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

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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

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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

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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.

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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.

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26TransAlta Corporation    Annual Report 2008

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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

---



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

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