facts and past experience, and take
into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, and the potential for technological
obsolescence. Major components of plants are depreciated over their own useful lives. A component is a tangible asset that can be separately identified as an asset and is expected to provide a
benefit of greater than one year.

Depreciation
and amortization expense was $428 million in 2008, of which $32 million relates to mining equipment, and is included in fuel and purchased
power.

The
rates used are reviewed on an ongoing basis to ensure they continue to be appropriate, and are also reviewed in conjunction with impairment testing, as discussed
above.

A
five per cent change in the estimated useful life of depreciable assets will result in a change of $22 million in depreciation and amortization expense
(2007  $20 million).

60TransAlta Corporation    Annual Report 2008

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Valuation of Goodwill

We evaluate goodwill for impairment at least annually or more frequently if indicators of impairment exist. If the carrying value of a reporting
unit, including goodwill, exceeds the reporting unit's fair value, any excess represents a goodwill impairment loss. A reporting unit is a portion of the business for which we can identify specific
cash flows.

Goodwill
was recorded on the acquisitions of Merchant Energy Group of the Americas, Vision Quest, and CE Gen. At Dec. 31, 2008, this goodwill had a total
carrying value of $142 million. The change in value from Dec. 31, 2007 is due to changes in foreign exchange rates related to CE Gen, which is denominated in
U.S. dollars. The change in foreign exchange rates related to the translation of self-sustaining foreign operations does not affect earnings and the cumulative translation gain is
reflected in AOCI.

We
reviewed the recorded value of goodwill prior to year-end and determined that the fair values of our reporting units, based on historical cash flows and estimates of
future cash flows, exceeded their carrying values. There were no significant events that impacted the fair values of the reporting units between the time of our testing and Dec. 31, 2008.
This includes consideration of the current economic environment and related credit crisis, which does not impact the fair value of our assets and liabilities of our reporting units because they are
contracted. Accordingly, no goodwill impairment charges were recorded for the year ended Dec. 31, 2008.

Determining
the fair value of the reporting units is susceptible to changes from period to period as management is required to make assumptions about future cash flows,
production and trading volumes, margins and fuel and operating costs. Had assumptions been made that resulted in fair values of the reporting units declining by 10 per cent from
current levels, there would not have been any impairment of goodwill.

Income Taxes

In accordance with Canadian GAAP, we use the liability method of accounting for future income taxes and provide future income taxes for all
significant income tax temporary differences.

Preparation
of the consolidated financial statements requires an estimate of income taxes in each of the jurisdictions in which we operate. The process involves an
estimate of our current tax exposure and an assessment of temporary differences resulting from differing treatment of items, such as depreciation and amortization, for tax and accounting purposes.
These differences result in future tax assets and liabilities that are included in our consolidated balance sheets.

An
assessment must also be made to determine the likelihood that our future tax assets will be recovered from future taxable income. To the extent that recovery is not
considered likely, a valuation allowance must be determined. Judgment is required in determining the provision for income taxes, future income tax assets and liabilities, and any related valuation
allowance. To the extent a valuation allowance is created or revised, current period earnings will be affected.

Future
tax assets of $251 million have been recorded on the consolidated balance sheets at Dec. 31, 2008
(2007  $343 million). These assets are comprised primarily of unrealized losses from risk management transactions, asset retirement obligation costs,
and net operating and capital loss carryforwards. We believe there will be sufficient taxable income and capital gains that will permit the use of these deductions and carryforwards in the tax
jurisdictions where they exist.

Future
tax liabilities of $610 million have been recorded on the consolidated balance sheets at Dec. 31, 2008
(2007  $649 million). These liabilities are comprised primarily of unrealized gains from risk management transactions and income tax deductions in
excess of related depreciation of PP&E.

Judgment
is required to assess continually changing tax interpretations, regulations and legislation, to ensure liabilities are complete and to ensure assets, net of
valuation allowances, are realizable. The impact of different interpretations and applications could be material.

Our
tax filings are subject to audit by taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately provided
for income taxes based on all information currently available. The outcome of the audits is not known nor is the potential impact on the financial statements determinable.

Employee Future Benefits

We provide selected post-retirement benefits to employees. The cost of providing these benefits is dependent upon many factors that
result from actual plan experience and assumptions of future experience.

The
liability for future benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation
levels, employment periods, the level of contributions made to the plans, and earnings on plan assets.

Changes
to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial
assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

The
plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in
increased or decreased pension costs in future periods.

The
discount rate used reflects high-quality fixed income securities currently available and expected to be available during the period to maturity of the
pension benefits. We do not expect to make any changes to the rate in 2009.

The
expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. For the
year ended Dec. 31, 2008, the plan assets had a negative return of $55 million compared to a positive return of

2008 Management's Discussion and Analysis61

---



$10 million
in 2007 and $35 million in 2006. The 2008 actuarial valuation used the same rate of return on plan assets (seven per cent) as was used in 2007 and 2006.

Current Accounting Changes

Financial Instruments  Disclosures and Presentation

On Jan. 1, 2008, we adopted two new accounting standards: Handbook Section 3862,Financial
Instruments  Disclosuresand Handbook Section 3863,Financial
Instruments  Presentation. Sections 3862 and 3863 replace Handbook Section 3861,Financial
Instruments  Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its
presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages
those risks.

Embedded Foreign Currency Derivatives

On Jan. 8, 2008, the CICA Emerging Issues Committee ("EIC") issued EIC-169Determining Whether a
Contract is Routinely Denominated in a Single Currency. The EIC is intended to provide guidance on when an embedded foreign currency derivative would require bifurcation from
a host contract. EIC-169 became effective for us on Jan. 1, 2008 and its implementation did not have a material impact upon the consolidated financial position or results
of operations.

Employee Future Benefits

During 2008, we assessed the accounting treatment for the amortization of the past service costs and actuarial gains and losses on defined benefit
plans. In prior years, the past service costs and actuarial gains and losses on defined benefit plans had been amortized using the Estimated Average Remaining Service Life ("EARSL"),
which is determined by the actuary as seven years. As a result of the assessment, we have amortized the past service costs and actuarial gains and losses on defined benefit plans under
Canadian GAAP using the Estimated Average Remaining Life ("EARL") for plans whose members are almost all retired, which is determined by the actuary as 17 years. As the members
of the Canadian Registered Plan are now almost all inactive, starting in 2008 the excess of the net cumulative unamortized actuarial gain or loss over 10 per cent of the greater of the
accrued benefit obligation and the market value of plan assets will be amortized over EARL.

We
adopted this method of amortization on Jan. 1, 2008 and its implementation had no material effect on previously reported amounts. This method has not been
applied to the Centralia plan as it did not qualify because its members are not almost all retired. The U.S. plan continues to be amortized using EARSL.

Reclassification of Fair Values

In order to be consistent with practices developed over 2008, we have reclassified over-the-counter derivatives with fair
values based upon observable commodity futures curves, and derivatives with inputs validated by broker quotes, from Level I to Level II. During 2008, we had previously reported these
as Level I. This reclassification did not affect our financial position or earnings.

Recognition of a Tax Loss Carryforward

On Aug. 28, 2008 the CICA EIC issued EIC-172Income Statement Presentation of a Tax Loss Carryforward Recognized Following
an Unrealized Gain Recorded in Other Comprehensive Income. The EIC is intended to provide guidance on whether the tax benefit from the recognition of tax loss carryforwards
consequent to the recording of unrealized gains in OCI, such as unrealized gain on available-for-sale financial assets, should be recognized in net earnings or in OCI. EIC-172 became effective for
us on Sept. 30, 2008 and its implementation did not impact the consolidated financial position or results of operations.

Future Accounting Changes

Credit Risk

On Jan. 20, 2009, the CICA EIC issued EIC-173Credit Risk and the Fair Value of Financial Assets and
Financial Liabilities. Under EIC-173, an entity's own credit risk and the credit risk of the counterparty should be taken into account in determining the fair
value of financial assets and liabilities, including derivative instruments. We will adopt the requirements of EIC-173 effective Jan. 1, 2009. Its implementation is not
expected to have a material impact upon our consolidated financial position or results of operations.

Business Combinations and Non-Controlling Interests  Financial Accounting
Standard ("FAS") 141(R) and FAS 160

The Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board ("IASB") have developed common standards on
Business Combinations and Non-Controlling Interests. The primary objective was to develop a single set of high-quality standards of accounting for business combinations that
could be used for both domestic and cross-border financial reporting. These standards propose significant changes with respect to accounting for business combinations, as well as the accounting and
reporting of non-controlling interests in consolidated financial statements.

The
Boards have completed re-deliberations, and issued final standards in the fourth quarter of 2007 (IASB issued standards in January 2008), that will
be effective for us on Jan. 1, 2009. FASB issued Statement No. 141(R),Business Combinations a
replacement of FASB Statement No. 141, and Statement No. 160,Non-Controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51, in conjunction with the IASB standards. We are currently assessing the impact of
adopting the above standards on the consolidated financial position and results of operations.

62TransAlta Corporation    Annual Report 2008

---



Deferral of Costs and Internally Developed Intangibles

In November 2007, the Accounting Standards Board ("AcSB") approved Section 3064,Goodwill
and Intangible Assets, replacing Section 3062,Goodwill and Other Intangible Assets, and
Section 3450,Research and Development Costs. Section 3064 incorporates material from IAS 38, Intangible Assets, addressing when an
internally developed intangible asset meets the criteria for recognition as an asset. The AcSB also approved
amendments to Accounting Guideline AcG-11,Enterprises in the Development Stagewhich provides consistency with Section 3064.
EIC-27,Revenues and Expenditures during the Pre-Operating Period, will not apply to entities that have adopted
Section 3064. These changes are effective for us on Jan. 1, 2009, and its implementation is not expected to have a material impact upon the consolidated financial position or results
of operations.

International Financial Reporting Standards ("IFRS")

In 2005, the AcSB announced that accounting standards in Canada are to converge with IFRS. On Feb. 13, 2008, the AcSB confirmed that the use
of IFRS will be required for interim and annual financial statements on Jan. 1, 2011, with appropriate comparative financial data for 2010. Under IFRS, there is significantly more disclosure
required, specifically for interim reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy that must
be addressed.

Our
project to convert to IFRS for January 1, 2011 commenced in 2007 and consists of four phases: diagnostic, design and planning, solution development, and
implementation. The diagnostic phase has been completed.

The
project has entered the design and planning stage with issue-specific teams being established to further analyze the key areas of convergence and coordinate with
Information Technology and Internal Control resources to determine process and system changes along with appropriate financial reporting controls. Staff training programs are also in the design and
planning stages and a communication plan is in place.

The
full impact of adopting IFRS on our future financial position and future results cannot be reasonably determined at this time. We are carefully evaluating the
transitional options available under IFRS at the adoption date as well as the most appropriate long-term accounting policies.

Our
preliminary view is that there are many similarities between Canadian GAAP and IFRS and that the major differences for us will likely arise in respect of property,
plant, and equipment, the impairment of long-lived assets, and accounting for long-term contracts.

A
steering committee has been established to monitor the progress and critical decisions in the transition to IFRS. This committee includes representatives from Finance,
Information Technology, Treasury, Investor Relations, Human Resources, and Operations. Quarterly updates are provided to the Audit and Risk Committee.

Non-GAAP Measures

We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below
are not defined under GAAP and therefore should not be considered in isolation or as an alternative to or more meaningful than net income or cash flow from operating activities, as determined in
accordance with GAAP, as an indicator of our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another
company.

Each
business unit assumes responsibility for its operating results measured to gross margin and operating income. Operating income and gross margin provides management
and investors with a measurement of operating performance that is readily comparable from period to period.

Net Earnings Reconciliation

Gross margin and operating income are reconciled to net earnings below:

Year ended Dec. 31


2008


2007


2006Gross margin

$
1,617

$
1,544

$
1,491Operating expenses


(1,084
)

(1,003
)

(1,012
)Operating income before mine closure and asset impairment charges


533


541


479Mine closure charges








(192
)Asset impairment charges








(130
)Operating income


533


541


157Foreign exchange (loss) gain


(12
)

3


(1
)Gain on sale of equipment


5


16


Net interest expense


(110
)

(133
)

(168
)Equity loss


(97
)

(50
)

(17
)Earnings (loss) before non-controlling interests and income taxes


319


377


(29
)Non-controlling interests


61


48


52Earnings before income taxes


258


329


(81
)Income tax expense (recovery)


23


20


(126
)Net earnings

$
235

$
309

$
45


2008 Management's Discussion and Analysis63

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Earnings on a Comparable Basis

Presenting earnings on a comparable basis from period to period provides management and investors with the ability to evaluate earnings trends more
readily in comparison with prior periods' results.

In
calculating comparable earnings for 2008, we have excluded the writedown of our Mexican investment as this is a one-time event.

The
change in life of certain component parts at Centralia Thermal was also excluded from the calculation of comparable earnings as it is related to the cessation of
mining activities at the Centralia coal mine and conversion to consuming solely third party supplied coal. Additionally, we excluded the gains recorded on the sale of assets in 2007 and 2008 at the
previously operated Centralia coal mine as we do not normally dispose of large quantities of fixed assets.

In
calculating comparable earnings for all three years, we have excluded the impact of tax rate changes, the resolution of outstanding uncertain tax positions, and the tax
law change in Mexico as they do not relate to the earnings in the period in which they have been reported.

In
arriving at comparable earnings for 2006 we have excluded the turbine impairment charge recorded in the first quarter of 2006.

Earnings
on a comparable basis are reconciled to net earnings below:

Year ended Dec. 31


2008


2007


2006Net earnings

$
235

$
309

$
45Sale of assets at Centralia


(4
)

(10
)

Change in life of Centralia parts, net of tax


12


3


Change in tax law in Mexico





28


Tax rate change





(48
)

(55
)Turbine impairment, net of tax








6Recovery from resolution of uncertain tax positions


(15
)

(18
)

Centralia Gas impairment, net of tax








84Centralia Coal writedown, net of tax








154Investments writedown, net of tax


62





Earnings on a comparable basis

$
290

$
264

$
234Weighted average common shares outstanding in the period


199


202


201Earnings on a comparable basis per share

$
1.46

$
1.31

$
1.16


Free Cash Flow

Free cash flow is intended to demonstrate the amount of cash we have available to invest in capital growth initiatives, repay recourse debt, or
repurchase common shares.

The
payment of Centralia coal mine closure costs have also been excluded as they are one-time in nature. Sustaining capital expenditures for the year ended
Dec. 31, 2008, represents total capital expenditures per the statement of cash flow less $541 million ($515 million net of joint venture contributions) that we have invested in
growth projects.

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

Year ended Dec. 31


2008


2007


2006Cash flow from operating activities

$
1,038

$
847

$
490Add (Deduct):Sustaining capital expenditures


(465
)

(417
)

(214
)Dividends on common shares


(212
)

(205
)

(134
)Distribution to subsidiaries' non-controlling interest


(98
)

(87
)

(74
)Non-recourse debt repayments


(28
)

(47
)

(51
)Timing of contractualy scheduled payments


(116
)




185Centralia closure costs





24


Cash flows from equity investments


2


(4
)

28Free cash flow

$
121

$
111

$
230


Cash flows from equity investments represent operational cash flow from our equity subsidiaries less sustaining and growth
capital expenditures.

Comparable Return on Capital Employed

Comparable ROCE measures economic value created from capital investments and is calculated by taking comparable earnings before tax and
dividing by total assets less current liabilities. Presenting this calculation using comparable earnings before tax provides management and investors with the ability to evaluate trends on the
returns generated in comparison with other periods.

64TransAlta Corporation    Annual Report 2008

---



The
calculation of comparable earnings before tax is presented below:

Year ended Dec. 31


2008


2007


2006Earnings (loss) before income taxes as per statement of earnings

$
258

$
329

$
(81
)Net interest expense


110


133


168Non-controlling interest


61


48


52Mine closure charges and inventory writedown, pre-tax








236Asset impairment charges, pre-tax








130Turbine impairment, pre-tax








10Change in life of Centralia parts, pre-tax


18


6


Sale of assets at Centralia, pre-tax


(6
)

(15
)

Change in tax law in Mexico





28


Investments writedown, pre-tax


97





Comparable earnings, pre-tax

$
538

$
529

$
515


Selected Quarterly Information

Q1 2008


Q2 2008


Q3 2008


Q4 2008Revenue

$
803

$
708

$
791

$
808Net earnings


33


47


61


94Basic earnings per common share


0.17


0.24


0.31


0.47Diluted earnings per common share


0.17


0.24


0.31


0.47




Q1 2007


Q2 2007


Q3 2007


Q4 2007Revenue

$
669

$
612

$
711

$
783Net earnings


56


57


66


130Basic earnings per common share


0.28


0.28


0.33


0.64Diluted earnings per common share


0.28


0.28


0.33


0.64


Controls and Procedures

As required by Rule 13a-15 under theSecurities Exchange
Actof 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 are 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 was 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, the Company's internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Dec. 31,
2008, 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 document, 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. In
some cases, forward-looking statements can be identified by terms such as "may", "will", "believe", "expect", "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 those projected.
Some of the risks, uncertainties, and factors include, but are not limited to electricity demand and generation capacity, plant availability, cost and availability of fuel necessary for the
production of electricity, legislative and regulatory developments, costs associated with environmental compliance, overall costs, competition, global capital markets activity, changes in prevailing
interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where we operate, results of financing efforts, changes in counterparty risk and the
impact of accounting policies issued by Canadian and U.S. standard setters. Given these uncertainties, readers are cautioned not to place undue reliance on this forward-looking information, which is
given as of the date hereof or otherwise, 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.

2008 Management's Discussion and Analysis65

---





Management's Report

To
the Shareholders of TransAlta Corporation

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

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

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



GRAPHIC

GRAPHICSTEPHEN G. SNYDERPresident & Chief Executive Officer

BRIAN BURDENExecutive Vice-President & Chief Financial Officer


March 4, 2009

66TransAlta Corporation    Annual Report 2008

---





Management's Annual Report on
Internal Control over Financial Reporting

To
the Shareholders of TransAlta Corporation

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

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

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

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

TransAlta
Corporation's Consolidated Financial Statements include the accounts of the Sheerness, CE Generation, Wailuku, and Genesee 3 joint ventures via
proportionate consolidation in accordance with Canadian GAAP. Management does not have the contractual ability to assess the internal controls of these joint ventures. Once the financial information
is obtained from the joint ventures it falls within the scope of TransAlta Corporation's internal controls framework. Management's conclusion regarding the effectiveness of internal controls does
not extend to the internal controls at the transactional level of the joint ventures. The 2008 Consolidated Financial Statements of TransAlta Corporation included $1,680 million and
$747 million of total and net assets, respectively, as of Dec. 31, 2008, and $481 million and $53 million of revenues and net earnings, respectively, for the year then
ended related to these joint ventures.

Management
has assessed the effectiveness of TransAlta Corporation's internal control over financial reporting, as at Dec. 31, 2008, and has concluded that such
internal control over financial reporting is effective.

Ernst &
Young LLP, who has audited the Consolidated Financial Statements of TransAlta Corporation for the year ended Dec. 31, 2008, has also issued a
report on internal control over financial reporting under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States). This report is located on
Page 68 of this Annual Report.



GRAPHIC

GRAPHICSTEPHEN G. SNYDERPresident & Chief Executive Officer

BRIAN BURDENExecutive Vice-President & Chief Financial Officer


March 4, 2009

2008 Consolidated Financial Statements67

---





Independent Auditors'Report on Internal Controls Under Standards  of the Public Company Accounting Oversight Board (United States)

To
the Shareholders of TransAlta Corporation

We
have audited TransAlta Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal
Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Corporation's
management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in
the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting
based on our audit.

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

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

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

As
indicated in the accompanying Management's Annual Report on Internal Control over Financial Reporting, management's assessment of and conclusion on the effectiveness of
internal control over financial reporting did not include the internal controls of the CE Generation, Sheerness, Wailuku, and Genesee 3 joint ventures, which is included in the 2008
consolidated financial statements of the Corporation and constituted $1,680 million and $747 million of total and net assets, respectively, as of December 31, 2008, and
$481 million and $53 million of revenues and net earnings, respectively, for the year then ended. Our audit of internal control over financial reporting of the Corporation did not
include an evaluation of the internal control over financial reporting of the CE Generation, Sheerness, Wailuku, and Genesee 3 joint ventures.

In
our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on
the COSO criteria.

We
have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of TransAlta Corporation as of December 31, 2008 and 2007 and the related consolidated statements of earnings and retained earnings,
comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated March 4, 2009, expressed an unqualified
opinion thereon.

GRAPHIC

ERNST & YOUNG LLPChartered Accountants

Calgary,
Canada
March 4, 2009

68TransAlta Corporation    Annual Report 2008

---





Independent Auditors'Report
on Financial Statements

To
the Shareholders of TransAlta Corporation

We
have audited the consolidated balance sheets of TransAlta Corporation as at December 31, 2008 and 2007 and the consolidated statements of earnings and retained
earnings, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the Corporation's
management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Corporation as at
December 31, 2008 and 2007 and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008 in conformity with
Canadian generally accepted accounting principles.

As
discussed in Note 2(B) to the consolidated financial statements, in 2007 the Corporation changed its method of accounting for comprehensive income, financial
instruments, hedges, and inventories.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation's internal control over
financial reporting as of December 31, 2008, based on criteria established in Internal Control  Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2009 expressed an unqualified opinion thereon.

GRAPHIC

ERNST & YOUNG LLPChartered Accountants

Calgary,
Canada
March 4, 2009

2008 Consolidated Financial Statements69

---





Consolidated Statements of Earnings  and Retained Earnings

Year ended Dec. 31(in millions of Canadian dollars)


2008


2007


2006Revenues

$
3,110

$
2,775

$
2,677Fuel and purchased power(Notes 1 and 3)


(1,493
)

(1,231
)

(1,186
)Gross margin


1,617


1,544


1,491Operations, maintenance, and administration


637


577


581Depreciation and amortization


428


406


410Taxes, other than income taxes


19


20


21Operating expenses


1,084


1,003


1,012Mine closure charges(Note 3)








192Asset impairment charges(Note 4)








130Operating income


533


541


157Foreign exchange (loss) gain(Note 7)


(12
)

3


(1
)Gain on sale of equipment(Note 16)


5


16


Net interest expense(Notes 7 and 21)


(110
)

(133
)

(168
)Equity loss(Notes 13 and 27)


(97
)

(50
)

(17
)Earnings (loss) before non-controlling interests and income taxes


319


377


(29
)Non-controlling interests(Note 5)


61


48


52Earnings (loss) before income taxes


258


329


(81
)Income tax expense (recovery)(Note 6)


23


20


(126
)Net earnings

$
235

$
309

$
45Retained earningsOpening balance


763


710


866Common share dividends


(215
)

(202
)

(201
)Shares cancelled under NCIB(Note 25)


(95
)

(54
)

Closing balance

$
688

$
763

$
710Weighted average number of common shares outstanding in the period


199


202


201Net earnings per share, basic and diluted(Note 24)

$
1.18

$
1.53

$
0.22


See accompanying notes.

70TransAlta Corporation    Annual Report 2008

---





Consolidated Balance Sheets

Dec. 31(in millions of Canadian dollars)


2008


2007Assets


(Restated, Note 2)Current assetsCash and cash equivalents(Note 7)

$
50

$
51Accounts receivable(Notes 7, 8, and 31)


542


546Prepaid expenses


6


9Risk management assets(Notes 7, 9, and 10)


200


93Future income tax assets(Note 6)


3


40Income taxes receivable


61


49Inventory(Note 11)


51


30913


818Restricted cash(Notes 7 and 12)





242Investments(Note 13)





125Long-term receivables(Notes 6 and 14)


14


6Property, plant, and equipment(Note 15)Cost


9,919


8,593Accumulated depreciation


(3,898
)

(3,476
)6,021


5,117Assets held for sale, net(Note 16)





29Goodwill(Notes 17 and 32)


142


125Intangible assets(Note 18)


213


209Future income tax assets(Note 6)


248


303Risk management assets(Notes 7, 9, and 10)


221


122Other assets(Note 19)


43


61Total assets

$
7,815

$
7,157Liabilities and Shareholders' EquityCurrent liabilitiesShort-term debt(Notes 7 and 20)

$
443

$
651Accounts payable and accrued liabilities(Note 7)


682


473Risk management liabilities(Notes 7, 9, and 10)


148


105Income taxes payable


15


17Future income tax liabilities(Note 6)


14


12Dividends payable


52


49Current portion of long-term debt  recourse(Notes 7 and 21)


211


122Current portion of long-term debt  non-recourse(Notes 7 and 21)


33


32Current portion of asset retirement obligations(Note 22)


45


431,643


1,504Long-term debt  recourse(Notes 7 and 21)


1,889


1,474Long-term debt  non-recourse(Notes 7 and 21)


232


209Asset retirement obligation(Note 22)


252


233Deferred credits and other long-term liabilities(Note 23)


122


101Future income tax liabilities(Note 6)


596


637Risk management liabilities(Notes 7, 9, and 10)


102


204Non-controlling interests(Note 5)


469


496Common shareholders' equityCommon shares(Notes 24 and 25)


1,761


1,781Retained earnings(Note 25)


688


763Accumulated other comprehensive income (loss)(Note 25)


61


(245
)Total shareholders' equity


2,510


2,299Total liabilities and shareholders' equity

$
7,815

$
7,157


Contingencies(Notes 29 and 31)Commitments(Notes 9 and 30)

Subsequent
events(Note 36)

On behalf of the Board:GRAPHIC

GRAPHICSee accompanying notes.

DONNA SOBLE KAUFMANDirector

WILLIAM D. ANDERSONDirector


2008 Consolidated Financial Statements71

---





Consolidated Statements of  Comprehensive Income

Year ended Dec. 31(in millions of Canadian dollars)


2008


2007


2006Net earnings

$
235

$
309

$
45Other comprehensive income (loss)Gains (losses) on translating net assets of self-sustaining foreign operations


342


(196
)

4(Losses) gains on financial instruments designated as
hedges of self-sustaining foreign operations


(356
)

240


(2
)Tax (recovery) expense


(61
)

25


(Losses) gains on financial instruments designated as
hedges of self-sustaining foreign operations


(295
)

215


(2
)Gains on translation of self-sustaining foreign operations


47


19


2Gains (losses) on derivatives designated as cash flow hedges


327


(57
)

Tax expense (recovery)


129


(16
)

Gains (losses) on derivatives designated as cash flow hedges


198


(41
)

Deferred foreign exchange losses on translating net assets
of self-sustaining foreign operations transferred to net earnings
in the current period(Note 27)


(147
)




Deferred gains on financial instruments designated as hedges
of self-sustaining foreign operations transferred to net earnings
in the current period(Note 27)


148





Tax expense


9





Loss on sale of Mexico reclassified to statement of earnings


(8
)




Derivatives designated as cash flow hedges in prior periods transferred to balance sheet in the current period


8


1


Derivatives designated as cash flow hedges in prior periods transferred to net earnings in the current period


91


25


Tax expense


30


7


Reclassification of derivatives designated as cash flow hedges


69


19


Other comprehensive income (loss)


306


(3
)

2Comprehensive income

$
541

$
306

$
47


See accompanying notes.

72TransAlta Corporation    Annual Report 2008

---





Consolidated Statements
of Cash Flows

Year ended Dec. 31(in millions of Canadian dollars)


2008


2007


2006Operating activitiesNet earnings

$
235

$
309

$
45Depreciation and amortization(Note 32)


451


415


438Gain on sale of equipment(Note 16)


(5
)

(16
)

Non-controlling interests(Note 5)


61


48


52Asset retirement obligation accretion(Note 22)


22


24


22Asset retirement costs settled(Note 22)


(37
)

(38
)

(29
)Future income taxes (recovered)(Note 6)


1


(34
)

(164
)Unrealized losses (gains) from risk management activities


12


26


(32
)Unrealized foreign exchange (gain) loss


(5
)

(3
)

1Mine closure charges(Note 3)








192Asset impairment charges(Note 4)








130Equity loss(Notes 13 and 27)


97


50


17Other non-cash items


(4
)




7828


781


679Change in non-cash operating working capital balances


210


66


(189
)Cash flow from operating activities


1,038


847


490Investing activitiesAdditions to property, plant, and equipment


(1,006
)

(599
)

(224
)Proceeds on sale of property, plant, and equipment


30


47


29Proceeds on sale of equity investment(Notes 13 and 27)


332





Equity investment(Notes 13 and 27)





(20
)

226Restricted cash(Note 12)


248


57


(333
)Income tax receivable(Notes 6 and 14)


(8
)




Realized gains on financial instruments


52


107


54Loan to equity investment


(245
)




Other(Note 27)


16


(2
)

(13
)Cash flow used in investing activities


(581
)

(410
)

(261
)Financing activities(Decrease) increase in short-term debt


(243
)

289


348Issuance of long-term debt(Note 21)


502


30


Repayment of long-term debt(Note 21)


(308
)

(252
)

(397
)Dividends paid on common shares


(212
)

(205
)

(134
)Redemption of preferred securities





(175
)

Funds paid to repurchase common shares under NCIB(Note 25)


(130
)

(75
)

Net proceeds on issuance of common shares(Note 24)


15


20


13Decrease in advances to TransAlta Power





6


1Realized gains on financial instruments


12





Distributions to subsidiaries' non-controlling interests


(98
)

(87
)

(74
)Other


(5
)

5


Cash flow used in financing activities


(467
)

(444
)

(243
)Cash flow used in operating, investing, and financing activities


(10
)

(7
)

(14
)Effect of translation on foreign currency cash


9


(8
)

1Decrease in cash and cash equivalents


(1
)

(15
)

(13
)Cash and cash equivalents, beginning of year


51


66


79Cash and cash equivalents, end of year

$
50

$
51

$
66Cash taxes paid

$
47

$
75

$
36Cash interest paid

$
106

$
142

$
181


See accompanying notes.

2008 Consolidated Financial Statements73

---





Notes to the Consolidated  Financial Statements

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

1.  Summary of Significant Accounting Policies

A.   Description of the Business

TransAlta Corporation ("TransAlta" or "the Corporation"), was incorporated under theCanada Business Corporations
Actin March 1985. The Corporation became a public company in December 1992 after TransAlta Utilities Corporation ("TAU") became a subsidiary. The Corporation has two
reportable segments that are supported by a corporate group that provides finance, treasury, tax, legal, environmental health and safety, sustainable development, corporate communications,
government relations, information technology, human resources, internal audit, and other administrative support.

The
two reportable segments of the Corporation are as follows:

I.   Generation

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

II.   Commercial Operations & Development ("COD")

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

B.   Consolidation

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

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

C.   Use of Estimates

The preparation of financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the
period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, currency exchange rates, inflation levels
and commodity prices, changes in economic conditions and legislative and regulatory changes (Notes 7, 9, 10, 15, 17, 18, 21, 22, 29, 33, and 34).

D.   Revenue Recognition

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

Trading
activities use derivatives such as physical and financial swaps, forward sales contracts and futures contracts and options, which are used to earn trading revenues
and to gain market information. These derivatives are accounted for using fair value accounting and are presented on a net basis in the statements of earnings. The initial recognition of fair value
and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized
gains or losses and are presented on the balance sheets as risk management assets or liabilities.

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

E.   Inventory

The majority of cost of goods sold as recorded on the statements of earnings reflects the cost of inventory consumed in the generation of
electricity. All inventory is carried at the lower of cost and net realizable value and cost is determined using the weighted average cost method.

74TransAlta Corporation    Annual Report 2008

---





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

The
cost of natural gas inventory is determined using absorption costing which includes all applicable expenditures and charges incurred in bringing inventory to its
existing condition and location.

F.   Property, Plant, and Equipment

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

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

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

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

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

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

G.   Goodwill

Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of an acquired business. Goodwill is not
subject to amortization, but instead is tested for impairment at least annually, or more frequently if an analysis of events and circumstances indicate that a possible impairment may exist. These
events could include a significant change in financial position of the reporting unit to which the goodwill relates or significant negative industry or economic trends. To test for impairment, the
fair value of the reporting units to which the goodwill relates is compared to the carrying values of the reporting units. The Corporation determined that the fair values of the reporting units,
exceeded their carrying values as at Dec. 31, 2008 and 2007.

H.   Intangible Assets

Intangible assets consist of power sale contracts, with rates higher than market rates at the date of acquisition, primarily
acquired in the purchase of CE Generation LLC ("CE Gen"), a jointly controlled enterprise(Note 35). Sale contracts are
valued at cost and are amortized on a straight-line basis over the remaining applicable contract period, which ranges from one to 24 years.

I.   Asset Retirement Obligations ("ARO")

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

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

2008 Notes to the Consolidated Financial Statements75

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For
active mines, accretion expense is included in fuel and purchased power. However, as the Centralia coal mine is considered inactive, related accretion expense is
included as part of depreciation expense. In 2006, $9 million was recorded in fuel expense related to accretion expense incurred at the Centralia coal mine.

J.   Investments

On Oct. 8, 2008, the Corporation successfully completed the sale of the Mexican business to InterGen Global Ventures B.V.
("InterGen")(Notes 13 and 27). Prior to the sale, the wholly owned subsidiaries that held TransAlta's interests in the Campeche and
Chihuahua power plants were considered Variable Interest Entities ("VIEs") and were shown as equity investments.

Investments
in shares of companies over which the Corporation exercises significant influence are accounted for using the equity method. Other investments are carried at
cost. If there is other than a temporary decline in the value of an investment, it is written down to net realizable value. There are currently no such investments.

K.   Income Taxes

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

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

L.   Employee Future Benefits

The Corporation accrues its obligations under employee benefit plans and the related costs, net of plan assets. The cost of
pensions and other post-employment and post-retirement benefits earned by employees is actuarially determined using the projected benefit method pro-rated on
services and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees, and expected health care costs. The defined benefit pension plans
are based on an employee's final average earnings and years of service. The expected return on plan assets is based on expected future capital market returns. The discount rate used to calculate the
interest cost on the accrued benefit obligation is determined by reference to market interest rates at the balance sheet date on high-quality debt instruments with cash flows that match
the timing and amount of expected benefit payments. Past service costs from plan amendments were amortized on a straight-line basis over the Estimated Average Remaining Service Life
("EARSL") of employees active at the date of amendment. The excess of the net cumulative unamortized actuarial gain or loss over 10 per cent of the greater of the
accrued benefit obligation and the market value of plan assets is amortized over EARSL(Note 2). When the restructuring of a benefit plan gives
rise to both a curtailment and settlement of obligations, the curtailment is accounted for prior to the settlement. Transition obligations and assets arising from the prospective adoption of new
accounting standards were amortized over EARSL. As the members of the Canadian Registered Plan are now almost all inactive, starting in 2008 the excess of the net cumulative unamortized actuarial
gain or loss over 10 per cent of the greater of the accrued benefit obligation and the market value of plan assets will be amortized over the Estimated Average Remaining Life ("EARL").
The U.S. plan continues to be amortized over EARSL.

M.   Foreign Currency Translation

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

The
Corporation's self-sustaining foreign operations are translated using the current rate method. Translation gains and losses resulting from translating
these foreign operations are included in Other Comprehensive Income ("OCI") with the cumulative gain or loss reported in Accumulated Other Comprehensive Income ("AOCI"). Foreign currency denominated
monetary and non-monetary assets and liabilities of self-sustaining foreign operations are translated at exchange rates in effect on the balance sheet date.

Transactions
denominated in foreign currencies are translated at the exchange rate on the transaction date. The resulting exchange gains and losses on these items are
included in net earnings.

N.   Financial Instruments and Hedges

I.   Financial Instruments

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

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

Derivative
instruments are recorded on the consolidated balance sheets at fair value, including those derivatives that are embedded in financial or
non-financial contracts that are not closely related to the host contracts. TransAlta recognizes as separate assets and liabilities only those derivatives embedded in hybrid instruments
issued, acquired, or substantively modified after Jan. 1, 2003. Changes in the fair values of derivative instruments are recognized in net earnings with the exception of the effective portion
of (i) derivatives designated as cash flow hedges or

76TransAlta Corporation    Annual Report 2008

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(ii) hedges
of foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in OCI. Derivatives used in trading activities are
described in more detail in Note 1(D).

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

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

II.   Hedges

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

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

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

a.   Fair Value Hedges

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

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

b.   Cash Flow Hedges

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

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

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

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

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

The
Corporation primarily uses cross-currency interest rate swaps, foreign currency forward contracts, and foreign currency debts to hedge exposure to changes in the
carrying values of the Corporation's net investments in foreign operations as a result of changes in foreign exchange

2008 Notes to the Consolidated Financial Statements77

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rates.
Gains and losses on these instruments that qualify for hedge accounting are reported in OCI with fair values recorded in risk management assets or liabilities.

O.   Stock-Based Compensation Plans

The Corporation has three types of stock-based compensation plans as described in Note 33. Under the fair value method for
stock options, compensation expense is measured at the grant date at fair value and recognized over the service period.

Stock
grants under the Performance Share Ownership Plan ("PSOP") are accrued in operations, maintenance, and administration ("OM&A") expense as earned to the balance sheet
date, based upon the percentile ranking of the total shareholder return of the Corporation's common shares in comparison to the total shareholder returns of companies comprising the
Standard & Poor's ("S&P")/Toronto Stock Exchange ("TSX") Composite Index. Compensation expense under the phantom stock option plan is recognized in OM&A for the amount by which the quoted
market price of TransAlta's shares exceed the option price, and adjusted for changes in each period for changes in the excess over the option price. If stock options or stock are repurchased from
employees, the excess of the consideration paid over the carrying amount of the stock option or stock cancelled is charged to retained earnings.

P.   Cash and Cash Equivalents

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

Q.   Long-Term Debt

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

R.   Accounting for Emission Credits and Allowances

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

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

S.   Planned Maintenance

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

2.  Accounting Changes

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

During
2008, the fair value balances related to interest rate swap unwinds were included as part of recourse debt. In 2007, $22 million was also reclassified in
order to present comparable figures.

A.   Current Accounting Changes

I.   Financial Instruments  Disclosures and Presentation

On Jan. 1, 2008, the Corporation adopted two new accounting standards: Handbook
Section 3862,Financial Instruments  Disclosuresand Handbook Section 3863, Financial Instruments  Presentation.Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments  Disclosure and Presentation, revising and enhancing its disclosure requirements, and
carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising
from financial instruments and how the entity manages those risks. Disclosures required as a result of adopting these sections can be found in Note 7.

II.   Embedded Foreign Currency Derivatives

On Jan. 8, 2008, the Canadian Institute of Chartered Accountants ("CICA") Emerging Issues
Committee ("EIC") issued EIC-169Determining Whether a Contract is Routinely Denominated in a Single Currency. The EIC is intended to
provide guidance on when an embedded foreign currency derivative would require bifurcation from a host contract. EIC-169 became effective for TransAlta on Jan. 1, 2008 and
its implementation did not have a material impact upon the consolidated financial position or results of operations.

III.   Employee Future Benefits

During 2008, TransAlta assessed the accounting treatment for the amortization of the past service costs
and actuarial gains and losses on defined benefit plans. In prior years, the past service costs and actuarial gains and losses on defined benefit plans had been amortized using EARSL, which is
determined by the actuary as seven years. As a result of the assessment, TransAlta amortized the past service costs and actuarial gains and losses on defined benefit plans under Canadian GAAP
using EARL for plans whose members are almost all retired, which is determined by the actuary as 17 years. As the members of the Canadian Registered Plan are now almost all inactive, starting
in 2008 the excess of the net cumulative unamortized actuarial gain or loss over 10 per cent of the greater of the accrued benefit obligation and the market value of plan assets will
be amortized over EARL.

TransAlta
adopted this method of amortization on Jan. 1, 2008 and its implementation had no material effect on previously reported amounts. This method has not been
applied to the Centralia plan as it did not qualify because its members are not almost all retired. The U.S. plan continues to be amortized using EARSL.

IV.   Reclassification of Fair Values

In order to be consistent with practices developed over 2008, the Corporation has reclassified
over-the-counter derivatives with fair values based

78TransAlta Corporation    Annual Report 2008

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upon
observable commodity futures curves, and derivatives with inputs validated by broker quotes, from Level I to Level II (Note 9). During 2008, the Corporation had previously reported these
as Level I. This reclassification did not affect the financial
position or earnings of the Corporation.

V.   Recognition of a Tax Loss Carryforward

On Aug. 28, 2008 the CICA EIC issued EIC-172Income Statement
Presentation of a Tax Loss Carryforward Recognized Following an Unrealized Gain Recorded in Other Comprehensive Income. The EIC is intended to provide guidance on whether the
tax benefit from the recognition of tax loss carryforwards consequent to the recording of unrealized gains in OCI, such as unrealized gain on available-for-sale financial assets, should be
recognized in net earnings or in OCI. EIC-172 became effective for TransAlta on Sept. 30, 2008 and its implementation did not impact the consolidated financial position or results
of operations.

B.   Prior Year Accounting Changes

I.   Inventories

In March 2007, the CICA issued Section 3031, Inventories, which aligns accounting for inventories under Canadian GAAP with International Financial Reporting Standards ("IFRS").
TransAlta early
adopted this standard. This standard did not have a material effect on the financial statements.

II.   Capital Disclosure

On Dec. 1, 2006, the CICA issued Section 1535,Capital
Disclosures. TransAlta early adopted this standard and provided the required disclosure in Note 26.

III.   General Standards on Financial Statement Presentation

On June 1, 2007, the CICA issued Section 1400,General Standards
on Financial Statement Presentation. TransAlta early adopted this standard and did not require any additional disclosures.

IV.   Financial Instruments

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

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

V.   Comprehensive Income

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

VI.   Financial Instruments  Recognition and Measurement

Section 3855 establishes standards for recognizing and measuring financial assets, financial
liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the consolidated balance sheets when the
Corporation becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to
be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as
held for trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Transaction costs are expensed as
incurred for financial instruments classified or designated as held for trading. For other financial instruments, transaction costs are capitalized on initial recognition and amortized using the
effective interest rate method. Financial liabilities are removed from the financial statements when the liability is extinguished either through settlement of or release from the obligation of the
underlying liability.

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

Derivative
instruments are recorded on the consolidated balance sheets at fair value, including those derivatives that are embedded in financial or
non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net earnings with the exception of the
effective portion of (i) derivatives designated as effective cash flow hedges or (ii) hedges of foreign currency exposure of a net investment in a self-sustaining foreign
operation, which are recognized in OCI.

Section 3855
also provides an entity the option to designate a financial instrument as held for trading (the fair value option) on its initial recognition or
upon adoption of the standard, even if the financial instrument, other than loans and receivables, was not acquired or incurred principally for the purpose of selling or repurchasing it in the near
term. An instrument that is classified as held for trading by way of this fair value option must have reliable fair values and satisfy one of the following criteria (i) when doing so
eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise from measuring assets or liabilities, or recognizing gains and losses on them on a different
basis or (ii) it belongs to a group of financial assets, financial liabilities or both which are managed and evaluated on a fair value basis in accordance with TransAlta's risk management
strategy, and are reported to senior management personnel on that basis.

Other
significant accounting implications arising upon the adoption of Section 3855 include the use of the effective interest rate method of amortization for any
transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost, and the recognition of the inception fair value of the obligation undertaken
in issuing a guarantee that meets the definition of a guarantee pursuant to Accounting Guideline 14,Disclosure of Guarantees("AcG-14"). No subsequent re-measurement at fair value is required unless the financial

2008 Notes to the Consolidated Financial Statements79

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guarantee
qualifies as a derivative. If the financial guarantee meets the definition of a derivative it is re-measured at fair value at each balance sheet date and reported as a
derivative in other assets or other liabilities, as appropriate.

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

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

VII.   Hedges

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

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

In
a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while any ineffective portion is
recognized in net earnings. When hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the variability in the cash
flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified immediately to net earnings when the hedged item is sold or early terminated, or the hedged
anticipated transaction is probable of not occurring.

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

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

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

The transition adjustments attributable to the re-measurement of financial assets and
financial liabilities at fair value, other than hedging instruments designated as cash flow hedges or hedges of foreign currency exposure of net investment in self-sustaining foreign
operations available for sale financial assets, were recognized in opening retained earnings (the value of which was nil) as at Jan. 1, 2007. Adjustments arising from
re-measuring financial assets classified as available-for-sale at fair value were recognized in opening AOCI as at that date.

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

IX.   Variable Interest Entities ("VIEs")

On Sept. 15, 2006, the EIC issued Abstract No. 163,Determining
the Variability to be Considered in Applying AcG-15("EIC-163"). EIC-163 provides additional clarification on how to analyze and
consolidate VIEs when transactions take place to reduce the variability in the entity. EIC-163 became effective on Jan. 1, 2007, and its implementation does not have a
material impact upon the consolidated financial position or results of operations.

C.   Future Accounting Changes

I.   Credit Risk

On Jan. 20, 2009, the CICA EIC issued EIC-173Credit Risk and
the Fair Value of Financial Assets and Financial Liabilities. Under EIC173, an entity's own credit risk and the credit risk of the counterparty should be taken
into account in determining the fair value of financial assets and liabilities, including derivative instruments. TransAlta will adopt the requirements of EIC-173 effective
Jan. 1, 2009. Its implementation is not expected to have a material impact upon the consolidated financial position or results of operations.

II.   Business Combinations and Non-Controlling
Interests  FAS 141(R) and FAS 160

The FASB and the IASB have developed common standards on Business Combinations and
Non-Controlling Interests. The primary objective was to develop a single set of high-quality standards of accounting for business combinations that could be used for both
domestic and cross-border financial reporting. These standards propose significant changes with respect to accounting for business combinations, as well as the accounting and reporting of
non-controlling interests in consolidated financial statements.

The
Boards have completed re-deliberations, and issued final standards in the fourth quarter of 2007 (IASB issued standards in January 2008), that will
be effective for TransAlta on Jan. 1, 2009. FASB issued Statement No. 141(R),Business
Combinations a replacement of FASB Statement

80TransAlta Corporation    Annual Report 2008

---



No. 141,
and Statement No. 160,Non-Controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51, in conjunction with the IASB standards. The Corporation is currently assessing the
impact of adopting the above standards on the consolidated financial position and results of operations.

III.   Deferral of Costs and Internally Developed Intangibles

In November 2007, the Accounting Standards Board ("AcSB") approved Section 3064, Goodwill and Intangible Assets, replacing Section 3062,Goodwill and Other Intangible
Assets, and Section 3450,Research and Development Costs. Section 3064 incorporates material from
IAS 38,Intangible Assets, addressing when an internally developed intangible asset meets the criteria for recognition as an asset. The AcSB
also approved amendments to Accounting Guideline AcG-11,Enterprises in the Development Stagewhich provides consistency with
Section 3064. EIC-27,Revenues and Expenditures during the Pre-Operating Period, will not apply to entities that have
adopted Section 3064. These changes are effective for TransAlta on Jan. 1, 2009, and its implementation is not expected to have a material impact upon the consolidated financial
position or results of operations.

IV.   International Financial Reporting Standards ("IFRS")

In 2005, the AcSB announced that accounting standards in Canada are to converge with IFRS. On
Feb. 13, 2008, the AcSB confirmed that the use of IFRS will be required for interim and annual financial statements on Jan. 1, 2011, with appropriate comparative financial data for
2010. Under IFRS, there is significantly more disclosure required, specifically for interim reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significant
differences in accounting policy that must be addressed.

TransAlta's
project to convert to IFRS for January 1, 2011 commenced in 2007 and consists of four phases: diagnostic, design and planning, solution development, and
implementation. The diagnostic phase has been completed.

The
project has entered the design and planning stage with issue-specific teams being established to further analyze the key areas of convergence and coordinate with
Information Technology and Internal Control resources to determine process and system changes along with appropriate financial reporting controls. Staff training programs are also in the design and
planning stages and a communication plan is in place.

The
full impact of adopting IFRS on TransAlta's future financial position and future results cannot be reasonably determined at this time. TransAlta is carefully
evaluating the transitional options available under IFRS at the adoption date as well as the most appropriate long-term accounting policies.

TransAlta's
preliminary view is that there are many similarities between Canadian GAAP and IFRS and that the major differences for TransAlta will likely arise in respect
of property, plant, and equipment, the impairment of long-lived assets, and accounting for long-term contracts.

A
steering committee has been established to monitor the progress and critical decisions in the transition to IFRS. This committee includes representatives from Finance,
Information Technology, Treasury, Investor Relations, Human Resources, and Operations. Quarterly updates are provided to the Audit and Risk Committee.

2008 Notes to the Consolidated Financial Statements81

---





3.  Mine Closure Charges

On Nov. 27, 2006, TransAlta ceased mining activities at the Centralia coal mine as a result of increased costs and
unfavourable geological conditions. All associated mining and reclamation equipment was written down to the lower of net book value or anticipated realized proceeds. Mine infrastructure, including
coal processing equipment and structures, haul roads, and other equipment were written down to anticipated net salvage value. Asset retirement costs, representing the unamortized cost of future
reclamation, were also written off. In addition, employee termination costs and other miscellaneous expenses were recorded. The total of these writedowns and provisions before taxes was
$192 million.

As
a result of the cessation of mining activities, all internally produced coal was also written down to fair market value, which is replacement cost, resulting in an
expense of $44 million being recorded in fuel and purchased power. The total amounts are summarized in the table below:

Writedown of coal
inventory

$
44Impact on gross margin


(44
)Mine closure chargesMine equipment and infrastructure writedown


72ARO writedown


81Severance costs and other


39Total mine closure charges


192Loss before income taxes

$
(236
)Income tax recovery


82Net loss impact of event

$
(154
)


As at Dec. 31, 2008 all severance costs and other have been paid.

4.  Asset Impairment Charges

For the year ended Dec. 31, 2006, changes in the outlook for dispatch rates and trading values and their impact on plant
profitability resulted in the determination that the full book value of the Centralia Gas facility was unlikely to be recovered from future cash flows. As a result, TransAlta recorded a
$130 million pre-tax impairment charge to write this plant down to its fair value. This asset is included in the Generation segment.

5.  Non-Controlling Interests

A.   Statements of Earnings

Year ended Dec. 31


2008


2007


2006Stanley Power's interest in TA Cogen(Note 35)

$
32

$
29

$
3625 per cent interest in Saranac Partnership not owned by CE Gen


29


19


16Total

$
61

$
48

$
52


B.   Balance Sheets

As at Dec. 31


2008


2007Stanley Power's interest in TA Cogen

$
449

$
46725 per cent interest in Saranac Partnership not owned by CE Gen


20


29Total

$
469

$
496


The change in non-controlling interests is outlined below:

Balance, Dec. 31, 2007

$
496Distributions paid


(98
)Non-controlling interests portion of net earnings


61Accrued cash distributions


10As at Dec. 31, 2008

$
469


82TransAlta Corporation    Annual Report 2008

---



6.  Income Taxes

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

A.   Statements of Earnings

I.   Rate Reconciliations

Year ended Dec. 31


2008


2007


2006Earnings (loss) before income taxes

$
258

$
329

$
(81
)Equity loss


(97
)

(50
)

(17
)Earnings (loss) before income taxes and excluding equity loss

$
355

$
379

$
(64
)Statutory Canadian federal and provincial income tax rate (%)


30


32


33Expected taxes (recovery) on income


105


121


(21
)Increase (decrease) in income taxes resulting from:Lower effective foreign tax rates


(24
)

(36
)

(33
)Asset impairment and mine closure charges recognized at higher tax rate








(9
)Resolution of uncertain tax positions


(15
)

(18
)

Tax recovery on sale of equity investment(Note 27)


(35
)




Capital taxes


1


2


3Effect of tax rate changes





(48
)

(55
)Statutory and other rate differences


(7
)

(1
)

(4
)Other


(2
)




(7
)Income tax expense (recovery)

$
23

$
20

$
(126
)Effective tax rate (%)


6


5


197


II.   Components of Income Tax Expense (Recovery)

Year ended Dec. 31


2008


2007


2006Current tax expense

$
22

$
54

$
38Future income tax expense (recovery) related to the origination
and reversal of temporary differences


1


14


(109
)Future income tax recovery resulting from changes in tax rates or laws





(48
)

(55
)Income tax expense (recovery)

$
23

$
20

$
(126
)


B.   Balance Sheets

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

As at Dec. 31


2008


2007Net operating and capital loss
carryforwards

$
231

$
178Future site restoration costs


71


77Property, plant, and equipment


(736
)

(717
)Risk management assets and liabilities


(52
)

75Employee future benefits and compensation plans


24


21Allowance for doubtful accounts


22


18Other deductible temporary differences


81


42Net future income tax liability

$
(359
)
$
(306
)


Presented in the balance sheet as follows:

As at Dec. 31


2008


2007AssetsCurrent

$
3

$
40Long-term


248


303LiabilitiesCurrent


(14
)

(12
)Long-term


(596
)

(637
)Net future income tax liability

$
(359
)
$
(306
)


As at Dec. 31, 2008, there were income tax loss carryforwards of nil
(2007  $61 million) for which no tax benefit has been recognized.

In
2008, the Corporation received a notice of reassessment from the federal taxation authority related to the disposal of the Transmission Business in the 2002 taxation
year. As a result of the reassessment, the Corporation is required to pay approximately $40 million in taxes plus interest and penalties. The Corporation funded a portion of this amount in
2008 by transferring $8 million from its tax prepayment account and anticipates additional cash payments in 2009 to fund the remaining balance. The Corporation is in the process of
challenging this reassessment. Since it is anticipated that the dispute will not be resolved within one year, any prepayment transfers and cash paid are recorded as a
long-term receivable.

2008 Notes to the Consolidated Financial Statements83

---



7.  Financial Instruments

A.   Analysis of Financial Assets and Liabilities by Measurement Basis

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

Carrying value of financial instruments as at Dec. 31, 2008

Derivatives
used for
hedging


Derivatives
classified as
held for
trading


Loans and
receivables


Other
financial
liabilities


Total
carrying
valueFinancial assetsCash and cash equivalents

$


$


$
50

$


$
50Accounts receivable








542





542Risk management assetsCurrent


121


79








200Long-term


220


1








221Financial liabilitiesShort-term debt

$


$


$


$
443

$
443Accounts payable and accrued liabilities











682


682Risk management liabilitiesCurrent


74


74








148Long-term


96


6








102Long-term debt recourse1











2,100


2,100Long-term debt non-recourse1











265


265


Carrying value of financial instruments as at Dec. 31, 2007

Derivatives
used for
hedging


Derivatives
classified as
held for
trading


Loans and
receivables


Other
financial
liabilities


Total
carrying
valueFinancial assetsCash and cash equivalents

$


$


$
51

$


$
51Accounts receivable








546





546Risk management assetsCurrent


69


24








93Long-term


122











122Restricted cash








242





242Financial liabilitiesShort-term debt

$


$


$


$
651

$
651Accounts payable and accrued liabilities











473


473Risk management liabilitiesCurrent


93


12








105Long-term


191


13








204Long-term debt recourse1











1,596


1,596Long-term debt non-recourse1











241


241


B.   Fair Value of Financial Instruments

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

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

I.   Level Determinations and Classifications

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

a.   Level I

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

84TransAlta Corporation    Annual Report 2008

---



b.   Level II

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

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

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

c.   Level III

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

In
limited circumstances, Energy Trading may enter into commodity transactions involving non-standard features for which market-observable data is not
available. In these cases, Level III fair values are determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion,
demand profiles, and/or volatilities and correlations between products derived from historical prices.

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

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

Fair value
1







Total
carryingAs at Dec. 31, 2008


Level I


Level II


Level III


Total


valueFinancial assets and liabilities measured at fair valueNet risk management liabilities (assets)2

$
(1
)
$
(170
)
$


$
(171
)
$
(171
)Financial assets and liabilities measured at
other than fair valueLong-term debt3

$


$
2,099

$


$
2,099

$
2,365




Fair value
1







Total
carryingAs at Dec. 31, 2007


Level I


Level II


Level III


Total


valueFinancial assets and liabilities measured at fair valueNet risk management liabilities (assets)2

$
(1
)
$
95

$


$
94

$
94Financial assets and liabilities measured at other than fair valueLong-term debt3

$


$
1,874

$


$
1,874

$
1,837


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

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

Where
the fair values have been developed using valuation models based on unobservable or internally developed assumptions or inputs (Level III Energy Trading Risk
Management fair values), the key inputs include historical data such as plant performance, volatilities and correlations between products derived from historical prices, congestion on transmission
paths, or demand profiles for individual non-standard deals and structured products.

The
effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III Energy Trading fair values are determined
would not result in materially different fair values.

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

2008 Notes to the Consolidated Financial Statements85

---





C.   Inception Gains and Losses

The majority of the Corporation's derivatives have quoted market prices on active exchanges or
over-the-counter quotes available from brokers. However, some derivatives are not traded on an active exchange requiring the use of internal valuation techniques
or models.

In
some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the transaction price) and the amount calculated
through a valuation model. This unrealized gain or loss at inception is recognized in net earnings only if the fair value of the instrument is evidenced by a quoted market price in an active market,
observable current market transactions that are substantially the same, or based on a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is
deferred on the balance sheet in Energy Trading Risk Management Assets or Liabilities, and is recognized in
earnings over the term of the related contracts. The difference yet to be recognized in net earnings and a reconciliation of changes during the period is as follows:

As at Dec. 31


2008


2007Unamortized gain at beginning of period

$
3

$
4New transactions


1


4Recognized in the statement of earnings during the period:Amortization


(2
)

(5
)Unamortized gain at end of period

$
2

$
3


D.   Nature and Extent of Risks Arising from Financial Instruments

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

I.   Market Risk

a.   Commodity Price Risk

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

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

i.   Commodity Price Risk  Proprietary Trading

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

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

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

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

Changes
in market prices associated with proprietary trading activities affect net income in the period that the price changes occur. VaR at Dec. 31, 2008
associated with the Corporation's proprietary trading activities was $6 million.

ii.   Commodity Price Risk  Generation

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

In
addition, certain electricity sale contracts do not qualify as NPNS contracts. These contracts are designated as all-in-one hedges and are
therefore accounted for as cash flow hedges. However, unlike a typical financial derivative used in a hedging relationship which results in a net settlement with the counterparty, settlement of
these electricity contracts will not likely result in a net cash outflow to or an adverse earnings impact to the Corporation, despite their fair value usually resulting in a liability and a related
AOCI cash flow loss on the Corporation's balance sheet. For contracts settled by physical delivery, the Corporation will physically deliver the electricity at the price fixed under the contract, and
receive cash payment for that physical delivery. Any related cash flow hedge after-tax losses will be offset by the notional fair value of the contract. If the
all-in-one hedge contracts cannot be settled by physical delivery of the underlying commodity they will be settled financially.

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

86TransAlta Corporation    Annual Report 2008

---



VaR
at Dec. 31, 2008 associated with the Corporation's commodity derivative instruments used in generation hedging activities was $86 million.

The
Corporation's policy on asset-backed transactions is to seek NPNS contract status or hedge accounting treatment. Where this is not possible, the transactions are
marked to the market value. These include, for example, positions and economic hedges that do not meet hedge accounting requirements or short-term optimization transactions such as
buybacks entered into to offset existing hedge positions. Changes in market prices associated with these transactions affect net earnings in the period in which the price change occurs. VaR at
Dec. 31, 2008 associated with the Corporation's commodity derivative instruments used in the generation business, but which are not designated as hedges, was nil.

b.   Interest Rate Risk

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

The
possible effect on pre-tax earnings and OCI for the year ended Dec. 31, 2008, due to changes in market interest rates affecting the Corporation's
floating rate debt, interest-bearing assets, and held for trading interest rate and other hedging derivatives outstanding at the balance sheet date, is outlined below. The sensitivity analysis has
been prepared using management's assessment that a 50 basis point increase or decrease is the most reasonably possible change in market interest rates over the next quarter and is consistent
with a +/- one standard deviation move from the mean.

Pre-tax
earnings
increase
1

OCI gain
150 basis point change

$
3

$



c.   Currency Rate Risk

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

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

The
possible effect on pre-tax earnings and OCI for the year ended Dec. 31, 2008, due to changes in the exchange rates associated with financial
instruments outstanding at the balance sheet date, is outlined below. The sensitivity analysis has been prepared using management's assessment that a five cent increase or decrease in these
currencies relative to the Canadian dollar is the most reasonably possible change and is consistent with a +/- one standard deviation move from the mean.

Currency


Pre-tax
earnings
decrease
1

OCI gain
1Euro

$


$
4U.S.


5


3AUD


2


Total

$
7

$
7


II.   Credit Risk

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

At
Dec. 31 2008, TransAlta had two counterparties whose net settlement position each accounted for greater than 10 per cent of the total trade
receivables outstanding at year-end.

The
Corporation's maximum exposure to credit risk at Dec. 31, 2008, without taking into account collateral held, is represented by the current carrying amounts of
accounts receivables and risk management assets as per the consolidated balance sheets. Letters of credit and cash are the primary types of collateral held as security related to
these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, excluding the California market receivables and including the fair value of open
trading positions, at Dec. 31, 2008 was $105 million (2007  $6 million).

The
Corporation uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for
counterparties. The following table outlines the distribution, by credit rating, of financial assets that are neither past due nor impaired:

Investment
grade %


Non-investment
grade %


Total %Accounts receivable


86


14


100Risk management assets


99


1


100


2008 Notes to the Consolidated Financial Statements87

---



The Corporation utilizes an allowance for doubtful accounts to record potential credit losses associated with trade receivables. A
reconciliation of the account for the period is presented in Note 8.

At
Dec. 31, 2008, the Corporation did not have any significant past due amounts, except as disclosed in Note 31.

III.   Liquidity Risk

Liquidity risk is the risk that the Corporation may encounter difficulties in meeting obligations
associated with financial liabilities and commitments related to collateral requirements under various contracts.

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

2009


2010


2011


2012


2013


2014 and
thereafter


TotalShort-term debt

$
443

$


$


$


$


$


$
443Accounts payable and accrued liabilities


682

















682Long-term debt1


244


32


254


397


396


1,033


2,356Energy Trading risk management (assets) liabilities2


(33
)

(18
)

(55
)

(59
)

1





(164
)Other risk management (assets) liabilities3


(19
)




(12
)







24


(7
)Interest on short- and long-term debt


172


145


133


112


98


564


1,224Total

$
1,489

$
159

$
320

$
450

$
495

$
1,621

$
4,534


E.   Financial Instruments Provided as Collateral

At Dec. 31, 2008, $63 million (2007  $57 million) of financial assets,
consisting of bank accounts and accounts receivable, related to the Corporation's proportionate share of CE Gen have been pledged as collateral for certain CE Gen debt. Should any
defaults occur the debt-holders would have first claim on these assets.

F.   Financial Assets Held as Collateral

At Dec. 31, 2008, the Corporation held U.S.$20 million in cash as collateral associated with counterparty
obligations. Under the terms of the contract, the Corporation is obligated to pay interest on the outstanding balance and to return the principal when the counterparty has met its
contractual obligations.

G.   Gains and Losses on Financial Instruments

The Corporation's COD segment utilizes a variety of derivatives in its proprietary trading activities, and the related assets and
liabilities are classified as held for trading. As outlined in Note 1(D), the net realized and unrealized gains are reported as revenue. For the year ended Dec. 31, 2008, the COD
segment recognized $105 million (2007  $55 million) of net realized and unrealized gains and
losses(Note 32).

Net
interest expense as reported on the consolidated statements of earnings includes interest income and expense, respectively, on the Corporation's interest-bearing
financial assets, primarily cash and restricted cash, and its interest-bearing financial liabilities, primarily short- and long-term debt. Interest expense is calculated
using the effective interest rate method(Note 21). Interest rate derivatives that are not designated as hedges are classified as held for
trading with the net gain or loss also recorded in net interest expense.

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

Other
derivatives that are not designated as hedges are also classified as held for trading, with the net gain or loss recorded in OM&A expense.

The
table below outlines the net gains (losses) included in earnings for the current and prior comparative periods:

Year ended Dec. 31


2008


2007Interest rate derivatives gains

$
3

$
2Foreign exchange derivatives (losses) gains


(15
)

4Other derivatives gains


1





8.  Accounts Receivable

As at Dec. 31


2008


2007Gross accounts receivable

$
599

$
592Allowance for doubtful accounts(Note 31)


(57
)

(46
)Net accounts receivable

$
542

$
546


The change in allowance for doubtful accounts is outlined below:

Balance, Dec. 31, 2007

$
46Change in foreign exchange rates


11Balance, Dec. 31, 2008

$
57


88TransAlta Corporation    Annual Report 2008

---



9.  Risk Management Assets and Liabilities

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

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

As at Dec. 31


2008


2007Balance Sheet  Totals


Energy
Trading


Other


Total


Energy
Trading


Other


TotalRisk management assetsCurrent

$
176

$
24

$
200

$
34

$
59

$
93Long-term


187


34


221


(4
)

126


122Risk management liabilitiesCurrent


(142
)

(6
)

(148
)

(87
)

(18
)

(105
)Long-term


(57
)

(45
)

(102
)

(192
)

(12
)

(204
)Net risk management assets (liabilities) outstanding

$
164

$
7

$
171

$
(249
)
$
155

$
(94
)


Energy Trading

The values of risk management assets and liabilities for Energy Trading are included on the consolidated balance sheets
as follows:

As at Dec. 31


2008


2007Balance Sheet  Energy Trading


Hedges


Non-hedges


Total


Total
related to
Energy
TradingRisk management assetsCurrent

$
99

$
77

$
176

$
34Long-term


186


1


187


(4
)Risk management liabilitiesCurrent


(71
)

(71
)

(142
)

(87
)Long-term


(51
)

(6
)

(57
)

(192
)Net risk management assets (liabilities) outstanding

$
163

$
1

$
164

$
(249
)


2008 Notes to the Consolidated Financial Statements89

---





The following table illustrates the disclosure on the movements in the fair value of the Corporation's Energy Trading net risk
management assets and liabilities separately by source of valuation during the year ended Dec. 31, 2008:

Hedges


Non-hedges


TotalLevel I


Level II


Level III


Level I


Level II


Level III


Level I


Level II


Level IIINet risk management (liabilities) assets outstanding at Dec. 31, 20071

$


$
(261
)
$


$
1

$
11

$


$
1

$
(250
)
$
Changes in net asset value attributable to:Market changes





261








5


13





266


13New contracts entered during the period





128





1


(5
)

3


1


123


3Contracts settled during the period





67





(1
)

(11
)

(16
)

(1
)

56


(16
)Change in foreign exchange rates





(32
)
















(32
)

Transfers in and/or out of Level III


























Net risk management assets outstanding at Dec. 31, 2008

$


$
163

$


$
1

$


$


$
1

$
163

$
Additional Level III gain (loss) information:Total change in fair value included in OCI







$








$








$
Total change in fair value included in pre-tax earnings







$








$








$
Total change in fair value included in pre-tax earnings relating to those net assets held at Dec. 31, 2008







$








$
16







$
16


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

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

2009


2010


2011


2012


2013


2014 and
thereafter


TotalHedges


Level I

$


$


$


$


$


$


$
Level II


32


18


55


59


(1
)




163Level III




















Non-hedges


Level I

$
1

$


$


$


$


$


$
1Level II




















Level III




















Total


Level I

$
1

$


$


$


$


$


$
1Level II


32


18


55


59


(1
)




163Level III




















Total assets (liabilities)

$
33

$
18

$
55

$
59

$
(1
)
$


$
164


The Corporation's fixed price proprietary trading positions at Dec. 31, 2008 and Dec. 31, 2007, were
as follows:

Units (000s)


Electricity
(MWh
)

Natural gas
(GJ
)

Transmission
(MWh
)

Coal
(tonnes
)

Emissions
(tonnes
)Fixed price payor, notional amounts, Dec. 31, 2008


18,569


57,718


1,489


401


Fixed price payor, notional amounts, Dec. 31, 2007


16,189


54,523


1,854


1,644


6Fixed price receiver, notional amounts, Dec. 31, 2008


18,500


57,507





401


Fixed price receiver, notional amounts, Dec. 31, 2007


16,009


61,977





1,644


15Maximum term in months, Dec. 31, 2008


60


12


12


12


Maximum term in months, Dec. 31, 2007


24


12


6


23


2


90TransAlta Corporation    Annual Report 2008

---



Other Risk Management Assets and Liabilities

The values of non-Energy Trading risk management assets and liabilities included on the consolidated balance sheets are
as follows:

As at Dec. 31


2008


2007Balance Sheet  Other


Hedges


Non-hedges


Total


Total
related to
non-Energy
TradingRisk management assetsCurrent

$
22

$
2

$
24

$
59Long-term


34





34


126Risk management liabilitiesCurrent


(3
)

(3
)

(6
)

(18
)Long-term


(45
)




(45
)

(12
)Net risk management assets (liabilities) outstanding

$
8

$
(1
)
$
7

$
155


The following table illustrates the disclosure on the movements in the fair value of the Corporation's other net risk management
assets and liabilities separately by source of valuation during the year ended Dec. 31, 2008:

Hedges
1

Non-hedges
1

TotalNet risk management assets (liabilities) outstanding at Dec. 31, 2007

$
168

$
(13
)
$
155Changes in net asset value attributable to:Market changes


9


14


23New contracts entered during the period


(8
)

(2
)

(10
)Contracts settled during the period


(161
)




(161
)Net risk management assets (liabilities) outstanding at Dec. 31, 2008

$
8

$
(1
)
$
7


Changes in net risk management assets and liabilities for hedge positions are reflected within net earnings to the extent
transactions have settled during the period or ineffectiveness exists in the hedging relationship. To the extent these hedges remain effective and qualify for hedge accounting, the change in value
of existing and new contracts will be deferred in OCI until settlement of the instrument or reduction in the net investment.

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

2009


2010


2011


2012


2013


2014 and
thereafter


TotalHedges

$
20

$


$
12

$


$


$
(24
)
$
8Non-hedges


(1
)
















(1
)Total assets (liabilities)

$
19

$


$
12

$


$


$
(24
)
$
7


Details of notional information related to the hedges and non-hedges of other risk management assets are
outlined below:

A.   Hedges

I.   Hedges of Foreign Operations

The Corporation has hedged a portion of its net investment in self-sustaining subsidiaries
with cross-currency and foreign currency forward sales contracts as shown below:

a.   Cross-Currency Swaps

Details of the notional amounts of cross-currency interest rate swaps are as follows:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturities


Notional
amount


Fair value


MaturitiesAustralian dollars

AUD$
34

$
2


2009

AUD$
34

$
1


2009U.S. dollars

U.S.$


$





U.S.$
533

$
106


2009-2014


b.   Foreign Sales Contracts

Details of the foreign currency forward sales contracts are as shown below:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturities


Notional
amount


Fair value


MaturitiesU.S. dollars

U.S.$
(107
)
$
(1
)

2009

U.S.$
473

$
52


2008Australian dollars

AUD$
108

$
(1
)

2009

AUD$
82

$
1


2008


2008 Notes to the Consolidated Financial Statements91

---





II.   Hedges of Future Foreign Currency Obligations

TransAlta's future foreign currency obligations are related to foreign capital purchases. The
Corporation has hedged these obligations through forward purchase contracts as follows:

As at Dec. 31


2008


2007Currency sold


Amount
sold

Currency
purchased

Amount
purchased


Fair value
asset


Maturities


Amount
sold

Amount
purchased


Fair value
liability


MaturitiesCanadian dollars

$
51

U.S.$

U.S.$48

$
8


2009-2010

$
96

U.S.$87

$
(11
)

2008-2010Australian dollars




CDN$









$
6

$5





2008Australian dollars




U.S.$









$
2

$2





2008U.S. dollars




GBP









$
2

GBP1





2008Canadian dollars

$
84

Euro

EUR57

$
13


2009

$
69

EUR46

$
(3
)

2008


III.   Interest Rate Risk Management

The Corporation has converted fixed interest rate debt with rates ranging from
6.65 per cent to 6.9 per cent to floating rates through receive fixed/pay floating interest rate swaps as shown below:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturities


Notional
amount


Fair value


MaturitiesFixed rate debt

$
100

$
12


2011

$
200

$
11


2011U.S.$
100

$
21


2018

U.S.$
100

$
2


2013


The Corporation has a forward start pay fixed swap outstanding at fixed rates ranging from 3.3 per cent to
4.2 per cent, as shown below:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturity


Notional
amount


Fair value


MaturityFloating rate debt

U.S.$
300

$
(46
)

2019

U.S.$
200

$
9


2018


Including the interest rate swaps above, 24 per cent of the Corporation's debt is subject to floating interest rates
(2007  38 per cent).

At
Dec. 31, 2008, a $33 million asset (2007  $13 million) related to the fair value of the interest rate swaps
was recorded in long-term risk management assets.

B.   Non-Hedges

I.   Cross-Currency Swaps

The Corporation has an intercompany loan between its Australian and Barbados companies. Cross-currency
interest rate swaps have been entered into in order to limit the Corporation's exposure to fluctuations in market interest rates. Details of the notional amounts of cross-currency interest rate
swaps are as follows:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturity


Notional
amount


Fair value


MaturityAustralian dollars

AUD$
41

$
1


2009

AUD$
80

$
(13
)

2009


II.   Held for Trading and Total Return Swaps

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

The
Corporation also has employee compensation and deferred share units programs under which share grants or cash awards whose value depends on the share price are
provided to certain employees and directors of the Corporation. To lower its cost of compensation, the Corporation has locked in the Dec. 31, 2008 settlement cost using a total return swap.

Details
on the notional amounts of held for trading and total return swaps are as follows:

As at Dec. 31


2008


2007Notional
amount


Fair value


Maturities


Notional
amount


Fair value


MaturitiesU.S. dollars

U.S.$
90

$
(2
)

2009

U.S.$
15

$



2008


10.  Hedging Activities

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

A.   Fair Value Hedges

Interest rate swaps are used to hedge exposures to the changes in a fixed interest rate instrument's fair value caused by changes
in interest rates. Foreign exchange contracts are also used to hedge foreign currency denominated assets and liabilities.

No
ineffective portion of fair value hedges was recorded in 2008, 2007, or 2006.

92TransAlta Corporation    Annual Report 2008

---



B.   Cash Flow Hedges

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

For
the year ended Dec. 31, 2008, a pre-tax unrealized gain of $327 million (2007  loss of
$57 million, 2006  nil) was recorded in OCI for the effective portion of the cash flow hedges, and a pre-tax total of $91 million
(2007  $25 million, 2006  nil) related to amounts previously related to OCI was reclassified to net earnings. For
the year ended Dec. 31, 2008, a realized loss of nil (2007  nil, 2006  nil), was recognized in earnings for the
ineffective portion.

Over
the next 12 months, the Corporation estimates that $17 million (2007  $44 million) of
after-tax losses will be reclassified from AOCI to net earnings. These estimates assume constant gas and power prices, interest rates, and exchange rates over time; however, the actual
amounts that will be reclassified will vary based on changes in these factors. In addition, it is the Corporation's intent to settle a substantial portion of the cash flow hedges by physical
delivery of the
underlying commodity, resulting in gross settlement at the contract price. These contracts are designated as all-in-one hedges and are required to be accounted for as cash
flow hedges. However, unlike a typical financial derivative used in a hedging relationship, which results in a net settlement with the counterparty, these contracts will not likely result in a net
cash outflow to the Corporation, despite their fair value usually resulting in a liability and a related AOCI loss on the Corporation's balance sheet. For contracts settled by physical delivery, the
Corporation will physically deliver the electricity at the price fixed under the contract, and receive cash payment for that physical delivery. Any related cash flow hedge after-tax
losses will be offset by the notional fair value of the contract. If the all-in-one hedge contracts cannot be settled by physical delivery of the underlying commodity they
will be settled financially.

C.   Net Investment Hedges

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

For
the year ended Dec. 31, 2008, the net after-tax gain of $47 million (2007  gain of
$19 million), relating to the net investment in foreign operations, net of hedging, was recognized in OCI.

The
following table presents the fair values of derivative instruments categorized by their hedging relationships, as well as derivatives that are not designated in
hedging relationships.

As at Dec. 31


2008


2007Fair value
hedges


Cash flow
hedges


Net
investment
hedges


Not
designated
in a
hedging
relationship


Total


TotalFinancial assetsDerivative instruments

$
33

$
306

$
2

$
80

$
421

$
215Financial liabilitiesDerivative instruments

$
(46
)
$
(122
)
$
(2
)
$
(80
)
$
(250
)
$
(309
)


U.S. dollar denominated long-term debt with a face value of U.S.$1,100 million
(2007  U.S.$600 million), and U.S. dollar denominated short-term debt with a face value of U.S.$238 million
(2007  nil) has been designated as a part of the hedge of TransAlta's self-sustaining foreign operations.

11.  Inventory

Inventory primarily represents coal and natural gas fuels that are valued at the lower of cost and net realizable value. The
classifications are as follows:

As at Dec. 31


2008


2007Coal

$
45

$
23Natural gas


5


7Purchased emission credits


1


Total

$
51

$
30


The increase in coal inventory in 2008 compared to 2007 is primarily due to lower production at the Alberta Thermal plant and
increased costs at the Alberta Thermal and Centralia Thermal plants.

The
change in inventory is outlined below:

Balance, Dec. 31, 2007

$
30Net additions


12Change in foreign exchange rates


9Balance, Dec. 31, 2008

$
51


No inventory is pledged as security for liabilities.

For
the years ended Dec. 31, 2008 and Dec. 31, 2007, no inventory was written down from its carrying value nor were any writedowns recorded in previous
periods reversed back into earnings.

2008 Notes to the Consolidated Financial Statements93

---



12.  Restricted Cash

Restricted cash is comprised of debt service funds that are legally restricted, and require the maintenance of specific minimum
balances equal to the next debt service payment, and amounts restricted for capital and maintenance expenditures.

The
change in restricted cash is outlined below:

Balance, Dec. 31, 2007

$
242Amount returned to TransAlta


(248
)Change in foreign exchange rates


6Balance, Dec. 31, 2008

$



During 2008, a subsidiary closed its position under a credit derivative agreement. The investment in notes held in trust as
security for the subsidiary's obligation of $245 million under this agreement was returned to the subsidiary.

13.  Investments

Investments previously represented TransAlta's investment in the Corporation's wholly owned Mexican operations.

On
Oct. 8, 2008, the Corporation completed the sale of the Mexican operations to InterGen for $334 million. The Corporation recorded a charge to 2008
earnings of $62 million, net of tax, to reflect the difference between the net carrying value and anticipated net sale price of these assets. The gross charge of $97 million is
recorded in equity loss and $35 million of tax recovery is recorded in income tax expense(Note 27).

14.  Long-Term Receivables

In 2008, the Corporation received a notice of reassessment from the federal taxation authority relating to the disposal of the
transmission business in the 2002 taxation year(Note 6). The Corporation is in the process of challenging this reassessment. Since it is
anticipated that the dispute will not be resolved within one year, any prepayment transfers and cash paid are recorded as a long-term receivable.

The
Corporation has a right to recover a portion of future asset retirement costs. The estimated present value of these payments has also been recorded as a
long-term receivable.

15.  Property, Plant, and Equipment
("PP&E")

As at Dec. 31





2008


2007Depreciation
rates


Cost


Accumulated
depreciation
and
amortization


Net book
value


Cost


Accumulated
depreciation
and
amortization


Net book
valueThermal generation equipment


2%-67%

$
4,835

$
1,993

$
2,842

$
4,338

$
1,752

$
2,586Mining property & equipment


2%-50%


763


352


411


617


330


287Gas generation


3%-33%


2,244


1,030


1,214


2,157


944


1,213Geothermal generation


3%-33%


386


87


299


288


42


246Hydro generation


1%-50%


399


226


173


385


215


170Wind generation


3%-5%


375


39


336


209


33


176Capital spares and other


2%-50%


228


68


160


186


62


124Assets under construction





443





443


181





181Coal rights 1





134


83


51


133


80


53Land





63





63


52





52Transmission systems


3%-4%


49


20


29


47


18


29Total




$
9,919

$
3,898

$
6,021

$
8,593

$
3,476

$
5,117


The Corporation capitalized $21 million of interest to PP&E in 2008
(2007  $6 million, 2006  nil).

An
increase in foreign exchange rates from 2007 to 2008 has resulted in a $280 million increase in net book value of property, plant, and equipment. The change in
foreign exchange rates related to translation of self-sustaining foreign operations does not affect earnings; rather any cumulative translation gain is reflected in AOCI.

16.  Assets Held for Sale

During 2008, mining equipment with a net book value of $2 million related to the cessation of mining activities at the
Centralia coal mine was sold for proceeds of $7 million; the remainder of the mining and reclamation equipment was reclassified to property, plant, and equipment as it is being retained for
reclamation activities. This reclassification did not, and is not anticipated to, have a material impact on depreciation expense.

17.  Goodwill

The change in goodwill is outlined below:

Balance, Dec. 31, 2007

$
125Change in foreign exchange rates


17Balance, Dec. 31, 2008

$
142


94TransAlta Corporation    Annual Report 2008

---



A portion of goodwill is related to CE Gen and is therefore denominated in U.S. dollars. The change in foreign
exchange rates related to translation of self-sustaining foreign operations does not affect earnings and the cumulative translation gain is reflected in AOCI.

18.  Intangible Assets

The change in intangible assets is outlined below:

Cost


Accumulated
amortization


Net book valueBalance, Dec. 31, 2007

$
401

$
192

$
209Change in foreign exchange rates


98


53


45Amortization





41


(41
)Balance, Dec. 31, 2008

$
499

$
286

$
213


The majority of intangible assets are related to CE Gen and are therefore denominated in U.S. dollars. The change in
foreign exchange rates related to translation of self-sustaining foreign operations does not affect earnings and the cumulative translation gain is reflected in AOCI.

19.  Other Assets

As at Dec. 31


2008


2007Deferred license fees

$
21

$
22Deferred contract costs


8


14Deferred project development costs


9


15Other


5


10Other assets

$
43

$
61


Deferred license fees consist primarily of an Australian license for a lease on the land on which the power station assets are
located, which is being amortized on a straight-line basis over the useful life of the power station assets to which the license relates.

Deferred
contract costs consist of prepayments related to long-term contracts, which are being amortized on a straight-line basis over the term of
the related contracts.

20.  Short-Term Debt

As at Dec. 31


2008


2007Outstanding


Interest
1

Outstanding


Interest
1Commercial paper

$





$
204


4.9%Bank debt2


443


2.8%


447


5.2%Total short-term debt

$
443




$
651


The short-term debt instruments are drawn on the Corporation's $1.5 billion committed syndicated bank credit
facility and on the Corporation's U.S.$300 million other commercial borrowings.

The
$1.5 billion committed syndicated bank facility is dated July 2003 and is the primary source for short-term liquidity. The facility is a five-year
revolver and was last renewed in May 2007, extending the maturity date to 2012. The syndicated credit facility is governed by reasonable commercial terms and bears interest at a floating rate
currently of 2.27%.

The
U.S.$300 million other commercial borrowings are a five-year facility, which bears interest at a floating rate currently of 3.46%.

21.  Long-Term Debt and Net Interest Expense

A.   Amounts Outstanding

As at Dec. 31


2008


2007Carrying
value


Cost


Interest
1

Carrying
value


Cost


Interest
1Debentures, due 2009 to 2033

$
682

$
681


6.8%

$
950

$
946


6.5%Senior notes, (2008  U.S.$1,100 million,
2007  U.S.$600 million)


1,352


1,344


6.3%


573


586


6.3%Non-recourse


265


265


7.4%


241


242


7.4%Notes payable  Windsor plant


37


37


7.4%


43


43


7.4%Commercial loan obligation


29


29


5.9%


30


30


5.9%2,365


2,356





1,837


1,847Less: current portion


(244
)

(244
)




(154
)

(154
)Total long-term debt

$
2,121

$
2,112




$
1,683

$
1,693


Fixed rate components of debentures and senior notes are hedged and therefore recorded at fair value. Non-recourse debt
is not hedged and therefore recorded at cost.

2008 Notes to the Consolidated Financial Statements95

---



Debenturesbear
interest at fixed rates ranging from 6.6 per cent to 7.3 per cent. The Corporation has converted $100 million fixed interest rate debt with a rate of
6.9 per cent to floating rates through the use of receive fixed/pay floating interest rate swaps(Note 9). These interest rate
swaps mature in 2011. Debentures in the amount of $265 million matured in 2008.

In
2008, $100 million of debentures were redeemed by the holder of the debentures at a price of $98.45 per $100 of notional. The debentures had been issued at a
fixed interest rate of 5.49 per cent, maturing in 2023 and redeemable at the option of the holder in 2008. In 2008, $50 million of debentures were redeemed at a negotiated
price. The debentures were originally issued at a fixed interest rate of 5.66 per cent and were to mature in 2033.

Senior NotesU.S.$300 million of the senior notes bear an interest rate of
5.8 per cent and mature in 2013 and another U.S.$300 million bear an interest rate of 6.8 per cent and mature in 2012. The remaining
U.S. $500 million of the U.S. $1,100 million senior notes bear an interest rate of 6.7 per cent and mature in 2018. In addition, the Corporation converted
U.S.$100 million fixed interest rate debt with a rate of 6.7 per cent to floating rates through the use of receive fixed/pay floating interest rate swaps. These interest rate swaps
mature in 2018. All senior notes have been designated as a hedge of the Corporation's net investment of U.S. operations. In 2008, the Corporation issued senior notes in the amount of
U.S.$500 million. The senior notes bear interest at a rate of 6.65 per cent and mature in 2018.

Non-Recourse Debtconsists of project financing debt, debt securities and
senior secured bonds of CE Gen and debt related to the Wailuku River Hydroelectric L.P ("Wailuku") acquisition. The CE Gen related assets have been pledged as security for the
project financing debt. The CE Gen debt securities are non-recourse, have maturity dates ranging from 2010 to 2018 and interest rates ranging from 7.5 per cent to
8.3 per cent. This debt is recorded at cost; the fair value as at Dec. 31, 2008 was $248 million (2007  $257 million). The
outstanding balance of the non-recourse senior secured bonds as of Dec. 31, 2008 was $149 million (2007  $133 million), bear
interest at 7.4 per cent, and are due in 2018. Wailuku debt at Dec. 31, 2008 has a cost of U.S.$9 million
(2007  U.S.$9 million) and bears interest at a floating rate currently of 1.2 per cent.

Notes Payable  Windsor Plantnotes bear interest at
fixed rates and are recourse to the Corporation through a standby letter of credit. These mature in November 2030.

Commercial Loan Obligationbears an interest rate of 5.9 per cent and will
mature in 2023. This is an unsecured loan and requires annual payments of interest and principal.

B.   Principal Repayments

2009

$
2442010


322011


2542012


3972013


3962014 and thereafter


1,033Total1

$
2,356


C.   Interest Expense

Year ended Dec. 31


2008


2007


2006Interest on long-term debt

$
147

$
145

$
154Interest on short-term debt


30


26


13Interest on preferred securities








14Interest income


(46
)

(32
)

(13
)Capitalized interest


(21
)

(6
)

Net interest expense

$
110

$
133

$
168


The Corporation capitalizes interest during the construction phase of longer-term capital projects. The capitalized
interest in 2008 relates to Keephills 3, Kent Hills, Summerview, and Blue Trail. In 2007 the capitalized interest related to the Corporation's investment in Keephills 3 and Kent Hills.

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

D.   Guarantees

I.   Letters of Credit

Letters of credit are issued to counterparties that have credit exposure to certain subsidiaries. If the
Corporation or its subsidiary does not pay amounts due under the contract, the counterparty may present its claim for payment to the financial institution through which the letter of credit was
issued. Any amounts owed by the Corporation or its subsidiaries are reflected in the consolidated balance sheets. All letters of credit expire within one year and are expected to be renewed, as
needed, through the normal course of business. The total outstanding letters of credit as at Dec. 31, 2008 totalled $430 million
(2007  $550 million) with nil (2007  nil) amounts exercised by third parties under these arrangements. TransAlta
has a total of $2.2 billion of committed and uncommitted credit facilities of which $1.4 billion is not drawn and is available as of Dec. 31, 2008, subject to customary
borrowing conditions.

TransAlta
letters of credit do not contain recourse provisions nor does the Corporation hold any assets as collateral against the guarantees issued.

96TransAlta Corporation    Annual Report 2008

---



22.  Asset Retirement Obligations

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

Balance, Dec. 31, 2006

$
329Liabilities incurred in period


3Liabilities settled in period


(38
)Accretion expense


24Revisions in estimated cash flows


(19
)Change in foreign exchange rates


(23
)Balance, Dec. 31, 2007

$
276Liabilities incurred in period


3Liabilities settled in period


(37
)Accretion expense


22Revisions in estimated cash flows


10Change in foreign exchange rates


23$
297Less current portion


(45
)Balance, Dec. 31, 2008

$
252


The Corporation has a right to recover a portion of future asset retirement costs. The estimated present value of these payments
has been recorded as a long-term receivable(Note 14).

During
2008, the Corporation prepared a revised decommissioning cost estimate of the future asset retirement costs at certain facilities. As a result, the total expected
costs have been increased by $10 million (2007  reduced by $19 million).

TransAlta
estimates that the undiscounted amount of cash flow required to settle the asset retirement obligations is approximately $0.8 billion, which will be
incurred between 2009 and 2072. The majority of the costs will be incurred between 2020 and 2030. A discount rate of eight per cent and an inflation rate of 2.3 per cent were
used to calculate the carrying value of the asset retirement obligations. At Dec. 31, 2008, the Corporation had a surety bond in the amount of U.S.$192 million
(2007  U.S.$192 million) in support of future retirement obligations at the Centralia coal mine. At Dec. 31, 2008, the Corporation had
letters of credit in the amount of $57 million (2007  $50 million) in support of future retirement obligations at the Alberta mines.

23.  Deferred Credits and Other Long-Term Liabilities

As at Dec. 31


2008


2007Deferred coal revenues(Note 28)

$
31

$
9Sale of emission credits


7


9Power purchase arrangement in limited partnership


23


25Accrued benefit liability(Note 34)


40


48Other


21


10Total deferred credits and other long-term liabilities

$
122

$
101


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

24.  Common Shares

A.   Issued and Outstanding

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

Year ended Dec. 31


2008


2007Common
shares
(millions
)

Amount


Common
shares
(millions
)

AmountIssued and outstanding, beginning of year


200.9

$
1,781


202.4

$
1,782Stock options expired











(2
)Issued for cash under stock option plans


0.4


8


0.8


19Issued under Performance Share Ownership Plan


0.2


7


0.1


3Shares purchased under NCIB(Note 25)


(3.9
)

(35
)

(2.4
)

(21
)Issued and outstanding, end of year


197.6

$
1,761


200.9

$
1,781


On Feb. 1, 2008, one million stock options were granted at an exercise price of $31.97, being the last sale price of
board lots of the shares on the TSX the day prior to the day the options were granted for Canadian employees, and U.S.$31.83, being the closing sale price on the New York Stock Exchange on
the same date for U.S. employees. These options will vest in equal installments over four years starting Feb. 1, 2009 and expire on Feb. 1, 2019 (Note 33).

2008 Notes to the Consolidated Financial Statements97

---



At
Dec. 31, 2008 the Corporation had 1.7 million outstanding employee stock options (2007  1.2 million). For
the year ended Dec. 31, 2008, 0.3 million options with a weighted average exercise price of $20.52 were exercised resulting in 0.3 million shares issued, and 0.2 million
options were cancelled with a weighted average exercise price of $27.96.

B.   Shareholder Rights Plan

The primary objective of the Shareholder Rights Plan is to provide the Corporation's Board of Directors sufficient time to explore
and develop alternatives for maximizing shareholder value if a takeover bid is made for the Corporation and to provide every shareholder with an equal opportunity to participate in such a bid. The
plan was originally approved in 1992, and has been revised since that time to ensure conformity with current practices. The plan was last approved by shareholders on April 26, 2007.

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

C.   Dividend Reinvestment and Share Purchase ("DRASP") Plan

Under the terms of the DRASP plan, participants are able to purchase additional common shares by reinvesting dividends. Effective
Jan. 1, 2007, the Corporation amended the DRASP plan, whereby after Dec. 31, 2006, the five per cent discount on the price of shares purchased through the DRASP plan and issued
from treasury was suspended. After Dec. 31, 2006, shares purchased under the DRASP plan are acquired in the open market at 100 per cent of the average purchase price of common
shares acquired on the TSX on the investment dates.

D.   Earnings Per Share ("EPS")

Year ended Dec. 31


2008


2007


2006Net earnings

$
235

$
309

$
45Basic and diluted weighted average number of common shares outstanding


199


202


201Earnings per shareBasic

$
1.18

$
1.53

$
0.22Diluted

$
1.18

$
1.53

$
0.22


The effect of the PSOP does not materially affect the calculation of the total weighted average number of common shares outstanding (Note 33).

25.  Shareholders'Equity

A.   Shareholder's Equity Reconciliation

Common
shares


Retained
earnings


Accumulated Other
Comprehensive
(Loss)/Income


Total
shareholders'
equityBalance, Dec. 31, 2007

$
1,781

$
763

$
(245
)
$
2,299Net earnings for the year ended Dec. 31, 2008





235





235Common shares issued (dividends declared)


15


(215
)




(200
)Shares purchased under NCIB


(35
)

(95
)




(130
)Gains on translating financial statements of self-sustaining foreign operations, net of tax








47


47Gains on derivatives designated as cash flow hedges, net of tax








198


198Derivatives designated as cash flow hedges in prior periods transferred to the balance sheet and net earnings in the current period








69


69Loss on Mexico sale reclassified to statement of earnings(Note 27)








(8
)

(8
)Balance, Dec. 31, 2008

$
1,761

$
688

$
61

$
2,510


B.   Components of AOCI

As at Dec. 31


2008


2007Cumulative unrealized gains (losses) on translating financial statements of self-sustaining foreign operations, net of tax

$
(7
)
$
(45
)Cumulative unrealized gains (losses) on cash flow hedges, net of tax


68


(200
)Accumulated Other Comprehensive Income (Loss)

$
61

$
(245
)


C.   Normal Course Issuer Bid ("NCIB") Program

On May 5, 2008, TransAlta announced plans to renew the NCIB program until May 5, 2009. The Corporation received the
approval to purchase, for cancellation, up to 19.9 million of its common shares representing 10 per cent of the 199 million common shares issued and outstanding as at
April 23, 2008. Any purchases undertaken will be made on the open market through the TSX at the market price of such shares at the time of acquisition.

98TransAlta Corporation    Annual Report 2008

---



For
the year ended Dec. 31, 2008, TransAlta purchased 3,886,400 (2007  2,371,800) shares at an average price of $33.46
(2007  $31.59) per share. The shares were purchased for an amount higher than their weighted average book value per share of $8.95 per share
(2007  $8.92 per share) resulting in a reduction of retained earnings of $95 million (2007  $54 million).

As at Dec. 31


2008


2007Total shares purchased


3,886,400


2,371,800Average purchase price per share

$
33.46

$
31.59Total cost

$
130

$
75Weighted average book value of shares cancelled


35


21Reduction to retained earnings

$
95

$
54


Given the current unprecedented level of volatility in the financial markets, TransAlta has decided to suspend purchases under its
NCIB program at this time in order to maintain maximum financial flexibility. TransAlta will re-evaluate financial market conditions throughout 2009 to determine the best use of cash
resources going forward.

26.  Capital

TransAlta's components of capital are listed below:

As at Dec. 31


2008


2007


Increase/
(decrease)Short-term debt including current portion of long-term
debt

$
687

$
805

$
(118
)Less: cash and cash equivalents


(50
)

(51
)

1637


754


(117
)Long-term debtRecourse


1,889


1,474


415Non-recourse


232


209


23Non-controlling interests


469


496


(27
)Common shareholders' equityCommon shares


1,761


1,781


(20
)Retained earnings


688


763


(75
)AOCI


61


(245
)

3065,100


4,478


622Total capital

$
5,737

$
5,232

$
505


The long-term portion of recourse debt increased from Dec. 31, 2007 as a result of the issuance of senior notes
in the amount of U.S.$500 million and changes in exchange rates. This increase in long-term debt was partially offset by scheduled payments.

TransAlta's
strategy for managing capital remained unchanged from Dec. 31, 2007.

TransAlta's
objectives in managing capital are to:

A.   Maintain an Investment Grade Credit Rating:

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

Cash flow to interestCash flow from operating activities before changes in working capital plus net
interest expense divided by net interest expense excluding capitalized interest. TransAlta targets this ratio to be a minimum multiple of four.

Cash flow to total debtCash flow from operating activities before changes in working
capital divided by two-year average of total debt. TransAlta targets this ratio to be a minimum of 25 per cent.

Debt to invested capitalShort-term debt and long-term debt less
cash and cash equivalents divided by total debt, non-controlling interests, and common shareholders' equity less cash and cash equivalents. TransAlta targets this ratio to be less than
55 per cent.

These ratios are presented below:

Year ended Dec. 31


2008


2007Cash flow to interest (times)


7.2


6.6Cash flow to total debt (%)


31.1


30.7Debt to invested capital (%)


48.1


46.8


The increase in cash flow to interest resulted from increased cash from operating activities and lower interest expense. The
increase in cash flow to total debt resulted from an increase in cash flows from operating activities offsetting the increase in debt balances(Notes 20
and 21). TransAlta routinely monitors forecasts for earnings, capital expenditures, and scheduled repayment of debt with a goal of meeting the above ratio targets.

2008 Notes to the Consolidated Financial Statements99

---





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

These amounts are summarized in the table below:

Year ended Dec. 31


2008


2007


Increase/
(decrease)Cash flow from operating
activities

$
1,038

$
847

$
191Dividends paid


(212
)

(205
)

(7
)Capital asset expenditures


(1,006
)

(599
)

(407
)Net cash (outflow) inflow

$
(180
)
$
43

$
(223
)


The decrease in the total net cash flows primarily resulted from higher capital expenditures on growth projects.

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

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

TransAlta's
formal dividend policy targets to pay shareholders an annual dividend in the range of 60 to 70 per cent of comparable earnings. TransAlta's
management defines comparable earnings as net earnings adjusted for items that are expected to be non-recurring in the future.

27.  Acquisitions and Disposals

A.   Acquisitions

On Feb. 17, 2006, the Corporation acquired a 50 per cent ownership in Wailuku for $1 million. The acquisition
is accounted for using the purchase method of accounting. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. The
financial operations of Wailuku have been proportionately consolidated with those of TransAlta.

Net assets acquired at assigned values:Working capital, including cash of $0.3 million

$
(3
)Property, plant, and equipment


26Long-term debt, including current portion


(22
)Total

$
1Consideration:Cash

$
1


This has been reported under "other" on the investing section of the cash flow statement.

B.   Disposals

On Oct. 8, 2008, TransAlta successfully completed the sale of the Mexican business to InterGen for a sale price of
$334 million(Note 13). The sale included the plants at both facilities and all associated commercial arrangements.

The
details of the sale are as follows:

Contractual proceeds




$
334Less: closing costs





(3
)Net proceeds excluding cash on hand of $1 million





331Book value of investment





420Loss before deferred foreign exchange losses





89Deferred foreign exchange losses on the net assets of the Mexican operations

$
147Deferred gains on financial instruments designated as hedges of the net assets
of the Mexican operations


(148
)Income tax expense on financial instruments


9Deferred foreign exchange losses





8Loss before income taxes




$
97Income tax recovery





35Net loss




$
62


Included in the book value of the investment is a provision for representations and warranties of $13 million.

28.  Related Party Transactions

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

On
Dec.16, 2006, TAU, a wholly owned subsidiary, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the
coal-fired plant. The joint venture project is held in a partnership with EPCOR Power Development Corporation. TAU will supply coal

100TransAlta Corporation    Annual Report 2008

---



until
the earlier of the permanent closure of the Keephills 3 facility or from early termination of the agreement by TAU and the partners of the joint venture. As at Dec. 31, 2008, TAU
had received $27 million from Keephills 3 Limited Partnership, a wholly owned subsidiary, for the right to coal. Commercial operation of the Keephills plant is scheduled to commence in
the first quarter of 2011. Payments received prior to that date for the right to coal are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply
agreement when operations commence.

In
August 2006, TransAlta entered into an agreement with CE Gen, a corporation jointly controlled by TransAlta and MidAmerican Energy Holdings Company
("MidAmerican"), a subsidiary of Berkshire Hathaway, whereby TransAlta buys available power from certain CE Gen subsidiaries at a fixed price. As this available power is from plants that are
already contracted, the value of this agreement is immaterial. In addition, CE Gen has entered into contracts with related parties to provide administrative and maintenance services.

For
the period November 2002 to November 2012, one of TransAlta's subsidiaries, TA Cogen, entered into various transportation swap transactions with
TEC. TEC operates and maintains TA Cogen's three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan, Alberta. TEC also provides management services to the Sheerness
thermal plant, which is operated by Canadian Utilities Limited. The business purpose of these transportation swaps is to provide TA Cogen with the delivery of fixed price gas without being
exposed to escalating costs of pipeline transportation for three of its plants over the period of the swap. The notional gas volume in the transaction was the total delivered fuel for each of the
facilities. Exchange amounts are based on the market value of the contract. TransAlta entered into an offsetting contract and therefore has no risk other than counterparty risk.

29.  Contingencies

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

30.  Commitments

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

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

Sarnia
has 20-year contracts with a customer group with three five-year options for extensions to the contracts. The contracts allow for up to
40 per cent of the plant's maximum capacity. These contracts set payments for peak megawatts, total megawatt hours supplied to the customers and steam consumed, while TransAlta assumes
the availability and heat rate risk. On Jan. 1, 2006, TransAlta signed a five-year agreement with the Ontario Power Authority to supply up to 500 megawatts ("MW") of
electricity to the Ontario electricity market. The remaining capacity at Sarnia is available for export to the merchant market, based on market prices. Production at the remaining Ontario plants is
subject to contracts expiring in five to 10 years.

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

At
Centralia Thermal, a significant portion of production is subject to short- to medium-term energy sales contracts.

Centralia
Thermal has various coal supply and associated rail transport contracts to provide coal for use in production. During 2008, TransAlta entered into various coal
supply agreements with three suppliers for the Centralia Thermal plant. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes and prices, with dates ranging from
June 1, 2008 to Dec. 31, 2013. The obligation under these agreements is expected to be U.S.$157 million over the six-year period.

At
Alberta Thermal, the mines are operated by a third party who is paid a fixed amount to provide a budgeted supply of coal. These amounts are included under coal supply
and mining agreements.

During
2008, TransAlta entered into several five-year agreements with Bonneville Power Administration Transmission ("BPAT") to purchase 400 MW of
Pacific Northwest transmission network capacity. Provided BPAT can meet certain conditions for delivering the service, the Corporation is committed to taking the services at BPAT's tariff rate
whether it is awarded immediately or delivered in the future after additional facilities are constructed. The obligation under these agreements is expected to be U.S.$46 million for the
five-year period.

On
May 27, 2008, TransAlta announced a 66 MW expansion of its Summerview wind farm located in southern Alberta near Pincher Creek. The capital cost of the
project is estimated at $123 million with construction commencing in the second quarter of 2009 and commercial operations expected to begin in the first quarter of 2010. As at Dec. 31,
2008, total capital spend on this project was $25 million.

On
April 21, 2008, TransAlta announced a 53 MW efficiency uprate at TransAlta's Sundance facility. The total capital cost of the project is estimated at
$75 million with commercial operations expected to commence by the end of 2009. As at Dec. 31, 2008, total capital spend on this project was $17 million.

2008 Notes to the Consolidated Financial Statements101

---



On
Feb. 13, 2008, TransAlta announced plans to design, build, and operate Blue Trail, a 66 MW wind power project in southern Alberta. The capital cost of the
project is estimated at $115 million. Commercial operations are expected to commence in the fourth quarter of 2009. As at Dec. 31, 2008, total capital spend on this project
was $26 million.

On
June 21, 2007, TAU entered into an agreement with Bucyrus Canada Limited and Bucyrus International Inc. for the purchase of a dragline to be used
primarily in the supply of coal to the Keephills 3 joint venture project. The total dragline purchase costs include approximately $121 million for the purchase of the equipment, and an
additional $29 million for the assembly and commissioning of the dragline, for a total of approximately $150 million, with final payments for goods and services due by May 2010.
As at Dec. 31, 2008, total payments under this agreement were $79 million.

Keephills
3 plant construction and associated mine capital costs via the Keephills 3 Limited Partnership are anticipated to be approximately
$1.7 billion with final payments for goods and services due by 2011. TransAlta's proportionate share is approximately $840 million. As at Dec. 31, 2008, total spend on this
project was $431 million.

On
Dec. 31, 2008, commercial operations began at the wind power facility in New Brunswick ("Kent Hills"). TransAlta also signed a purchase and sale agreement
with Vector Wind Energy, a wholly owned subsidiary of Canadian Hydro Developers Inc., for its Fairfield Hill wind power site. Under the purchase and sale agreement, TransAlta acquired
Canadian Hydro's Fairfield Hill wind power site, including the option to develop the site at a future date, for $1 million. Natural Forces Technologies Inc. has an option to purchase
up to 17 per cent of the Kent Hills project within 180 days of its completion.

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

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

Fixed price
gas
purchase
contracts


Operating
leases


Coal supply
and mining
agreements


Interest on
long-term
debt1


Project
commitments


Total2009

$
9

$
17

$
51

$
158

$
292

$
5272010


7


19


47


145


74


2922011


7


19


47


133


4


2102012


7


19


47


112





1852013


8


18


51


98





1752014 and thereafter


37


73


317


564





991Total

$
75

$
165

$
560

$
1,210

$
370

$
2,380


31.  Prior Period Regulatory Decision

In response to a complaint filed by San Diego Gas & Electric Company under Section 206 of the Federal Power Act("FPA"), the Federal Energy Regulatory Commission ("FERC")
established a claim of approximately U.S.$46 million in refunds
owing by TransAlta for sales made by it in the organized markets of the California Power Exchange ("PX") and the California Independent System Operator ("ISO") during the Oct. 2, 2000 through
June 20, 2001 period (the "Main Refund Transactions"). TransAlta has provided U.S.$46 million to account for refund liabilities relating to Main Refund Transactions. TransAlta
filed a cost-of-service-based petition for relief from these refund obligations. FERC rejected TransAlta's relief petition. On Dec. 1, 2006, TransAlta filed for rehearing of FERC's rejection.
On Aug. 24, 2007, the U.S. Court of Appeals for the Ninth Circuit granted the appeal. TransAlta has requested a rehearing, however; FERC has yet to make a ruling on such a request and
such a decision is not expected in the near future.

During
settlement negotiations, the complaintants have sought to obtain refunds for two sets of transactions beyond the Main Refund Transactions. The first set includes
sales made by sellers in the PX and ISO markets in the period May 1 to Oct. 1, 2001 (the "Summer Transactions"). The other set includes bilateral transactions between all
sellers and a component of the California Department of Water Resources ("CDWR") referred to as CERS (the "CERS Transactions"). FERC has specifically rejected attempts to introduce refunds
for the Summer and CERS Transactions. Nonetheless, the California parties have sought rehearing of FERC's refusal and appealed the refusal to the U.S. Court of Appeals for the Ninth Circuit.
The Ninth Circuit held that FERC's authorization of market-based rate tariffs in these proceedings complied with the FPA, but that FERC erred in refusing refunds on the grounds that it lacked
authority to order refunds for violations of its reporting requirement and remanded the case for further refund proceedings. The court did not itself order any refunds, leaving it to FERC to
consider appropriate remedial options.

On
March 21, 2008, FERC issued an Order on Remand establishing a refund hearing before an Administrative Law Judge to determine whether any individual public
utility seller's violation of FERC's market-based rate quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and
thus cause its market-based rates to be unjust and unreasonable in California during the 2000-2001 period. The California parties appealed FERC's basis for determining refund liability
but the appeal was denied by FERC on October 6, 2008.

TransAlta
does not presently believe the California parties will be successful in obtaining refunds alleged for the Summer and CERS transactions. TransAlta has not made
any provision for such alleged refunds at this time.

32.  Segment Disclosures

A.   Description of Reportable Segments

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

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

Generation
expenses include COD's intersegment charge for energy marketing and financial risk management services in the amount of $30 million
(2007  $27 million, 2006  $28 million). COD's operating expenses are presented net of these intersegment
charges.

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

102TransAlta Corporation    Annual Report 2008

---





B.   Reported Segment Earnings and Segment Assets

I.   Earnings Information

Year ended Dec. 31, 2008


Generation


COD


Corporate


TotalRevenues

$
3,005

$
105

$


$
3,110Fuel and purchased power(Notes 1 and 3)


(1,493
)







(1,493
)Gross margin


1,512


105





1,617Operations, maintenance, and administration


487


53


97


637Depreciation and amortization


409


3


16


428Taxes, other than income taxes


19








19Intersegment cost allocation


30


(30
)




Operating expenses


945


26


113


1,084Operating income (loss)

$
567

$
79

$
(113
)
$
533Foreign exchange loss











(12
)Gain on sale of equipment(Note 16)











5Net interest expense(Note 21)











(110
)Equity loss(Notes 13 and 27)











(97
)Earnings before non-controlling interests and income taxes










$
319




Year ended Dec. 31, 2007


Generation


COD


Corporate


TotalRevenues

$
2,720

$
55

$


$
2,775Fuel and purchased power(Notes 1 and 3)


(1,231
)







(1,231
)Gross margin


1,489


55





1,544Operations, maintenance, and administration


447


34


96


577Depreciation and amortization


391


1


14


406Taxes, other than income taxes


20








20Intersegment cost allocation


27


(27
)




Operating expenses


885


8


110


1,003Operating income (loss)

$
604

$
47

$
(110
)
$
541Foreign exchange gain











3Gain on sale of equipment(Note 16)











16Net interest expense(Note 21)











(133
)Equity loss(Note 13)











(50
)Earnings before non-controlling interests and income taxes










$
377




Year ended Dec. 31, 2006


Generation


COD


Corporate


TotalRevenues

$
2,612

$
65

$


$
2,677Fuel and purchased power(Note 1)


(1,186
)







(1,186
)Gross margin


1,426


65





1,491Operations, maintenance, and administration


458


37


86


581Depreciation and amortization


397


1


12


410Taxes, other than income taxes


21








21Intersegment cost allocation


28


(28
)




Operating expenses


904


10


98


1,012Mine closure charges(Note 3)


192








192Asset impairment charges(Note 4)


130








130Operating income (loss)

$
200

$
55

$
(98
)
$
157Foreign exchange loss











(1
)Net interest expense(Note 21)











(168
)Equity loss(Note 13)











(17
)Loss before non-controlling interests and income taxes










$
(29
)


2008 Notes to the Consolidated Financial Statements103

---



II.   Selected Balance Sheet Information

Dec. 31, 2008


Generation


COD


Corporate


TotalGoodwill(Note 17)

$
112

$
30

$


$
142Total segment assets

$
7,110

$
206

$
499

$
7,815Dec. 31, 2007Goodwill(Note 17)

$
95

$
30

$


$
125Total segment assets

$
5,950

$
147

$
1,060

$
7,157


An increase in foreign exchange rates has resulted in a $17 million change in goodwill. A portion of goodwill is related to
CE Gen and is therefore denominated in U.S. dollars. The change in foreign exchange rates related to translation of self-sustaining foreign operations does not affect
earnings and the cumulative translation loss is reflected in AOCI.

III.   Selected Cash Flow Information

Year ended Dec. 31, 2008


Generation


COD


Corporate


TotalCapital
expenditures

$
992

$
7

$
7

$
1,006Year ended Dec. 31, 2007Capital expenditures

$
577

$
5

$
17

$
599Year ended Dec. 31, 2006Capital expenditures

$
206

$
2

$
16

$
224


IV.   Depreciation and Amortization Expense Per Statements of Cash Flows

The reconciliation between depreciation expense on the statements of earnings and statements of cash
flows is presented below:

Year ended Dec. 31


2008


2007


2006Depreciation and amortization expense for reportable segments

$
428

$
406

$
410Depreciation included in fuel, and purchased power


38


30


50Accretion expense, included in depreciation and amortization expense


(22
)

(24
)

(22
)Other


7


3


Depreciation and amortization expense per statements of cash flows

$
451

$
415

$
438


C.   Geographic Information

I.   Revenues

Year ended Dec. 31


2008


2007


2006Canada

$
1,839

$
1,742

$
1,761U.S.


1,165


932


825Australia


106


101


91Total revenue

$
3,110

$
2,775

$
2,677


II.   Property, Plant, and Equipment and Goodwill

Property, Plant, and Equipment(Note 15)


Goodwill(Note 17)As at Dec. 31


2008


2007


2008


2007Canada

$
4,464

$
3,877

$
57

$
57U.S.


1,405


1,087


85


68Australia


152


153





Total

$
6,021

$
5,117

$
142

$
125


33.  Stock-Based Compensation Plans

At Dec. 31, 2008, the Corporation had three types of stock-based compensation plans and an employee share
purchase plan.

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

A.   Fixed Stock Option Plans

I.   Canadian Employee Plan

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

104TransAlta Corporation    Annual Report 2008

---



II.   U.S. Plan

This plan mirrors the rules of the Canadian plan.

III.   Australian Phantom Plan

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

Summary
of the total options outstanding and options exercisable at Dec. 31, 2008 are shown below:

Options outstanding


Options exercisableNumber
outstanding
at Dec. 31,
2008
(millions
)

Weighted
average
remaining
contractual
life (years
)

Weighted
average
exercise
price


Number
exercisable
at Dec. 31,
2008
(millions
)

Weighted
average
exercise
priceRange of exercise
prices$13.32  20.55


0.5


5.0

$
16.11


0.3

$
15.64$20.56  27.80


0.3


2.2


24.41


0.2


24.41$27.81  35.05


0.7


9.1


32.11





$35.06  42.26


0.1


9.1


38.95





$13.32  42.26


1.6


6.8

$
27.06


0.5

$
19.51


The change in the fixed option plans are outlined below:

Year ended Dec. 31


2008


2007


2006Number of
share
options
(millions
)

Weighted
average
exercise
price


Number of
share
options
(millions
)

Weighted
average
exercise
price


Number of
share
options
(millions
)

Weighted
average
exercise
priceOutstanding, beginning of year


1.1

$
19.42


2.0

$
19.95


2.7

$
19.45Granted


1.0


32.10











Exercised


(0.3
)

20.52


(0.7
)

21.19


(0.6
)

17.51Cancelled or expired


(0.2
)

27.96


(0.2
)

17.52


(0.1
)

20.65Outstanding, end of year


1.6

$
27.06


1.1


19.42


2.0

$
19.95


B.   Performance Stock Option Plan

In 1999, the Corporation expanded enrolment in the stock option program to include all Canadian employees of the Corporation,
excluding the level of director and above, by issuing stock options with an expiry date of 2009 and vesting dependent upon achieving certain earnings per share targets.

The
change in the performance stock option plan is outlined below:

Year ended Dec. 31


2008


2007


2006Number of
share
options
(millions
)

Weighted
average
exercise
price


Number of
share
options
(millions
)

Weighted
average
exercise
price


Number of
share
options
(millions
)

Weighted
average
exercise
priceOutstanding, beginning of year


0.1

$
22.71


0.2

$
22.73


0.2

$
22.62Exercised





22.92


(0.1
)

22.75





21.99Cancelled or expired





23.05











23.05Outstanding, end of year


0.1

$
22.55


0.1

$
22.71


0.2

$
22.73


No options were issued in 2008 (2007  nil,
2006  nil).

At
Dec. 31, 2008, the Corporation had 3,000 options under this plan with an exercise price of $14.15 and a weighted average remaining contractual life of one
year and 49,875 options with an exercise price of $23.05 and a weighted average remaining contractual life of 0.1 years outstanding. At Dec. 31, 2008, all outstanding options
had vested.

C.   Performance Share Ownership Plan ("PSOP")

Under the terms of the PSOP, which commenced in 1997, the Corporation was authorized to grant to employees and directors up to an
aggregate of 2.0 million common shares. The number of common shares that could be issued under both the PSOP and the share option plans, however, could not exceed 6.0 million common
shares. Participants in the PSOP receive grants which, after three years, make them eligible to receive a set number of common shares or cash equivalent up to the maximum of the grant amount plus
any accrued dividends thereon. The actual number of common shares or cash equivalent a participant may receive is determined by the percentile ranking of the total shareholder return over three
years of the Corporation's common shares amongst the companies comprising the S&P/TSX Composite Index. Expense related to this plan is recorded during the period earned, with corresponding payable
recorded in liabilities.

On
Dec. 31, 2001, the plan was modified so that after three years, once the PSOP eligibility has been determined, 50 per cent of the shares may be
released to the participant, while the remaining 50 per cent will be held in trust for one additional year. In addition, the number of common

2008 Notes to the Consolidated Financial Statements105

---



shares
the Corporation is authorized to grant under the terms of the PSOP was increased to 4.0 million common shares and the maximum number of common shares that may be issued under both the
PSOP and share option plans was increased to 13.0 million common shares.

Year ended Dec. 31


2008


2007


2006Number of awards outstanding, beginning of year (in millions)


1.0


1.2


1.1Granted


0.2


0.4


0.6Awarded


(0.2
)

(0.1
)

(0.1
)Cancelled or expired


(0.1
)

(0.5
)

(0.4
)Number of awards outstanding, end of year


0.9


1.0


1.2


In 2008, PSOP compensation expense was $5 million after-tax
(2007  $7 million after-tax, 2006  $4 million after-tax), which is included in
OM&A expense in the statements of earnings. In 2008, 221,855 common shares were issued at $24.30 per share. In 2007, 103,896 common shares were issued at $33.35 per share. In 2006,
137,039 common shares were issued at $25.41 per share.

D.   Employee Share Purchase Plan

Under the terms of the employee share purchase plan, the Corporation will extend an interest-free loan (up to
30 per cent of an employee's base salary) to employees below executive level and allow for payroll deductions over a three-year period to repay the loan. Executives are no
longer eligible for this program in accordance with the Sarbanes-Oxley legislation. The Corporation will purchase these common shares on the open market on behalf of employees at prices based on the
market price of the shares as determined on the date of purchase. Employee sales of these shares are handled in the same manner. At Dec. 31, 2008, accounts receivable from employees under the
plan totalled $3 million (2007  $0.3 million).

E.   Stock-Based Compensation

At Dec. 31, 2008, the Corporation had 1.7 million outstanding employee stock options
(2007  1.2 million).

The
Corporation uses the fair value method of accounting for awards granted under its fixed stock option plans and its performance stock option plan. On Feb. 1,
2008, 1.0 million stock options were granted at a strike price of $31.97, being the last sale price of board lots of the shares on the TSX the day prior to the day the options were granted
for Canadian employees, and U.S.$31.83, being the closing sale price on the New York Stock Exchange on the same date for U.S. employees. These options will vest in equal installments over
four years starting Feb. 1, 2009 and expire after 10 years. The estimated fair value of these options granted was determined using the Black-Scholes option-pricing model and the
following assumptions, resulting in a fair value of $6.31 per option:

Risk-free interest rate (%)


3.6Expected life of the options (years)


7Dividend rate (%)


3.4Volatility in the price of the corporation's shares (%)


23.2


The estimated fair value of these options granted in 2005 was determined using the binomial model and the following assumptions,
resulting in a fair value of $6.84 per option:

Risk-free interest rate (%)


4.3Expected life of the options (years)


10Dividend rate (%)


5.6Volatility in the price of the corporation's shares (%)


47.0


The estimated fair value of these options granted in 2002 and prior was determined using the binomial model and the following
assumptions, resulting in a weighted average fair value of $4.25 per option:

Risk-free interest rate (%)


5.9Expected hold period to exercise (years)


7Volatility in the price of the corporation's shares (%)


28.3




34.  Employee Future Benefits

A.   Description

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

The
latest actuarial valuations for accounting purposes of the registered and supplemental pension plans were as at Dec. 31, 2008. The measurement date used to
determine plan assets and accrued benefit obligation was Dec. 31, 2008. The last actuarial valuation for funding purposes of the registered plan was Dec. 31, 2007, and the effective
date of the next required valuation for funding purposes is Dec. 31, 2010. The supplemental pension plan is solely the obligation of the Corporation. The Corporation is not obligated to fund
the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation has posted a letter of credit in the amount of $52 million to secure the
obligations under the supplemental plan.

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

106TransAlta Corporation    Annual Report 2008

---



B.   Costs Recognized

Year ended Dec. 31, 2008


Registered


Supplemental


Other


TotalCurrent service cost

$
3

$
1

$
1

$
5Interest cost


20


3


1


24Actual return on plan assets


55








55Actuarial gain


(49
)

(5
)

(4
)

(58
)Difference between expected return and actual return on plan assets


(79
)







(79
)Difference between amortized and actuarial loss on accrued benefit obligation for year


50


6


5


61Past service costs





2





2Difference between amortized and actual plan amendments of past service costs for the year





(2
)




(2
)Amortization of net transition (asset) obligation


(9
)







(9
)Defined benefit (income) expense


(9
)

5


3


(1
)Defined contribution option expense of registered pension plan


17








17Net expense

$
8

$
5

$
3

$
16




Year ended Dec. 31, 2007


Registered


Supplemental


Other


TotalCurrent service cost

$
4

$
2

$
1

$
7Interest cost


19


2


2


23Actual return on plan assets


(10
)







(10
)Actuarial (gain) loss


(15
)

6


(2
)

(11
)Difference between expected return and actual return on plan assets


(15
)







(15
)Difference between amortized and actuarial loss (gain) on accrued benefit obligation for year


16


(4
)

2


14Amortization of net transition (asset) obligation


(9
)







(9
)Defined benefit (income) expense


(10
)

6


3


(1
)Defined contribution option expense of registered pension plan


15








15Net expense

$
5

$
6

$
3

$
14




Year ended Dec. 31, 2006


Registered


Supplemental


Other


TotalCurrent service cost

$
4

$
1

$
2

$
7Interest cost


20


2


1


23Actual return on plan assets


(35
)







(35
)Actuarial (gain) loss


(1
)

1





Difference between expected return and actual return on plan assets


10








10Difference between amortized and actuarial loss on accrued benefit obligation for year


4








4Centralia coal mine closure charges


1








1Amortization of net transition (asset) obligation


(9
)







(9
)Defined benefit (income) expense


(6
)

4


3


1Defined contribution option expense of registered pension plan


17








17Net expense

$
11

$
4

$
3

$
18


In 2008, 2007, and 2006, the entire net expense is related to continuing operations.

C.   Status of Plans

Year ended Dec. 31, 2008


Registered


Supplemental


OtherFair value of plan
assets

$
279

$
3

$
Accrued benefit obligation


324


47


20Funded status  plan deficit


(45
)

(44
)

(20
)Amounts not yet recognized in financial statements:Unrecognized past service costs





1


3Unamortized transition (asset) obligation


(18
)

1


Unamortized net actuarial gains


72


9


Total recognized in financial statements:Accrued benefit asset (liability)

$
9

$
(33
)
$
(17
)Amortization period in years (EARSL)/(EARL)(Note 2)


15


13


15


2008 Notes to the Consolidated Financial Statements107

---





Year ended Dec. 31, 2007


Registered


Supplemental


OtherFair value of plan
assets

$
356

$
2

$
Accrued benefit obligation


373


49


23Funded status  plan deficit


(17
)

(47
)

(23
)Amounts not yet recognized in financial statements:Unrecognized past service costs


1


(1
)

3Unamortized transition (asset) obligation


(28
)

2


Unamortized net actuarial gains


42


15


4Total recognized in financial statements:Accrued benefit liability

$
(2
)
$
(31
)
$
(16
)Amortization period in years (EARSL)


7


6


14


The current portion of the accrued benefit liability is included in accounts payable and accrued liabilities on the consolidated
balance sheets. The long-term portion is included in deferred credits and other long-term liabilities.

Year ended Dec. 31, 2008


Registered


Supplemental


OtherAccrued current
liabilities

$


$


$
1Other long-term (assets) liabilities


(9
)

33


16Accrued benefit liability

$
(9
)
$
33

$
17




Year ended Dec. 31, 2007


Registered


Supplemental


OtherAccrued current
liabilities

$


$


$
1Other long-term liabilities


2


31


15Accrued benefit liability

$
2

$
31

$
16


D.   Contributions

Expected cash flows are as follows:

Registered


Supplemental


Other


TotalEmployer
contributions2009 (expected)

$
9

$
3

$
2

$
14Expected benefit payments2009


26


2


2


302010


26


3


2


312011


27


3


2


322012


27


3


2


322013


28


3


2


332014-2018


142


18


10


170


E.   Plan Assets

Registered


Supplemental


OtherFair value of plan assets at Dec. 31,
2006

$
374

$
2

$
Contributions


1


4


2Benefits paid


(29
)

(4
)

(2
)Effect of translation on U.S. plans








Actual return on plan assets1


10





Fair value of plan assets at Dec. 31, 2007

$
356

$
2

$
Contributions


3


4


2Benefits paid


(27
)

(3
)

(2
)Effect of translation on U.S. plans


2





Actual return on plan assets1


(55
)




Fair value of plan assets at Dec. 31, 2008

$
279

$
3

$



The Corporation's investment policy is to seek a consistently high investment return over time while maintaining an acceptable
level of risk to satisfy the benefit obligations of the pension plans. The goal is to maintain a long-term rate of return on the fund that at least equals the growth of liabilities,
currently seven per cent. The pension fund may be invested in publicly traded common or preferred equity shares, rights or warrants, convertible debentures or preferred securities, bonds,
debentures, mortgages, notes or other debt instruments of government agencies or corporations, private company securities, guaranteed investment contracts, term deposits, cash or money market
securities, and mutual or pooled funds eligible for pension fund investment. The target allocation percentages are 60 per cent equity and 40 per cent fixed income. Cash
and money market instruments may be held from time-to-time as short-term investment decisions or as defensive reserves within the portfolios of each asset class.
The fund may invest in derivatives for the purpose of hedging the portfolio or altering the desired mix of the fund. Derivative transactions that leverage the fund in any way are not permitted
without the specific approval of the Corporation's pension committee.

108TransAlta Corporation    Annual Report 2008

---



The
allocation of plan assets by major asset category at Dec. 31, 2008 and 2007 is as follows:

Year ended Dec. 31, 2008


Registered


SupplementalEquity
securities


51%


Debt securities


48%


Cash equivalents


1%


100%Total


100%


100%




Year ended Dec. 31, 2007


Registered


SupplementalEquity
securities


58%


Debt securities


41%


Cash equivalents


1%


100%Total


100%


100%


Plan assets include common shares of the Corporation having a fair value of $0.4 million at Dec. 31, 2008
(2007  $1 million). The Corporation charged the registered plan $0.1 million for administrative services provided for the year ended
Dec. 31, 2008 (2007  $0.1 million).

F.   Reconciliation of Accrued Benefit Obligation

Registered


Supplemental


OtherAccrued benefit obligation as at Dec. 31,
2006

$
399

$
44

$
24Current service cost


4


2


1Interest cost


19


2


2Benefits paid


(29
)

(4
)

(2
)Effect of translation on U.S. plans


(1
)




Actuarial (gain) loss


(19
)

5


(2
)Accrued benefit obligation as at Dec. 31, 2007

$
373

$
49

$
23Current service cost


3


1


1Past service cost





2


Interest cost


20


3


1Benefits paid


(27
)

(3
)

(2
)Effect of translation on U.S. plans


4





1Actuarial gain


(49
)

(5
)

(4
)Accrued benefit obligation as at Dec. 31, 2008

$
324

$
47

$
20


G.   Assumptions

The significant actuarial assumptions adopted in measuring the Corporation's accrued benefit obligation was as follows:

Year ended Dec. 31, 2008


Registered


Supplemental


OtherAccrued benefit obligation at
Dec. 31Discount rate (%)


7.2


7.3


7.1Rate of compensation increase (%)


3.2


3.3


Benefit cost for year ended Dec. 31Discount rate (%)


5.5


5.5


5.7Rate of compensation increase (%)


3.7


3.8


Expected rate of return on plan assets (%)


7.1





Assumed health care cost trend rate at Dec. 31Health care cost escalation (%)








9.0-10.5
1Dental care cost escalation (%)








4.0Provincial health care premium escalation (%)








2.5




Year ended Dec. 31, 2007


Registered


Supplemental


OtherAccrued benefit obligation at
Dec. 31Discount rate (%)


5.5


5.5


5.7Rate of compensation increase (%)


3.7


3.8


Benefit cost for year ended Dec. 31Discount rate (%)


5.0


5.0


5.3Rate of compensation increase (%)


3.8


3.8


Expected rate of return on plan assets (%)


7.1





Assumed health care cost trend rate at Dec. 31Health care cost escalation (%)








9.0-10.0
1Dental care cost escalation (%)








4.0Provincial health care premium escalation (%)








2.5


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

2008 Notes to the Consolidated Financial Statements109

---





35.  Joint Ventures

Joint ventures at Dec. 31, 2008 included the following:

Joint venture




DescriptionSheerness joint venture


50%

Coal-fired plant in Alberta, of which TA Cogen has a 50 per cent interest, and is operated by Canadian UtilitiesMeridian joint venture


50%

Cogeneration plant in Alberta, of which TA Cogen has a 50 per cent interest, and is operated by
TransAltaFort Saskatchewan joint venture


60%

Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest, and is operated by
TransAltaMcBride Lake joint venture


50%

Wind generation facilities in Alberta, operated by TransAltaGoldfields Power joint venture


50%

Gas-fired plant in Australia, operated by TransAltaCE Generation LLC


50%

Geothermal and gas plants in the United States, operated by CE Gen affiliatesGenesee 3


50%

Coal-fired plant in Alberta, operated by EPCOR Utilities Inc.Wailuku


50%

A run-of-river generation facility in Hawaii, operated by MidAmericanKeephills 3


50%

Coal-fired plant under construction in Alberta. The plant is being developed jointly with EPCOR Utilities Inc.


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

2008


2007


2006Results of operationsRevenues

$
619

$
609

$
611Expenses


(494
)

(454
)

(457
)Non-controlling interests


(55
)

(44
)

(42
)Proportionate share of net earnings

$
70

$
111

$
112Cash flowsCash flow from operations

$
273

$
112

$
115Cash flow used in investing activities


(376
)

(147
)

(44
)Cash flow from (used in) financing activities


30


(93
)

(52
)Proportionate share of (decrease)/increase in cash and cash equivalents

$
(73
)
$
(128
)
$
19Financial positionCurrent assets

$
166

$
91

$
147Long-term assets


2,144


1,924


1,850Current liabilities


(202
)

(144
)

(117
)Long-term liabilities


(503
)

(390
)

(503
)Non-controlling interests


(351
)

(373
)

(394
)Proportionate share of net assets

$
1,254

$
1,108

$
983


110TransAlta Corporation    Annual Report 2008

---



36.  Subsequent Events

Sundance Unit 4 Derate

On Feb. 10, 2009, TransAlta reported the first quarter financial impact of an extended derate at Unit 4 of the Sundance
thermal plant ("Unit 4"). The facility experienced an unplanned outage in December 2008 related to the failure of an induced draft ("ID") fan. At that time, Unit 4, which has a capacity of
406 MW, had been derated to approximately 205 MW. The repair of the ID fan components by the original equipment manufacturer took longer than planned, and therefore, Unit 4 did
not return to full service until Feb. 23, 2009. As a result of the extended derate, first quarter production was reduced by 328 GWh and net income declined by $17 million.

TransAlta
has given notice of a High Impact Low Probability Event to the PPA Buyer and the Balancing Pool, which if successful, will protect the Corporation from the
financial loss and related penalties. The available penalties that TransAlta expects to recover in net income are anticipated to be $14 million.

Keephills Units 1 and 2 Uprates

On Jan. 29, 2009, TransAlta announced a 46 MW (23 MW per unit) efficiency uprate at Unit 1 and Unit 2 of its
Keephills facility. The total capital cost of the project is estimated at $68 million with commercial operations expected to commence by the end of 2011 and 2012, respectively.

Dividend Increase

On Jan. 28, 2009, TransAlta's Board of Directors declared a quarterly dividend of $0.29 per share on common shares, an
increase of $0.02 per share, which on an annual basis will yield $1.16 per share versus $1.08.

Carbon Capture and Storage

On Jan. 27, 2009, the Government of Canada announced in the 2009 federal budget an additional $850 million of
funding that has been earmarked to support the development of carbon capture and storage technologies. The impact of this announcement on the Corporation cannot be reasonably determined at this time
because specific information regarding the use, distribution timelines, and recipients of the funding have not been clarified by the government.

2008 Notes to the Consolidated Financial Statements111

---





Eleven-Year Financial and Statistical Summary

(in millions of Canadian dollars, except where noted)



Year ended Dec. 31


2008


2007


2006


2005Financial SummaryEarnings StatementRevenues

$
3,110

$
2,775

$
2,677

$
2,664Operating income

$
533

$
541

$
157

$
421Net earnings applicable to common shareholders

$
235

$
309

$
45

$
199Balance SheetTotal assets

$
7,815

$
7,157

$
7,460

$
7,741Short-term debt, net of cash and cash equivalents

$
393

$
600

$
296

$
(66
)Long-term debt

$
2,365

$
1,837

$
2,221

$
2,605Preferred shares of a subsidiary

$


$


$


$
Other non-controlling interests

$
469

$
496

$
535

$
559Preferred securities

$


$


$
175

$
175Common shareholder's equity

$
2,510

$
2,299

$
2,428

$
2,543Total invested capital

$
5,737

$
5,232

$
5,655

$
5,756Cash FlowCash flow from operating activities

$
1,038

$
847

$
490

$
619Cash flow used in investing activities

$
(581
)
$
(410
)
$
(261
)
$
(242
)Common Share Information(per share)Net earnings

$
1.18

$
1.53

$
0.22

$
1.01Dividends declared

$
1.08

$
1.00

$
1.00

$
1.00Book value (at year-end)

$
12.70

$
11.39

$
11.99

$
12.80Market price:High

$
37.50

$
34.00

$
26.91

$
26.66Low

$
21.00

$
23.79

$
20.22

$
17.67Close (TSX at Dec. 31)

$
24.30

$
33.35

$
26.64

$
25.41Ratios(percentage except where noted)Debt/invested capital


48.1


46.8


44.5


43.9Return on common shareholder's equity


9.8


13.1


1.8


7.0Return on invested capital


7.8


9.8


2.4


7.1Cash flow to total debt


31.1


30.7


26.2


23.0Cash flow to interest coverage (times)


7.2


6.6


5.5


4.7Dividend payout


91.5


65.6


447.7


113.0Dividend yield


4.4


3.0


3.8


3.9Price/earnings multiple


20.6


21.8


121.1


26.7Weighted average common shares
for the year (in millions)


199


202


201


197Common shares oustanding at Dec. 31 (in millions)


198


201


202


199Statistical SummaryNumber of employees


2,200


2,201


2,687


2,657Generating Capacity(net MW)3Hydro


807


807


807


802Coal


4,942


4,942


4,887


4,885Gas


1,913


1,960


1,953


1,933Renewables


411


315


315


315Total generating capacity


8,073


8,024


7,962


7,935Total generation production (GWh)4


48,891


50,395


48,213


51,810Prior years have not been restated to conform with the current year's presentation.1  2002 and 2001 Energy Marketing real-time trading
    contract revenues restated to be presented on a
    gross basis.
2  Includes discontinued operations.
3  Represents TransAlta's ownership.
4  Includes discontinued operations.


Ratio FormulasDebt/invested capital = (short-term debt + long-term debt  cash and cash equivalents)/(debt + preferred securities + non-controlling interests + common equity)
Return on common shareholder's equity = net earnings excluding gain on discontinued operations/average of opening and closing common equity


112TransAlta Corporation    Annual Report 2008

---







2004


2003


2002


2001


2000


1999


1998$
2,838

$
2,509

$
1,815
1
$
2,560
1
$
1,587

$
1,029

$
1,090$
478

$
554

$
224
2
$
469
2
$
605
2
$
442

$
660
2$
170

$
234

$
190

$
215

$
280

$
170

$
211$
8,133

$
8,420

$
7,420

$
7,878

$
7,627

$
6,038

$
5,393$
(103
)
$
(35
)
$
146

$
475

$
221

$
(173
)
$
(149
)$
3,058

$
3,162

$
2,707

$
2,511

$
2,201

$
2,177

$
1,904$


$


$


$


$
122

$
268

$
268$
616

$
478

$
263

$
281

$
253

$
377

$
503$
175

$
451

$
452

$
453

$
292

$
287

$
$
2,473

$
2,460

$
2,040

$
1,990

$
1,957

$
1,836

$
1,855$
6,061

$
6,516

$
5,608

$
5,710

$
5,046

$
4,772

$
4,381$
613

$
757

$
438

$
716

$
189

$
422

$
471$
(65
)
$
(535
)
$
(36
)
$
(1,077
)
$
(205
)
$
(989
)
$
(137
)$
0.88

$
1.26

$
1.12

$
1.27

$
1.66

$
1.00

$
1.31$
1.00

$
1.00

$
1.00

$
1.00

$
1.00

$
1.00

$
0.99$
12.74

$
12.90

$
12.01

$
11.82

$
11.61

$
10.85

$
10.94$
18.75

$
19.55

$
23.95

$
30.13

$
22.55

$
25.15

$
25.40$
15.25

$
15.36

$
16.69

$
19.15

$
13.20

$
12.25

$
18.20$
18.05

$
18.53

$
17.11

$
21.60

$
22.00

$
14.15

$
22.6047.4


47.9


50.9


52.3


48.0


45.6


40.06.5


10.3


3.5


10.9


11.7


9.2


12.37.5


9.1


4.0


8.7


12.3


9.7


15.418.5


17.9


16.1


21.8


25.3


21.7


22.84.1


3.3


3.8











120.0


79.0


241.8


78.5


75.8


99.7


75.85.5


5.4


5.8


4.6


4.6


7.1


4.421.7


14.7


41.7


17.3


16.7


14.2


17.3193


185


170


169


169


170


161194


191


170


168


169


169


1702,505


2,563


2,573


2,656


2,363


2,679


2,455802


801


801


800


800


800


8004,778


4,777


4,966


5,090


5,016


3,676


3,6762,444


2,499


1,333


1,108


1,054


1,464


1,008313


245


44











8,337


8,322


7,144


6,998


6,870


5,940


5,48454,560


53,134


46,877


44,136


40,644


37,771


39,001Return on invested capital = earnings before non-controlling interests + income taxes + net interest expense/average annual invested capital
Cash flow to total debt = cash flow from operations before changes in working capital/two-year average of total debt
Dividend payout = dividends/net earnings excluding gain on discontinued operations


Dividend yield = common share dividends/current year's close price
Price/earnings multiple = current year's close/basic earnings per share from continuing operations


2008 Notes to the Consolidated Financial Statements113

---



114 TransAlta Corporation 08 Annual Meeting The Annual meeting
  will be held at 11:00 a.m. MST on Thursday, April 30, 2009, at Boyce Theatre,
  Calgary Stampede Roundup Centre, 1410 Olympic Way S.E., Calgary, Alberta.
  Transfer Agent CIBC Mellon Trust Company P.O. Box 7010 Adelaide Street
  Station Toronto, Ontario M5C 2W9 Phone North America: 1.800.387.0825
  toll-free Toronto/outside North America: 416.643.5500 E-mail
  inquiries@cibcmellon.com Fax 416.643.5501 Website www.cibcmellon.com
  Exchanges Toronto Stock Exchange (TSX) New York Stock Exchange (NYSE) Ticker
  Symbols TransAlta Corporation common shares: TSX: TA NYSE: TAC Voting Rights
  Common shareholders receive one vote for each common share held. Additional
  Information Requests can be directed to: Investor Relations TransAlta
  Corporation P.O. Box 1900, Station M 110 - 12th Avenue S.W. Calgary,
  Alberta T2P 2M1 Phone North America: 1.800.387.3598 toll-free Calgary/outside
  North America: 403.267.2520 E-mail investor_relations@transalta.com Fax
  403.267.2590 Website www.transalta.com Shareholder Information Special
  Services for Registered Shareholders Service Description Dividend
  reinvestment Conveniently reinvest your TransAlta dividends and and share
  purchase plan* purchase common shares without brokerage costs Direct deposit
  for Automatically have dividend payments deposited to your dividend payments
  bank account Account Eliminate costly duplicate mailings by consolidating
  account consolidations registrations Address changes Receive tax slips and
  dividends without the delays resulting and share transfers from address and
  ownership changes To use these services please contact our transfer agent. *
  Also available to non-registered shareholders. Stock Splits and Share
  Consolidations Date Events Ratio May 8, 1980 Stock split 3:1 Feb. 1, 1988
  Stock split 1 2:1 Dec. 31, 1992 Reorganization  TransAlta Utilities shares
  exchanged for TransAlta Corporation shares 2 1:1 The valuation date value of
  common shares owned on Dec. 31, 1971, adjusted for stock splits, is $4.54 per
  share. 1 The adjusted cost base for shares held on Jan. 31, 1988, was reduced
  by $0.75 per share following the Feb. 1, 1988, share split. 2 TransAlta
  Utilities Corporation became a wholly owned subsidiary of TransAlta
  Corporation as a result of this reorganization. Dividend Declaration
  Dividends are paid quarterly as determined by the Board. In determining the
  dividend, the Board reviews the Companys financial performance and balances
  financial liquidity require ments, capital investment and returning capital
  to shareholders. The Board has adopted a formal dividend policy that targets
  to pay shareholders an annual dividend in the range of 60 to 70 per cent of
  comparable earnings. The Board continues to focus on building sustainable
  earnings and dividend growth. Important Dividend Dates Payment Date Record
  Date Ex-Dividend Date Dividend April 1, 2008 March 1, 2008 Feb. 27, 2008
  $0.27 July 1, 2008 June 1, 2008 May 28, 2008 $0.27 Oct. 1, 2008 Sept. 1, 2008
  Aug. 27, 2008 $0.27 Jan. 1, 2009 Dec. 1, 2008 Nov. 27, 2008 $0.27 April 1,
  2009 March 1, 2009 Feb. 25, 2009 $0.29 Dividends are paid on the first of the
  month in January, April, July and October. When a dividend payment date falls
  on a weekend or holiday, the payment is made on the following business day. Only
  dividend payments that have been approved by the Board of Directors are
  included in this table. Submission of Concerns Regarding Accounting or
  Auditing Matters TransAlta has adopted a procedure for employees,
  shareholders or others to report con cerns or complaints regarding accounting
  or auditing matters on an anonymous, confidential basis to the Audit and Risk
  Committee of the Board of Directors. Such submissions may be directed to the
  Audit and Risk Committee c/o the Corporate Secretary of the Corporation.


115 08 Shareholder Highlights Shareholder Highlights 31.9 35.11
  33.97 36.03 36.86 37.15 22.90 24.30 Volume (millions of shares) TSX closing
  market price on last day of the month ($ per share) TRANSALTA 100 66 108 111
  92 105 109 161 176 228 172 S&P/ TSX COMPOSITE INDEX 100 132 141 124 108
  137 157 195 229 251 168 MARKET VALUE 14.15 22.00 21.60 17.11 18.53 18.05
  25.41 26.64 33.35 24.30 BOOK VALUE 10.85 11.61 11.82 12.01 12.90 12.74 12.80
  11.99 11.39 12.70 TRADING RANGE 0 7.5 15.0 22.5 30.0 37.5 0 100 50 150 200
  250 This chart compares what $100 invested in TransAlta and the S&P/TSX
  Composite Index at the end of 1997 would be worth today, assuming the
  reinvestment of all dividends. 9.2 11.7 10.9 3.5 10.3 6.5 7.0 1.8 13.1 9.8 08
  07 06 05 04 03 02 01 00 99 15 27 32 16 17 17 43 20 29 25 15 12 D N O S A J J
  M A M F J 08 07 06 05 04 03 02 01 00 99 08 07 06 05 04 03 02 01 00 99 98
  36.41 28.60 24.20 31.93 (millions of shares) Total Shareholder Return vs.
  S&P/TSX Composite Total Return Index Year Ended Dec. 31 ($) Monthly
  Volume and Market Price (2008) Ten-Year Trading Range and Market Value vs.
  Book Value ($ per share) Return on Common Shareholders Equity (%) Source:
  Factset Source: Thompson Financial Source: Thompson Financial and TransAlta
  (MD&A) Source: TransAlta (MD&A)


116 TransAlta Corporation 08 TransAlta Corporate Officers
  Stephen G. Snyder President & Chief Executive Officer Brian Burden
  Executive Vice-President & Chief Financial Officer William D.A. Bridge
  Executive Vice-President, Generation Technology & Procurement &
  Material Management Dawn Farrell Executive Vice-President, Commercial
  Operations & Development Richard P. Langhammer Executive Vice-President,
  Generation Operations Ken Stickland Executive Vice-President, Legal, Sustainable
  Development & Environment, Health & Safety Michael Williams Executive
  Vice-President, Human Resources, Information Technology & Communications
  Frank Hawkins Vice-President & Treasurer Maryse St.-Laurent Corporate
  Secretary TransAlta Senior Management Dawn de Lima Vice-President, Corporate
  Human Resources Robert Emmott Vice-President, Engineering Services Darcy
  Fedorchuk Vice-President, Procurement & Material Management Stephen W.
  Foster Vice-President, Generation Human Resources Brett Gellner
  Vice-President, Commercial Operations David J. Koch Vice-President, Financial
  Operations Mark B. Mackay Vice-President, Energy Technology Alex R. McFadden
  Vice-President, Environment, Health & Safety Colin Mills Vice-President,
  Western Canada Operations Parviz Mohamed Vice-President, Information
  Technology Jennifer M. E. Pierce Vice-President, Communications &
  Investor Relations Gregory P. Reinhart Vice-President, Commercial Operations
  & Development Human Resources Martin Ridge Vice-President, Internal Audit
  Rob Schaefer Vice-President, Development Hugo Shaw Vice-President,
  Maintenance, Field Engineering & Project Management Office Don Wharton
  Vice-President, Sustainable Development TransAlta Subsidiaries Doug Jackson
  President, TransAlta Centralia Generation LLC & Mining LLC Aron Willis
  Country Manager, TransAlta Energy (Australia) Pty Ltd. Corporate Governance
  TransAltas Corporate Governance Guidelines, Board Charter, Committee
  Charters, position descriptions for the Chair, Committee Chair, President
  & CEO and codes of business conduct and ethics are available on our
  website at www.transalta.com. Also available on our website is a summary of
  the significant ways in which TransAltas corporate governance practices
  differ from those required to be followed by U.S. domestic companies under
  the New York Stock Exchanges listing standards. Ethics Help-Line The Audit
  and Risk Committee of the Board of Directors has established an anonymous and
  confidential toll-free telephone number for employees, contractors and others
  to call with respect to accounting irregularities and ethical violations. The
  Ethics Help-Line number is 1.888.806.6646. Corporate Information In an effort
  to be environmentally responsible, please notify your financial institution
  to avoid duplicate mail ings of this annual report. Design & Production:
  Karo Group, Calgary Original Photography: Jason Stang Financial Production:
  Merrill Corp. Printing: MI5 * The TransAlta design and TransAlta wordmark are
  trademarks of TransAlta Corporation. This report was printed in Canada by MI5
  on FSC Certified paper. The paper, paper mills and printer are all Forest
  Stewardship Council certified, which is an international network that
  promotes environmentally appropriate and socially beneficial management of
  the worlds forests. The report was pro duced in a printing facility that
  results in nearly zero volatile organic compound (VOC) emissions


Glossary Glossary Air Emissions
  Substances released to the atmosphere through industrial operations. For the
  fossil-fuel-fired power sector, the most common air emissions are sulphur
  dioxide, oxides of nitrogen, mercury and greenhouse gases. Alberta 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. Availability A measure of 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. Boiler A device for generating steam for
  power, processing or heating purposes or for producing hot water for heating
  purposes or hot water supply. Heat from an external combustion source is
  transmitted to a fluid contained within the tubes of the boiler shell.
  Brownfield Asset A previously constructed electric power generating facility.
  BTU (British Thermal Unit) 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. Clean
  Coal Technology New technologies such as gasification using solid fuels (coal
  and coke) to produce power and chemical products with very low emissions. CO2
  Emissions Intensity Amount of carbon dioxide emitted per MWh produced. Coal
  Gasification The conversion of solid fuel to gaseous form, for subsequent
  conversion into power, synthetic gas, hydrogen or a variety of other chemical
  products. Cogeneration A generating facility that produces electricity and
  another form of useful thermal energy (such as heat or steam) used for
  industrial, commercial, heating or cooling purposes. Combined Cycle An
  electric generating technology in which electricity is produced from
  otherwise lost waste heat exiting from one or more gas (combustion) turbines.
  The exiting heat is routed to a conventional boiler or to a heat recovery
  steam generator for use by a steam turbine in the production of electricity.
  This process increases the efficiency of the electric generating unit. Derate
  To lower the rated electrical capability of a power generating facility or
  unit. Expected Capability Plant capacity after consideration of station
  service use, planned outages, forced and maintenance outages, and derates.
  Flue Gas Desulphurization Unit (Scrubber) Equipment used to remove sulphur
  oxides from the combustion gases of a boiler plant before discharge to the
  atmosphere. Chemicals, such as lime, are used as the scrubbing media. Force
  Majeure Literally means greater 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.
  Gigajoule (GJ) A metric unit of energy commonly used in the energy industry.
  One GJ equals 947,817 BTU. Gigawatt (GW) 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.
  Greenfield Asset A new electric power generating facility built from the
  ground up on a new site. 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. Merchant Asset TransAlta uses the term merchant to describe
  assets that have contracts with terms less than five years. Given our
  low-to-moderate risk profile, TransAlta contracts a significant portion of
  its merchant capability through short- and medium-term contracts. 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. Peaker Plant A plant usually housing low-efficiency
  steam units, gas turbines, diesels or pumped-storage hydro-electric equipment
  normally used during peakload periods. Renewable Power Power generated from
  renewable terrestrial mechanisms including wind, geothermal, solar and
  biomass with regeneration. Reserve Margin An indication of a markets
  capacity to meet unusual demand or deal with unforeseen outages/shutdowns of
  generating capacity. Run Rate The result of extrapolating financial data
  collected from a period of time less than one year to a full year. Spark
  Spread A measure of gross margin per MW (sales price less cost of natural
  gas). Supercritical 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. Target Zero TransAltas initiative designed to drive
  health, safety and environmental performance to zero lost-time, medical aid
  and environmental incidents. 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 the 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
  shutdown 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 trading
  activities.


TransAlta Corporation Box 1900, Station M, 110  12th Avenue
  SW, Calgary, Alberta, Canada T2P 2M1 403.267.7110 www.transalta.com


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