Exhibit 13.2

TransAlta Management’s Discussion and Analysis

December 31, 2009

PLANT SUMMARY

As of January 31, 2010	Facility	Capacity (MW)	(1)	Ownership (%)	Net capacity ownership interest (MW)	(1)	Fuel	Revenue source		Contract expiry date
	Sundance, AB	2,126		100	2,126		Coal	Alberta PPA/Merchant	(2)	2017, 2020
	Keephills, AB(3)	812		100	812		Coal	Alberta PPA/Merchant		2020
	Keephills 3, AB(4)	450		50	225		Coal	Merchant		–
	Sheerness, AB	780		25	195		Coal	Alberta PPA		2020
	Wabamun, AB(5)	279		100	279		Coal	Merchant		–
	Genesee 3, AB	450		50	225		Coal	Merchant		–
	Fort Saskatchewan, AB	118		30	35		Gas	LTC		2019
	Meridian, SK	220		25	55		Gas	LTC		2024
	Poplar Creek, AB	356		100	356		Gas	LTC/Merchant		2024
	Barrier, AB	13		100	13		Hydro	Alberta PPA		2020
	Bearspaw, AB	17		100	17		Hydro	Alberta PPA		2020
	Belly River, AB	3		100	3		Hydro	Merchant		–
	Big Horn, AB	120		100	120		Hydro	Alberta PPA		2020
	Brazeau, AB	355		100	355		Hydro	Alberta PPA		2020
	Cascade, AB	36		100	36		Hydro	Alberta PPA		2020
	Ghost, AB	51		100	51		Hydro	Alberta PPA		2020
	Horseshoe, AB	14		100	14		Hydro	Alberta PPA		2020
	Interlakes, AB	5		100	5		Hydro	Alberta PPA		2020
	Kananaskis, AB	19		100	19		Hydro	Alberta PPA		2020
	Pocaterra, AB	15		100	15		Hydro	Alberta PPA		2013
Western	Rundle, AB	50		100	50		Hydro	Alberta PPA		2020
Canada	Spray, AB	103		100	103		Hydro	Alberta PPA		2020
44 Facilities	St. Mary, AB	2		100	2		Hydro	Merchant		–
	Taylor Hydro, AB	13		50	6		Hydro	Merchant		–
	Three Sisters, AB	3		100	3		Hydro	Alberta PPA		2020
	Waterton, AB	3		100	3		Hydro	Merchant		–
	Akolkolex, BC	10		100	10		Hydro	LTC		2015
	Pingston, BC	45		50	23		Hydro	LTC		2023
	Upper Mamquam, BC	25		100	25		Hydro	LTC		2025
	Bone Creek, BC(4)	18		100	18		Hydro	LTC		2047
	Blue Trail, AB	66		100	66		Wind	Merchant		–
	Castle River, AB(6)	44		100	44		Wind	LTC/Merchant		2011
	Cowley North, AB	20		100	20		Wind	Merchant		–
	Cowley Ridge, AB	21		100	21		Wind	Merchant		–
	Macleod Flats, AB	3		100	3		Wind	Merchant		–
	McBride Lake, AB	75		50	38		Wind	LTC		2024
	Sinnott, AB	7		100	7		Wind	Merchant		–
	Soderglen, AB	71		50	35		Wind	Merchant		–
	Summerview 1, AB(7)	70		100	70		Wind	Merchant		–
	Taylor Wind, AB	3		100	3		Wind	Merchant		–
	Ardenville, AB(4)	69		100	69		Wind	Merchant		–
	Summerview 2, AB(4)	66		100	66		Wind	Merchant		–
	Grand Prairie, AB	25		100	25		Biomass	LTC		2019–2024
	Total Western Canada	7,051			5,666
	Mississauga, ON	108		50	54		Gas	LTC		2017
	Ottawa, ON	68		50	34		Gas	LTC		2012
	Sarnia(8), ON	506		100	506		Gas	LTC		2022–2025
	Windsor, ON	68		50	34		Gas	LTC/Merchant		2016
	Moose Rapids, ON	1		100	1		Hydro	LTC		2011
	Ragged Chute, ON	7		100	7		Hydro	LTC		2011
Eastern	Misema, ON	3		100	3		Hydro	LTC		2027
Canada	Appleton, ON	1		100	1		Hydro	LTC		2011
15 Facilities	Galetta, ON	2		100	2		Hydro	LTC		2011
	Kent Hills, NB	96		83	80		Wind	LTC		2033
	Kent Hills 2, NB(4)	54		100	54		Wind	LTC		2035
	Le Nordais, QC	99		100	99		Wind	LTC		2033
	Melancthon I, ON	68		100	68		Wind	LTC		2026
	Melancthon II, ON	132		100	132		Wind	LTC		2028
	Wolfe Island, ON	198		100	198		Wind	LTC		2029
	Total Eastern Canada	1,411			1,273
	Centralia, WA(9)	1,376		100	1,376		Coal	Merchant		–
	Centralia Gas, WA	248		100	248		Gas	Merchant		–
	Power Resources, TX	212		50	106		Gas	Merchant		–
United States	Saranac, NY	240		37.5	90		Gas	Merchant		–
17 Facilities	Yuma, AZ	50		50	25		Gas	LTC		2024
	Imperial Valley(10), CA	327		50	164		Geothermal	LTC		2016–2029
	Skookumchuk, WA	1		100	1		Hydro	–		–
	Wailuku, HI	10		50	5		Hydro	LTC		2023
	Total U.S.	2,464			2,015
Australia	Parkeston, WA	110		50	55		Gas	LTC		2016
5 Facilities	Southern Cross(11), WA	245		100	245		Gas/Diesel	LTC		2013
	Total Australia	355			300
Total		11,281			9,254

1	Megawatts are rounded to the nearest whole number	5	To be retired in 2010	9	Centralia Thermal’s NMC has been reduced from
2	Merchant capacity refers to uprates on unit 4 (53 MW),	6	Includes 7 individual turbines at other locations		1,404 MW to reflect a lower plant output as a result
	unit 5 (53 MW) and unit 6 (44 MW)	7	Comprised of 2 facilities		of its conversion to burning Power River Basin coal
3	Includes two 23 MW uprates on units 1 and 2 expected	8	Sarnia’s NMC has been adjusted from 575 MW due	10	Comprised of 10 facilities
	to be commercial in 2011 and 2012, respectively		to decommissioning of equipment at the facility	11	Comprised of 4 facilities
4	These facilities are currently under development

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MANAGEMENT’S DISCUSSION AND ANALYSIS

3 Business Environment 5 Strategy 5 Capability to Deliver Results 6 Performance Metrics 9 Results of Operations 10 Reported Earnings 11 Significant Events 16 Subsequent Events 16 Discussion of Segmented Results 21 Financial Position 22 Financial Instruments 25 Statements of Cash Flows 26 Liquidity and Capital Resources 27 Climate Change and the Environment 29 2010 Outlook 32 Risk Management 39 Critical Accounting Policies and Estimates 43 Future Accounting Changes 44 Non-GAAP Measures 47 Forward Looking Statements

This management’s discussion and analysis (“MD&A”) should be read in conjunction with the audited 2009 consolidated financial statements. The consolidated financial statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian 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 Feb. 23, 2010. 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.

Management’s Discussion and Analysis  |  2

BUSINESS ENVIRONMENT

Overview of the Business

We are a wholesale power generator and marketer with operations in Canada, the United States (“U. S.”), and Australia. In 2009, we celebrated our 100th year since incorporation. We own, operate, and manage a highly contracted and geographically diversified portfolio of assets and utilize a broad range of generation fuels including coal, natural gas, hydro, wind, geothermal, and biomass. During 2009, we increased our renewables portfolio from 15 per cent to 22 per cent of our net generating capacity with the acquisition of Canadian Hydro Developers, Inc. (“Canadian Hydro”) and the completion of our Blue Trail wind facility.

We operate in a variety of markets to generate electricity, find buyers for the power we generate, and arrange for its transmission. The major markets we operate in are Western Canada, the 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 main driver of longer-term changes in the demand for electricity. Historically, demand for electricity in all three of our major markets has grown at an average rate of one to three per cent per year; however, the weak economic environment experienced in 2009 resulted in zero to negative demand growth in our key markets. In Alberta, demand growth is expected to resume again in 2010 after three years of stagnation. Cost reductions combined with relatively well-supported oil prices are expected to result in a modest but sustained increase in oil sands development which will, in turn, lead to higher electricity demand. Due to the economic recession, the Pacific Northwest has seen demand destruction in 2009. Load in this region is not expected to return to 2008 levels until 2011 or 2012. The long-term growth rate in this region is expected to be lower than historical trends because there is a large emphasis on energy efficiency across the region. Demand in Ontario is expected to increase in 2010 as the economy recovers. In the longer-term, demand in Ontario is expected to remain constrained as the province’s economy continues to move away from manufacturing and as other energy efficiency policies take hold.

Supply

In all markets in which we operate, the cost of building most types of new generating capacity has decreased due to the global economic slowdown. Going forward, costs are expected to increase again as an economic recovery takes hold and markets tighten.

Greenhouse gas (“GHG”) legislation of some form is still expected in Canada and the U.S. Given this anticipated future legislation, new generating capacity in the short- to medium-term is expected to be primarily in renewable energy and natural gas-fired generation.

Reserve margins, which measure available capacity in a market over and above the capacity needed to meet normal peak demand levels, have increased due to low or negative levels of load growth combined with new supply coming on line. It is expected that reserve margins will begin to decline slowly from current levels as load growth resumes.

Green technologies have gained favour with regulators and the general public, creating increasing pressure to supply power using renewable resources such as wind, hydro, geothermal, and solar. The economic feasibility of solar power is still being debated.

While there are many new developments that will likely impact the future supply of electricity, the low cost of our base load operations still means that our plants are supported in 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 with the generating supply, allows for an amount of power required for system integrity and security, and allows for reserve capacity to respond to contingency situations on the system. Most transmission businesses in North America are still regulated.

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

In 2009, the provincial government declared several important projects as being critical, including transmission lines between the Edmonton and Calgary regions, and between Edmonton and northeast Alberta. As a result, transmission lines within one of our key markets will receive the necessary upgrade to become less congested, and therefore will be more efficient in meeting the needs of the growth in the demand for electricity in the long-term.

Historically, transmission systems have been designed to serve loads in only their local area, and interties between jurisdictions were only a small fraction of the local generation capacity or load. Future transmission lines will need to connect beyond provincial and state borders as there is a desire to improve efficiency by distributing large quantities of electricity from one region to another.

Environmental Legislation and Technologies

Environmental issues and related legislation have, and will continue to have, an impact upon our business. Since 2007, we have incurred costs as a result of GHG legislation in Alberta. Legislation in other jurisdictions and at different levels of government is in various stages

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of maturity and sophistication. 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 GHG emissions. However, economic uncertainty fueled by financial market volatility, a developing recovery, and Canada’s political environment may delay the adoption of such systems. For these reasons, the Canadian government may not implement new environmental legislation until the end of 2010 or later.

While carbon capture and storage (“CCS”) technologies are being developed, these technologies are not sufficiently advanced at this time. A $2 billion dollar provincial fund and a $1 billion federal fund have been dispersed to several, large demonstration projects. Those investments are expected to bring the cost of CCS down over the next 10 years. The outlook for these costs sets a floor price for carbon abatement technologies if regulatory or trading schemes are implemented. The future of carbon regulation remains uncertain.

Economic Environment

Although we are seeing signs of an economic recovery, it is too early to judge the pace and magnitude with which the recovery will occur. Our strong financial position, available committed lines of credit, and relatively low debt maturity profile allows us to be selective about when we go to the market for financing. In 2009, we took advantage of our strong financial position by completing the acquisition of Canadian Hydro, which included issuing debt and equity to finance the purchase. The market reacted favourably to these transactions and we see continued capital market support for other projects that meet our return requirements and risk profile.

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. Long-term contracts at Sarnia, and our short-term contracts at Centralia Thermal, minimize the impact of spot price changes. Spot electricity prices in our markets are driven by customer demand, generator supply, natural gas prices, and the other business environment dynamics discussed above. We monitor these trends in prices and schedule maintenance, where possible, during times of lower prices.

In 2009, average spot prices decreased in Alberta, the Pacific Northwest, and in Ontario due to lower natural gas prices and weaker demand for electricity. In Alberta, prices also decreased due to increased availability across the province’s thermal coal fleet.

During the year, our consolidated power portfolio was over 95 per cent hedged at an average price ranging from $60 – $65 per megawatt hour (“MWh”) in Alberta, and an average price ranging from U.S.$50 – $55/MWh in the Pacific Northwest. The use of these hedges reduced the impact of lower prices upon our consolidated financial results.

Technological advancements have made it possible to develop shale gas reserves that were previously inaccessible. In the short-term, economic conditions and new shale gas supply have created a market where supply is expected to exceed demand. This over-supply of natural gas puts negative pressure on electricity prices. In the long-term, natural gas prices will depend on investment in additional infrastructure, the shale gas supply, and the demand for natural gas in the transportation and electricity sectors.

Spark Spreads

Spark 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 the fuel source to electricity. For most markets, a standardized plant heat rate is assumed to be 7,000 British Thermal Units (“Btu”) per Kilowatt hour (“KWh”). 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 the resulting spark spreads in our three major markets, affect our Generation and Commercial Operations & Development (“COD”) business segments.

In 2009, average spark spreads decreased in Alberta due to power prices decreasing more than natural gas prices as a result of increased availability in the province’s thermal coal fleet. Spark spreads in the Pacific Northwest and Ontario increased as power prices have decreased less than natural gas prices. In the Pacific Northwest, the increase in spark spreads is primarily because 2009 had lower hydro based electricity production than 2008.

Management’s Discussion and Analysis  |  4

STRATEGY

Our goals are to deliver shareholder value by providing dividend yield plus disciplined comparable earnings per share(1) (“EPS”) and cash flow from operations growth, while maintaining a low-to-moderate risk profile, disciplined capital allocation, and financial strength. Our comparable EPS and cash flow from operations growth is driven by growing our renewable portfolio across Canada and by further expanding our overall portfolio and operations in the western regions of Canada and the U.S. We are focusing on these geographic areas as our expertise, scale, and access to numerous fuel resources, including coal, wind, geothermal, hydro, and natural gas, allow us to create expansion opportunities in our core markets. Our strategy to achieve these goals has the following key elements:

Financial Strategy

Our financial strategy is to maintain a strong balance sheet and investment grade credit ratings to provide a solid foundation for our long-cycle, capital-intensive, and commodity-sensitive business. A strong balance sheet and investment grade credit ratings improve 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 2009, demand and prices in our key markets decreased significantly compared to prior years primarily due to the weak economic environment. While we are not immune to softening power prices, the impact of these lower prices is significantly mitigated because approximately 89 per cent of 2010 and approximately 83 per cent of 2011 expected capacity across our fleet is contracted. It is this low-to-moderate risk contracting strategy that helps protect our cash flow and our strong financial position through economic cycles.

Operational Strategy

We manage our facilities to achieve operations that are low cost and predictable. Our target for 2010 is to increase productivity and return overall fleet availability to 90 per cent. This increase in availability involves developing and executing unit-specific maintenance plans that will create stability in our operations and reduce overall maintenance costs.

Growth Strategy

Our growth strategy is focused upon greening our portfolio to reduce our carbon footprint and develop long-term, sustainable power generation. We’ve delivered on this plan in 2009 by acquiring Canadian Hydro, expanding our wind portfolio, and completing efficiency uprates on Alberta Thermal units. We continue to develop opportunities for future sustainable power projects.

CAPABILITY TO DELIVER RESULTS

We have numerous core competencies and non-capital resources that give us the capability 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.

Operational Excellence

We seek to optimize our generating portfolio by owning and managing a mix of relatively low risk assets and fuels to deliver an acceptable and predictable return. The following chart demonstrates the significant progress that we have already made in each of our strategic focus areas.

Execution of our Strategy in 2009

Improve base operations	n	Improved our cash flows through PPAs and other long-term contracts, which includes a new contract with the Ontario Power Authority for our Sarnia power plant that extends to 2025
	n	Completed Unit 1 boiler modifications at Centralia Thermal
	n	Implemented productivity and cost reductions
	n	Revised our Alberta Thermal plants major maintenance schedule on a unit-by-unit basis to improve stability and predictability
Reposition coal	n	Partnered with Alstom Canada, Capital Power Corporation, and the federal and provincial governments to fund Project Pioneer, our CCS pilot project
Green our portfolio	n	Completed the 66 MW Blue Trail wind farm and have an additional 189 MW of wind energy under construction that is scheduled to be operational between Q1 2010 and Q1 2011
	n	Accelerated the growth of our renewables portfolio with the acquisition of Canadian Hydro
	n	Approved the expansion of Kent Hills and the construction of Bone Creek
	n	Continued our work on the construction of our Ardenville and Summerview 2 wind farms
	n	Continued active involvement in environmental policy discussions with various levels of government in Canada and the U.S.

1 Comparable earnings per share are not defined under Canadian GAAP. 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. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of comparable earnings per share, including a reconciliation to net earnings.

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Over the last three years, our average availability has been 86.0 per cent, which is below our corporate target of 90 per cent. This decrease in average availability has been primarily due to the accelerated planned maintenance undertaken in 2009, higher than normal unplanned outages at our coal-fired plants in 2009 and 2008, and derating at Centralia Thermal in 2007. In 2009, we reviewed each unit and developed asset-specific maintenance plans to achieve our target of 90 per cent availability, which should result in more predictable performance and stable costs.

Financial Strength

We carefully manage our financial position and cash flows to maintain financial strength and flexibility throughout all economic cycles. This financial discipline proved invaluable during the economic environment of 2009 and will continue to be important during 2010. We continue to maintain $2.1 billion in committed credit facilities, and as of Dec. 31, 2009, $0.7 billion was available to us. These strong ratios, available credit, continued reliable cash flow from operations, and limited debt maturity profile 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.

The funding required for our growth strategy is supported by our financial strength. In 2009, we took advantage of our strong financial position by completing the acquisition of Canadian Hydro, which included issuing debt and equity to finance the purchase. The market reacted favourably to these transactions and we have maintained our investment grade credit ratings. Looking forward, we see continued capital market support for projects that meet our return requirements and risk profile.

Disciplined Capital Allocation

We are committed to optimizing the balance between returning capital to shareholders, liquidity requirements, base business investment, and growth opportunities. We have a proven track record of maintaining our long-term financial stability, which includes balancing the cash distributions to our shareholders through dividends and share buybacks, with making investments in growth projects that will deliver long-term cash flow.

We continue to grow our diversified generating fleet in order to increase production and meet future demand requirements, with all growth projects having the ability to exceed our target rates of returns. We currently have 478 megawatts (“MW”) of capacity under construction, which is comprised of 225 MW of coal-fired generation, 46 MW of uprates to our thermal coal fleet, 189 MW of wind power, and 18 MW of hydro. We also have more than 600 MW of advanced development wind, hydro, and geothermal projects in our development pipeline.

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 attractive rates of return. In 2009, we completed the uprate on Unit 5 of our Sundance facility and in 2010, we will continue our work on the uprates of Units 1 and 2 of our Keephills facility.

People

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, our employees’ knowledge and dedication to superior operations, and our entire organization’s knowledge of the renewable energy business 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 at all times throughout the year 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 86.0 per cent, which is below our long-term target of 90 per cent. Our availability in 2009 was 85.1 per cent.

Availability for the year ended Dec. 31, 2009 decreased due to higher planned and unplanned outages at Alberta Thermal, higher unplanned outages at Centralia Thermal, and higher planned outages at the Windsor and Mississauga plants, partially offset by lower planned outages at Centralia Thermal and lower planned and unplanned outages at Genesee 3.

Availability for the year ended Dec. 31, 2008 decreased 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 powder river basin (“PRB”) coal.

Management’s Discussion and Analysis  |6

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.

Production for the year ended Dec. 31, 2009 decreased 3,155 gigawatt hours (“GWh”) due to higher economic dispatching and higher unplanned outages at Centralia Thermal, higher planned and unplanned outages at Alberta Thermal, lower PPA customer demand at Alberta Thermal and Sheerness, the expiration of the long-term contract at Saranac, and lower hydro volumes, partially offset by higher wind volumes due to the acquisition of Canadian Hydro and the commissioning of Kent Hills, lower planned outages at Centralia Thermal, and lower planned and unplanned outages at Genesee 3.

For the year ended Dec. 31, 2008, production decreased 1,504 GWh 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.

Productivity

Our 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 reflects the cost of day-to-day operations. Our target is to offset 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 MWh of capacity.

For the year ended Dec. 31, 2009, OM&A costs per MWh hour increased primarily due to higher planned outages and unfavourable foreign exchange rates, partially offset by targeted cost savings throughout the Corporation, and lower compensation costs.

For the year ended Dec. 31, 2008, OM&A costs per MWh increased 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 our Injury Frequency Rate (“IFR”) to 1 over the next five years.

	2007	2008	2009	Target
Injury Frequency Rate	1.76	1.28	1.41	1 over next five years

The IFR increased in 2009 as a result of us not meeting safety targets while completing the uprate on Unit 5 of our Sundance facility. In 2008, the IFR decreased 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 three components: (1) routine and mine capital, (2) planned maintenance, and (3) productivity. In 2009, we spent $86 million less on routine and mine capital, $10 million less on planned maintenance, and an additional $11 million on productivity compared to 2008. The decrease in both routine and mine capital and planned maintenance in 2009 was due to lower mine capital and decreased spending on equipment modifications at Centralia Thermal. The increase in productivity expenditures was for various projects undertaken throughout the Corporation to improve operations and increase efficiencies.

In 2008, we spent an additional $14 million on routine and mine capital and an additional $47 million on planned maintenance compared to 2007. The increase in both routine and mine capital and planned maintenance 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. In 2007, there were no productivity expenditures.

Our annual target for sustaining capital expenditures is expected to decrease for 2010 to approximately $295 to $340 million, primarily due to lower planned maintenance. We expect to return to normal sustaining capital expenditure levels of $310 to $355 million in 2011.

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Earnings and Cash Flow From Operating Activities

We focus our base business on delivering strong earnings and cash flow growth.

	2007	2008	2009	Target
Comparable earnings per share	1.31	1.46	0.90	Low double digit growth
EBITDA(1)	980	1,006	895	Low double digit growth
Cash flow from operating activities	847	1,038	580	850–950

1EBITDA is not defined under Canadian GAAP. Presenting EBITDA from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before net interest expense, non-controlling interests, income taxes, and working capital adjustments. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of EBITDA, including a reconciliation to net earnings.

In 2009, comparable earnings per share and earnings before interest, taxes, depreciation, and amortization (“EBITDA”) decreased due to higher planned and unplanned outages at Alberta Thermal, lower hydro volumes and prices, and lower trading margins.

In 2008, comparable earnings per share and EBITDA increased 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 2009, cash flow from operating activities decreased due to lower cash earnings, the receipt of an additional PPA payment in 2008, higher inventory balances in 2009, and unfavourable movements in other working capital balances.

In 2008, cash flow from operating activities increased due to an increase in cash earnings and favourable changes in working capital including the timing of PPA receipts in 2008.

Investment Grade 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 cash flow coverage ratios to support stable investment grade credit ratings.

	2007	2008	2009	Target
Cash flow to interest coverage (times)	6.6	7.2	4.9	4–5
Cash flow to debt (%)	30.7	31.1	20.1	20–25
Debt to invested capital (%)	46.8	48.1	56.1	55–60

Cash flow to interest coverage decreased in 2009 compared to the same period in 2008 as a result of lower cash flow from operating activities and higher interest expense. Cash flow to interest coverage increased in 2008 compared to 2007 as a result of increased cash from operating activities and lower interest expense.

Cash flow to debt decreased in 2009 due to a decrease in cash flows from operating activities and higher debt as a result of our issuances of senior- and medium-term notes during 2009 to acquire Canadian Hydro. Cash flow to debt increased in 2008 due to an increase in cash flows from operating activities, which offset the increase in debt balances.

Debt to invested capital increased in 2009 compared to the same period in 2008 as a result of the issuance of debt throughout the year to fund growth and for the acquisition of Canadian Hydro. Debt to invested capital increased in 2008 compared to 2007 as a result of the issuance of senior notes in the amount of U. S.$500 million.

We seek to maintain financial flexibility by using multiple sources of capital to finance capital allocation plans effectively, while maintaining a sufficient level of available liquidity to support contracting and trading activities. Further, financial flexibility 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 target is to consistently grow our comparable return on capital employed (“ROCE”)(2) and total shareholder return (“TSR”)(2) each year.

The table below shows our historical performance and targets on these measures:

	2007	2008		2009	Target
Comparable ROCE (%)	9.7	9.6		5.8	> 10%
TSR (%)	29.0	(23.9	)	1.4	> 10%

Comparable ROCE decreased in 2009 due to lower comparable earnings as a result of higher planned and unplanned outages at AlbertaThermal, lower hydro volumes and prices, and lower trading margins. Comparable ROCE in 2008 was consistent with 2007.

The limited increase in TSR for 2009 is due to the beginning of the slow recovery from the economic recession in 2008. The decrease in TSR for 2008 was due to a decrease in share price as a result of the economic recession, during which time the Standard & Poor’s/Toronto Stock Exchange Composite Index decreased 35 per cent.

2These measures are not defined under Canadian GAAP. We evaluate our performance and the performance of our business segments using a variety of measures. These measures are not necessarily comparable to a similarly titled measure of another company. Comparable ROCE is a measure of the efficiency and profitability of capital investments and is calculated by taking comparable earnings before net interest expense, non-controlling interests and taxes, and dividing by the average invested capital excluding AOCI. 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. TSR is the total amount returned to investors over a specific holding period and includes capital gains, capital losses, and dividends.

Management’s Discussion and Analysis  |8

RESULTS OF OPERATIONS

The results of operations are presented on a consolidated basis and by business segment. We have two business segments: Generation and 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 obligation (“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 items from the Consolidated Statements of Earnings and the Consolidated Balance Sheets. While individual line items on the Consolidated Balance Sheets will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items is reflected in the equity section.

HIGHLIGHTS AND SUMMARY OF RESULTS

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

Year ended Dec. 31	2009		2008	2007
Availability (%)	85.1		85.8	87.2
Production (GWh)	45,736		48,891	50,395
Revenue	2,770		3,110	2,775
Gross margin(1)	1,542		1,617	1,544
Operating income(1)	378		533	541
Net earnings	181		235	309
Net earnings per share, basic and diluted	0.90		1.18	1.53
Comparable earnings per share	0.90		1.46	1.31
Cash flow from operating activities	580		1,038	847
Free cash flow(1) (deficiency)	(117	)	121	111
Cash dividends declared per share	1.16		1.08	1.00
As at Dec. 31	2009		2008	2007
Total assets	9,762		7,824	7,157
Total long-term financial liabilities	5,512		3,645	2,858

1Gross margin, operating income, and free cash flow are not defined under Canadian GAAP. Refer to the Non-GAAP Measures section of this MD&A for further discussion of these items, including reconciliations to net earnings and cash flow from operating activities.

9|  TransAlta Corporation

REPORTED EARNINGS

The primary factors contributing to the change in net earnings for the years ended Dec. 31, 2009 and 2008 are presented below:

Net earnings for the year ended Dec. 31, 2007	309
Increase in Generation gross margins	7
Mark-to-market movements—Generation	16
Increase in COD gross margins	50
Increase 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	23
Increase in equity loss	(47	)
Increase in non-controlling interests	(13	)
Increase in income tax expense	(3	)
Other	(14	)
Net earnings for the year ended Dec. 31, 2008	235
Decrease in Generation gross margins	(33	)
Mark-to-market movements—Generation	16
Decrease in COD gross margins	(58	)
Increase in operations, maintenance, and administration costs	(30	)
Increase in depreciation expense	(47	)
Writedown of mining development costs	(16	)
Increase in net interest expense	(34	)
Equity loss recorded in 2008	97
Decrease in non-controlling interests	23
Decrease in income tax expense	8
Other	20
Net earnings for the year ended Dec. 31, 2009	181

For the year ended Dec. 31, 2009, Generation gross margins, net of mark-to-market movements, decreased due to higher planned outages at Alberta Thermal, lower hydro volumes and prices, and the expiration of the long-term contract at Saranac, partially offset by lower planned and unplanned outages at Genesee 3, higher wind volumes due to the acquisition of Canadian Hydro and the commissioning of Kent Hills, favourable foreign exchange rates, and favourable contractual pricing.

In 2008, Generation gross margins, net of mark-to-market movements, increased 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.

For the year ended Dec. 31, 2009, COD gross margins decreased due to a reduction in industrial demand, gas price uncertainty, and the change in the California market, which resulted in reduced pricing spreads and smaller margins.

In 2008, COD gross margins increased due to all regions experienced positive results in 2008, with the increase primarily attributable to successful trading strategies involving regional power demand and price differentials in the eastern region.

For the year ended Dec. 31, 2009, OM&A costs increased primarily due to higher planned outages and unfavourable foreign exchange rates, partially offset by targeted cost savings throughout the Corporation, and lower compensation costs. In 2008, OM&A costs increased due to cost escalations, higher planned maintenance costs, and increased compensation costs.

For the year ended Dec. 31, 2009, depreciation expense increased due to an increased asset base, unfavourable foreign exchange rates, and the retirement of certain assets that were not fully depreciated during planned maintenance activities, partially offset by lower production at Saranac and the early retirement of certain components as a result of equipment modifications made at Centralia Thermal in 2008.

In 2008, depreciation expense increased 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 2006, we ceased mining activities at the Centralia mine but continued to develop the option to mine the Westfield site, a coal reserve located adjacent to Centralia Thermal. With the successful modifications of the boilers at Centralia Thermal and longer-term contracts in place to supply coal, the project to develop the Westfields site has now been placed on hold indefinitely and the costs that have been capitalized were expensed during the fourth quarter of 2009.

Net interest expense increased for the year ended Dec. 31, 2009 due to higher long-term debt levels and lower interest income as a result of the receipt of interest income from a tax settlement in 2008, partially offset by lower interest rates and higher capitalized interest primarily due to the construction of Keephills 3. In 2008, net interest expense decreased 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.

Management’s Discussion and Analysis  |10

In the first quarter of 2008, an equity loss of $97 million was recorded to reflect the writedown of our Mexican equity investment that was sold in the fourth quarter of the same year. Equity loss increased for the year ended Dec. 31, 2008 compared to the same period in 2007 due to the writedown of our Mexican equity 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.

For the year ended Dec. 31, 2009, non-controlling interests decreased primarily due to lower earnings resulting from the expiration of the long-term contract at Saranac. Non-controlling interests for the year ended Dec. 31, 2008 were comparable to 2007.

For the year ended Dec. 31, 2009, income tax expense decreased due to lower pre-tax earnings and the recovery recorded for a change in future tax rates related to tax liabilities recorded in prior periods, partially offset by the income tax recovery related to tax positions recorded in 2008. Income tax expense for the year ended Dec. 31, 2008 was comparable to the same period in 2007.

SIGNIFICANT EVENTS

Our consolidated financial results include the following significant events:

2009

Medium-Term Notes Offerings

On Nov. 18, 2009, we completed our offering in the Canadian bond market of $400 million medium-term notes maturing in 2019 and bearing an interest rate of 6.40 per cent. The net proceeds from the offering were used to repay a portion of the indebtedness relating to our acquisition of Canadian Hydro.

On May 29, 2009, we completed our offering in the Canadian bond market of $200 million medium-term notes maturing in 2014 and bearing an interest rate of 6.45 per cent. The net proceeds from the offering were used for debt repayment, financing of our long-term investment plan, and for general corporate purposes.

Senior Notes Offering

On Nov. 13, 2009, we completed our offering of U.S.$500 million senior notes maturing in 2015 and bearing an interest rate of 4.75 per cent. The net proceeds from the offering were used to repay a portion of the indebtedness relating to our acquisition of Canadian Hydro.

Sale of Common Shares

On Nov. 5, 2009, we completed our public offering of 20,522,500 Common shares at a price of $20.10 per common share, which resulted in net proceeds of approximately $413 million. The net proceeds from the offering were used to repay a portion of the indebtedness relating to our acquisition of Canadian Hydro.

Blue Trail

On Nov. 2, 2009, our Blue Trail wind farm began commercial operations on budget and one month ahead of schedule. The 66 MW facility is located southwest of Fort McLeod in southern Alberta.

Keephills 3

On Oct. 26, 2009, the Board of Directors approved an increase in the construction cost of Keephills 3 to $988 million due to a change in our original expectations of the labour required to complete the project, and a change to the commencement of commercial operations from the first quarter of 2011 to the second quarter of 2011. Even with the delay of operations and increased cost, Keephills 3 is still expected to meet our investment hurdles.

Carbon Capture and Storage

On Oct. 14, 2009, the federal and provincial governments announced that our CCS project, Project Pioneer, has received committed funding of more than $750 million. The funding is being provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will support the undertaking of a Front End Engineering and Design (“FEED”) study to determine if the project is viable. The FEED study is expected to cost $20 million; $10 million will come from the federal government, $5 million will come from the provincial government, and $5 million will come from TransAlta and from industry partners Alstom Canada and Capital Power Corporation (“Capital Power”). The FEED study is expected to be completed by the end of 2010 or in early 2011, and if we proceed with construction, the prototype plant has a targeted start-up date of 2015.

Acquisition of Canadian Hydro

On Oct. 5, 2009, we entered into a definitive pre-acquisition agreement with Canadian Hydro to acquire all of their issued and outstanding common shares for $5.25 per share in cash. On Oct. 23, 2009, we acquired 87 per cent of Canadian Hydro through the purchase of all of their issued and outstanding shares. On Nov. 4, 2009, we acquired the remaining 13 per cent. The total cash consideration of the acquisition was $766 million. The results of Canadian Hydro are included in our consolidated financial statements from Oct. 23, 2009, when we acquired control.

Canadian Hydro operated 694 MW of wind, hydro, and biomass facilities in Alberta, Ontario, Quebec, and British Columbia. Canadian Hydro’s assets are highly contracted with counterparties of recognized financial standing. On a combined basis at Dec. 31, 2009, we have 9,199 MW of gross generating capacity (1) in operation (8,775 MW net ownership interest). The combined renewables portfolio includes more than 1,900 MW in operation, or 22 per cent of the total portfolio. In addition, there was a combined 424 MW net under construction and over 600 MW in advanced-stage development at Dec. 31, 2009.

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

11|  TransAlta Corporation

The following table depicts the impact of Canadian Hydro on our consolidated operations portfolio by geographic region and fuel type:

Net Capacity Ownership Interest (MW)
	Canadian		TransAlta
Dec. 31, 2009	Hydro	TransAlta(1)	Consolidated
Western Canada	183	5,059	5,242
Eastern Canada	511	707	1,218
International	–	2,315	2,315
	694	8,081	8,775
Coal	–	4,967	4,967
Natural Gas	–	1,843	1,843
Geothermal	–	164	164
Wind	583	300	883
Hydro	86	807	893
Biomass	25	–	25
	694	8,081	8,775

1Excluding Canadian Hydro.

The following table depicts the impact of certain Canadian Hydro financial assets and long-term financial liabilities on our consolidated financial results:

	Canadian		TransAlta
As at Dec. 31, 2009	Hydro	TransAlta(1)	Consolidated
Property, plant, and equipment	1,289	6,289	7,578
Intangible assets	176	157	333
Risk management liabilities	31	47	78
Long-term debt, non-recourse	374	180	554
Future income tax liabilities	28	609	637

1Excluding Canadian Hydro.

Sarnia Contract

On Sept. 30, 2009, we entered into a new agreement with the Ontario Power Authority (“OPA”) for our Sarnia regional cogeneration power plant. The contract is capacity based and the term of the new agreement is from July 1, 2009 through to the end of 2025. While the specific terms and conditions of the new agreement are confidential, the OPA has indicated that the agreement is in line with other similar agreements issued by the OPA.

Major Maintenance Plans

On May 20, 2009, we announced the advancement of a major maintenance outage on Unit 3 of our Sundance facility from the second quarter of 2010 into the second and third quarters of 2009. The advancement of the maintenance outage took advantage of low power prices, optimized preventative maintenance in the short-term, and is expected to provide an economic cash benefit over the two-year period due to improved unit availability. As a result of the change in schedule, 2009 lost GWh increased by 396 GWh and net earnings declined by $24 million ($0.12 per share).

Normal Course Issuer Bid (“NCIB”) Program

On May 6, 2009, we announced plans to renew our NCIB program until May 6, 2010. We received the approval to purchase, for cancellation, up to 9.9 million of our common shares representing 5 per cent of our 198 million common shares issued and outstanding as at April 30, 2009. Any purchases undertaken will be made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition. No purchases were made under the NCIB in 2009.

Chief Operating Officer

On April 28, 2009 we announced the appointment of Dawn Farrell to the position of Chief Operating Officer. In this new role, Ms. Farrell leads our operations, trading, development, commercial, engineering, technology, and procurement activities. Prior to this appointment, Ms. Farrell was Executive Vice President of Commercial Operations and Development.

Additionally, Richard Langhammer, Executive Vice President of Generation Operations, took on a new assignment as Chief Productivity Officer for the remainder of 2009 with the responsibility for identifying strategies to create sustainable costs savings across the Corporation. Mr. Langhammer formally retired at the end of 2009 after 23 years of service.

Ardenville Wind Power Project

On April 28, 2009, we announced plans to design, build, and operate Ardenville, a 69 MW wind power project in southern Alberta. The capital cost of the project is estimated at $135 million. Included in the capital cost of the project is the purchase of an already operational 3 MW turbine at Macleod Flats. Commercial operations of the remainder of the Ardenville wind project is expected to commence in the first quarter of 2011.

Management’s Discussion and Analysis|12

Sundance Unit 4 Derate

On Feb. 10, 2009, we reported the first quarter financial impact of an extended derate on Unit 4 of our Sundance facility (“Unit 4”). The facility experienced an unplanned outage in December 2008 related to the failure of an induced draft fan. At that time, Unit 4, which has a capacity of 406 MW, had been derated to approximately 205 MW. The repair of the induced draft 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 and net earnings were reduced by 328 GWh and $10 million, respectively representing both lost merchant revenue and penalties.

In response to this event, we gave notice of a High Impact Low Probability Force Majeure Event to the PPA Buyer and the Balancing Pool, and we paid the required penalties related to the derate. On April 27, 2009, the Balancing Pool rejected our assertion that this outage should be regarded as a High Impact Low Probability Force Majeure Event. As a result, we also record an additional charge in the second quarter of $7 million after-tax related to this event. We settled the issue in the third quarter and the terms of the settlement are confidential.

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 of Unit 1 expected by the end of 2011 and Unit 2 by the end of 2012.

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 per share in 2008.

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. We constructed, own, and operate the Kent Hills facility. Total capital costs for the construction of Kent Hills were approximately $170 million. Natural Forces Technologies Inc. (“Natural Forces”) exercised their option to purchase a 17 per cent interest in the Kent Hills project subsequent to the commencement of commercial operations.

Debentures

On July 31, 2008, $100 million of debentures issued by TransAlta Utilities Corporation (“TAU”) were redeemed at the option of 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 were 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 was no longer a reporting issuer.

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

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 Capital Power (225 MW net ownership interest), experienced an unplanned outage as a result of a turbine blade failure. Capital Power, 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.

Mexican Equity Investment

On Oct. 8, 2008, we successfully completed the sale of our Mexican equity investment to InterGen Global Ventures B.V. (“InterGen”) for gross proceeds of $334 million (U.S.$304 million). The sale included the plants and all associated commercial arrangements. The actual after-tax loss as a result of the sale was $62 million. The pre-tax charge of $97 million was recorded in equity loss.

13|TransAlta Corporation

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 Corporation 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 was $123 million and commercial operations commenced on Feb. 23, 2010. Please refer to the subsequent Events section of this MD&A.

Senior Notes 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 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.

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). Purchases were made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition. 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).

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 was approximately $77 million. Commercial operations commenced in the fourth quarter 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.

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 was $113 million. Commercial operations commenced in the fourth quarter of 2009.

Management’s Discussion and Analysis|14

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 long-term contract 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.

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.

For the year ended Dec. 31, 2007, we purchased 2,371,800 shares at an average price of $31.59 per share. Purchases were made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition. 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”).

Sundance Unit 4 Uprate

In December 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, the Climate Change and Emissions Management Amendment Act was 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 our PPA customers. After flow-through, the net compliance costs were 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 July 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 Capital Power and by us. The capital cost of the project is expected to be approximately $1.9 billion, including associated mine capital, and is anticipated to begin commercial operations in the second quarter of 2011. We own a 50 per cent interest in this unit.

15  |  TransAlta Corporation

SUBSEQUENT EVENTS

Summerview 2

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

Kent Hills Expansion

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

DISCUSSION OF SEGMENTED RESULTS

GENERATION: Owns and operates hydro, wind, geothermal, biomass, 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, 2009, Generation had 9,199 MW of gross generating capacity in operation (8,775 MW net ownership interest) and 424 MW net under construction. At Dec. 31, 2009, 1,964 MW net was renewable. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of this MD&A.

During 2009, we completed the acquisition of Canadian Hydro, which operates 694 MW of wind, hydro, and biomass facilities in Alberta, Ontario, Quebec, and British Columbia. We also completed the uprate on Unit 5 of our Sundance facility and the construction of the Blue Trail wind farm in southern Alberta. Please refer to the Significant Events section of this MD&A for further details.

We have strategic alliances with Stanley Power, Capital Power, ENMAX Corporation (“ENMAX”), MidAmerican Energy Holdings Company (“MidAmerican”), Nexen Incorporated (“Nexen”), and Brookfield Asset Management Inc. (“Brookfield”). Stanley Power owns the minority interest in TransAlta Cogeneration, L.P. (“TA Cogen”). The Capital Power alliance provided the opportunity for us to acquire 50 per cent ownerships in both the 450 MW Genesee 3 project and the Taylor Hydro facility, as well as to build the Keephills 3 project. ENMAX and our Corporation each own 50 per cent of the partnership in the McBride Lake wind project. MidAmerican owns the other 50 per cent interest in CE Generation, LLC (“CE Gen”) and Wailuku Holding Company, LLC. Nexen and our Corporation each have a 50 per cent ownership in the Soderglen wind project. Brookfield owns the other 50 per cent interest in our Pingston hydro facility.

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:

Year ended Dec. 31	2009				2008				2007
			Per installed				Per installed				Per installed
	Total		MWh		Total		MWh		Total		MWh
Revenues	2,723		36.37		3,005		40.63		2,720		37.03
Fuel and purchased power	(1,228	)	(16.40	)	(1,493	)	(20.18	)	(1,231	)	(16.76	)
Gross margin	1,495		19.97		1,512		20.45		1,489		20.27
Operations, maintenance, and administration	550		7.35		487		6.58		447		6.08
Depreciation and amortization	453		6.05		409		5.53		391		5.33
Taxes, other than income taxes	22		0.29		19		0.26		20		0.27
Intersegment cost allocation	32		0.43		30		0.41		27		0.37
Operating expenses	1,057		14.12		945		12.78		885		12.05
Operating income	438		5.85		567		7.67		604		8.22
Installed capacity (GWh)	74,866				73,969				73,447
Production (GWh)	45,736				48,891				50,395
Availability (%)	85.1				85.8				87.2

Management’s Discussion and Analysis  |  16

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.

							Fuel &
				Fuel &		Revenue	purchased	Gross
	Production	Installed		purchased		per installed	power per	margin per
Year ended Dec. 31, 2009	(GWh)	(GWh)	Revenue	power	Gross margin	MWh	installed MWh	installed MWh
Western Canada	30,443	46,334	1,182	435	747	25.51	9.39	16.12
Eastern Canada	3,829	8,256	428	225	203	51.84	27.25	24.59
International	11,464	20,276	1,113	568	545	54.89	28.01	26.88
	45,736	74,866	2,723	1,228	1,495	36.37	16.40	19.97

							Fuel &
				Fuel &		Revenue	purchased	Gross
	Production	Installed		purchased		per installed	power per	margin per
Year ended Dec. 31, 2008	(GWh)	(GWh)	Revenue	power	Gross margin	MWh	installed MWh	installed MWh
Western Canada	32,364	46,096	1,314	525	789	28.51	11.39	17.12
Eastern Canada	3,290	7,194	501	351	150	69.64	48.79	20.85
International	13,237	20,679	1,190	617	573	57.55	29.84	27.71
	48,891	73,969	3,005	1,493	1,512	40.63	20.18	20.45

							Fuel &
				Fuel &		Revenue	purchased	Gross
	Production	Installed		purchased		per installed	power per	margin per
Year ended Dec. 31, 2007	(GWh)	(GWh)	Revenue	power	Gross margin	MWh	installed MWh	installed MWh
Western Canada	33,398	45,385	1,302	449	853	28.69	9.90	18.79
Eastern Canada	3,775	7,173	443	303	140	61.75	42.19	19.56
International	13,222	20,889	975	479	496	46.66	22.92	23.74
	50,395	73,447	2,720	1,231	1,489	37.03	16.76	20.27

Western Canada

Our Western Canada assets consist of five coal facilities, three natural gas-fired facilities, 20 hydro facilities, 10 wind farms, and one biomass facility with a total gross generating capacity of 5,528 MW (5,242 MW net ownership interest). On Feb. 23, 2010, commercial operations of our 66 MW Summerview wind farm commenced. Refer to the Subsequent Events section of this MD&A for further details. We are currently constructing a 450 MW (225 MW net ownership interest) merchant thermal plant at our Keephills facility under a joint venture with Capital Power, which is scheduled to enter commercial production in 2011. We are currently performing uprates of 23 MW each on Unit 1 and Unit 2 of our Keephills facility, which are scheduled to be completed by the fourth quarter of 2011 and 2012, respectively. We are also currently constructing Ardenville, a wind farm in southern Alberta, and Bone Creek, a hydro facility in British Columbia. Ardenville will have a generating capacity of 69 MW and is scheduled to enter commercial production in 2011. Bone Creek will have a generating capacity of 18 MW and is scheduled to enter commercial production in 2011.

Our Sundance, Keephills, and Sheerness plants, and 13 hydro facilities operate under PPAs with a gross generating capacity of 4,083 MW (3,888 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, a portion of our Poplar Creek and Castle River facilities, four hydro facilities, and nine additional wind 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 Wabamun plant will be decommissioned in the first quarter of 2010.

McBride Lake, Meridian, Fort Saskatchewan, a significant portion of our Poplar Creek and Castle River assets, and three hydro facilities 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 10 years and payments do not fluctuate significantly with changes in levels of production.

Our Grande Prairie biomass facility earns revenues under long-term contracts based on actual production delivered at a specified price per MWh.

For the year ended Dec. 31, 2009, production decreased 1,921 GWh due to higher planned and unplanned outages at Alberta Thermal, lower PPA customer demand at Alberta Thermal and Sheerness, and lower hydro volumes, partially offset by lower planned and unplanned outages at Genesee 3, and higher wind volumes due to the acquisition of Canadian Hydro.

In 2008, production decreased 1,034 GWh 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.

17|  TransAlta Corporation

Gross margin for the year ended Dec. 31, 2009 decreased $42 million ($1.00 per installed MWh) due to higher planned outages at Alberta Thermal and lower hydro volumes and prices, partially offset by lower planned and unplanned outages at Genesee 3, an adjustment to prior period indices, lower penalties due to lower spot prices, and higher wind volumes due to the acquisition of Canadian Hydro.

In 2008, gross margin decreased $64 million ($1.67 per installed MWh) 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.

Eastern Canada

Our Eastern Canada assets consist of four natural gas-fired facilities, five hydro facilities, and five wind farms with a total gross generating capacity of 1,356 MW (1,218 MW net ownership interest). All of our facilities in Eastern Canada earn revenue under long-term contracts for which revenues are derived from payments for capacity and/or the production of electrical energy and steam. Our Windsor facility also sells a portion of its production on the merchant spot market.

For the year ended Dec. 31, 2009, production increased 539 GWh primarily due to higher wind volumes as a result of the acquisition of Canadian Hydro and the commissioning of Kent Hills.

In 2008, production decreased 485 GWh, primarily due to higher planned outages and lower market heat rates at Sarnia.

For the year ended Dec. 31, 2009, gross margins increased $53 million ($3.74 per installed MWh) due to higher wind volumes as a result of the acquisition of Canadian Hydro and the commissioning of Kent Hills, and the new agreement with the OPA at our Sarnia regional cogeneration power plant.

In 2008, gross margins were comparable to the same period in 2007.

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 2,015 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 in which we have a 50 per cent interest.

Our Centralia Thermal, Centralia Gas, Power Resources, Skookumchuck, and two units 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, 2009, production decreased 1,773 GWh due to higher unplanned outages and higher economic dispatching at Centralia Thermal, and the expiration of the long-term contract at Saranac, partially offset by lower planned outages at Centralia Thermal.

In 2008, production increased 15 GWh 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.

For the year ended Dec. 31, 2009, gross margins decreased $28 million ($0.83 per installed MWh) due to the expiration of the long-term contract at Saranac, higher coal costs, and lower production at Centralia Thermal, partially offset by favourable foreign exchange, favourable pricing, and favourable mark-to-market movements.

In 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.

The long-term contract between our Saranac facility and New York State Electric and Gas expired in June 2009. The facility now operates under a combined capacity and merchant dispatch contract. As the facility is depreciated on a unit of production basis, there is a corresponding $11 million decrease in depreciation expense from this lower level of production for the year ended Dec. 31, 2009. Further, as a portion of the facility is owned by a third party, there is also a decrease in earnings attributable to non-controlling interests. Therefore, the net pre-tax earnings impact of this event is approximately $12 million for the year ended Dec. 31, 2009.

Operations, Maintenance, and Administration

For the year ended Dec. 31, 2009, OM&A expenses increased primarily due to higher planned outages, unfavourable foreign exchange rates, and the acquisition of Canadian Hydro, partially offset by targeted cost savings.

In 2008, OM&A expenses increased compared to the same period in 2007 due to cost escalations and higher planned maintenance costs.

Planned Maintenance

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

Year ended Dec. 31	2009	2008	2007
Capitalized	115	125	78
Expensed	118	68	54
	233	193	132
GWh lost	3,732	3,478	2,056

Production lost as a result of planned maintenance in the year ended Dec. 31, 2009 increased by 254 GWh primarily due to the uprate on Unit 5 at our Sundance facility. In 2008, production lost increased by 1,422 GWh primarily due to the Unit 2 boiler modifications at Centralia Thermal.

Management’s Discussion and Analysis  |  18

For the year ended Dec. 31, 2009, total planned maintenance costs increased compared to the same period in 2008 due to higher planned outages across the fleet and cost escalations.

In 2008, total planned 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.

Depreciation Expense

For the year ended Dec. 31, 2009, depreciation expense increased due to an increased asset base, unfavourable foreign exchange rates, and the retirement of certain assets that were not fully depreciated during planned maintenance activities, partially offset by lower production at Saranac and the early retirement of certain components as a result of equipment modifications made at Centralia Thermal in 2008.

In 2008, depreciation expense increased compared to 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.

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 recommending 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 earnings 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	2009		2008		2007
Gross margin	47		105		55
Operations, maintenance, and administration	31		53		34
Depreciation and amortization	4		3		1
Intersegment cost allocation	(32	)	(30	)	(27	)
Operating expenses	3		26		8
Operating income	44		79		47

For the year ended Dec. 31, 2009, COD gross margins decreased due to a reduction in industrial demand, gas price uncertainty, and the change in the California market, which resulted in reduced pricing spreads and smaller margins.

In 2008, gross margins increased due to all regions experienced positive results in 2008, with the increase primarily attributable to successful trading strategies involving regional power demand and price differentials in the eastern region.

For the year ended Dec. 31, 2009, OM&A expenses decreased due to a reduction in both discretionary expenditures and staff compensation costs. In 2008, OM&A expenses increased primarily due to additional trading compensation as a result of increased gross margins.

The inter-segment cost allocations have increased slightly in both 2009 and 2008 due to an increase in the work performed on behalf of the Generation segment.

NET INTEREST EXPENSE

Year ended Dec. 31	2009		2008		2007
Interest on long-term debt	183		177		171
Interest income from tax settlement	–		(30	)	–
Interest income	(6	)	(16	)	(32	)
Capitalized interest	(36	)	(21	)	(6	)
Other	3		–		–
Net interest expense	144		110		133

19|  TransAlta Corporation

Net interest expense increased for the year ended Dec. 31, 2009 due to higher debt levels and lower interest income as a result of the receipt of interest income from a tax settlement in 2008, partially offset by lower interest rates and higher capitalized interest primarily due to the construction of Keephills 3.

In 2008, $30 million of reported interest income reflects a refund resulting from the receipt of a tax settlement in 2008 in connection with outstanding tax issues related to prior periods.

For the year ended Dec. 31, 2008, net interest expense decreased 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.

OTHER INCOME

During 2009, we settled an outstanding commercial issue that was recorded as a pre-tax gain of $7 million in other income as it related to our previously held Mexican equity investment. We also recorded a pre-tax gain of $1 million on the sale of a 17 per cent interest in our Kent Hills wind farm.

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.

NON-CONTROLLING INTERESTS

We own 50.01 per cent of 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. Stanley Power 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. Natural Forces owns a 17 per cent interest in our Kent Hills facility, which operates 96 MW of wind assets. Since we own a controlling interest in TA Cogen and Kent Hills, we consolidate the entire earnings, assets, and liabilities in relation to our ownership of those assets. For Saranac, we proportionately consolidate our share of the earnings, assets, and liabilities in relation to our ownership.

Non-controlling interests on the Consolidated Statements of Earnings and Consolidated Balance Sheets relate to the earnings and net assets attributable to TA Cogen, Saranac, and Kent Hills that are not owned by us. On the Consolidated Statements of Cash Flows, cash paid to the minority shareholders of TA Cogen, Saranac, and Kent Hills is shown as distributions paid to subsidiaries’ non-controlling interests in the financing section.

The earnings attributable to non-controlling interests for the year ended Dec. 31, 2009 decreased due to lower earnings at CE Gen as a result of the expiration of the long-term contract at our Saranac facility, and lower earnings at TA Cogen.

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

EQUITY LOSS

As required under Accounting Guideline 15, Consolidation of Variable Interest Entities, of the Canadian Institute of Chartered Accountants (“CICA”), our previously held Mexican operations were accounted for as an equity investment. 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 and all associated commercial arrangements. Refer to the Significant Events section for further details.

For the year ended Dec. 31, 2008, equity loss reflected the writedown of our Mexican equity investment in the first quarter of 2008.

INCOME TAXES

Income tax expense under Canadian 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 Canadian 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.

Management’s Discussion and Analysis  |  20

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

Year ended Dec. 31	2009		2008		2007
Earnings before income taxes	196		258		329
Equity loss	–		(97	)	(50	)
Other income	7		5		16
Earnings before income taxes, equity loss, and other income	189		350		363
Income tax expense	15		23		20
Income tax expense on other income	(1	)	(1	)	(4	)
Income tax recovery recorded on the sale of our Mexican equity investment	–		35		–
Income tax recovery related to tax positions	–		15		18
Income tax recovery related to change in future tax rates	5		–		48
Income tax expense excluding equity loss and other items	19		72		82
Effective tax rate on earnings before income taxes, equity loss, and other items(1) (%)	10		21		23

1  To present comparable reconciliations, prior years’ effective tax rate analyses were calculated based on earnings before income tax, equity loss, and other income.

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 $5 million and $48 million in 2009 and 2007, respectively.

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

Adjusting for the items mentioned above, income tax expense decreased for the year ended Dec. 31, 2009 due to lower pre-tax earnings and the recovery recorded for a change in future tax rates related to tax liabilities recorded in prior periods, partially offset by the tax recovery related to tax positions recorded in 2008. For the year ended Dec. 31, 2008, the adjusted income tax expense decreased compared to 2007 due to lower pre-tax income.

The effective tax rate on earnings before income taxes, equity loss, and other items decreased for the years ended Dec. 31, 2009 and 2008 primarily due to a change in pre-tax earnings and certain deductions that do not fluctuate with earnings.

FINANCIAL POSITION

The following chart outlines significant changes in the Consolidated Balance Sheets from Dec. 31, 2008 to Dec. 31, 2009:

	Increase/
	(Decrease)		Primary factors explaining change
Cash and cash equivalents	32		Acquisition of Canadian Hydro and the timing of operational payments
Accounts receivable	(84	)	Timing of customer receipts and lower revenues
Income taxes receivable	(22	)	Recovery of tax prepayments and overpayments
Inventory	39		Lower production, economic dispatching, and cost increases
Long-term receivable	35		Deposit made with tax authorities for a dispute not expected to be settled within one year
Risk management assets (current and long-term)	(53	)	Price movements
Property, plant, and equipment, net	1,544		Acquisition of Canadian Hydro and capital additions, partially offset by depreciation expense and foreign exchange
Goodwill	292		Acquisition of Canadian Hydro
Intangible assets	120		Acquisition of Canadian Hydro, partially offset by amortization expense
Other assets	63		Acquisition of Canadian Hydro, combined with new growth and productivity initiatives
Accounts payable and accrued liabilities	(137	)	Timing of payments and lower operational and construction expenditures
Collateral received	62		Collateral collected from counterparties associated with their obligations as a result of a change in forward prices
Long-term debt (including current portion)	1,634		Issuance of long-term debt due to the acquisition of Canadian Hydro and increased draws on credit facilities, partially offset by foreign exchange and maturities
Risk management liabilities (current and long-term)	(127	)	Price movements
Asset retirement obligation (including current portion)	(15	)	Favourable foreign exchange movement
Net future income tax liabilities (including current portions)	114		Acquisition of Canadian Hydro and tax effect on the increase in net risk management assets
Shareholders’ equity	419		Issuance of common shares, net earnings, and movements in AOCI, partially offset by dividends declared

21|  TransAlta Corporation

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

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 Consolidated Statements of Earnings as a result of differences between the contract price and the current forecast of future prices. We record the changes in fair value of these contracts through the Consolidated Statements 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 are ineffective, 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 Consolidated Statements 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, 2009, approximately six per cent of our financial instruments are fair value hedges.

All gains or losses related to fair value hedges are recorded on the Consolidated Statements of Earnings, which, in turn, are completely offset by the value of the gains or losses related to the hedged risk of the debt instruments on the foreign currency denominated assets and liabilities.

A summary of how typical fair value hedges are recorded in our financial statements is as follows:

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract(1)	–	–	–	–
Reporting date (marked-to-market)	ü	–	ü	–
Settle contract	ü	–	ü	ü

1  Option contracts may require an upfront cash investment.

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, 2009, approximately 91 per cent of our financial instruments are cash flow hedges.

Management’s Discussion and Analysis  |  22

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 typical project hedges are recorded in our financial statements is as follows:

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract	–	–	–	–
Reporting date (marked-to-market)(1)	–	ü	ü	–
Roll-over into new contract	–	ü	ü	ü
Settle contract	–	ü	ü	ü

1  Any ineffective portion is recorded in the Consolidated Statements of Earnings.

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 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.

Our physical commodity contracts are designated as all-in-one hedges and result in a net asset or liability position on our Consolidated Balance Sheets. Upon physical delivery of the commodity, we receive a gross settlement at the contracted price. Upon receipt of payment, the related net risk management asset or liability is eliminated. If an all-in-one hedge contract cannot be settled by physical delivery of the underlying commodity, it will be settled financially.

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract(1)	–	–	–	–
Reporting date (marked-to-market)(2)	–	ü	ü	–
Settle contract	ü	ü	ü	ü

1  Option contracts may require an upfront cash investment.

2  Any ineffective portion is recorded in the Consolidated Statements of Earnings.

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, 2008.

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 Canadian GAAP as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, therefore fair value is determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles, and/or volatilities and correlations between products derived from historical prices. Where commodity transactions extend into periods for which market-observable prices are not available, an internally-developed fundamental price forecast is used in the valuation. 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, 2009, Level III instruments had a net liability carrying value of $26 million. For the year ended Dec. 31, 2009, a realized gain of $1 million was included in earnings before income taxes relating to those Level III instruments.

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 Consolidated Statements of Earnings and Retained 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 can be used to hedge exposure to changes in the carrying values of our net investments in foreign operations having functional currency other than the Canadian dollar. Foreign denominated expenses are also used to assist in managing foreign currency exposures on earnings from self-sustaining foreign operations. Based on the fair value of risk management assets and liabilities at Dec. 31, 2009, approximately two per cent of our financial instruments are net investment hedges.

23  |  TransAlta Corporation

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 Consolidated Statements of Cash Flows 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 typical net investment hedges are recorded in our financial statements is as follows:

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract	–	–	–	–
Reporting date (marked-to-market)	–	ü	ü	–
Roll-over into new contract	–	ü	ü	ü
Settle contract	–	ü	ü	ü
Reduction of net investment of foreign operation	ü	ü	ü	–

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 Consolidated Statements of Earnings as they do not qualify for, nor have they been designated for, hedge accounting. Based on the fair value of risk management assets and liabilities at Dec. 31, 2009, approximately one per cent of our financial instruments are non-hedges.

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract(1)	–	–	ü	–
Reporting date (marked-to-market)	ü	–	ü	–
Roll-over into new contract	ü	–	ü	ü
Settle contract	ü	–	ü	ü
Divest contract	ü	–	ü	ü

1  Some contracts may require an initial cash investment.

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 Toronto Stock Exchange 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. The conversion of these options is not dilutive.

On Feb. 22, 2010, we had 2.3 million outstanding employee stock options with a weighted average exercise price of $25.01.

At Dec. 31, 2009, 1.5 million options to purchase our common shares were outstanding with a weighted average exercise price of $26.36, and 0.9 million were exercisable at the reporting date. For the year ended Dec. 31, 2009, no options were exercised and 0.1 million options were cancelled with a weighted average exercise price of $29.88.

At Dec. 31, 2008, 1.6 million options to purchase our common shares were outstanding with a weighted average exercise price of $27.06, and 0.6 million were exercisable at the reporting date. 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 comparator group. After three years, once PSOP eligibility has been determined and if common shares are granted, 50 per cent of the common shares are released to the participant and the remaining 50 per cent are held in trust for one additional year. The granting of common shares under the PSOP plan is not dilutive.

Under the terms of the Employee Share Purchase Plan, we extend an interest-free loan to our employees below senior manager 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, 2009, accounts receivable from employees under the plan totalled $3 million (2008–$3 million). This program is not available to officers and senior management.

Management’s Discussion and Analysis  |  24

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, 2009.

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 $58 million to secure the obligations under the supplemental plan.

STATEMENTS OF CASH FLOWS

The following charts highlight significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2009 and 2008:

Year ended Dec. 31	2009		2008		Explanation of change
Cash and cash equivalents, beginning of year	50		51
Provided by (used in):
Operating activities	580		1,038		Decrease in cash earnings of $99 million and unfavourable changes in working capital of $359 million.
Investing activities	(1,598	)	(581	)	Acquisition of Canadian Hydro, net of cash acquired, for $766 million and the sale of our Mexican equity investment in 2008 for $332 million, partially offset by a decrease in capital spending of $102 million and an increase in collateral received from counterparties of $87 million.
Financing activities	1,053		(467	)	Increase in draws on credit facilities of $863 million, increase in proceeds from issuance of long-term debt of $617 million, increase in proceeds from issuance of common shares of $382 million, and the purchase of common shares under the NCIB program in 2008 of $130 million, partially offset by a $488 million increase in the repayment of long-term debt.
Translation of foreign currency cash	(3	)	9
Cash and cash equivalents, end of year	82		50

Year ended Dec. 31	2008		2007		Explanation of change
Cash and cash equivalents, beginning of year	51		66
Provided 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 our Mexican 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 year	50		51

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LIQUIDITY AND CAPITAL RESOURCES

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

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

Debt

Recourse and non-recourse debt totalled $4.4 billion at Dec. 31, 2009 compared to $2.8 billion at Dec. 31, 2008. Total long-term debt increased from Dec. 31, 2008 primarily due to the debt issued during the fourth quarter of 2009 to fund the acquisition of Canadian Hydro and growth expenditures.

Credit Facilities

We have a total of $2.1 billion of committed long-term credit facilities of which $0.7 billion is not drawn and is available as of Dec. 31, 2009, subject to customary borrowing conditions. At Dec. 31, 2009, credit utilized under these facilities is $1.4 billion, which is comprised of actual drawings of $1.1 billion and of letters of credit of $334 million. Amounts drawn on credit facilities increased in 2009 as a result of lower cash earnings, partially offset by an increase in collateral received in 2009, which was used to repay credit facility balances.

Beyond the cash flow generated by our business, our primary source for short-term liquidity requirements is from our $2.1 billion of committed credit facilities. These facilities are comprised of a $1.5 billion committed syndicated bank facility, which matures in 2012, with the remainder comprised of bilateral credit facilities which mature between 2011 and 2013. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

Share Capital

On Feb. 22, 2009, we had 219 million common shares outstanding.

Normal Course Issuer Bid Program

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

For the year ended Dec. 31, 2009, no shares were purchased under the NCIB program.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties including those related to potential environmental obligations, trading activities, hedging activities, and purchase obligations. At Dec. 31, 2009, we provided letters of credit totalling $334 million (2008 – $430 million) and cash collateral of $27 million (2008 – $37 million). The decrease in letters of credit and cash collateral is due primarily to lower forward electricity prices in the Pacific Northwest and reduced trading activity with exchanges. These letters of credit and cash collateral secure certain amounts included on our Consolidated Balance Sheets under “Risk Management Liabilities” and “Asset Retirement Obligation”.

Working Capital

At Dec. 31, 2009, the excess of current liabilities over current assets is $5 million (2008 – $287 million). The excess of current liabilities over current assets decreased $282 million compared to 2008 due to a reduction in the current portion of long-term debt, the timing of operational commitments, and an increase in net risk management assets, partially offset by lower revenues and an increase in collateral received from counterparties.

Capital Structure

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

As at Dec. 31	2009		2008
	Amount	%	Amount	%
Debt, net of cash and cash equivalents	4,360	56	2,758	48
Non-controlling interests	478	6	469	8
Common shareholders’ equity	2,929	38	2,510	44
	7,767	100	5,737	100

Management’s Discussion and Analysis  |  26

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

	Fixed price			Coal supply	Long-term		Interest on	Growth
	gas purchase		Operating	and mining	service	Long-term	Long-term	project
	contracts	Transmission	leases	agreements	agreements	debt(1)	debt(2)	commitments	Total
2010	8	–	10	51	14	29	224	497	833
2011	7	2	10	47	16	251	203	87	623
2012	7	3	9	47	16	1,090	183	14	1,369
2013	7	3	9	47	16	659	170	–	911
2014	7	3	8	51	16	231	142	–	458
2015 and
thereafter	25	38	56	269	18	2,203	600	–	3,209
Total	61	49	102	512	96	4,463	1,522	598	7,403

1  Repayments of long-term debt include amounts related to our credit facilities that are currently scheduled to mature in 2012 and 2013.

2  Interest on long-term debt is based on debt currently in place with no assumption as to re-financing an instrument on maturity.

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 THE ENVIRONMENT

The varieties 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 while seeking to 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 December 2009, the Copenhagen Accord (“The Accord”) on climate change was negotiated and announced. The Accord is not binding nor does it stipulate a global target for GHG reductions, but rather countries are left to determine their individual targets and policies to manage emissions. The federal government’s previously-announced goal of a 17 per cent GHG reduction from a 2005 baseline by 2020 remains the target. However, the federal government has not yet implemented a framework or regulations to achieve those goals. At this point, it appears that the details and schedule of the Canadian program will depend on the development and direction of the U.S. approach.

Separately, the Government of Canada announced its intent to develop new Canadian air pollutant requirements for sulphur dioxide, nitrogen oxide (“NOx”), and mercury. Stakeholder consultations involving industry, provincial and federal governments, and environmental organizations are underway; however there is currently no defined date for the finalization and implementation of any recommendations.

On Dec. 1, 2009, the Government of Ontario released its mandatory GHG reporting regulation, requiring industrial facilities with more than 25,000 tonnes of carbon dioxide (“CO2”) emissions per year to report annually. The first reporting deadline for 2010 emissions is June 2011. This regulation is intended to lay the groundwork for an Ontario-based GHG regulatory framework to be implemented in 2010.

Alberta continues to maintain its GHG regulatory regime which requires reductions of 12 per cent in emission intensity from a 2003-2005 average baseline. The PPAs for our Alberta-based coal facilities contain change-in-law provisions that allow us to recover these compliance costs from our PPA customers. For 2009, after flow-through, our annual net GHG compliance costs are less than $4 million (2008–less than $2 million). We continue to examine compliance options, including additions to our offsets portfolio to minimize our compliance risk beyond the expiration of our PPAs.

United States

The American Clean Energy and Security Act was passed in June 2009, which established a cap and trade system designed to achieve a 17 per cent reduction in GHG emissions by 2020. There is significant uncertainty regarding the form and schedule of legislation that will be developed as a result of the cap and trade system designed, or if legislation will even emerge in 2010.

Meanwhile, the U.S. Environmental Protection Agency (“EPA”) is pursuing a separate path to regulate GHGs under the Clean Air Act. In November 2009, the U.S. courts upheld the endangerment finding which determines that CO2 is a pollutant and therefore able to be regulated by the EPA under the Clean Air Act. How and when a legislative option will develop versus the EPA regulatory approach is uncertain. In September 2009, the EPA separately announced requirements for nationwide GHG reporting beginning in 2010.

27  |  TransAlta Corporation

In Washington State in May 2009, Governor Gregoire signed an Executive Order laying out the state’s plan for addressing climate change related emissions. In the Order the Governor included a directive to the State Department of Ecology to work with us to apply the state’s GHG performance standard for power generation to the Centralia plant no later than 2025. That standard would require emissions reductions of approximately 0.5 tonnes/MWh, or about half of what is currently emitted at Centralia. Exploratory discussions are underway with the Department of Ecology to examine opportunities to achieve this reduction in emissions. At this time it is not clear how the state’s target and timeframe will endure should federal GHG legislation come into effect.

Also, in Washington State since September, there has been a public process to review a draft agreement between us and the state regarding our voluntary initiative to reduce NOx and mercury emissions from the Centralia plant. Specifically, we have proposed to:

nControl NOx emissions to a maximum of 0.24  lbs/million Btus of fuel input, and

nReduce mercury emissions by 50 per cent from current levels

It is expected that Washington State will issue its final determination in the spring of 2010.

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. Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but also to the communities in which we operate. We expect 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:

n      construction of renewable power sources;

n      environmental controls and efficiency improvements;

n      active participation in policy discussions;

n      clean energy technology development including CCS; and

n      investment in an offsets portfolio.

Renewable Power

In addition to our acquisition of Canadian Hydro, our investment in renewable power sources continues through the building of renewable power resources such as the Summerview 2, Kent Hills, and Ardenville wind farms. An increased renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or, in future, offsets.

Environmental Controls and Efficiency

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We are installing mercury control equipment at our Alberta Thermal operations in 2010 in order to meet the province’s 70 per cent reduction objectives. Our new Keephills 3 plant will use supercritical combustion technology to maximize thermal efficiency, as well as sulphur dioxide capture and low NOx combustion technology.

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

Policy Participation

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 and industry participants to meet environmental requirements over the longer-term.

CCS Development

On Oct. 14, 2009, the governments of Canada and Alberta announced that Project Pioneer, our CCS project, received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will support the undertaking of a FEED study that is expected to be complete in 2010 or early 2011. Once built, the prototype 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.

In addition, we look to advance other clean energy technologies through organizations such as the Canadian Clean Coal Power Coalition which examines emerging clean combustion technologies such as gasification. We are also part of a group of companies participating in the Integrated CO2 Network to develop carbon capture and storage systems and infrastructure for Canada.

Offsets Portfolio

TransAlta maintains an offset portfolio with a variety of instruments than can be used for compliance purposes or otherwise banked or sold. We continue to examine additional 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.

Management’s Discussion and Analysis  |  28

Future Growth

In 2009, we estimate that 40 million tonnes of GHGs with an intensity of 0.900 tonnes/MWh (2008–38.5 million tonnes of GHGs with an intensity of 0.893 tonnes/MWh) were emitted as a result of normal operating activities(1). Total GHG emissions increased in 2009 largely due to more dispatch variability at our Alberta Thermal operations leading to slightly lower combustion efficiencies. New generation growth and the related increase in emissions will be partially offset by the decommissioning of Unit 4 at our Wabamun plant. 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.

2010 OUTLOOK

BUSINESS ENVIRONMENT

Power Prices

In 2010, power prices are expected to remain at or slightly above 2009 levels due to the influence of low natural gas prices and minimal demand growth. In the Alberta market, the longer-term fundamentals of the market remain strong and the recovery of the oil sands is expected to drive load growth. In the Pacific Northwest, the recovery of natural gas prices is the main driver behind the recovery of power prices. Natural gas prices are expected to remain low until 2011.

Environmental Legislation

The state of development of environmental regulations in both Canada and the U.S. remains fluid. Canada has expressed its plan to coordinate the timing and structure of its regulatory framework with the U.S. In the U.S., it is not clear if climate change legislation will prevail or if instead regulation will be applied by the EPA. Each of these outcomes could create widely different results for the energy industry in the U.S., and indirectly for Canada’s regulatory approach.

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

Economic Environment

While we do expect our results from operations in 2010 to be impacted by the current economic environment, we expect that this impact will be somewhat mitigated by the contracted production and prices through our PPAs and other long-term contracts.

A number of our financial and industrial counterparties have experienced credit rating downgrades and we expect 2010 will continue to be challenging for some of our counterparties. While we had no counterparty losses in 2009, 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.

OPERATIONS

Capacity, Production, and Availability

Generating capacity is expected to increase in 2010 due to the commissioning of Summerview 2 and Kent Hills 2. Overall production and availability for 2010 is expected to increase compared to 2009 due to lower planned and unplanned outages across the fleet, and the acquisition of Canadian Hydro. Overall fleet availability for 2010 is expected to be approximately 90 per cent.

Commodity Hedging

Through the Alberta PPAs and our other long-term contracts, approximately 75 per cent of our capacity is contracted over the next seven years. To provide further stability to future earnings, we enter into physical and financial contracts for periods of up to five years. As a result of the acquisition of Canadian Hydro, we also have various contracts with terms that extend beyond five years. Under this strategy, we target being up to 90 per cent contracted for the upcoming year, stepping down to 70 per cent in the fourth year. Approximately 89 per cent of our 2010 capacity is contracted with the average contracted price of $60–$65/MWh in Alberta and U.S.$50–$55/MWh in the Pacific Northwest.

12009 data are estimates based on best available data at the time of report production. GHGs include water vapour, CO2 , methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO2 .

29  |  TransAlta Corporation

Fuel Costs

Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mines are minimized through the application of standard costing. Coal costs for 2010, on a standard cost basis, are expected to increase five to 10 per cent compared to the prior year as a result of depreciation due to mine capital and higher diesel costs.

Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel for 2010 is expected to be consistent with 2009.

We purchase natural gas from outside companies coincident with production or have it supplied by our customers, thereby minimizing our risk to changes in prices. The continued success of unconventional gas production in North America is expected to reduce the year to year volatility of prices going forward and may lead to greater opportunities to hedge our natural gas price exposure with longer term contracts.

In 2010, approximately 20 per cent of our fuel at our natural gas-fired facilities and seven per cent of our fuel at our coal-fired facilities is exposed to market fluctuations in energy commodity prices. We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risk.

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 for 2010 are expected to remain flat compared to 2009 as costs related to Canadian Hydro are expected to be offset by lower planned maintenance, our operational synergies, and productivity measures. OM&A costs per installed MWh for 2010 are expected to decrease primarily as a result of lower planned maintenance and an increase in installed capacity due to the acquisition of Canadian Hydro.

Energy Trading

Earnings from our COD segment are affected by prices in the market, 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 2010 objective is for Energy Trading to contribute between $50 million and $70 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 used to largely offset our net foreign currency-denominated earnings.

Net Interest Expense

Net interest expense for 2010 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 expect to maintain $2.1 billion of committed credit facilities, and will monitor our exposures and obligations to ensure we have sufficient liquidity to meet our requirements.

Accounting Estimates

A number of our accounting estimates, including those outlined in the Critical Accounting Policies and Estimates section of this MD&A, are based on the current economic environment and outlook. While we do not anticipate significant changes to these estimates as a result of the current economic environment, market fluctuations could impact, among other things, future commodity prices, foreign exchange rates, and interest rates, which could, in turn, impact future earnings and the unrealized gains or losses associated with our risk management assets and liabilities. The unrealized gains or losses related to our risk management assets and liabilities are not expected to impact our cash flows as they are generally settled at contracted prices.

Management’s Discussion and Analysis  |  30

CAPITAL EXPENDITURES

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

Growth Capital Expenditures

In 2009, we successfully completed two of our growth capital projects, Blue Trail and the Sundance Unit 5 uprate. We have nine significant growth capital projects that are currently in progress with targeted completion dates between Q4 2010 and Q4 2012.

A summary of each of these significant projects is outlined below:

	Total Project		2009	2010	Target
	Estimated	Incurred	Actual	Estimated	completion
Project	spend(1)	to date(1)	spend(1)	spend(1)	date	Details
						A 450 MW (225 MW net ownership interest) supercritical coal-fired plant and associated mine capital in a partnership
Keephills 3	988	707	231	225–245	Q2 2011	with Capital Power
					Completed	A 66 MW wind farm in southern
Blue Trail	113	113	87	–	in Q4 2009	Alberta
					Completed	A 53 MW efficiency uprate at our
Sundance Unit 5 uprate	77	77	60	–	in Q4 2009	Sundance facility
					Completed	A 66 MW expansion of our Summerview
Summerview 2	123	106	81	15–25	in Q1 2010	wind farm in southern Alberta
						A 23 MW efficiency uprate at our
Keephills Unit 1 uprate	34	1	1	5–10	Q4 2011	Keephills facility
						A 23 MW efficiency uprate at our
Keephills Unit 2 uprate	34	1	1	0–5	Q4 2012	Keephills facility
Ardenville	135	27	27	95–105	Q1 2011	A 69 MW wind farm in southern Alberta
						An 18 MW hydro facility in
Bone Creek	48	4	4	40–45	Q1 2011	British Columbia
						A 54 MW expansion of our wind farm
Kent Hills 2	100	18	18	80–85	Q4 2010	in New Brunswick
Total growth	1,652	1,054	510	460–520

1  Amounts are shown net of joint venture contributions.

Prior to our acquisition of Canadian Hydro, $23 million of costs were incurred in respect of Bone Creek, which do not form part of our total project cost.

Sustaining Capital Expenditures

For 2010, our estimate for total sustaining capital expenditures, net of any contributions received, is allocated among the following:

		Incurred in	Expected
Category	Description	2009	cost
Routine capital	Expenditures to maintain our existing generating capacity	158	120–140
Productivity capital	Projects to improve power production efficiency	44	10–15
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	42	25–30
Centralia modifications	Capital project to convert to external coal	21	–
Planned maintenance	Regularly scheduled major maintenance	115	140-155
Total sustaining expenditures		380	295–340

Details of the 2010 planned maintenance program are outlined as follows:

				Expected
	Coal	Gas	Renewables	cost
Capitalized	70–75	45–50	25-30	140–155
Expensed	60–65	0–5	–	60–70
	130–140	45–55	25–30	200–225

	Coal	Gas	Renewables	Total
GWh lost	1,770–1,780	360–370	–	2,130–2,150

31  |  TransAlta Corporation

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities, existing borrowing capacity, and capital markets. 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, our solid financial position, and the amount of capital available to us under existing committed credit facilities.

RELATED PARTY TRANSACTIONS

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

On Dec.16, 2006, predecessors of TAGP, a firm owned by the Corporation and one of its subsidiaries, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the coal-fired plant. The joint venture project is held in a partnership owned by Keephills 3 Limited Partnership (“K3LP”), a wholly owned subsidiary of the Corporation, and Capital Power. TAGP will supply coal until the earlier of the permanent closure of the Keephills 3 facility or the early termination of the agreement by TAGP and the partners of the joint venture. As at Dec. 31, 2009, TAGP had received $51 million from K3LP for future coal deliveries. Commercial operation of the Keephills plant is scheduled to commence in the second quarter of 2011. Payments received prior to that date for future coal deliveries are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply agreement when TAGP starts delivering coal for commissioning activities.

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

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

RISK MANAGEMENT

Our business activities expose us to a wide variety of risks. Our goal is to manage these risks so that we are reasonably protected from an unacceptable level of earnings or financial exposure while still enabling business development. We use a multi-level risk management oversight structure to manage the risks arising from our business activities, the markets in which we operate, and the political environments and structures with which we interface. As evidence of our dedication to excellent risk management and corporate governance, we were awarded both the Private Sector and Overall Conference Board of Canada/ Spencer Stuart National Award in Governance in 2009. For a further description of the following risk factors, refer to the Risk Factors section of our 2009 Annual Information Form.

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

THE BOARD OF DIRECTORS provides stewardship of the Corporation, establishes policies and procedures, defines risk tolerance as established under the Toronto Stock Exchange corporate governance guidelines, and receives an annual comprehensive Enterprise Risk Management (“ERM”) review. The ERM reviews consist of a holistic view of the Corporation’s inherent risks, how we mitigate these risks, and residual risks. It defines our risks, discusses who is responsible to manage each risk, how the risks are inter-related with each other, and identifies the applicable risk metrics. The Board of Directors also examines the ERM review in order to fulfill its requirement to understand the key risks of the Corporation and directs management to address any risk levels with which it believes are not optimal for shareholder value creation.

AUDIT AND RISK COMMITTEE (“ARC”) 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 ARC approves our Commodity Risk and Financial Exposure Management policies and reviews quarterly ERM reporting.

EXPOSURE MANAGEMENT COMMITTEE (“EMC”) is chaired by our Chief Financial Officer and is comprised of the Chief Operating Officer, Vice-President and Treasurer, Vice-President of Finance and Controller, Vice-President Financial Operations, Vice-President Risk Management, Vice-President Commercial Operations, and Managing Director of Trading. The EMC is responsible for reviewing, monitoring, and reporting on our compliance with approved financial and commodity risk exposure management policies.

TECHNICAL RISK AND COMMERCIAL TEAM (“TRACT”) is a committee chaired by the Vice-President, Project Management Office, and is comprised of our financial and operations vice presidents. It reviews major projects and commercial agreements at various stages through development, prior to submission for executive and Board approval.

Management’s Discussion and Analysis|32

CORPORATE TREASURY is responsible for the identification, management, monitoring, and reporting of financial risks, including: interest rate, foreign exchange, credit, liquidity, and insurable risks. The objective of Corporate Treasury is to maintain a strong financial position and a low cost of capital by sustaining a well capitalized balance sheet, mitigating earnings volatility, and maintaining ready access to capital markets. 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 MANAGEMENT is staffed by experienced risk professionals who are responsible for ERM reporting to the Board and ARC, participating in risk identification, analysis, and reporting in major projects, analyzing commercial and environmental risk exposures in our assets and trading operations, as well as ensuring our daily market price exposure is kept within approved risk metrics, including VaR, position limits, term limits, and market limits. The Risk Management group uses a variety of processes and models to perform this analysis.

RISK CONTROLS

Our risk controls have several key components:

Enterprise Tone

Every corporate culture is unique. We strive to be more than unique by fostering beliefs and actions that are true to and respectful of our many stakeholders. We do this by investing in communities where we live and work, operating and growing sustainability, putting safety first, and being responsible to the many groups and individuals with whom we work.

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 to the EMC includes analysis of new risks, existing risk exposures, events that can affect these risks, and recommendations for any suggested course of action to mitigate the existing level of risk. This monthly reporting provides for effective and timely risk management and oversight.

Whistleblower System

We have a system in place where employees, shareholders, or other stakeholders may report any potential ethical concerns. These concerns can be submitted anonymously, either directly to the ARC or 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 ARC.

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 three day average VaR for the year ending Dec. 31, 2009 was $3 million compared to $6 million for the same period in 2008.

We estimate VaR using the historical variance/covariance approach. Currently, there are two accepted energy industry methodologies for estimating VaR: historical variance/covariance and monte carlo. 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 of this MD&A.

RISK FACTORS

Risk is inherent in all business activities and can never be entirely eliminated. However, shareholder value can be protected and enhanced by identifying, mitigating, monitoring, reporting, 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 2009. 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.

33  |  TransAlta Corporation

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:

nactively managing our assets and their condition through the Generation and Capital and Asset Reporting groups in order to be proactive in plant maintenance so that they are available to produce when market requires,

nmonitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities,

nplacing our wind and geothermal facilities in locations that we believe to have sufficient resources in order for us to be able to generate sufficient electricity to meet the requirements of our contracts.  However, we cannot guarantee that these resources will be available when we need them or in the quantities that we require, and

nmonitoring market volumes and liquidity to ensure sufficient volumes are available to fulfill proprietary trading requirements.

The sensitivities of volumes to our net earnings are shown below:

		Approximate impact
Factor	Increase or decrease (%)	on net earnings
Availability/production	1	17

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 where our equipment is unavailable to produce electricity.

We manage our generation equipment and technology risk by:

noperating our generating facilities within defined and proven operating standards that are designed to maximize the output of our generating facilities for the longest period of time,

nperforming preventative maintenance on a regular basis,

nadhering to a comprehensive plant maintenance program and regular turnaround schedules,

nadjusting maintenance plans by facility to reflect the equipment type and age,

nhaving sufficient business interruption insurance in place in the event of an extended outage,

nhaving force majeure clauses in the PPAs and other long-term  contracts,

nusing technology in our generating facilities that is selected and maintained with the goal of maximizing the return on those assets,

nmonitoring technological advances and evaluating their impact upon our existing generating fleet and related maintenance programs,

nnegotiating strategic supply agreements with selected vendors to ensure key components are available in the event of a significant outage

nentering into long-term  arrangements with our strategic supply partners to ensure availability of critical spare parts, and

ndeveloping a long-term  asset management strategy with the objective of maximizing the life cycles of our existing facilities and/or  replacement of selected generating assets.

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 exposure to fluctuations in gross margin associated with commodity price risk by:

nentering into long-term  contracts that specify the price at which electricity, steam, and other services are provided,

nentering into a variety of short-  and long-term  contracts to minimize our exposure to short-term  fluctuations in electricity prices,

npurchasing natural gas coincident with production for merchant plants so spot market spark spreads are adequate to produce and sell electricity at a profit, and

nensuring limits and controls are in place for our proprietary trading activities to ensure they are in line with our VaR methodologies.

In 2009, we had approximately 97 per cent of production under short-term and long-term contracts and hedges (2008 – 97 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.

Management’s Discussion and Analysis|34

We manage fuel price commodity risk by:

nentering into long-term contracts that specify the price at which fuel is to be supplied to our plants, and

nselectively using hedges, where available, to set prices for fuel.

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 2009, 79 per cent (2008–82 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2008–100 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 earnings are shown below:

		Approximate impact
Factor	Increase or decrease	on net earning
Electricity price	$1.00/MWh	7
Natural gas price	$0.10/GJ	2
Coal price	$1.00/tonne	14

Fuel Supply Risk

We buy natural gas and some of our coal to supply the fuel needed to operate our facilities. Having sufficient fuel available when required for generation is essential to maintaining 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:

nensuring that the majority of the coal used in electrical generation is from coal reserves owned by us, thereby limiting our exposure to fluctuations in the supply of coal from third parties.  As at Dec. 31, 2009, approximately 75 per cent (2008–70 per cent) of the coal used in generating activities is from coal reserves owned by us,

nusing longer-term mining plans to ensure the optimal supply of coal from our mines,

nsourcing the majority of the coal used at Centralia Thermal under a mix of short-, medium-, and long-term contracts and from multiple mine sources to ensure sufficient coal is available at a competitive cost,

ncontracting sufficient trains to deliver the coal requirements at Centralia Thermal,

nensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a timely and efficient manner,

nmonitoring and maintaining coal specifications, carefully matching the specifications mined with the requirements of our plants, and

nhedging diesel exposure in mining and transportation costs.

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 compliance costs will increase due to increased political and public attention to environmental concerns.

We manage environmental risk by:

nseeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts, and environmental incidents,

nhaving an International Organization for Standardization and Occupational Health and Safety Assessment Series-based environmental health and safety (“EHS”) management system in place that is designed to continuously improve environmental performance,

ncommitting significant effort to work with regulators in Canada and the United States to ensure regulatory changes are well designed and cost effective,

ndeveloping compliance plans that address how to meet or exceed emission standards for GHGs, mercury, sulphur dioxide and oxides of nitrogen, which will be adjusted as regulations are finalized,

npurchasing emission reduction offsets outside of our operations,

ninvesting in renewable energy projects, such as wind generation, and

ninvesting in clean coal technology development, which provides long-term promise for large emission reductions from fossil-fired generation.

35  |  TransAlta Corporation

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 2009, we spent approximately $45 million (2008–$47 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 assess and develop clean combustion technologies. On Oct. 14, 2009, the federal and provincial governments announced that Project Pioneer, our CCS project, has received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative.

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 or performance 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 net earnings and cash flows.

We manage our exposure to credit risk by:

nestablishing and adhering to policies that define credit limits based on creditworthiness of counterparties, define contract term limits, and credit concentration with any specific counterparty,

nusing formal sign-off on contracts that include commercial, financial, legal, and operational reviews,

nusing security instruments, such as parental guarantees, letters of credit, and cash collateral that can be collected if a counterparty fails to fulfill their obligation or go over their limits, and

nreporting our exposure using a variety of methods that allow key decision makers to assess credit exposure by counterparty.  This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on their credit ratings.

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 2009 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 2009, 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, 2008.

A summary of our credit exposure for commodity trading operations and hedging at Dec. 31, 2009 is provided below:

Counterparty credit rating	Net exposure
Investment grade	279
Non-investment grade	–
No external rating, internally rated as investment grade	23
No external rating, internally rated as non-investment grade	1

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 $63 million (2008–$105 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. Our exposures are 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.

We manage our currency rate risk by:

nhedging our net investments in foreign operations using a combination of foreign-denominated debt and financial instruments.  Our strategy is to offset 90 to 100 per cent of all foreign currency exposures.  At Dec. 31, 2009, we have hedged approximately 97 per cent (2008–97 per cent) of our foreign currency net investment exposure, and

noffsetting earnings from our foreign operations as much as possible by using expenditures denominated in the same foreign currencies.  We use financial instruments to hedge the balance of our exposure in foreign operations earnings.

Translation gains and losses related to the carrying value of our foreign operations are included in accumulated other comprehensive income (“AOCI”) in shareholders’ equity. At Dec. 31, 2009, the balance in AOCI represents a $126 million gain (2008–$61 million gain).

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

	Increase or decrease	Approximate impact
Factor	(foreign currency)	on net earnings
Exchange rate	$0.05	2

Management’s Discussion and Analysis  |  36

Liquidity Risk

Liquidity risk relates to our ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing, and general corporate purposes. Investment grade ratings support these activities and provide a more reliable and cost effective means to access capital markets through commodity and credit cycles. We are focused on maintaining a strong balance sheet and stable investment grade credit ratings.

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

We manage liquidity risk by:

nmonitoring liquidity on trading positions,

npreparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital,

nreporting liquidity risk exposure for proprietary trading activities on a regular basis to the EMC, senior management, and Board of Directors,

nmaintaining investment grade credit ratings, and

n      maintaining committed credit lines to support potential liquidity requirements.

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:

nemploying a combination of fixed and floating rate debt instruments, and

nmonitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient mixture of these types of debt.

At Dec. 31, 2009, approximately 31 per cent (2008–24 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 net earnings is shown below:

		Approximate impact
Factor	Increase or decrease (%)	on net earnings
Interest rate	1	10

Project Management Risk

As we are currently working on seven generating projects, we face risks associated with cost-overruns, delays, and performance.

We attempt to minimize these project risks by:

nensuring all projects are vetted by the TRACT Committee so that projects have been highly scrutinized to see that established processes and policies are followed, risks have been properly identified and quantified, input assumptions are reasonable, and returns are realistically forecasted prior to Executive and Board approvals,

nusing a consistent and disciplined project management methodology and processes,

nperforming detailed analysis of project economics prior to construction or acquisition and by determining our asset contracting strategy to ensure the right mix of contracted and merchant capacity prior to commencement of construction,

npartnering with those who have previously been able to deliver projects economically and on budget.  Our partnership with Capital Power on the construction of Keephills 3 is a direct result of this type of partnership,

ndeveloping and following through with comprehensive plans that include critical paths identified, key delivery points, and backup plans,

nensuring project closeouts so that any learnings from the project are incorporated into the next significant project,

nfixing the price and availability of the equipment, foreign currency rates, warranties, and source agreements as much as economically feasible prior to proceeding with the project, and

nentering into labour agreements to provide security around cost and productivity.

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:

npotential disruption as a result of labour action at our generating facilities,

nreduced productivity due to turnover in positions,

ninability to complete critical work due to vacant positions,

nfailure to maintain fair compensation with respect to market rate changes, and

nreduced competencies due to insufficient training, failure to transfer knowledge from existing employees, or insufficient expertise within current employees.

37  |  TransAlta Corporation

We manage this risk by:

nmonitoring industry compensation and aligning salaries with those benchmarks,

nusing incentive pay to align employee goals with corporate goals,

nmonitoring and managing target levels of employee turnover, and

nensuring new employees have the appropriate training and qualifications to perform their jobs.

In 2009, 46 per cent (2008–46 per cent) of our labour force is covered by 11 (2008–11) collective bargaining agreements. In 2009, five (2008–three) agreements were renegotiated. We anticipate negotiating four additional agreements in 2010. 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. 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 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 reduced reliability and capacity on the existing transmission facilities, and the risk associated with the existing transmission infrastructure in Alberta, Ontario, and the Pacific Northwest continues to increase.

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:

nstriving as a neighbour and business partner in the regions where we operate to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders,

nclearly communicating our business objectives and priorities to a variety of stakeholders on a routine basis,

nmaintaining positive relationships with various levels of government,

npursuing sustainable development as a longer-term corporate strategy,

nensuring that each business decision is made with integrity and in line with our corporate values, and

ncommunicating the impact and rationale of business decisions to stakeholders in a timely manner.

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 Resources in determining the appropriate course of action. These concerns and any actions taken are discussed with the ARC. 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 Canadian GAAP, based on all information currently available.

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

		Approximate impact
Factor	Increase or decrease (%)	on net earnings
Tax rate	1	2

Management’s Discussion and Analysis  |  38

The effective tax rate on earnings before income taxes, equity loss, and other items for 2009 was 10 per cent. The effective income tax rate can change depending on the mix of earnings from various countries and certain deductions that do not fluctuate with earnings.

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 2009. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims.

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, financial instruments and hedges, PP&E, goodwill, income taxes, employee future benefits, and asset retirement obligation (Notes 1(D), (F), (J), (K), (N), (O), and (Q), respectively). Each policy involves a number of estimates and assumptions to be made about matters that are 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 ARC and our independent auditors. The ARC 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.

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, to earn trading revenues and to gain market information. These derivatives are accounted for using fair value accounting and are presented on a net basis in the Consolidated Statements of Earnings when hedge accounting is not applied. 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 Consolidated 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 the Consolidated Statements of Comprehensive Income and are presented on the Consolidated 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 are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or models.

39  |  TransAlta Corporation

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 2009, 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. Where commodity transactions extend into periods for which market-observable prices are not available, an internally-developed fundamental price forecast is used in the valuation.

As a result of the acquisition of Canadian Hydro, we also have various contracts with terms that extend beyond five years. Valuation of these contracts must be extrapolated as the lengths of these contracts make reasonably alternate fundamental price forecasts unavailable.

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

Valuation of PP&E and Associated Contracts

As at Dec. 31, 2009, PP&E makes up 78 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 and associated contracts are 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.

Our businesses, the markets, and the business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates possible impairment. If such an event has occurred, an estimate is made of 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 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.

Management’s Discussion and Analysis|40

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 more frequently if events indicate, we perform an impairment review of our plants. As a result of this review in 2009, there were no changes to asset values.

Project Development Costs

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

Useful Life of PP&E

PP&E is depreciated over its estimated useful life. Estimated useful lives are 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.

In 2009, depreciation and amortization expense per the Consolidated Statements of Cash Flows was $493 million (2008–$451million), of which $40 million (2008–$38 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 $23 million in depreciation and amortization expense (2008–$ 22 million).

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 Canadian Hydro, Merchant Energy Group of the Americas, Inc., Vision Quest Windelectric Inc., and CE Gen. At Dec. 31, 2009, this goodwill had a total carrying value of $434 million (2008–$142 million). The change in value from Dec. 31, 2008 is mainly due to the acquisition of Canadian Hydro.

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, 2009. This includes consideration of the current economic environment and related credit crisis, which does not materially impact the fair value of our assets and liabilities of our reporting units because they are highly contracted. Accordingly, no goodwill impairment charges were recorded for the year ended Dec. 31, 2009.

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 $221 million have been recorded on the Consolidated Balance Sheets at Dec. 31, 2009 (2008–$251 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.

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Future tax liabilities of $694 million have been recorded on the Consolidated Balance Sheets at Dec. 31, 2009 (2008–$610 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 in accordance with Canadian GAAP based on all information currently available. The outcome of pending 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 2010.

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, 2009, the plan assets had a positive return of $38 million compared to a negative return of $55 million in 2008, and a positive return of $10 million in 2007. The 2009 actuarial valuation used the same rate of return on plan assets (seven per cent) as was used in 2008 and 2007.

Asset Retirement Obligation

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, 2009, the ARO recorded on the Consolidated Balance Sheets was $282 million (2008–$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 2010 and 2072. The majority of the costs will be incurred between 2020 and 2030. An average discount rate of eight per cent was used to calculate the carrying value of the ARO.

Sensitivities for the major assumptions are as follows:

		Approximate impact
Factor	Increase or decrease (%)	on net earnings
Discount rate	1	2
Undiscounted ARO	1	–

CURRENT ACCOUNTING CHANGES

Financial Instruments Disclosures

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

Financial Instruments–Recognition and Measurement

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

Management’s Discussion and Analysis|42

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

Credit Risk

On Jan. 1, 2009, we adopted the Emerging Issues Committee (“EIC”) Abstract 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. Under EIC–173, an entity’s own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. The implementation of this standard did not have a material impact upon our consolidated financial statements.

Deferral of Costs and Internally Developed Intangibles

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

Mining Exploration Costs

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

FUTURE ACCOUNTING CHANGES

Business Combinations and Non-Controlling Interests

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

IFRS Convergence

On May 8, 2009, the AcSB re-confirmed that IFRS will be required for interim and annual financial statements commencing on Jan. 1, 2011, with appropriate comparative IFRS financial information for 2010. Our project to convert to IFRS consists of the following phases:

Phase	Description	Status
Diagnostic	In-depth identification and analysis of differences between Canadian GAAP and IFRS	Complete
Design and planning	Cross-functional, issue-specific teams analyze the key areas of convergence, and along with Information Technology and Internal Control resources, determine process, system, and financial reporting controls changes required for the conversion to IFRS	Complete
Solution development	Plans to address identified conversion issues are developed and tested in a controlled environment. Staff training programs and internal communication plans are implemented to communicate process changes as a result of the conversion to IFRS	In progress
Implementation	Processes required for dual reporting in 2010 and full convergence in 2011 are implemented in a live environment with change management in place for a successful transition to steady state	In progress

A steering committee monitors the progress and critical decisions of the transition to IFRS and continues to meet regularly. This committee includes representatives from Finance, Information Technology, Treasury, Investor Relations, Human Resources, and Operations. Quarterly updates are provided to the ARC.

Based on the work to date, our view is that while IFRS uses a conceptual framework similar to Canadian GAAP and has many similarities to Canadian GAAP, there are several significant differences in accounting policies that must be addressed. The majority of differences for us are expected to arise in respect to:

nAdditional disclosure reconciling the changes in individual classes of property, plant, and equipment and accumulated amortization,

nCosts related to major inspection activities being recognized as part of the carrying value of property, plant, and equipment and depreciated over the period until the next major inspection,

nAllowing an entity to recognize as at Jan.  1, 2010, all experience and transitional gains and losses related to employee future benefits to retained earnings with subsequent experience gains and losses being recorded in other comprehensive income, and

nCertain long-term  contracts being deemed finance leases resulting in the associated property, plant, and equipment being removed  from the Consolidated Balance Sheets and replaced with a long-term  receivable representing the present value of lease payments  to be received over the life of the contract.  Payments received under the contract are recorded in revenue and interest income, dependent upon the interest rate and duration of the contract.

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As we prepare for 2010 dual reporting, we continue to evaluate the transitional options available under IFRS 1, First-Time Adoption of International Financial Reporting Standards as well as the most appropriate long-term accounting policies available under IFRS.

In 2010, the International Accounting Standards Board (“IASB”) is expected to issue new guidance on the accounting for joint ventures. Under the issued exposure draft, certain joint ventures cannot be proportionately consolidated and must instead be accounted for as an equity investment on the balance sheet with the associated net income or loss from these joint ventures being recorded as equity earnings on the statement of earnings.

At this time, it is not anticipated that any other material new standards or amendments relating to these projects will be effective on convergence in 2011. However, the progress and recommendations of other IASB projects for financial instruments, post-employment benefits, financial statement presentation, revenue recognition, and leases are being closely monitored to ensure that any potential adverse impacts to the convergence project can be minimized. As a result, the full impact of adopting IFRS on our financial position and future results cannot reasonably be determined at this time.

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 Canadian GAAP and therefore should not be considered in isolation or as an alternative to or to be more meaningful than net earnings or cash flow from operating activities, as determined in accordance with Canadian 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	2009		2008		2007
Revenues	2770		3,110		2,775
Fuel and purchased power	(1,228	)	(1,493	)	(1,231	)
Gross margin	1,542		1,617		1,544
Operations, maintenance, and administration	667		637		577
Depreciation and amortization	475		428		406
Taxes, other than income taxes	22		19		20
Operating expenses	1,164		1,084		1,003
Operating income	378		533		541
Foreign exchange gain (loss)	8		(12	)	3
Writedown of mining development costs	(16	)	–		–
Net interest expense	(144	)	(110	)	(133	)
Equity loss	–		(97	)	(50	)
Other income	8		5		16
Earnings before non-controlling interests and income taxes	234		319		377
Non-controlling interests	38		61		48
Earnings before income taxes	196		258		329
Income tax expense	15		23		20
Net earnings	181		235		309

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. Earnings on a comparable basis are calculated using the weighted average common shares outstanding during the year.

In calculating comparable earnings for 2009, we have excluded the writedown of mining development costs, the impact of a future tax rate change, and the settlement of an outstanding commercial issue that has been recorded in other income as this was related to our previously held Mexican equity investment.

In calculating comparable earnings for 2008, we have also excluded the writedown of our Mexican equity investment.

In calculating comparable earnings for 2008 and 2007, we have excluded the impact of future tax rate changes, recoveries related to 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. We also excluded the gains recorded on the sale of assets at the previously operated Centralia coal mine in 2008 and 2007 as we do not normally dispose of large quantities of fixed assets.

The change in life of certain component parts at Centralia Thermal was excluded from the calculation of comparable earnings in all three years as it relates to the cessation of mining activities at the Centralia coal mine and conversion to consuming solely third party supplied coal.

Management’s Discussion and Analysis  |  44

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

Year ended Dec. 31	2009		2008		2007
Net earnings	181		235		309
Gain on sale of assets at Centralia, net of tax	–		(4	)	(10	)
Change in life of Centralia parts, net of tax	1		12		3
Writedown of mining development costs, net of tax	10		–		–
Settlement of commercial issue, net of tax	(6	)	–		–
Tax rate change	(5	)	–		(48	)
Recovery related to tax positions	–		(15	)	(18	)
Writedown of Mexican equity investment, net of tax	–		62		–
Change in tax law in Mexico	–		–		28
Earnings on a comparable basis	181		290		264
Weighted average common shares outstanding in the year	201		199		202
Earnings on a comparable basis per share	0.90		1.46		1.31

Free Cash Flow (Deficiency)

Free cash flow represents the amount of cash generated by our business that is available to invest in growth initiatives, repay scheduled principal repayments of recourse debt, pay additional common share dividends, or repurchase common shares.

Sustaining capital expenditures for the year ended Dec. 31, 2009, represents total additions to property, plant, and equipment per the Consolidated Statements of Cash Flows less $524 million ($510 million net of joint venture contributions) that we have invested in growth projects. For the same period in 2008, we invested $541 million ($515 million net of joint venture contributions). In 2007, we invested $182 million in growth projects.

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

Year ended Dec. 31	2009		2008		2007
Cash flow from operating activities	580		1,038		847
Add (Deduct):
Sustaining capital expenditures	(380	)	(465	)	(417	)
Dividends on common shares	(226	)	(212	)	(205	)
Distribution to subsidiaries’ non-controlling interests	(58	)	(98	)	(87	)
Non-recourse debt repayments(1)	(25	)	(28	)	(47	)
Other income	(8	)	–		–
Timing of contractualy scheduled payments	–		(116	)	–
Cash flows from equity investments	–		2		(4	)
Centralia closure costs	–		–		24
Free cash flow (deficiency)	(117	)	121		111

1  Excludes debt repayments related to recourse debt that have been or will be refinanced with long-term debt issuances, consistent with our overall capital strategy.

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

Earnings before Interest, Taxes, Depreciation, and Amortization (“EBITDA”)

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

Year ended Dec. 31	2009	2008	2007
Operating income	378	533	541
Accretion	24	22	24
Depreciation and amortization per the Consolidated Statements of Cash Flows(1)	493	451	415
EBITDA	895	1,006	980

1To calculate EBITDA, we use depreciation and amortization per the Consolidated Statements of Cash Flows because this number takes into account depreciation related to mine assets, which is included in cost of sales per the Consolidated Statements of Earnings .

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Comparable Return on Capital Employed

Comparable ROCE measures the efficiency and profitability of capital investments and is calculated by taking comparable earnings before net interest expense, non-controlling interests, and income taxes, and dividing by the average invested capital excluding AOCI. 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.

The calculation of comparable earnings before net interest expense, non-controlling interests, and income taxes is presented below:

Year ended Dec. 31	2009		2008		2007
Earnings before income taxes per the Consolidated Statements of Earnings	196		258		329
Net interest expense	144		110		133
Non-controlling interests	38		61		48
Change in life of Centralia parts, pre-tax	2		18		6
Writedown of mining development costs, pre-tax	16		–		–
Settlement of commercial issue, pre-tax	(7	)	–		–
Writedown of Mexican equity investment, pre-tax	–		97		–
Gain on sale of assets at Centralia, pre-tax	–		(6	)	(15	)
Change in tax law in Mexico	–		–		28
Comparable earnings before net interest expense, non-controlling interests, and income taxes	389		538		529

SELECTED QUARTERLY INFORMATION

	Q1 2009	Q2 2009		Q3 2009	Q4 2009
Revenue	756	585		666	763
Net earnings (loss)	42	(6	)	66	79
Basic and diluted earnings (loss) per common share	0.21	(0.03	)	0.34	0.37
Comparable earnings (loss) per common share	0.18	(0.03	)	0.34	0.40

	Q1 2008	Q2 2008	Q3 2008	Q4 2008
Revenue	803	708	791	808
Net earnings	33	47	61	94
Basic and diluted earnings per common share	0.17	0.24	0.31	0.47
Comparable earnings per common share	0.50	0.25	0.32	0.40

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

CONTROLS AND PROCEDURES

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (“Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act 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. Management’s evaluation of our internal control over financial reporting did not include an evaluation of the internal controls of Canadian Hydro, and management’s conclusion regarding the effectiveness of our internal control over financial reporting does not extend to the internal controls of Canadian Hydro.

There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Dec. 31, 2009, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

Management’s Discussion and Analysis  |  46

FORWARD LOOKING STATEMENTS

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

In particular, this MD&A contains forward looking statements pertaining to the following: expectations relating to the timing of the completion and commissioning of projects under development, including uprates and upgrades, and their attendant costs; expectations related to future earnings and cash flow from operating activities; expectations relating to the timing of the completion of the FEED study regarding CCS and the cost of the study; estimates of fuel supply and demand conditions and the costs of procuring fuel; our plans to invest in existing and new capacity, and the expected return on those investments; expectations for demand for electricity in both the short-term and long-term, and the resulting impact on electricity prices; expectations in respect of generation availability and production; expectations in terms of the cost of operations and maintenance, and the variability of those costs; our plans to install mercury control equipment at our Alberta Thermal operations and our initiative to reduce nitrogen oxide and mercury emissions from our Centralia Plant; expected governmental regulatory regimes and legislation, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; expectations relating to the renegotiation of certain of the collective bargaining agreements to which we are a party; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; expectations for the outcome of existing or potential legal claims; and expectations for the ability to access capital markets at reasonable terms.

Factors that may adversely impact our forward looking statements include risks relating to: (i) fluctuations in market prices and availability of fuel supplies required to generate electricity and in the price of electricity; (ii) the regulatory and political environments in the jurisdictions in which we operate; (iii) environmental requirements and changes in, or liabilities under, these requirements; (iv) changes in general economic conditions including interest rates; (v) operational risks involving our facilities, including unplanned outages at such facilities; (vi) disruptions in the transmission and distribution of electricity; (vii) effects of weather; (viii) disruptions in the source of fuels, water, wind or biomass required to operate our facilities; (ix) natural disasters; (x) equipment failure; (xi) trading risks; (xii) industry risk and competition; (xiii) fluctuations in the value of foreign currencies and foreign political risks; (xiv) need for additional financing; (xv) structural subordination of securities; (xvi) counterparty credit risk; (xvii) insurance coverage; (xviii) our provision for income taxes; (xix) legal proceedings involving the Corporation; (xx) reliance on key personnel (xxi) labour relations matters; and (xxii) development projects and acquisitions. The foregoing risk factors, among others, are described in further detail in the Risk Management section of this MD&A and under the heading “Risk Factors” in our 2009 Annual Information Form.

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

47|  TransAlta Corporation