EX-13.2 3 a12-5919_1ex13d2.htm MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2011.

Exhibit 13.2

13	TransAlta Corporation
13	2011 Annual Report	Plant Summary

						Net capacity
		Capacity		Ownership		ownership					Contract
As of December 31, 2011	Facility	(MW	)1	(%	)	interest (MW	)1	Fuel	Revenue source		expiry date


Western Canada	Sundance, AB2	1,581		100%		1,581		Coal	Alberta PPA/Merchant	3	2020
39 Facilities	Keephills, AB4	812		100%		812		Coal	Alberta PPA/Merchant	4	2020
	Keephills 3, AB	450		50%		225		Coal	Merchant		—
	Genesee 3, AB	466		50%		233		Coal	Merchant		—
	Sheerness, AB	780		25%		195		Coal	Alberta PPA		2020
	Poplar Creek, AB	356		100%		356		Gas	LTC/Merchant		2024
	Fort Saskatchewan, AB	118		30%		35		Gas	LTC		2019
	Brazeau, AB	355		100%		355		Hydro	Alberta PPA		2020
	Big Horn, AB	120		100%		120		Hydro	Alberta PPA		2020
	Spray, AB	103		100%		103		Hydro	Alberta PPA		2020
	Ghost, AB	51		100%		51		Hydro	Alberta PPA		2020
	Rundle, AB	50		100%		50		Hydro	Alberta PPA		2020
	Cascade, AB	36		100%		36		Hydro	Alberta PPA		2020
	Kananaskis, AB	19		100%		19		Hydro	Alberta PPA		2020
	Bearspaw, AB	17		100%		17		Hydro	Alberta PPA		2020
	Pocaterra, AB	15		100%		15		Hydro	Alberta PPA		2013
	Horseshoe, AB	14		100%		14		Hydro	Alberta PPA		2020
	Barrier, AB	13		100%		13		Hydro	Alberta PPA		2020
	Taylor Hydro, AB	13		100%		13		Hydro	Merchant		—
	Interlakes, AB	5		100%		5		Hydro	Alberta PPA		2020
	Belly River, AB	3		100%		3		Hydro	Merchant		—
	Three Sisters, AB	3		100%		3		Hydro	Alberta PPA		2020
	Waterton, AB	3		100%		3		Hydro	Merchant		—
	St. Mary, AB	2		100%		2		Hydro	Merchant		—
	Upper Mamquam, BC	25		100%		25		Hydro	LTC		2025
	Pingston, BC	45		50%		23		Hydro	LTC		2023
	Bone Creek, BC	19		100%		19		Hydro	LTC		2031
	Akolkolex, BC	10		100%		10		Hydro	LTC		2015
	Summerview 1, AB	70		100%		70		Wind	Merchant		—
	Summerview 2, AB	66		100%		66		Wind	Merchant		—
	Ardenville, AB	69		100%		69		Wind	Merchant		—
	Blue Trail, AB	66		100%		66		Wind	Merchant		—
	Castle River, AB5	44		100%		44		Wind	Merchant		—
	McBride Lake, AB	75		50%		38		Wind	LTC		2023
	Soderglen, AB	71		50%		35		Wind	Merchant		—
	Cowley Ridge, AB	21		100%		21		Wind	Merchant		—
	Cowley North, AB	20		100%		20		Wind	Merchant		—
	Sinnott, AB	7		100%		7		Wind	Merchant		—
	Macleod Flats, AB	3		100%		3		Wind	Merchant		—
	Total Western Canada	5,996				4,775
Eastern Canada	Sarnia, ON	506		100%		506		Gas	LTC		2022-2025
14 Facilities	Mississauga, ON	108		50%		54		Gas	LTC		2017
	Ottawa, ON	68		50%		34		Gas	LTC		2012
	Windsor, ON	68		50%		34		Gas	LTC/Merchant		2016
	Ragged Chute, ON	7		100%		7		Hydro	Merchant		—
	Misema, ON	3		100%		3		Hydro	LTC		2027
	Galetta, ON	2		100%		2		Hydro	LTC		2031
	Appleton, ON	1		100%		1		Hydro	LTC		2031
	Moose Rapids, ON	1		100%		1		Hydro	LTC		2031
	Wolfe Island, ON	198		100%		198		Wind	LTC		2029
	Melancthon, ON	200		100%		200		Wind	LTC		2026-2028
	Le Nordais, QC	99		100%		99		Wind	LTC		2033
	Kent Hills, NB	150		83%		125		Wind	LTC		2033-2035
	New Richmond, QC6	68		100%		68		Wind	Quebec PPA		2032
	Total Eastern Canada	1,479				1,332
United States	Centralia, WA	1,340		100%		1,340		Coal	Merchant		—
17 Facilities	Centralia Gas, WA	248		100%		248		Gas	Merchant		—
	Power Resources, TX	212		50%		106		Gas	Merchant		—
	Saranac, NY	240		37.5%		90		Gas	Merchant		—
	Yuma, AZ	50		50%		25		Gas	LTC		2024
	Imperial Valley, CA7	327		50%		164		Geothermal	LTC		2016-2029
	Skookumchuck, WA	1		100%		1		Hydro	LTC		2020
	Wailuku, HI	10		50%		5		Hydro	LTC		2023
	Total U.S.	2,428				1,979
Australia	Parkeston, WA	110		50%		55		Gas	LTC		2016
5 Facilities	Southern Cross, WA8	245		100%		245		Gas/Diesel	LTC		2013
	Total Australia	355				300
TOTAL		10,258				8,386

1	Megawatts are rounded to the nearest whole number.
2	Includes a 15 MW uprate on Sundance Unit 3 expected to be commercial in 2012; excludes Sundance Units 1 and 2.
3	Merchant capacity refers to uprates on Unit 4 (53 MW), Unit 5 (53 MW), and Unit 6 (44 MW).
4	Includes two 23 MW uprates on Keephills Units 1 and 2 expected to be commercial in 2012 as merchant capacity.
5	Includes seven individual turbines at other locations.
6	Facilities currently under development.
7	Comprised of 10 facilities.
8	Comprised of four facilities.

	TransAlta Corporation	14
Management’s Discussion and Analysis	2011 Annual Report	14

management’s discussion and analysis


Business Environment	15

Strategy	17

Capability to Deliver Results	18

Performance Metrics	19

Results of Operations	22

Highlights and Summary of Results	22

Net Earnings Attributable to Common Shareholders	23

Significant Events	24

Subsequent Events	27

Discussion of Segmented Results	28

Net Interest Expense	34

Non-Controlling Interests	34

Income Taxes	35

Financial Position	36

Financial Instruments	36

Employee Share Ownership	39

Employee Future Benefits	40

Statements of Cash Flows	40

Liquidity and Capital Resources	41

Unconsolidated Structured Entities or Arrangements	42

Climate Change and the Environment	42

Forward Looking Statements	44

2012 Outlook	45

Risk Management	48

Critical Accounting Policies and Estimates	56

Future Accounting Changes	61

Non-IFRS Measures	63

Selected Quarterly Information	66

Controls and Procedures	66

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited 2011 consolidated financial statements and our 2012 Annual Information Form. On Jan. 1, 2011, we adopted International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises. Prior to the adoption of IFRS, we followed Canadian Generally Accepted Accounting Principles (“Canadian GAAP” or our “previous GAAP”). All dollar amounts in the following discussion, including the tables, are in millions of Canadian dollars unless otherwise noted. This MD&A is dated March 1, 2012. Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us”, or “the Corporation”), including our Annual Information Form, is available on SEDAR at www.sedar.com, or EDGAR at www.sec.gov, and on our website at www.transalta.com.

15	TransAlta Corporation
15	2011 Annual Report	Management’s Discussion and Analysis

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. 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, and geothermal. During 2011, we began commercial operations at our Keephills Unit 3 coal-fired plant and our Bone Creek hydro facility, which added 244 megawatts (“MW”) of power to our generation portfolio and increased our total generating capacity to 8,174 MW.

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 Western U.S., 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 annual rate of one to three per cent. During the recession in 2008 and 2009 demand decreased in the Pacific Northwest and Ontario an average of two and four per cent, respectively, and stayed flat in Alberta. Demand growth has returned, although at varying rates among Alberta, the Pacific Northwest, and Ontario.

After flat demand in Alberta from 2007 to 2009, 2010 and 2011 showed a return to about three per cent annual growth. In Alberta, investment in oil sands development is a key driver of electricity demand growth, and high oil prices are currently driving a major expansion of this resource. In the Pacific Northwest, demand recovered in 2011 by approximately three per cent after decreasing in 2010, although we believe approximately half of the growth in 2011 was due to unseasonable weather. Demand in Ontario increased in 2010 and 2011 at an average rate of around one per cent annually.

Supply

Reserve margins, which measure available capacity in a market over and above the capacity needed to meet normal peak demand levels, declined in Alberta, the Pacific Northwest, and Ontario in 2011.

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 Pacific Northwest currently has just over 5,000 MW of wind capacity after adding approximately 2,300 MW from 2009 to 2011 and Ontario has been developing wind and solar capacity through its Feed in Tariff program. Wind generation in Alberta has also grown significantly in the last few years.

Transmission

Transmission refers to the bulk delivery system of power and energy between generating units and wholesale and/or retail customers. Power lines serve as the physical path, transporting electricity from generating units to customers. Transmission systems are designed with reserve capacity to allow for an amount of “real-time” fluctuations in both energy supply and demand caused by generation plants or loads increasing or decreasing output or consumption.

Transmission capacity refers to the ability of the transmission line, or lines, to safely and reliably transport electricity in an amount that balances the dispatched generating supply with demand, and allows for contingency situations on the system. Most transmission businesses in North America are still regulated.

In the North American market, we believe investment in transmission capacity has not kept pace with the growth in demand for electricity. Lead times in new transmission infrastructure projects are significant, subject to extensive consultation processes with landowners, and subject to regulatory requirements that can change frequently. As a result, existing generation or additions of generating capacity may not have ready access to markets until key bulk transmission upgrades and additions are completed.

In 2009, the Government of Alberta declared several important transmission projects as being critical, including lines between the Edmonton and Calgary regions, and between Edmonton and northeast Alberta. In late 2011, the Government of Alberta initiated a review of critical transmission projects. The results of the review by an independent panel were released in early 2012 and the panel recommends proceeding as soon as possible with development of two high-voltage direct current transmission lines between the Edmonton and Calgary regions. The provincial government is reviewing the panel’s recommendation.

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Management’s Discussion and Analysis	2011 Annual Report	16

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 Greenhouse Gas (“GHG”) legislation in Alberta. Our exposure to increased costs as a result of environmental legislation in Alberta is mitigated through change-in-law provisions in our Power Purchase Arrangements (“PPAs”). In the State of Washington, the TransAlta Energy Bill was signed into law and provides a framework to transition from coal. Legislation in other jurisdictions is in various stages of maturity and sophistication.

While Carbon Capture and Storage (“CCS”) technologies are being developed, these technologies require large-scale demonstration. Project Pioneer, our CCS project, continues to progress with the financial support of industry partners and the Canadian and Alberta governments. This investment is intended to determine whether the cost of CCS can be reduced over the next 10 years in order to assess if CCS is viable from a business perspective.

Economic Environment

The economic environment showed signs of improvement in 2011 and we expect this trend to continue in 2012 at a slow to moderate pace. We continue to monitor global events, including conditions in Europe, and their potential impact on the economy and our supplier and commodity counterparty relationships.

Contracted Cash Flows

During the year, approximately 93 per cent of our consolidated power portfolio was contracted through the use of PPAs, long-term, and short-term contracts. We also enter into short-term physical and financial contracts for the remaining volumes, which are primarily for periods of up to five years, with the average price of these contracts in 2011 ranging from $65 to $70 per megawatt hour (“MWh”) in Alberta, and from U.S.$50 to $55 per MWh in the Pacific Northwest.

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, economic dispatching, and any contracting strategy. Our Alberta plants, operating under PPAs, receive contracted capacity payments based on targeted availability and will pay penalties or receive payments for production outside targeted availability based upon a rolling 30-day average of spot prices. The PPAs and long-term contracts covering a number of our generating facilities help 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.

For the year ended Dec. 31, 2011, average spot prices increased in Alberta due to load growth from the prior year and supply tightening in the market. In the Pacific Northwest and Ontario, average spot prices decreased compared to 2010 due to lower natural gas prices and increased hydro generation in both regions.

17	TransAlta Corporation
17	2011 Annual Report	Management’s Discussion and Analysis

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 plants due to their design, geographical region in which they operate, and customer and/or market requirements. The change in the prices of electricity and natural gas, and the resulting spark spreads in our three major markets, affect our Generation and Energy Trading Segments.

For the year ended Dec. 31, 2011, average spark spreads increased in Alberta due to higher power prices. In the Pacific Northwest, average spark spreads decreased due to strong hydro generation, which caused power prices to decrease more than natural gas prices compared to 2010. In Ontario, spark spreads decreased as power prices weakened more than natural gas prices.

Strategy

Our goals are to deliver shareholder value by delivering solid returns through a combination of dividend yield, and disciplined comparable Earnings Per Share (“EPS”) 2 and funds from operations 2 growth, while maintaining a low to moderate risk profile, balancing capital allocation, and maintaining financial strength. Our comparable EPS and funds from operations growth are driven by optimizing and diversifying our portfolio, growing our renewable portfolio across Canada, and further expanding our overall portfolio and operations in the western regions of Canada, the U.S., and Australia. 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 financial position and investment grade credit ratings to provide a solid foundation for our long-cycle, capital-intensive, and commodity-sensitive business. A strong financial position 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 Strategy

In 2011, we continued to see some demand growth and prices in our key markets improved from the lower prices experienced in 2010 primarily due to supply tightening in the market. While we are not immune to lower power prices, the impact of these lower prices is expected to be mitigated as approximately 86 per cent of 2012 and approximately 77 per cent of 2013 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 stable and predictable operations that are comparatively low cost and balanced with our fleet availability target. Our target for 2012 is to increase productivity and achieve overall fleet availability of 89 to 90 per cent. Over the last two years, our average adjusted availability has been 88.6 per cent, which is slightly below our corporate target.

2 Comparable EPS and funds from operations are not defined under IFRS. 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-IFRS Measures section of this MD&A for further discussion of these items, including reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

	TransAlta Corporation	18
Management’s Discussion and Analysis	2011 Annual Report	18

Growth Strategy

During 2011, commercial operations began at Keephills Unit 3, one of Canada’s largest and cleanest coal-fired facilities which we believe is one of the most advanced facilities of its kind in the world. Emissions per MW are lower than those from a conventional coal plant because less fuel is used to produce the same amount of power. This facility is an important step in ensuring future power needs are met with a reliable, cost-effective and environmentally responsible source of electricity.

Our growth strategy is also focused upon greening and diversifying our portfolio to reduce our carbon footprint and develop long-term, sustainable power generation in our core markets. We furthered this strategy in 2011 by completing our Bone Creek hydro facility on time and on budget and commencing construction of the 68 MW New Richmond wind farm. We continue to explore and selectively develop opportunities for future sustainable power projects.

Capability to Deliver Results

We have the following core competencies and non-capital resources that give us the capability to achieve our corporate objectives. Refer to the Liquidity and Capital Resources section of this MD&A for further discussion of the capital resources available that will assist us in achieving 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 Strategic Focus Areas in 2011

Improve base operations		Began commercial operations at Keephills Unit 3
		Implemented productivity and cost reductions that lowered operating expenses across the fleet
		Continued to align plans and capital spending for coal units based on the proposal to reduce GHG emissions by their 45th year of operation

Reposition coal		Continued active involvement in environmental policy discussions with various levels of government in Canada and the U.S.

Green and diversify our portfolio		Added 19 MW of hydro generation to our portfolio by completing construction of the Bone Creek hydro facility
		Continued our work on the construction of New Richmond, a 68 MW wind farm in Quebec

Financial Strength

We manage our financial position and cash flows to maintain financial strength and flexibility throughout all economic cycles. This financial discipline proved valuable during the weak economic environment of 2011 and will continue to be important during 2012. We continue to maintain $2.0 billion in committed credit facilities, and as of Dec. 31, 2011, $0.9 billion was available to us. Our investment grade credit rating, available credit facilities, funds from operations, and our limited debt maturity profile provide us with financial flexibility. As a result we can be selective as to 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 2011, we took advantage of favourable capital markets by completing the sale of $275 million of Series C Preferred Shares. Looking forward, we expect continued capital market support for projects that meet our return requirements and risk profile.

19	TransAlta Corporation
19	2011 Annual Report	Management’s Discussion and Analysis

Disciplined Capital Allocation

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

We continue to selectively grow our diversified generating fleet in order to increase production and meet future demand requirements, with growth projects that have the ability to meet or exceed our targeted rate of return. We currently have 68 MW of wind generation under construction and 61 MW of uprates to our thermal coal fleet planned for 2012. We also have more than 2,600 MW of advanced development wind, hydro, natural gas, and geothermal projects in our development pipeline.

People

Our experienced leadership team is made up 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 energy business, in our opinion, has resulted in a long-term proven track record of financial stability.

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

We strive to optimize the availability of our plants 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, as well as by 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 in order to balance our maintenance costs with optimal availability targets. Over the past two years, we have achieved an average adjusted availability of 88.6 per cent, which is slightly below our long-term target of 89 to 90 per cent. Our adjusted availability in 2011 was 88.2 per cent.

Availability for the year ended Dec. 31, 2011 decreased compared to 2010 primarily due to higher planned and unplanned outages at Centralia Thermal and higher unplanned outages at Genesee Unit 3, partially offset by lower planned and unplanned outages at the Alberta coal PPA facilities and lower planned outages at Genesee Unit 3.

The outages at Centralia Thermal did not negatively impact our gross margins for the year ended Dec. 31, 2011 as we were able to extend our planned outages to take advantage of lower market prices to purchase power on the market to fulfill our power contracts.

	TransAlta Corporation	20
Management’s Discussion and Analysis	2011 Annual Report	20

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, 2011, OM&A costs per installed MWh increased compared to 2010 due to higher compensation costs associated with favourable results in the Energy Trading Segment, the writeoff of certain wind development costs and costs associated with several productivity initiatives, partially offset by lower costs associated with the discontinuation of managing the base plant at Poplar Creek.

Sustaining Capital Expenditures

We are in a long-cycle capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensure our facilities operate reliably and safely over a long period of time. Our sustaining capital is comprised of three components: (1) routine and mine capital, (2) planned maintenance, and (3) productivity capital.

In 2011, we spent $6 million more on sustaining capital expenditures compared to 2010, which was made up of $33 million more on productivity capital, $17 million less on routine and mine capital, and $10 million less on planned maintenance. The decrease in routine and mine capital was due to lower information technology capital and non-turnaround maintenance costs as well as a decrease in mine capital due to lower land costs. Planned maintenance decreased primarily due to fewer major coal outages due to the shut down of Sundance Units 1 and 2, partially offset by higher gas plant outages. The increase in productivity expenditures was primarily due to instrument and controls projects at the Keephills and Sundance facilities, site improvements at our Sundance facility, and the implementation of new software programs.

Safety

Safety is our top priority with all of our staff, contractors, and visitors. Our objective is to improve safety by reducing our Injury Frequency Rate (“IFR”) to 0.5 by 2015. Our ultimate goal is to achieve zero injury incidents.

	2011	2010

IFR	0.89	1.19

In 2011, our IFR decreased due to fewer injuries at our Alberta coal facilities, primarily at our Keephills and Sundance facilities. These improvements are a result of continuous efforts to enhance our safety programs through near miss reporting, safety improvement, education, and awareness.

21	TransAlta Corporation
21	2011 Annual Report	Management’s Discussion and Analysis

Earnings and Funds from Operations

We focus our base business on delivering strong earnings and funds from operations growth. Our goal is to steadily grow comparable Earnings Before Interest, Taxes, Depreciation, and Amortization (“EBITDA”) 1, comparable EPS, and funds from operations, over the long term, recognizing that the amount of growth may fluctuate year over year with the commodity cycle.

	2011	2010

Comparable EBITDA	1,077	955
Comparable EPS	1.04	0.97
Funds from operations	809	805
Funds from operations per share 1	3.64	3.68

1 Comparable EBITDA and funds from operations per share are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

In 2011, comparable EPS and comparable EBITDA increased compared to 2010 primarily due to higher comparable earnings.

In 2011, funds from operations increased compared to 2010 due to higher net earnings.

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 financial position and cash flow coverage ratios to support stable investment grade credit ratings.

	2011	2010

Cash flow to interest coverage (times)	4.4	4.6
Cash flow to debt (%)	20.2	19.6
Debt to invested capital (%)	52.4	53.1

Cash flow to interest coverage decreased in 2011 compared to 2010 primarily due to lower capitalized interest. Our goal is to maintain this ratio in a range of four to five times.

Cash flow to debt improved in 2011 compared to 2010 due to lower average debt levels in 2011. Our goal is to maintain this ratio in a range of 20 to 25 per cent.

Debt to invested capital decreased as at Dec. 31, 2011 compared to 2010 due to lower debt levels and higher net earnings. Our goal is to maintain this ratio in a range of 55 to 60 per cent.

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 goal is to grow Total Shareholder Return (“TSR”) 2 by achieving a return of eight to 10 per cent per year over the long-term, with four to five per cent resulting from yield and four to five per cent resulting from growth.

The table below shows our historical performance on this measure:

	2011	2010

TSR (%)	4.9	(5.0	)

While 2011 was below our target of eight to 10 per cent, we continue to focus on delivering strong shareholder returns.

2 This measure is not defined under IFRS. We evaluate our performance and the performance of our business segments using a variety of measures. This measure is not necessarily comparable to a similarly titled measure of another company. TSR is the total amount returned to investors over a specific holding period and includes capital gains, capital losses, and dividends.

	TransAlta Corporation	22
Management’s Discussion and Analysis	2011 Annual Report	22

Results of Operations

Our results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading and Corporate. Some of our accounting policies require management to make estimates or assumptions that in some cases may relate to matters that are inherently uncertain. Some of our critical accounting policies and estimates include: revenue recognition, valuation and useful life of Property, Plant, and Equipment (“PP&E”), financial instruments, decommissioning and restoration provisions, 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 Statements of Financial Position. While individual line items on the Consolidated Statements of Financial Position will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items relating to foreign operations is reflected in the equity section of the Consolidated Statements of Financial Position.

Highlights and Summary of Results

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

Year ended Dec. 31	2011	2010	2009	1

Availability (%) 2	85.4	88.9	85.1

Production (GWh) 2	41,012	48,614	45,736

Revenues	2,663	2,673	2,770

Gross margin 3	1,716	1,488	1,542

Operating income 3	662	487	378

Net earnings attributable to common shareholders	290	255	181

Net earnings per share attributable to common shareholders, basic and diluted	1.31	1.16	0.90

Comparable earnings per share	1.04	0.97	0.90

Comparable EBITDA	1,077	955	888

Funds from operations	809	805	580

Funds from operations per share	3.64	3.68	2.89

Cash flow from operating activities	694	838	729

Free cash flow 3	181	172	(117	)

Dividends paid per common share	1.16	1.16	1.16

1 Canadian GAAP figures.

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

3 Gross margin, operating income and free cash flow are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

As at Dec. 31	2011	2010

Total assets	9,760	9,635

Total long-term liabilities	4,942	5,009

23	TransAlta Corporation
23	2011 Annual Report	Management’s Discussion and Analysis

Net Earnings Attributable to Common Shareholders

The primary factors contributing to the change in net earnings attributable to common shareholders for the year ended Dec. 31, 2011 are presented below:


Net earnings attributable to common shareholders for the year ended Dec. 31, 2010	255

Increase in Generation gross margins	54

Mark-to-market movements – Generation	78

Increase in Energy Trading gross margins	96

Increase in OM&A costs	(35	)

Increase in depreciation expense	(18	)

Increase in gain on sale of assets	16

Decrease in asset impairment charges	11

Increase in net interest expense	(37	)

Increase in equity earnings	7

Increase in income taxes expense	(82	)

Increase in net earnings attributable to non-controlling interests	(14	)

Increase in preferred share dividends	(14	)

Increase in reserve on collateral	(18	)

Other	(9	)

Net earnings attributable to common shareholders for the year ended Dec. 31, 2011	290

For the year ended Dec. 31, 2011, Generation gross margins, excluding the impact of mark-to-market movements, increased compared to 2010 primarily due to higher hydro margins, the commencement of commercial operations of Keephills Unit 3 in 2011, higher wind volumes, lower planned and unplanned outages at the Alberta coal PPA facilities, and lower planned outages at Genesee Unit 3, partially offset by lower recoveries from the Poplar Creek base plant that we no longer operate, the sale of the Meridian facility, unfavourable pricing related to penalties paid under Alberta PPAs during outages, the decommissioning of Wabamun, and higher unplanned outages at Genesee Unit 3. The lower recoveries at the Poplar Creek base plant were offset by lower OM&A costs.

Mark-to-market movements increased for the year ended Dec. 31, 2011 compared to 2010 due to the recognition of unrealized gains resulting from certain hedges being deemed ineffective for accounting purposes and increased weakening in market prices in the Pacific Northwest relative to our hedged prices.

For the year ended Dec. 31, 2011, Energy Trading gross margins increased compared to 2010 primarily due to strong trading results in the Western regions and increased earnings from the acquisition of electricity and natural gas contracts. These positive results were partially offset by lower gross margins in the Pacific Northwest region resulting from weak pricing.

OM&A costs increased for the year ended Dec. 31, 2011 compared to 2010 due to higher compensation costs primarily associated with favourable results in the Energy Trading Segment, the writeoff of certain wind development costs and costs associated with several productivity initiatives, partially offset by lower costs associated with the discontinuation of managing the base plant at Poplar Creek.

For the year ended Dec. 31, 2011, depreciation expense increased compared to 2010 primarily due to an increased asset base, the impact of the 2010 decrease in Wabamun decommissioning and restoration costs, and the writedown of capital spares, partially offset by changes to estimated residual values, the sale of the Meridian facility, and favourable foreign exchange rates.

Gain on sale of assets for the year ended Dec. 31, 2011 increased compared to 2010 due to the sale of the Meridian gas facility, the Grande Prairie biomass facility, and other development projects.

Asset impairment charges for the year ended Dec. 31, 2011 decreased compared to 2010 due to impairment charges related to Sundance Units 1 and 2 and the Meridian facility recorded in 2010. Refer to the Asset Impairment Charges section of this MD&A for further discussion.

For the year ended Dec. 31, 2011, net interest expense increased compared to 2010 due to lower capitalized interest, lower interest income related to the resolution of certain tax matters in 2010, and higher interest rates, partially offset by favourable foreign exchange rates and lower debt levels.

Equity earnings increased for the year ended Dec. 31, 2011 compared to 2010 primarily due to favourable market conditions, partially offset by unfavourable foreign exchange rates and higher planned and unplanned outages.

	TransAlta Corporation	24
Management’s Discussion and Analysis	2011 Annual Report	24

For the year ended Dec. 31, 2011, income tax expense increased compared to 2010 due to higher earnings and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.

Net earnings attributable to non-controlling interests increased for the year ended Dec. 31, 2011 compared to 2010 due to higher earnings at TransAlta Cogeneration, L.P. (“TA Cogen”).

The preferred share dividends for year ended Dec. 31, 2011 increased compared to 2010 due to a higher balance of preferred shares outstanding during 2011. Preferred shares were issued in the fourth quarter of 2010 and there was an additional issuance in the fourth quarter of 2011.

A reserve on collateral was taken in the fourth quarter of 2011 related to collateral on hand at MF Global Inc. In October of 2011, MF Global Holdings Ltd. filed for bankruptcy protection in the United States. MF Global Holdings Ltd. is the parent company of MF Global Inc., which we used as a broker-dealer for certain commodity transactions. A trustee has been appointed to take control of and liquidate the assets of MF Global Inc. and return client collateral. The reserve was recognized due to the uncertainty of collection of the collateral.

Significant Events

Our consolidated financial results include the following significant events:

2011

Sale of Preferred Shares

On Nov. 30, 2011, we completed our public offering of 11 million Series C 4.60 per cent Cumulative Redeemable Rate Reset First Preferred Shares, resulting in gross proceeds of $275 million. The net proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation and its affiliates.

Genesee Unit 3 Outage

On Nov. 11, 2011, the Genesee Unit 3 plant, a 466 MW joint venture with Capital Power Corporation (“Capital Power”) (233 MW net ownership interest), experienced an unplanned outage that resulted in damage to the turbine/generator bearings. Genesee Unit 3 returned to service on Jan. 15, 2012.

MF Global Inc.

In October of 2011, MF Global Holdings Ltd. filed for bankruptcy protection in the United States. MF Global Holdings Ltd. is the parent company of MF Global Inc., which we used as a broker-dealer for certain commodity transactions. MF Global Inc. has not filed for bankruptcy but, under the U.S. Securities Investor Protection Act, the Securities Investor Protection Corp. is overseeing a liquidation of the broker-dealer to return assets to customers. A trustee has been appointed to take control of and liquidate the assets of MF Global Inc. and return client collateral. A significant portion of our collateral relates to collateral on foreign futures transactions that would have been in accounts in the United Kingdom (“U.K.”) and is subject to a dispute between the U.S. trustee and the U.K. administrator. We have collateral of approximately $36 million with MF Global Inc. and due to the uncertainty of collection, we have recognized an $18 million reserve against the collateral that had been posted. The net amount of the collateral has been reclassified to a long-term asset.

Keephills Unit 3

On Sept. 1, 2011, our 450 MW Keephills Unit 3 thermal facility, of which we have a 50 per cent ownership interest, began commercial operations. The total cost of the project was approximately $1.98 billion.

Sale of Grande Prairie Facility

On July 27, 2011, we signed an agreement to sell our interest in the biomass facility located in Grande Prairie. This deal closed on Oct. 1, 2011. As a result, we realized a pre-tax gain of $9 million in the fourth quarter of 2011.

President and Chief Executive Officer

On July 27, 2011, we announced that TransAlta’s President and Chief Executive Officer Steve Snyder would retire, effective Jan. 1, 2012. Dawn Farrell, TransAlta’s Chief Operating Officer, succeeded Mr. Snyder as President and Chief Executive Officer on Jan. 2, 2012.

Sundance Unit 3 Outage

On June 7, 2010, we announced an outage at Unit 3 of our Sundance facility due to the mechanical failure of critical generator components. In response to this event, we gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the PPA. Since the event, we have recorded an after-tax charge of $16 million, or 50 per cent of the penalties, as calculated under the PPA, pending a resolution of this matter.

25	TransAlta Corporation
25	2011 Annual Report	Management’s Discussion and Analysis

On Oct. 20, 2010, the Balancing Pool confirmed our determination that the mechanical failure met the requirements of a HILP event under the PPA. On July 5, 2011, the Balancing Pool purported to rescind its earlier determination. Neither action is a conclusive finding of a force majeure event, nor does either provide a definitive resolution to the dispute. Management continues to be of the view that the event constitutes both a HILP and force majeure and that it will be resolved in TransAlta’s favour, although no assurance can be given as to the outcome of this matter. The arbitration hearing has been set for May 2012. In the event of an unfavourable resolution of this matter, we may be required to pay to the PPA Buyers the penalties as calculated under the PPA and record an additional $16 million charge to earnings. There is no additional impact to earnings at this time as the facility is operating at full capacity. The unit may be operated in that manner for as long as our monitoring indicates that it can be operated safely, subject to the terms of the agreement, market conditions, and other operating requirements. The previously announced major maintenance at this facility remains scheduled for the middle of 2012.

Bone Creek

On June 1, 2011, our 19 MW Bone Creek hydro facility began commercial operations. The total capital cost of the project was approximately $52 million.

Centralia Coal

In 2011, the TransAlta Energy Bill (the “Bill”) was signed into law in the State of Washington. The Bill, and a Memorandum of Agreement (the “MoA”) signed on Dec. 23, 2011, which is part of the Bill, provide a framework to transition from coal-fired energy produced at our Centralia Coal plant by 2025. The Bill and MoA include key elements regarding, among other things, the timing of the shut down of the units and the removal of restrictions on the terms of power contracts that we can enter into.

At Dec. 31, 2011, we completed an assessment of whether the carrying amount of the Centralia Coal plant was recoverable from the future cash flows expected to be derived from the plant’s operations. Based on this assessment, which included assumptions regarding our ability to enter into power contracts longer than five years as permitted in the Bill and MoA, we concluded that the plant was not impaired.

However, given the significance of the contracting assumptions, it is possible that actual outcomes could differ from these assumptions and that a material adjustment to the $786 million carrying amount of the plant could arise within the next fiscal year.

We have established a dedicated commercial team to pursue long-term contracts for the plant, and as a result, we expect to be able to more clearly determine the impact of this uncertainty on the future cash flows of the plant in 2012. If we achieve our long-term contracting targets for the plant in 2012, we do not expect that an impairment loss will result.

Sale of Meridian

On Dec. 20, 2010, TA Cogen, a subsidiary that is owned 50.01 per cent by TransAlta, entered into an agreement for the sale of its 50 per cent interest in the Meridian facility. On April 1, 2011, TA Cogen closed the sale of its interest in the Meridian facility. The sale was effective Jan. 1, 2011. As a result, we realized a pre-tax gain of $3 million during the second quarter of 2011.

New Richmond

On March 28, 2011, we announced that we had received approval from the Government of Quebec to proceed with the construction of the 68 MW New Richmond wind project located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution. The cost of the project is estimated to be approximately $205 million and commercial operations are expected to commence during the fourth quarter of 2012.

Sundance Units 1 and 2 Shut Down

In December 2010, Unit 1 and Unit 2 of our Sundance coal-fired generation facility were shut down due to conditions observed in the boilers at both units. As a result, all 560 MW from both units, with potential production of 4,906 gigawatt hours (“GWh”), was unavailable for the year ended Dec. 31, 2011.

We are pursuing all our remedies under the PPA resulting from these events. Firstly, under the terms of the PPA for these units, we notified the PPA Buyer and the Balancing Pool of a force majeure event. To the extent the event meets the force majeure criteria set out in the PPA, we believe we are entitled to receive our PPA capacity payments and are protected from having to pay penalties for the units’ lack of availability, and as a result, we do not expect any material adverse effect on our results or operations. Secondly, on Feb. 8, 2011, we issued a notice of termination for destruction on Sundance Units 1 and 2 under the terms of the PPA. This action was based on the determination that the physical state of the boilers was such that the units cannot be economically restored to service under the terms of the PPA. To the extent the event meets the termination for destruction criteria set out in the PPA, we believe we are entitled to recover the net book value specified in the PPA, and as a result, we do not expect any material financial impact.

	TransAlta Corporation	26
Management’s Discussion and Analysis	2011 Annual Report	26

On Feb. 18, 2011, the PPA Buyer provided notice that it intends to dispute the notice of force majeure and termination for destruction, and intends to pursue the dispute resolution process as set out under the terms of the PPA. The binding arbitration process to resolve the dispute is underway. The arbitration panel identified dates in March and April 2012 to hear these claims, and unless timelines are shortened by agreement of the parties, indicated that its decision would be forthcoming in mid-2012. No assurance can be given as to the timing or ultimate outcome of these matters.

Change in Estimated Residual Values

During the first quarter of 2011, management completed a comprehensive review of the residual values of all of our generating assets, having regard for, among other things, expectations about the future condition of the assets, metal volumes, as well as other market-related factors. As a result, estimated residual values were revised, resulting in depreciation decreasing by $13 million for the year ended Dec. 31, 2011 compared to 2010.

2010

Allocation of Consideration Transferred Adjustment

During the fourth quarter of 2010, management updated the preliminary allocation of consideration transferred related to our acquisition of Canadian Hydro Developers, Inc. (“Canadian Hydro”) to better reflect the value of the underlying assets and liabilities acquired. As a result, a $114 million adjustment was made to depreciable assets, producing a $4 million decrease in depreciation expense. The adjustment to depreciable assets was offset by adjustments to goodwill and deferred income taxes.

Resolution of Tax Matters

During 2010, we recognized and received a $30 million income tax recovery related to the resolution of certain outstanding tax matters. Interest expense also decreased by $14 million as a result of tax-related interest recoveries.

Sale of Preferred Shares

On Dec. 10, 2010, we completed our public offering of 12 million Series A 4.60 per cent Cumulative Redeemable Rate Reset First Preferred Shares, resulting in gross proceeds of $300 million. The net proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation and its affiliates.

Kent Hills 2

On Nov. 21, 2010, the 54 MW expansion of our Kent Hills wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was approximately $100 million. Natural Forces Technologies, Inc. (“Natural Forces”) exercised its option to purchase a 17 per cent interest in the Kent Hills 2 project subsequent to the commencement of commercial operations for proceeds of $15 million based on costs incurred in 2010. The pre-tax gain recorded related to this transaction did not have a significant impact on net earnings.

Ardenville

On Nov. 10, 2010, our 69 MW Ardenville wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was approximately $135 million.

Project Pioneer

On Nov. 28, 2010, we announced that the Global Carbon Capture and Storage Institute awarded the Corporation AUD$5 million to share knowledge around the world from Project Pioneer, Canada’s first fully integrated CCS project involving retrofitting a coal-fired generation plant. The funding will help Project Pioneer both contribute to and access international research and leading-edge knowledge from a global CCS forum.

On June 28, 2010, we announced that Enbridge Inc. will officially participate as a partner in the development of Project Pioneer.

Sundance Unit 3 Uprate

On Sept. 13, 2010, we obtained approval from the Board of Directors for a 15 MW efficiency uprate at Unit 3 of our Sundance facility. The total capital cost of the project is estimated to be $27 million with commercial operations expected to begin during the fourth quarter of 2012.

27	TransAlta Corporation
27	2011 Annual Report	Management’s Discussion and Analysis

Chief Financial Officer

On June 18, 2010, we announced that Brett Gellner was appointed Chief Financial Officer, succeeding Brian Burden, who retired from the Corporation. Mr. Burden assisted Mr. Gellner with the transition through Sept. 30, 2010.

Dividend Reinvestment and Share Purchase (“DRASP”)

On April 29, 2010, in accordance with the terms of the DRASP plan, the Board of Directors approved the issuance of shares from Treasury at a three per cent discount from the weighted average price of the shares traded on the Toronto Stock Exchange on the last five days preceding the dividend payment date. Under the terms of our DRASP plan, eligible participants are able to purchase additional common shares by reinvesting dividends or making an additional contribution of up to $5,000 per quarter. The Corporation reserves the right to alter the discount or return to purchasing the shares on the open market at any time.

Decommissioning of Wabamun Plant

On March 31, 2010, we fully retired all units of the Wabamun plant as part of our previously announced shut down. Over the next several years, we will complete the Wabamun plant remediation and reclamation work as approved by the Government of Alberta. Based on our review of our schedule and detailed costing of the decommissioning and reclamation activities, the decommissioning and reclamation obligation associated with the Wabamun plant was reduced by $14 million during the first quarter of 2010, with the offset recorded as a recovery in depreciation.

Senior Notes Offering

On March 12, 2010, we completed our offering of U.S.$300 million senior notes maturing in 2040 and bearing an interest rate of 6.50 per cent. The net proceeds from the offering were used to repay borrowings under existing credit facilities and for general corporate purposes.

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 approximately $118 million.

Change in Economic Useful Life

In 2010, management initiated a comprehensive review of the estimated useful lives of all generating facilities and coal mining assets, having regard for, among other things, our economic lifecycle maintenance program, the existing condition of the assets, progress on carbon capture and other technologies, as well as other market-related factors.

Management concluded its review of the coal fleet, as well as its mining assets, and updated the estimated useful lives of these assets to reflect their current expected economic lives. As a result, depreciation was reduced by $26 million for the year ended Dec. 31, 2010 compared to 2009.

Subsequent Events

Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan

On Feb. 21, 2012, we announced that we added a Premium DividendTM Component to our existing DRASP plan. The amended and restated plan is called the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan (“the Plan”). The Plan provides our eligible shareholders with two options, to reinvest dividends at a current three per cent discount towards the purchase of new shares of TransAlta or instead, to receive the equivalent to 102 per cent of the dividends payable in cash. The discount on reinvested dividends can be adjusted to between zero to five percent at the discretion of the Board of Directors.

Eligible shareholders are not required to participate in the Plan. Those shareholders who have not elected or been deemed to have elected to participate in the Plan will continue to receive their quarterly cash dividends in the usual manner. To participate in the Plan, eligible shareholders must be resident in Canada. Residents of the U.S., or an individual who is otherwise a “U.S. Person” under applicable U.S. securities laws, may not participate in the Plan. Shareholders who are resident in any jurisdiction outside of Canada (other than the U.S.) may participate in the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that we are satisfied, in our sole discretion, that such laws do not subject the Plan, TransAlta, the Plan Agent, or the Plan Broker to additional legal or regulatory requirements.

	TransAlta Corporation	28
Management’s Discussion and Analysis	2011 Annual Report	28

Discussion of Segmented Results

GENERATION: Owns and operates hydro, wind, natural gas- and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation revenues and overall profitability are derived from the availability and production of electricity and steam as well as ancillary services such as system support.

We have strategic alliances with Stanley Power Inc. (“Stanley Power”), Capital Power, ENMAX Corporation (“ENMAX”), MidAmerican Energy Holdings Company (“MidAmerican”), Nexen Inc. (“Nexen”), and Brookfield Asset Management Inc. (“Brookfield”). Stanley Power owns the minority interest in TA Cogen. The Capital Power alliance provided the opportunity for us to acquire 50 per cent ownership in the 466 MW Genesee 3 project, as well as to build the Keephills Unit 3 project. ENMAX and our Corporation each own 50 per cent of 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.

Due to our transition to IFRS, our interest in the Fort Saskatchewan generating facility is now accounted for as a finance lease and our interests in the CE Gen and Wailuku River Hydroelectric, L.P. (“Wailuku”) joint ventures are now accounted for using the equity method. Accordingly, the related operational and financial results of these facilities are no longer included in the results of our Western Canada and International geographical regions, respectively. Under Canadian GAAP, these assets were proportionately consolidated. Although these assets no longer contribute to the operating income of the Generation Segment for accounting purposes, it is management’s view that these facilities still form part of our Generation Segment. Refer to the Finance Lease and Equity Investments sections of the Generation Segment discussion of this MD&A for further details.

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.

Generation Operations

At Dec. 31, 2011, Generation Operations had 8,174 MW of gross generating capacity 1 in operation (7,831 MW net ownership interest) and 129 MW (net ownership interest) under construction. The following information excludes assets that are accounted for as a finance lease or using the equity method, which are discussed separately within the discussion of the Generation Segment. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary.

During 2011, we began commercial operations at our Keephills Unit 3 coal-fired plant and our Bone Creek hydro facility, which added 244 MW of power to our generation portfolio. Refer to the Significant Events section of this MD&A for further discussion.

The results of Generation Operations are as follows:

Year ended Dec. 31		2011					2010

		Comparable		Comparable		Per installed	Comparable		Per installed
	Total	adjustments	2	total	2	MWh	total	2	MWh
Revenues	2,526	(127	)	2,399		33.94	2,589		34.26
Fuel and purchased power	947	-		947		13.40	1,185		15.68
Gross margin	1,579	(127	)	1,452		20.54	1,404		18.58

Operations, maintenance, and administration	419	(6	)	413		5.84	424		5.61
Depreciation and amortization	460	(4	)	456		6.45	443		5.86
Taxes, other than income taxes	27	-		27		0.38	27		0.36
Intersegment cost allocation	8	-		8		0.11	5		0.07

Operating expenses	914	(10	)	904		12.78	899		11.90

Operating income	665	(117	)	548		7.76	505		6.68

Installed capacity (GWh)	70,681			70,681			75,559

Production (GWh)	38,911			38,911			46,416

Availability (%)	84.8			84.8			88.5

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

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

29	TransAlta Corporation
29	2011 Annual Report	Management’s Discussion and Analysis

Generation Production and Comparable Gross Margins 1

Generation’s production volumes, comparable revenues 1, fuel and purchased power costs, and comparable gross margins 1 based on geographical regions and fuel types are presented below.

Fuel &

Revenue

purchased

Gross

Fuel &

per

power per

margin per

Production

Installed

purchased

Gross

installed

Year ended Dec. 31, 2011

(GWh)

Revenue

power

margin

MWh

Coal

21,475

26,846

863

379

484

32.15

14.12

18.03

Gas

2,588

3,282

118

35.95

10.05

25.90

Renewables

3,237

11,645

220

209

18.89

0.94

17.95

Total Western Canada

27,300

41,773

1,201

423

778

28.75

10.13

18.62

Gas

3,578

6,570

410

219

191

62.40

33.33

29.07

Renewables

1,521

5,790

147

140

25.39

1.21

24.18

Total Eastern Canada

5,099

12,360

557

226

331

45.06

18.28

26.78

Coal

5,135

11,742

520

261

259

44.29

22.23

22.06

Gas

1,377

4,806

121

25.18

7.70

17.48

Total International

6,512

16,548

641

298

343

38.74

18.01

20.73

38,911

70,681

2,399

947

1,452

33.94

13.40

20.54

2 Amounts represent comparable figures.

										Fuel &
								Revenue		purchased	Gross
					Fuel &			per		power per	margin per
	Production	Installed			purchased	Gross		installed		installed	installed
Year ended Dec. 31, 2010	(GWh)	(GWh)	Revenue	3	power	margin	3	MWh	3	MWh	MWh	3

Coal	25,025	31,325	813		331	482		25.95		10.57	15.38
Gas	3,493	4,246	222		76	146		52.28		17.90	34.38
Renewables	2,506	11,120	142		10	132		12.77		0.90	11.87

Total Western Canada	31,024	46,691	1,177		417	760		25.21		8.93	16.28
Gas	3,816	6,570	435		243	192		66.21		36.99	29.22
Renewables	1,330	5,435	126		7	119		23.18		1.29	21.89

Total Eastern Canada	5,146	12,005	561		250	311		46.73		20.82	25.91
Coal	8,594	12,057	730		469	261		60.55		38.90	21.65
Gas	1,652	4,806	121		49	72		25.18		10.20	14.98

Total International	10,246	16,863	851		518	333		50.47		30.72	19.75

	46,416	75,559	2,589		1,185	1,404		34.26		15.68	18.58

3 Amounts represent comparable figures.

Western Canada

Our Western Canada assets consist of five coal plants, one natural gas-fired facility, 21 hydro facilities, and 11 wind farms, with a total gross generating capacity of 4,874 MW (4,678 MW net ownership interest). In 2011, we began commercial operations at Keephills Unit 3, a 450 MW (225 MW net ownership interest) coal-fired plant in Alberta, and Bone Creek, a 19 MW hydro facility in British Columbia. We are currently performing uprates of 23 MW each on Unit 1 and Unit 2 of our Keephills plant, and a 15 MW uprate on Unit 3 of our Sundance plant, which are scheduled to be completed by the third quarter, second quarter, and fourth quarter of 2012, respectively.

Our Sundance, Keephills Units 1 and 2, and Sheerness plants, and 14 hydro facilities with gross generating capacity of 4,103 MW (3,907 MW net ownership interest) operate under PPAs. 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.

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

	TransAlta Corporation	30
Management’s Discussion and Analysis	2011 Annual Report	30

Genesee Unit 3, Keephills Unit 3, a portion of Poplar Creek and Castle River, four hydro facilities, and 11 additional wind farms 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.

McBride Lake, three hydro facilities, and a significant portion of Poplar Creek and Castle River 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.

For the year ended Dec. 31, 2011, production decreased 3,724 GWh compared to 2010, primarily due to the shut down at Sundance Units 1 and 2, the sale of the Meridian facility, and the decommissioning of Wabamun, partially offset by the commencement of commercial operations of Keephills Unit 3, lower planned and unplanned outages at the Alberta coal PPA facilities, higher wind volumes, and higher hydro volumes.

Comparable gross margin for the year ended Dec. 31, 2011 increased $18 million ($0.04 per installed MWh) compared to 2010 primarily due to higher hydro margins and the commencement of commercial operations at Keephills Unit 3, partially offset by the discontinuation of managing the base plant at Poplar Creek. The lower recoveries at the Poplar Creek base plant were offset by lower OM&A costs.

Eastern Canada

Our Eastern Canada assets consist of four natural gas-fired facilities, five hydro facilities, and four wind farms, with a total gross generating capacity of 1,411 MW (1,264 MW net ownership interest). All of our assets 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, 2011, production decreased 47 GWh compared to 2010 due to higher outages and unfavourable market conditions at natural gas-fired facilities, partially offset by higher wind volumes.

Gross margin for the year ended Dec. 31, 2011 increased $20 million ($0.16 per installed MWh) compared to 2010 primarily due to higher wind volumes at a higher price per installed MWh.

International

Our international assets consist of natural gas, coal, and hydro assets in various locations in the United States with a generating capacity of 1,589 MW and natural gas- and diesel-fired assets in Australia with a generating capacity of 300 MW.

Our Centralia Thermal, Centralia Gas, and Skookumchuck 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, 2011, production decreased 3,734 GWh compared to 2010, primarily due to higher planned and unplanned outages and higher economic dispatching at Centralia Thermal. The outages at Centralia did not negatively impact our gross margins for the year ended Dec. 31, 2011 as we were able to extend our planned outages to take advantage of lower market prices to purchase power on the market to fulfill our power contracts.

For the year ended Dec. 31, 2011, comparable gross margin increased $10 million ($0.06 per installed MWh) compared to 2010 primarily due to favourable pricing primarily driven by lower purchased power prices.

During 2011, unrealized pre-tax gains of $127 million were recorded in earnings due to certain hedges being deemed ineffective for accounting purposes. These unrealized gains were calculated using current forward prices that will change between now and the time the underlying hedged transactions are expected to occur. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in the period that they settle, the majority of which will do so during 2012. While future reported earnings will be lower, the expected cash flows from these contracts will not change.

31	TransAlta Corporation
31	2011 Annual Report	Management’s Discussion and Analysis

Operations, Maintenance, and Administration Expense

For the year ended Dec. 31, 2011, OM&A costs decreased compared to 2010 due to lower costs associated with the discontinuation of managing the base plant at Poplar Creek, partially offset by the writeoff of certain wind development costs, costs associated with several productivity initiatives, and the commencement of commercial operations of Keephills Unit 3.

Planned Maintenance

The table below shows the amount of planned maintenance capitalized and expensed:

Year ended Dec. 31	2011	2010

Capitalized	184	194
Expensed	2	3

	186	197

GWh lost	2,872	2,739

For the year ended Dec. 31, 2011, total planned maintenance costs decreased $11 million compared to 2010 due to fewer major coal outages due to the shut down of Sundance Units 1 and 2, partially offset by higher gas plant outages. In 2011, production lost as a result of planned maintenance increased 133 GWh compared to 2010 primarily due to higher planned outages at natural gas-fired facilities.

Depreciation Expense

For the year ended Dec. 31, 2011, depreciation expense increased compared to 2010 due to an increased asset base, the impact of the 2010 decrease in Wabamun decommissioning and restoration costs, and the writedown of capital spares, partially offset by changes to estimated residual values, the sale of the Meridian facility, and favourable foreign exchange rates.

Asset Impairment Charges

During 2011, we recorded a pre-tax impairment charge of $17 million related to four Generation assets within the renewables fleet that were part of the acquisition of Canadian Hydro, in order to write the assets down to their estimated fair values less cost to sell. The fair value estimates are derived from the long-range forecasts for the assets and prices evidenced in the marketplace. Two of the assets were impaired due to operational factors that impacted their useful lives, resulting in an impairment charge of $5 million. The impairment charges on the other two assets, totalling $12 million, resulted from our annual comprehensive impairment assessment and reflect lower forecast pricing at these merchant facilities.

During 2010, we recorded a pre-tax impairment charge of $28 million ($21 million after deducting the amount that was attributed to the non-controlling interest) on certain Generation assets, consisting of a $7 million charge against the natural gas fleet and a $21 million charge against the coal fleet. The natural gas fleet impairment reflects the pending sale of our 50 per cent interest in the Meridian facility, which was attributed to the non-controlling interest. The coal fleet impairment relates to Units 1 and 2 at the Sundance facility and resulted from the shut down due to the physical state of the boilers such that the units cannot be economically restored to service under the terms of the PPA.

	TransAlta Corporation	32
Management’s Discussion and Analysis	2011 Annual Report	32

Finance Lease

Although we continue to operate the Fort Saskatchewan facility, our long-term contract was determined to be a finance lease under IFRS, as the principal risks and rewards of ownership have been transferred to the customer. As a result, the assets subject to the lease have been removed from PP&E and the amounts due under the lease have been recorded in the Consolidated Statements of Financial Position as a finance lease receivable. Under Canadian GAAP, we had proportionately consolidated our interest in the financial and operational results of the Fort Saskatchewan facility.

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

Year ended Dec. 31	2011	2010

Availability (%)	98.1	97.1
Production (GWh)	481	488

Availability for the year ended Dec. 31, 2011 was comparable to 2010.

For the year ended Dec. 31, 2011, production decreased by 7 GWh compared to 2010 primarily due to lower customer demand partially offset by lower planned outages.

Finance lease income for the year ended Dec. 31, 2011 was consistent with 2010 at $8 million.

Equity Investments

Under IFRS, interests in joint ventures that are jointly controlled entities, like our CE Gen and Wailuku joint ventures, can be recognized using either the proportionate consolidation or equity method. We adopted the equity method to account for these interests to align with the requirements of IFRS 11 Joint Arrangements (“IFRS 11”), which was issued by the International Accounting Standards Board in May 2011. Under Canadian GAAP, we had proportionately consolidated our interests in the financial and operational results of CE Gen and Wailuku.

This change resulted in the reclassification of our share of assets and liabilities from each respective line item on our Consolidated Statements of Financial Position to a single line item entitled “Investments”. Our proportionate share of revenue and expenses was also reclassified from each respective line item and presented as a single amount entitled “Equity income” on the Consolidated Statements of Earnings.

Our investments accounted for under the equity method are comprised of geothermal, natural gas, and hydro facilities in various locations throughout the U.S., with 839 MW of gross generating capacity (390 MW net ownership interest). The table below summarizes key operational information from our investments accounted for under the equity method:

Year ended Dec. 31	2011	2010

Availability (%)	94.9	95.5

Production (GWh)
Gas	308	411
Renewables	1,312	1,299

Total production	1,620	1,710

Availability for the year ended Dec. 31, 2011 decreased compared to 2010 due to higher planned and unplanned outages at our CE Gen facilities.

Production for the year ended Dec. 31, 2011 decreased compared to 2010 due to unfavourable market conditions and higher planned and unplanned outages.

Equity earnings from CE Gen and Wailuku for the year ended Dec. 31, 2011 were $14 million as compared to income of $7 million for 2010. The equity earnings increased primarily due to favourable market conditions, partially offset by unfavourable foreign exchange rates and higher planned and unplanned outages.

33	TransAlta Corporation
33	2011 Annual Report	Management’s Discussion and Analysis

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

Energy Trading manages available generating capacity, as well as the fuel and transmission needs, of the Generation Segment by utilizing contracts of various durations for the forward purchase and sale of electricity and for the purchase and sale of natural gas and transmission capacity. Energy Trading is also responsible for recommending portfolio optimization decisions. The results 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 IFRS. 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 Energy Trading is allocated to the Generation Segment based on an estimate of operating expenses and a percentage of resources dedicated to providing support and analysis. This fixed fee intersegment allocation is represented as a cost recovery in Energy Trading and an operating expense within Generation.

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

Year ended Dec. 31	2011		2010

Revenues	137		41
Fuel and purchased power	-		-

Gross margin	137		41

Operations, maintenance, and administration	43		17
Depreciation and amortization	1		2
Intersegment cost allocation	(8	)	(5	)

Operating expenses	36		14

Operating income	101		27

For the year ended Dec. 31, 2011, OM&A costs increased compared to 2010 as a result of higher compensation costs associated with favourable results and costs associated with several productivity initiatives.

	TransAlta Corporation	34
Management’s Discussion and Analysis	2011 Annual Report	34

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

The expenses incurred by the Corporate Segment are as follows:

Year ended Dec. 31	2011	2010

Operations, maintenance, and administration	83	69
Depreciation and amortization	21	19

Operating expenses	104	88

OM&A costs increased for the year ended Dec. 31, 2011 compared to 2010 due to costs associated with several productivity initiatives and higher compensation costs.

Net Interest Expense

Under IFRS, where discounting is used, the increase in the carrying amount of a provision, such as for decommissioning and restoration activities, associated with the passage of time is recognized as a finance cost and included in net interest expense. Under Canadian GAAP, this was recognized as part of depreciation and amortization expense or fuel and purchased power.

The components of net interest expense are shown below:

Year ended Dec. 31	2011		2010

Interest on debt	228		226
Interest income	-		(18	)
Capitalized interest	(31	)	(48	)
Ineffectiveness on fair value hedges	(1	)	-

Interest expense	196		160
Accretion of provisions	19		18

Net interest expense	215		178

Net interest expense for the year ended Dec. 31, 2011 increased compared to 2010 due to lower capitalized interest, lower interest income related to the resolution of certain tax matters in 2010, and higher interest rates, partially offset by favourable foreign exchange rates and lower debt levels.

Non-Controlling Interests

We own 50.01 per cent of TA Cogen, which owns, operates, or has an interest in four natural gas-fired and one coal-fired generating facility with a total gross generating capacity of 704 MW. Stanley Power owns the minority interest in TA Cogen. Natural Forces owns a 17 per cent interest in our Kent Hills facility, which operates 150 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.

Non-controlling interests on the Consolidated Statements of Earnings and Consolidated Statements of Financial Position relate to the earnings and net assets attributable to TA Cogen and Kent Hills that we do not own. On the Consolidated Statements of Cash Flows, cash paid to the minority shareholders of TA Cogen and Kent Hills is shown in the financing section as distributions paid to subsidiaries’ non-controlling interests.

The earnings attributable to non-controlling interests for the year ended Dec. 31, 2011 increased compared to 2010 due to higher earnings at TA Cogen.

35	TransAlta Corporation
35	2011 Annual Report	Management’s Discussion and Analysis

Income Taxes

Our income tax rates and tax expense are based on the earnings generated in each jurisdiction in which we operate and any permanent differences between how pre-tax income is calculated for accounting and tax purposes. If there is a timing difference between when an expense or revenue item is recognized for accounting and tax purposes, these differences result in deferred income tax assets or liabilities and are measured using the income tax rate expected to be in effect when these temporary differences reverse. The impact of any changes in future income tax rates on deferred income tax assets or liabilities is recognized in earnings in the period the new rates are substantively enacted.

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

Year ended Dec. 31	2011		2010

Earnings before income taxes	449		304
Income attributable to non-controlling interests	(38	)	(24	)
Equity income	(14	)	(7	)
Impacts associated with certain de-designated and ineffective hedges	(127	)	(43	)
Asset impairment charges	17		28
Gain on sale of facilities and development projects	(16	)	-
Reserve on collateral	18		-
Other non-comparable items	10		-

Earnings attributable to TransAlta shareholders excluding non-comparable items subject to tax	299		258

Income tax expense	106		24
Income tax expense related to impacts associated with certain de-designated and ineffective hedges	(46	)	(15	)
Income tax recovery related to asset impairment charges	4		12
Income tax recovery related to the resolution of certain outstanding tax matters	-		30
Income tax expense related to gain on sale of facilities and development projects	(4	)	-
Income tax recovery related to reserve on collateral	5		-
Reclassification of Part VI. 1 tax	(2	)	-
Income tax recovery related to other non-comparable items	3		-

Income tax expense excluding non-comparable items	66		51

Effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items (%)	22		20

For the year ended Dec. 31, 2011, income tax expense excluding non-comparable items increased compared to 2010 due to higher comparable earnings and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.

For the year ended Dec. 31, 2011, the effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items increased compared to 2010 due to the effect of certain deductions that do not fluctuate with earnings and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.

	TransAlta Corporation	36
Management’s Discussion and Analysis	2011 Annual Report	36

Financial Position

The following chart outlines significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2010 to Dec. 31, 2011:

	Increase/
	(decrease)		Primary factors explaining change

Cash and cash equivalents	14		Increase in net earnings
Accounts receivable	129		Timing of customer receipts and higher revenues
Collateral paid	18		Increased collateral requirements associated with changes in forward prices
Income taxes receivable	(16	)	Resolution of certain tax matters
Inventory	32		Lower production at our coal facilities and higher average coal costs
Assets held for sale	(60	)	Completion of sale of the Meridian facility
Long-term receivable	18		Collateral on hand at MF Global Inc., net of reserve recognized
Risk management assets (current and long-term)	17		Price movements and changes in underlying positions
Other assets	(12	)	Transfer of project to property, plant, and equipment and writeoff of development costs
Accounts payable and accrued liabilities	(19	)	Timing of payments and lower capital accruals
Collateral received	(110	)	Reduction in collateral received from counterparties associated with changes in forward prices
Income tax payable	14		Increase in net earnings
Dividends payable	(63	)	Timing of common share dividend declarations
Long-term debt (including current portion)	(23	)	Repayment of medium term note, offset by unfavourable foreign exchange movements and increased borrowings under credit facilities
Decommissioning and other provisions (current and long-term)	72		Increase in decommissioning and commercial provisions
Deferred credits and other long-term liabilities	36		Increase in defined benefit accrual
Deferred income tax liabilities	(47	)	Increase in tax loss carry-forward balances
Risk management liabilities (current and long-term)	192		Price movements and changes in underlying positions
Equity attributable to shareholders	149		Increase in net earnings and issuance of preferred and common shares, offset by movements in accumulated other comprehensive (loss) income
Non-controlling interests	(73	)	Distributions paid, partially offset by non-controlling interests' portion of net earnings

Financial Instruments

Financial instruments are used to manage our exposure to interest rates, commodity prices, currency fluctuations, as well as 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 generally not affect earnings until the financial instrument is settled.

We have two types of financial instruments: (1) those that are used in the Energy Trading 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 foreign operations.

A portion of our financial instruments and physical commodity contracts are recorded under own use accounting or qualify for, and are recorded under, hedge accounting rules. The accounting for those contracts for which we have elected to apply hedge accounting depends on the type of hedge, and is outlined in further detail below.

For all types of hedges, 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. All financial instruments are designed to ensure that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value of the hedging derivative does not impact net earnings, while any ineffective portion is recognized in net earnings.

37	TransAlta Corporation
37	2011 Annual Report	Management’s Discussion and Analysis

As well, there are certain contracts in our portfolio that at their inception do not qualify for, or we have chosen not to elect to apply, 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.

The fair value of derivatives traded by the Corporation that are not traded on an active exchange, or extend beyond the time period for which exchange-based quotes are available, are determined using valuation techniques or models.

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 changes in the fair value of fixed rate long-term debt caused by variations in market interest rates. We use interest rate swaps in our fair value hedges.

All gains or losses related to interest rate swaps used in fair value hedges are recorded on the Consolidated Statements of Earnings. These gains or losses are, in turn, offset by the gains or losses related to the change in fair value of the debt due to the hedged risk. Any resulting net gain or loss is related to ineffectiveness in the fair value hedge relationship.

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

		Consolidated	Consolidated
	Consolidated	Statements of	Statements of	Consolidated
	Statements of	Comprehensive	Financial	Statements of
Event	Earnings	Income	Position	Cash Flows

Enter into contract 1	-	-	-	-
Reporting date (marked-to-market)	ü	-	ü	-
Settle contract	ü	-	ü	ü

1 Some contracts may require an upfront cash investment.

Cash Flow Hedges

Cash flow hedges are categorized as project, foreign exchange, interest rate or commodity hedges and are used to offset foreign exchange, interest rate, and commodity price exposures resulting from market fluctuations.

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 Other Comprehensive Income (“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
	Consolidated	Statements of	Statements of	Consolidated
	Statements of	Comprehensive	Financial	Statements of
Event	Earnings	Income	Position	Cash Flows

Enter into contract 2	-	-	-	-
Reporting date (marked-to-market) 3	-	ü	ü	-
Roll-over into new contract	-	ü	ü	ü
Settle contract	-	ü	ü	ü

2 Some contracts may require an upfront cash investment.

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

	TransAlta Corporation	38
Management’s Discussion and Analysis	2011 Annual Report	38

Foreign Exchange, Interest Rate, and Commodity Hedges

Physical and financial swaps, forward sale and purchase contracts, futures contracts, and options are used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Foreign exchange forward contracts and cross-currency swaps are used to offset the exposures resulting from foreign denominated long-term debt. Forward start interest rate swaps are used to offset the variability in cash flows resulting from anticipated issuances of long-term debt. When these instruments 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. The amounts previously recognized in OCI are reclassified to net earnings upon settlement of the financial instruments, or periodically, when the hedged forecast cash flows affect net earnings.

A summary of how typical foreign exchange, interest rate, and commodity hedges are recorded in our financial statements is as follows:

		Consolidated	Consolidated
	Consolidated	Statements of	Statements of	Consolidated
	Statements of	Comprehensive	Financial	Statements of
Event	Earnings	Income	Position	Cash Flows

Enter into contract 1	-	-	-	-
Reporting date (marked-to-market) 2	-	ü	ü	-
Settle contract	ü	ü	ü	ü

1 Some 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 used in cash flow hedges to a net liability is primarily a result of changes in future prices on contracts in our Generation Segment and the impact of discontinued hedge accounting for certain contracts.

The fair value of the majority of our project, foreign exchange, interest rate, and commodity hedges are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. 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 IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, and fair value is therefore 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 reasonable possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements. At Dec. 31, 2011, Level III instruments had a net liability carrying value of $14 million. Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2010.

When we do not elect hedge accounting, or when the hedge is no longer effective and does not qualify for hedge accounting, the gains or losses as a result of changes in prices, interest or exchange rates related to these financial instruments are recorded through the Consolidated Statements of Earnings in the period in which they arise.

Net Investment Hedges

Foreign currency forward contracts and foreign denominated long-term debt are used to hedge exposure to changes in the carrying values of our net investments in foreign operations having a functional currency other than the Canadian dollar. We attempt to manage our foreign exchange exposure by matching foreign denominated expenses with revenues, such as offsetting revenues from our U.S. operations with interest payments on our U.S. dollar debt.

Foreign exchange gains or losses related to net investment hedges are recorded in OCI until there is a permanent reduction in the net investment of the foreign operation. If there is a permanent reduction in the net investment of the foreign operation, the foreign exchange gains or losses previously recorded in OCI are transferred to net earnings in that period.

39	TransAlta Corporation
39	2011 Annual Report	Management’s Discussion and Analysis

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

		Consolidated	Consolidated
	Consolidated	Statements of	Statements of	Consolidated
	Statements of	Comprehensive	Financial	Statements of
Event	Earnings	Income	Position	Cash Flows

Enter into contract 1	-	-	-	-
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	-

1 Some contracts may require an upfront cash investment.

Non-Hedges

Financial instruments not designated as hedges are used to reduce commodity price, foreign exchange, and interest rate risks. All gains or losses related to non-hedges are recorded in the Consolidated Statements of Earnings as they either do not qualify for, or have not been designated for, hedge accounting.

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

		Consolidated	Consolidated
	Consolidated	Statements of	Statements of	Consolidated
	Statements of	Comprehensive	Financial	Statements of
Event	Earnings	Income	Position	Cash Flows

Enter into contract 2	-	-	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

2 Some contracts may require an upfront cash investment.

Employee Share Ownership

We employ a variety of stock-based compensation plans to align employee and corporate objectives.

Under the terms of our Stock Option Plans, employees below manager level receive grants that vest in equal instalments over four years and expire after 10 years.

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, including the value of reinvested dividends over the period, 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 awarded, 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 for employees below vice-president level, and for two additional years for employees at the vice-president level and above. The effect of the PSOP does not materially affect the calculation of the total weighted average number of common shares outstanding.

Under the terms of the Employee Share Purchase Plan, we extend an interest-free loan to our employees below executive level for up to 30 per cent of the employee’s base salary for the purchase of our common shares from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2011, accounts receivable from employees under the plan totalled $1 million (2010 - $2 million). This program is not available to officers and senior management.

	TransAlta Corporation	40
Management’s Discussion and Analysis	2011 Annual Report	40

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, and in Canada there is an additional 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 for accounting purposes of the registered and supplemental pension plans were as at Dec. 31, 2011.

We provide other health and dental benefits to the age of 65 for both disabled members and retired members (other post-employment benefits). The last actuarial valuation of these plans was conducted at Dec. 31, 2011.

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 $63 million to secure the obligations under the supplemental plan.

Statements of Cash Flows

Our transition to IFRS changed the presentation of several items on the Consolidated Statements of Cash Flows. The most significant of these items is the effect of using the equity method instead of the proportionate consolidation method to account for our interests in CE Gen and Wailuku. Our share of CE Gen’s and Wailuku’s cash and cash equivalents and cash flow changes are no longer presented within each line item of the operating, investing, or financing activities sections of the Consolidated Statements of Cash Flows, and instead, cash distributions received are presented as an operating activity and cash returns of invested capital or additional cash invested are presented as an investing activity. The capitalization of costs associated with planned major maintenance and inspection activities that were previously expensed under Canadian GAAP will result in these cash expenditures being reported as an investing activity under IFRS. Under Canadian GAAP these expenditures impacted cash flow from operations.

The following charts highlight significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2011:

Year ended Dec. 31	2011		2010		Explanation of change

Cash and cash equivalents, beginning of year	35		53
Provided by (used in):
Operating activities	694		838		Unfavourable changes in working capital balances of $148 million primarily due to the timing of payments and receipts offset by higher cash earnings of $4 million
Investing activities	(615	)	(765	)	Decrease in additions to PP&E of $355 million and proceeds on the sale of facilities and development projects of $40 million, offset by a $156 million decrease in collateral received from counterparties, an increase of $54 million in collateral paid to counterparties, a decrease of $15 million in proceeds on the sale of the minority interest in Kent Hills, and a decrease of $26 million due to the resolution of certain tax matters in 2010
Financing activities	(67	)	(90	)	Lower net debt repayments, decrease in cash dividends paid on common shares of $25 million, offset by a decrease in proceeds on issuance of preferred shares of $24 million and an increase in dividends paid on preferred shares of $15 million
Translation of foreign currency cash	2		(1	)

Cash and cash equivalents, end of year	49		35

41	TransAlta Corporation
41	2011 Annual Report	Management’s Discussion and Analysis

Liquidity and Capital Resources

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

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

Debt

Long-term debt totalled $4.0 billion at Dec. 31, 2011 compared to $4.1 billion at Dec. 31, 2010. Total long-term debt decreased from Dec. 31, 2010 primarily due to the maturity of a medium term note.

Credit Facilities

At Dec. 31, 2011, we had a total of $2.0 billion (2010 - $2.0 billion) of committed credit facilities of which $0.9 billion (2010 - $1.1 billion) is not drawn and is available, subject to customary borrowing conditions. At Dec. 31, 2011, the $1.1 billion (2010 - $0.9 billion) of credit utilized under these facilities was comprised of actual drawings of $0.8 billion (2010 - $0.6 billion) and of letters of credit of $0.3 billion (2010 - $0.3 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility, that matures in 2015, with the remainder comprised of bilateral credit facilities that mature between the third and fourth quarter of 2013. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

In addition to the $0.9 billion available under the credit facilities, we also have $49 million of cash.

Share Capital

At Dec. 31, 2011, we had 223.6 million (2010 - 220.3 million) common shares issued and outstanding. During the year ended Dec. 31, 2011, 3.3 million (2010 - 1.9 million) common shares were issued for $69 million (2010 - $40 million), of which $67 million (2010 - $35 million) was issued under the terms of the DRASP plan.

At Dec. 31, 2011, we had 23.0 million (2010 - 12.0 million) preferred shares issued and outstanding. During the year ended Dec. 31, 2011, 11.0 million (2010 - 12.0 million) Series C Preferred Shares were issued for $269 million, net of after-tax issuance costs of $6 million (2010 - $293 million, net of after-tax issuance costs of $7 million).

On March 1, 2012, we had 224.7 million common shares and 12.0 million Series A and 11.0 million Series C first preferred shares outstanding.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, energy trading activities, hedging activities, and purchase obligations. At Dec. 31, 2011, we provided letters of credit totalling $328 million (2010 - $297 million) and cash collateral of $45 million (2010 - $27 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Working Capital

At Dec. 31, 2011, the excess of current liabilities over current assets is $67 million (2010 - $190 million). The excess of current liabilities over current assets decreased $123 million compared to 2010 due to an increase in accounts receivable, an increase in net risk management assets, favourable inventory movements, and a decrease in net collateral paid by counterparties, partially offset by an increase in net risk management liabilities and an increase in the current portion of long-term debt.

Capital Structure

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

As at Dec. 31	2011		2010

	Amount	%	Amount	%

Debt, net of cash and cash equivalents	3,988	52	4,025	53
Non-controlling interests	358	5	431	6
Equity attributable to shareholders	3,269	43	3,120	41

Total capital	7,615	100	7,576	100

	TransAlta Corporation	42
Management’s Discussion and Analysis	2011 Annual Report	42

Commitments

Contractual repayments of 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 gas
	purchase and			Coal supply	Long-term			Interest on		Growth
	transportation		Operating	and mining	service	Long-term		long-term		project
	contracts	Transmission	leases	agreements	agreements	debt	1	debt	2	commitments	Total

2012	78	6	16	54	18	316		205		220	913
2013	45	8	11	54	17	622		191		-	948
2014	43	8	11	54	17	209		164		-	506
2015	22	8	11	54	17	1,167		125		-	1,404
2016	20	8	10	59	9	29		111		-	246
2017 and thereafter	484	5	42	291	3	1,680		843		-	3,348

Total	692	43	101	566	81	4,023		1,639		220	7,365

1 Repayments of long-term debt include amounts related to our credit facilities that are currently scheduled to mature between the fourth quarter of 2012 and the third quarter of 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.

As part of the Bill and MoA signed into law in the State of Washington, we have committed to fund $55 million over the life of the Centralia coal plant to support economic development, promote energy efficiency, and develop energy technologies related to the improvement of the environment. In the event that legislation changes, this payment will no longer be required.

Unconsolidated Structured Entities or Arrangements

Disclosure is required of all unconsolidated structured entities or 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 unconsolidated structured entities or arrangements.

Climate Change and the Environment

All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business strategy that includes investing in low-impact renewable energy resources such as wind, hydro, and geothermal, we also believe that coal and natural gas as fuels will continue to play an important role in meeting future energy needs. Regardless of the fuel type, we place significant importance on environmental compliance and continued environmental impact mitigation, while seeking to deliver low cost electricity.

Ongoing and Recently Passed Environmental Legislation

Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business.

Alberta

In Alberta there are requirements for coal-fired generation units to implement additional air emission controls for NOx, sulphur dioxide (“SO2”), and particulate matter once they reach the end of their PPAs, in most cases at 2020. These regulatory requirements were developed by the Province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”). However, as new GHG regulations for coal-fired power are developed there is a risk that the CASA air pollutant requirements and schedules become misaligned with GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO2, and particulates. We are in discussions with both the federal and provincial governments to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most economically effective manner while maintaining the reliability of Alberta’s generation supply.

Canada

On Aug. 27, 2011, the Government of Canada published in the Canada Gazette draft regulations entitled “Reduction of CO2 Emissions from Coal-Fired Generation of Electricity”. These regulations propose a 45-year end-of-life for coal-fired power units, at which point the units would have to meet a GHG emissions performance standard similar to natural gas-fired levels, or close. Should they be passed, the regulations would become effective on July 1, 2015. Under federal consultation provisions, industry, provinces, and other stakeholders have 60 days to provide comments on the regulations and subsequently the federal government will consider this input in the development of the second draft.

We are currently in discussions with both the governments of Canada and Alberta about modifications to the regulations that would result in significant GHG emission reductions in the most economically efficient manner, and would also provide alignment with other current and future regulations on air pollutants and on natural gas generation. These discussions are expected to continue through early 2012.

United States

In the U.S., the Environmental Protection Agency (“EPA”) announced on Sept. 14, 2011, that it was further delaying the release of draft GHG regulations for new and modified coal-fired power plants beyond its Sept. 30, 2011 target date. Draft regulations are now expected at the end of January 2012. There are no announced plans for new GHG regulations for existing power plants such as our Centralia plant.

43	TransAlta Corporation
43	2011 Annual Report	Management’s Discussion and Analysis

In December 2011, the EPA issued national standards for mercury pollution from power plants. Existing sources will have up to four years to comply. We are already proceeding with the installation of voluntary mercury capture technology at the Centralia coal-fired plant, to be operational by the end of 2012. That plant is also planning for the installation of additional capture technology to further reduce oxides of nitrogen (“NOx”), consistent with the Washington State Bill passed in April 2011 requiring TransAlta to begin operating such technology by Jan. 1, 2013.

In addition to the Federal, Regional and State regulations that we must comply with, we also comply with the standards established by the North American Reliability Corporation (“NERC”). NERC is the electric reliability organization certified by the Federal Energy Regulatory Commission in the U.S. to establish and enforce reliability standards for the bulk-power system. NERC develops and enforces reliability standards; assesses adequacy annually; monitors the bulk-power system; and educates, trains and certifies industry personnel.

Recent changes to environmental regulations may materially adversely affect us. As indicated under “Risk Factors” in our Annual Information Form and within the Risk Management section of this MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities under these requirements, which may have a material adverse effect upon our consolidated financial results.

TransAlta Activities

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 Board of Directors provides oversight to our environmental management programs and emission reduction initiatives in order to ensure continued compliance with environmental regulations.

In 2011, we estimate that 36 million tonnes of GHGs with an intensity of 0.923 tonnes per MWh (2010 - 37 million tonnes of GHGs with an intensity of 0.976 tonnes per MWh) were emitted as a result of normal operating activities.1

Our environmental management programs encompass the following elements:

Renewable Power

We continue to invest in and build renewable power resources. Our Bone Creek hydro facility became operational in 2011 and our 68 MW New Richmond wind facility is currently under construction and slated for completion during the fourth quarter of 2012. A larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or through 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 have installed 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 Unit 3 plant began operation in September 2011 using supercritical combustion technology to maximize thermal efficiency, as well as SO2 capture and low NOx combustion technology, which is consistent with the technology that is currently in use at Genesee Unit 3. Uprate projects at our Keephills and Sundance plants were undertaken in 2011 and scheduled for completion in 2012, which will improve the energy and emissions efficiency of those units.

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 discussions have allowed us to engage in proactive discussions with governments and industry participants to meet environmental requirements over the longer term.

CCS Development

In October 2009, the governments of Canada and Alberta announced that Project Pioneer, our CCS project, had received funding commitments of more than $770 million. Since then, TransAlta has advanced engineering work on the capture, pipeline, and storage components of the project and is assessing if CCS costs and other commercial terms and risks are appropriate to ensure CCS is viable from a business perspective. If built, the prototype plant will be one of the largest integrated CCS power facilities in the world, designed to capture one megatonne of carbon dioxide (“CO2”) per year from the new 450 MW Keephills Unit 3 coal-fired plant. The CO2 will be used for enhanced oil recovery as well as injected into a permanent geological storage site.

1 2011 data are estimates based on best available data at the time of report production. GHGs include water vapour, CO , methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO emissions from stationary combustion.

	TransAlta Corporation	44
Management’s Discussion and Analysis	2011 Annual Report	44

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 offsets 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.

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, and other factors deemed appropriate in the circumstances. Forward looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from that projected.

In particular, this MD&A contains forward looking statements pertaining to the following: expectations relating to the timing of the completion and commissioning of projects under development, including uprates, and their attendant costs; expectations related to future earnings and cash flow from operating activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; our estimated spend on growth and sustaining capital projects; 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; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation and their expected impact on us, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; expectations for the outcome of existing or potential legal and contractual claims; expectations for the ability to access capital markets at reasonable terms; the impact of certain hedges on future reported earnings; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. dollar; and the monitoring of our exposure to liquidity risk.

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

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

45	TransAlta Corporation
45	2011 Annual Report	Management’s Discussion and Analysis

2012 Outlook

Business Environment

Demand

Alberta electricity demand is expected to grow at an average rate of approximately three per cent annually over the next few years. Electricity demand in the Pacific Northwest is expected to increase approximately two per cent per year over the next three years due to expectations of a modest pace of economic recovery. However, the region’s long-term growth rate is expected to be at the lower end of historical trends as there is a large emphasis on energy efficiency across the region. Demand in Ontario is expected to continue to grow at about one per cent annually.

Supply

New supply in the near term and intermediate term is expected to come primarily from investment in renewable energy and natural gas-fired generation. This expectation is driven by the price reduction that has occurred in the North American natural gas market, combined with a continued expectation that GHG legislation of some form will be enacted in Canada and the U.S.

Alberta will likely see a decreasing reserve margin over the next several years until new supply is expected to come online around 2015. The Ontario reserve margin is expected to increase notably in 2012 through 2014 as nuclear capacity is refurbished and other new capacity comes online. The Pacific Northwest is also expected to see decreasing reserve margins in the near term, although the market is expected to remain well supplied.

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. Wind generation is also growing in Alberta, as 119 MW are currently under construction and over 1,200 MW, has received regulatory approval, although not all announced generation is expected to be built prior to transmission expansions are in place.

While there are many new developments that will likely impact the future supply of electricity, the comparatively low cost of our base load operations means that we expect our plants will continue to be supported in the market.

Transmission

Historically, transmission systems have been designed to serve loads in only their local area, and interties between jurisdictions that were built for reliability served only a small fraction of the local generation capacity or load. We believe future transmission lines will need to connect beyond provincial and state borders as there is a desire to improve efficiency by transmitting large quantities of electricity from one region to another. Such inter-regional lines will either be alternating current or direct current high voltage lines.

Power Prices

In 2012, power prices in Alberta are expected to be in line with 2011, driven by continued load growth, partially offset by lower natural gas prices. In the Pacific Northwest, we continue to expect weak prices due to low natural gas prices and slow load growth.

Environmental Legislation

The state of development of environmental regulations in both Canada and the U.S. remains fluid. Canada has indicated its intention to regulate GHG emissions from coal-fired power units by 2015. This regulatory framework is under discussion between the federal and provincial governments and the industry, and is expected to be finalized in 2012.

In the U.S., it is not yet clear how climate change legislation for existing fossil-fuel-based generation will unfold. Additionally, new air pollutant regulations for the power sector are anticipated in 2012, but will not directly affect our coal-fired operations in Washington State. TransAlta’s agreement with Washington State, established in March 2011, provides regulatory clarity regarding an emissions regime related to the Centralia Coal plant until 2025.

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

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

	TransAlta Corporation	46
Management’s Discussion and Analysis	2011 Annual Report	46

Economic Environment

The economic environment showed signs of improvement in 2011 and we expect this trend to continue through 2012 at a slow to moderate pace. We continue to monitor global events, including conditions in Europe, and their potential impact on the economy and our supplier and commodity counterparty relationships.

We had no counterparty losses in 2011, and 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.

We have recorded a provision on collateral held with MF Global Inc. Refer to the Significant Events section of this MD&A for further discusssion.

Operations

Capacity, Production, and Availability

Generating capacity is expected to increase for 2012 due to the completion of New Richmond and the three uprates at our Alberta PPA facilities. Prior to the effect of any economic dispatching, overall production is expected to increase for 2012 due to a full year of operating Keephills Unit 3 and lower unplanned outages, offset by higher than normal major maintenance or planned outages, scheduled in the thermal fleet in 2012. Overall availability is expected to be in the range of 89 to 90 per cent in 2012 due to lower unplanned outages.

Contracted Cash Flows

Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average approximately 70 per cent of our capacity is contracted over the next seven years. On an aggregated portfolio basis, we target being up to 90 per cent contracted for the upcoming year, stepping down to 65 per cent in the fourth year. As at the end of 2011, approximately 86 per cent of our 2012 capacity was contracted through the use of PPAs, long-term, and short-term contracts. The average price of our short-term physical and financial contracts for 2012 ranges from $60 to $65 per MWh in Alberta, and from U.S.$50 to U.S.$55 per MWh in the Pacific Northwest.

Fuel Costs

Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. Coal costs for 2012, on a standard cost basis, are expected to increase by approximately four per cent compared to 2011 due to the drivers mentioned above.

Although we own the Centralia mine in the State of Washington, it currently is not operational. Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per MWh for 2012 is expected to increase by approximately nine per cent due to higher diesel, commodity costs, and coal dust mitigation expenses.

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

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 for 2012 are expected to be approximately five per cent lower than 2011 OM&A.

Energy Trading

Earnings from our Energy Trading Segment are affected by prices in the market, overall strategies adopted, and changes in legislation. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2012 objective is for Energy Trading to contribute between $65 million and $85 million in gross margin.

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47	2011 Annual Report	Management’s Discussion and Analysis

Exposure to Fluctuations in Foreign Currencies

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

Net Interest Expense

Net interest expense for 2012 is expected to be higher than our reported 2011 net interest expense mainly due to lower capitalized interest. However, changes in interest rates and in the value of the Canadian dollar relative 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 in the future. To mitigate this liquidity risk, we expect to maintain $2.0 billion of committed credit facilities, and will continuously monitor our exposures and obligations.

Accounting Estimates

A number of our accounting estimates, including those outlined in 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 and asset valuation for our asset impairment calculations.

Income Taxes

The effective tax rate on earnings excluding non-comparable items for 2012 is expected to be approximately 20 to 25 per cent.

Capital Expenditures

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

Growth Capital Expenditures

In 2011, we spent a total of $123 million on growth capital expenditures, net of any joint venture contributions received. We successfully commenced commercial operations at Keephills Unit 3 and Bone Creek. In addition, of the $123 million, $50 million is associated with four significant growth projects that will be completed in 2012.

A summary of the significant projects that are in progress is outlined below:

Total project

2011

2012

Target

Estimated

Spent

Actual

Estimated

completion

Project

spend

to date

spend

date

Details

Keephills Unit 1 uprate

10-20

Q3 2012

A 23 MW efficiency uprate at our Keephills facility

Keephills Unit 2 uprate

10-20

Q2 2012

A 23 MW efficiency uprate at our Keephills facility

Sundance Unit 3 uprate

15-20

Q4 2012

A 15 MW efficiency uprate at our Sundance facility

New Richmond 3

205

165-185

Q4 2012

A 68 MW wind farm in Quebec

Total growth

283

200-245

1	In 2011, we also spent a combined total of $73 million on Keephills Unit 3, Bone Creek, Ardenville, and Kent Hills 2. Keephills Unit 3 amounts spent included a non-capital expenditure of $7 million and a coal cost reduction of $2 million. Bone Creek amounts spent as of Dec. 31, 2011 included a non-capital credit of $9 million.
2	Represents amounts spent as of Dec. 31, 2011.
3	New Richmond amounts spent as of Dec. 31, 2011 include expenditures of $5 million, which had been previously included in project development costs.

Transmission

For the year ended Dec. 31, 2011, a total of $5 million was spent on transmission projects. The estimated spend for 2012 for transmission projects is $8 million. Transmission projects consist of the major maintenance and reconfiguration of the transmission networks of Alberta to increase capacity of power flow in the lines.

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Management’s Discussion and Analysis	2011 Annual Report	48

Sustaining Capital Expenditures

A significant portion of our sustaining capital expenditures is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Some of these amounts were previously expensed under Canadian GAAP. Under IFRS, planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event.

For 2012, our estimate for total sustaining capital and productivity expenditures, net of any contributions received, is allocated among the following:

			Expected
		Spent	spend in
Category	Description	in 2011	2012

Routine capital	Expenditures to maintain our existing generating capacity	114	100 - 115
Productivity capital	Projects to improve power production efficiency	42	70 - 90
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	21	40 - 50
Planned maintenance	Regularly scheduled major maintenance	184	290 - 310

Total sustaining expenditures		361	500-565

Details of the 2012 planned maintenance program, including major inspection costs, are outlined as follows:

		Gas and	Expected
	Coal	Renewables	spend in 2012

Capitalized	215 - 230	75 - 80	290 - 310
Expensed	0 - 0	0 - 5	0 - 5

	215 - 230	75 - 85	290 - 315

		Gas and
	Coal	Renewables	Total

GWh lost	2,880 - 2,890	420 - 430	3,300 - 3,320

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 financial position, and the amount of capital available to us under existing committed credit facilities.

Risk Management

Our business activities expose us to a 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.

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

The Board of Directors provides stewardship of the Corporation; ensures that the Corporation establishes policies and procedures for the identification, assessment and management of principal risks; 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 review consists 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 interrelated with each other, and identifies the applicable risk metrics.

The 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 and 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 and Financial Exposure Management policies and reviews quarterly ERM reporting.

The Risk Management Committee (“RMC”) is chaired by our Chief Financial Officer and is comprised of the Executive Vice-President Corporate Development, Treasurer, Managing Director Trading, Executive Vice-President Operations, Vice-President Risk, and Chief Engineer. The RMC acts as the operational and financial risk oversight body for the Corporation.

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49	2011 Annual Report	Management’s Discussion and Analysis

The Technical Risk and Commercial Team (“TRACT”) is a committee chaired by the Vice-President, Engineering, Environment, and Construction Services, 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.

Risk Controls

Our risk controls have several key components:

Enterprise Tone

We strive to foster 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 sustainably, putting safety first, and being responsible to the many groups and individuals with whom we work.

Policies

We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for business transactions, as well as allow for an exceptional approval process. Periodic reviews and audits are performed to ensure compliance with these policies. All employees and directors are required to sign a corporate code of conduct on an annual basis.

Reporting

On a regular basis, risk exposures are reported to key decision makers including the Board of Directors, senior management, and the RMC. Reporting to the RMC includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks, and discussion of actions to minimize risks. 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 anonymously report any potential ethical concerns. These concerns can be submitted anonymously, either directly to the ARC or to the Director, 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 chair of the ARC.

Value at Risk and Trading Positions

VaR is the primary measure used to manage our exposure to market risk resulting from energy trading activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.

VaR is a commonly used metric that is employed by industry to track the risk in energy trading positions and portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices, and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2011 associated with our proprietary energy trading activities was $5 million (2010 - $5 million). Refer to the Commodity Price Risk section of this MD&A for further discussion.

Risk Factors

Risk is an inherent factor of doing business. 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 of changes in certain key variables. The analysis is based on business conditions and production volumes in 2011. 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.

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Volume Risk

Volume risk relates to the variances from our expected production. For example, the financial performance of our hydro, wind, and geothermal operations are partially dependent upon the availability of their input resources in a given year. 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.

We manage volume risk by:

< actively 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 required,

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

< placing 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.

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

		Approximate impact
Factor	Increase or decrease (%)	on net earnings

Availability/production	1	24

Generation Equipment and Technology Risk

There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, 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 may be required to compensate the purchaser for the loss in the availability of production or record reduced energy 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:

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

< performing preventative maintenance on a regular basis,

< adhering to a comprehensive plant maintenance program and regular turnaround schedules,

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

< having sufficient business interruption coverage in place in the event of an extended outage,

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

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

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

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

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

< developing a long-term asset management strategy with the objective of maximizing the lifecycles of our existing facilities and/or replacement of selected generating assets.

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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 the financial exposure associated with fluctuations in electricity price risk by:

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

< maintaining a portfolio of short-, medium-, and long-term contracts to mitigate our exposure to short-term fluctuations in electricity prices,

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

< ensuring limits and controls are in place for our proprietary trading activities.

In 2011, we had approximately 93 per cent of production under short-term and long-term contracts and hedges (2010 - 95 per cent). In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfill our supply obligations under these short- and long-term contracts.

We manage the financial exposure to fluctuations in the costs of fuels used in production by:

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

< selectively using hedges, where available, to set prices for fuel.

In 2011, 69 per cent (2010 - 81 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2010 - 100 per cent) of our purchased coal costs were contractually fixed.

The sensitivities of price changes to our net earnings are shown below:

		Approximate impact
Factor	Increase or decrease	on net earnings

Electricity price	$1.00/MWh	6
Natural gas price	$0.10/GJ	1
Coal price	$1.00/tonne	12

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 our coal-fired plants, input costs, such as diesel, tires, the price of mining equipment, the volume of overburden removed to access coal reserves, and the location of mining operations relative to the power plants are some of the exposures in our mining operations. 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 coal supply risk by:

< ensuring 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, 2011, approximately 79 per cent (2010 - 75 per cent) of the coal used in generating activities is from coal reserves that we own,

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

< sourcing 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,

< contracting sufficient trains to deliver the coal requirements at Centralia Thermal,

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

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

< hedging 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.

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Environmental Risk

Environmental risks are risks to our business associated with existing and/or changes in environmental regulations. New emission reduction objectives for the power sector are being established by governments in Canada and the U.S. 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:

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

< having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based environmental health and safety management system in place that is designed to continuously improve environmental performance,

< committing significant effort to work with regulators in Canada and the U.S. to ensure regulatory changes are well designed and cost effective,

< developing compliance plans that address how to meet or exceed emission standards for GHGs, mercury, SO2 , and oxides of nitrogen, which will be adjusted as regulations are finalized,

< purchasing emission reduction offsets outside of our operations,

< investing in renewable energy projects, such as wind and hydro generation, and

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

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 2011, we spent approximately $47 million (2010 - $50 million) on environmental management activities, systems, and processes.

We are a founder of the Canadian Clean Power Coalition and the Integrated CO2 Network, industry consortia dedicated to developing clean combustion technologies, which in turn will reduce the environmental and financial risks associated with continued fossil fuel use for power generation.

The Canadian Securities Administrators published guidance on environmental disclosure in Staff Notice 51-333. The guidance directs issuers to address:

< environmental risks and related matters,

< environmental risk oversight and management,

< forward looking information requirements as they relate to environmental goals and targets, and

< the impact of the adoption of IFRS on disclosure of environmental liabilities.

TransAlta has reviewed this guidance and believe that we comply with these requirements.

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 results from the ability of a counterparty to either fulfill its 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:

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

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

< using security instruments, such as parental guarantees, letters of credit, and cash collateral that can be collected if a counterparty fails to fulfill its obligation or goes over its limits, and

< reporting 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.

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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.

Our credit risk management profile and practices have not changed materially from Dec. 31, 2010. We had no counterparty losses in 2011, and 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. We continue to keep a close watch on changes and trends in the market and the impact these changes could have on our energy trading business and hedging activities, and will take appropriate actions as required although no assurance can be given that we will always be successful.

A summary of our credit exposure for our energy trading operations and hedging activities at Dec. 31, 2011 is provided below:

		Net exposure
Counterparty credit rating		amount

Investment grade		258
Non-investment grade		-
No external rating, internally rated as investment grade		70
No external rating, internally rated as non-investment grade		24

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 $38 million (2010 - $43 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, the acquisition of equipment and services and foreign denominated commodities from foreign suppliers, and our U.S. denominated debt. Our exposures are primarily to the U.S., Euro, 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 or the hedges are ineffective.

We manage our currency rate risk by establishing and adhering to policies that include:

< hedging 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 such foreign currency exposures. At Dec. 31, 2011, we have hedged approximately 92 per cent (2010 - 95 per cent) of our foreign currency net investment exposure,

< offsetting earnings from our foreign operations as much as possible by using expenditures denominated in the same foreign currencies and financial instruments to hedge the balance of this exposure, and

< entering into forward foreign exchange contracts to hedge future foreign denominated receipts and expenditures, and all U.S. denominated debt outside of our net investment portfolio.

The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment that a six cent increase or decrease in the U.S., Euro or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter, and is shown below:

Factor	Increase or decrease	Approximate impact on net earnings

Exchange rate	$0.06	4

Liquidity Risk

Liquidity risk relates to our ability to access capital to be used for energy 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 financial position 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.

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We manage liquidity risk by:

< monitoring liquidity on trading positions,

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

< reporting liquidity risk exposure for energy trading activities on a regular basis to the RMC, senior management, and Board of Directors,

< maintaining investment grade credit ratings, and

< maintaining sufficient undrawn 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 establishing and adhering to policies that include:

< employing a combination of fixed and floating rate debt instruments, and

< monitoring 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, 2011, approximately 23 per cent (2010 - 25 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	8

Project Management Risk

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

We manage project risks by:

< ensuring 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 senior management and Board of Directors approvals,

< using a consistent and disciplined project management methodology and processes,

< performing 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,

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

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

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

< fixing 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

< entering 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:

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

< reduced productivity due to turnover in positions,

< inability to complete critical work due to vacant positions,

< failure to maintain fair compensation with respect to market rate changes, and

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

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We manage this risk by:

< monitoring industry compensation and aligning salaries with those benchmarks,

< using incentive pay to align employee goals with corporate goals,

< monitoring and managing target levels of employee turnover, and

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

In 2011, 44 per cent (2010 - 46 per cent) of our labour force was covered by 11 (2010 - 11) collective bargaining agreements. In 2011, three (2010 - four) agreements were renegotiated. We anticipate negotiating three agreements in 2012. 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 potential changes to the 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 of those transmission lines are key in our ability to deliver energy produced at our power plants to our customers. However, with the continued growth in demand for electricity coupled with very little transmission capacity being added and the reduced reliability and available capacity on the existing transmission facilities, the risks associated with the aging existing transmission infrastructure in Alberta, Ontario, and the Pacific Northwest continue 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:

< striving 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,

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

< maintaining positive relationships with various levels of government,

< pursuing sustainable development as a longer-term corporate strategy,

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

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

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, the timing and extent of capital expenditures, the net recoverable value of PP&E, financing costs, credit risk, and counterparty risk.

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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 IFRS, 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	3

The effective tax rate on comparable earnings before income taxes, equity income, and other items for 2011 was 22 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 that 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. There can be no assurance that any particular claim will be resolved in our favour or that such claims may not have a material adverse effect on us.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during 2011. 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 2 to the consolidated financial statements. The most critical of these policies are those related to revenue recognition, financial instruments and hedges, PP&E, project development costs, goodwill, income taxes, employee future benefits, and decommissioning and other provisions. 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.

These critical accounting estimates are described as follows:

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Revenue Recognition

The majority of our revenues are derived from the sale of physical power, leasing of power facilities, and from energy trading activities.

Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for availability, energy payments for generation of electricity, 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, at market prices, for each MWh produced and are recognized upon delivery.

In certain situations, a long-term electricity or thermal sales contract may contain, or be considered a lease. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above.

Energy 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 financial position date represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position 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. Some of our derivatives 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.

Financial Instruments

The fair value of a financial instrument is the amount of consideration that would be agreed upon in an arm’s-length transaction between knowledgeable and willing parties who are under no compulsion to act. Fair values can be determined by reference to prices for that instrument in active markets to which we have access. In the absence of an active market, we determine fair values based on valuation models or by reference to other similar products in active markets.

Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look primarily to external readily observable market inputs. In limited circumstances, we use inputs that are not based on observable market data.

Level Determinations and Classifications

The Level I, II, and III classifications in the fair value hierarchy we use are defined below:

Level I

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

Level II

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

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

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In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or currency rate inputs and other third-party information such as credit spreads.

Level III

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

In limited circumstances, we 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 for individual non-standard deals and structured products, 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.

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

The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.

The effect of using reasonable possible alternative assumptions as inputs to valuation techniques from which the Level III fair values are determined at Dec. 31, 2011 is estimated to be +/- $33 million (2010 - +/- $14 million). Where an internally developed fundamental price forecast is used, reasonable alternate fundamental price forecasts sourced from external consultants are included in the estimate. In limited circumstances, certain contracts have terms extending beyond five years that require valuations to be extrapolated as the lengths of these contracts make reasonable alternate fundamental price forecasts unavailable.

Valuation of PP&E and Associated Contracts

As at Dec. 31, 2011, PP&E makes up 75 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, or the cash generating unit (“CGU”) to which it belongs, is in excess of its recoverable amount.

Factors that could indicate that an impairment exists include significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used, or in our overall business strategy; or 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 market, and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the PP&E or CGU to which it belongs. Recoverable amount is the higher of an asset’s fair value less costs to sell and its value in use. In estimating either fair value less costs to sell or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, retirement costs and other related cash inflows or outflows over the life of the plants, which can range from 30 to 60 years. In developing these assumptions, management uses 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. These estimates and assumptions are susceptible to change from period to period and 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.

As a result of our review in 2011, pre-tax asset impairment charges of $17 million were recorded related to certain renewables facilities. Refer to the Asset Impairment Charges section of this MD&A for further details.

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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 recognized 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 us, at which time the costs incurred subsequently are included in PP&E or Investments. The appropriateness of the carrying amount of these costs is evaluated each reporting period, and unrecoverable amounts of capitalized costs for projects no longer probable of occurring are charged to net earnings.

Useful Life of PP&E

Each significant component of an item of PP&E is depreciated over its estimated useful life. 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. 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, the potential for technological obsolescence, and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure they continue to be appropriate.

In 2011, depreciation and amortization expense per the Consolidated Statements of Cash Flows was $532 million (2010 - $511 million), of which $40 million (2010 - $37 million) relates to mining equipment, and is included in fuel and purchased power.

Valuation of Goodwill

We evaluate goodwill for impairment at least annually, or more frequently, if indicators of impairment exist. If the carrying amount of a CGU, including goodwill, exceeds the unit’s fair value, any excess represents a goodwill impairment loss. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets.

Goodwill arose on the acquisitions of Canadian Hydro, Merchant Energy Group of the Americas, Inc., and Vision Quest Windelectric Inc. At Dec. 31, 2011, this goodwill had a total carrying amount of $447 million (2010 - $447 million). Under the equity method of accounting, the goodwill arising on the acquisition of CE Gen is included in the determination of the amount of the investment in CE Gen and is tested for impairment as part of the net investment.

We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs, based on estimates of future cash flows, exceeded their carrying amounts, and no goodwill impairments existed.

Determining the fair value of the CGUs 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 CGUs declining by 10 per cent from current levels, there would not have been any impairment of goodwill.

Income Taxes

In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis.

Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations and legislation, to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could materially impact the amount recognized for deferred assets and liabilities. 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 IFRS based on all information currently available. The outcome of pending audits is not known nor is the potential impact on the consolidated financial statements determinable.

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Management’s Discussion and Analysis	2011 Annual Report	60

Deferred income tax assets of $176 million have been recorded on the Consolidated Statements of Financial Position at Dec. 31, 2011 (2010 - $178 million). These assets primarily relate to net operating and capital loss carryforwards. We believe there will be sufficient taxable income and capital gains that will permit the use of these carryforwards in the tax jurisdictions where they exist.

Deferred income tax liabilities of $491 million have been recorded on the Consolidated Statements of Financial Position at Dec. 31, 2011 (2010 - $538 million). These liabilities are comprised primarily of taxes on unrealized gains from risk management transactions and income tax deductions in excess of related depreciation of PP&E.

Employee Future Benefits

We provide selected pension and post-employment 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 to estimate our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.

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, 2011, the plan assets had a positive return of $11 million, compared to $28 million in 2010. The 2011 actuarial valuation used the same rate of return on plan assets (seven per cent) as was used in 2010.

Decommissioning and Restoration Provisions

We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a legal or constructive obligation 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 decommissioning and restoration provisions. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.

At Dec. 31, 2011, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial Position were $275 million (2010 - $247 million). We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.0 billion, which will be incurred between 2012 and 2072. The majority of these costs will be incurred between 2020 and 2050. The average discount used to calculate the carrying value of the decommissioning and restoration provisions was six per cent.

Sensitivities for the major assumptions are as follows:

		Approximate impact
Factor	Increase or decrease (%)	on net earnings


Discount rate	1	3

Undiscounted decommissioning and restoration provision	1	-

Other Provisions

Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of contract terms and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized.

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61	2011 Annual Report	Management’s Discussion and Analysis

Future Accounting Changes

Consolidated Financial Statements

In May 2011, the International Accounting Standards Board (“IASB”) issued IFRS 10 Consolidated Financial Statements, which replaces International Accounting Standard 27 Consolidated and Separate Financial Statements (“IAS 27”) and Standing Interpretations Committee Interpretation 12 Consolidation - Special Purpose Entities (“SIC-12”). IFRS 10 provides a revised definition of control so that a single control model can be applied to all entities for consolidation purposes.

Joint Arrangements

In May 2011, the IASB issued IFRS 11, which supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers. IFRS 11 provides for a principle-based approach to the accounting for joint arrangements that requires an entity to recognize its contractual rights and obligations arising from its joint arrangements. IFRS 11 also generally requires the use of the equity method of accounting for interests in joint ventures. Improvements in disclosure requirements are intended to allow investors to gain a better understanding of the nature, extent and financial effects of the activities that an entity carries out through joint arrangements.

Disclosure of Interests in Other Entities

In May 2011, the IASB issued IFRS 12 Disclosure of Interests in Other Entities, which contains enhanced disclosure requirements about an entity’s interests in consolidated and unconsolidated entities, such as subsidiaries, joint arrangements, associates, and unconsolidated structured entities (special purpose entities).

Investments in Associates and Joint Ventures and Separate Financial Statements

In May 2011, two existing standards, IAS 28 Investments in Associates and Joint Ventures and IAS 27 Separate Financial Statements, were amended. The amendments are not significant, and result from the issuance of IFRS 10, IFRS 11, and IFRS 12.

The requirements of the preceding new standards and amendments to existing standards outlined above are effective for annual periods beginning on or after Jan. 1, 2013. The disclosure requirements of IFRS 12 may be incorporated into the financial statements earlier than Jan. 1, 2013. However, early adoption of the other standards is only permitted if all five are applied at the same time. We are currently assessing the impact of adopting these new standards and amendments on the consolidated financial statements, and do not expect the impact to be significant.

Fair Value Measurements

In June 2011, the IASB issued IFRS 13 Fair Value Measurements, which establishes a single source of guidance for all fair value measurements required by other IFRS; clarifies the definition of fair value; and enhances disclosures about fair value measurements. IFRS 13 applies when other IFRS require or permit fair value measurements or disclosures. IFRS 13 specifies how an entity should measure fair value and disclose fair value information. It does not specify when an entity should measure an asset, a liability or its own equity instrument at fair value. IFRS 13 is effective for annual periods beginning on or after Jan. 1, 2013. Earlier application is permitted. We are currently assessing the impact of adopting IFRS 13 on the consolidated financial statements.

Presentation of Financial Statements

In June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements to improve the consistency and clarity of the presentation of items of comprehensive income by requiring that items presented in OCI be grouped on the basis of whether they are at some point reclassified from OCI to net earnings or not. The amendments to IAS 1 are effective for annual periods beginning on or after July 1, 2012. Earlier application is permitted. As a result of the amendment, the items presented within the Statement of Other Comprehensive Income will be reorganized to comply with the required groupings.

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Management’s Discussion and Analysis	2011 Annual Report	62

Employee Benefits

In June 2011, the IASB issued amendments to IAS 19 Employee Benefits to improve the recognition, presentation, and disclosure of defined benefit plans. The amendments require a new presentation approach that improves the visibility of the different types of gains and losses arising from defined benefit plans, as follows: service cost is presented in net earnings; finance cost is presented as part of finance costs in net earnings; and remeasurements of the net defined benefit asset or liability are recognized immediately in OCI. The amendments eliminate the option to defer the recognition of actuarial gains and losses, known as the ‘corridor method’. The disclosure requirements are enhanced to provide better information about the characteristics of defined benefit plans and the risks that entities are exposed to through participation in these plans. The amendments to IAS 19 are effective for annual periods beginning on or after Jan. 1, 2013. Earlier application is permitted. We are currently assessing the impact of adopting the amendments to IAS 19 on the consolidated financial statements.

Financial Instruments

In November 2009, the IASB issued IFRS 9 Financial Instruments, which replaced the classification and measurement requirements in IAS 39 Financial Instruments: Recognition and Measurement for financial assets. Financial assets must be classified and measured at either amortized cost or fair value through profit or loss or through OCI depending on the basis of the entity’s business model for managing the financial asset, and the contractual cash flow characteristics of the financial asset.

In October 2010, the IASB issued additions to IFRS 9 regarding financial liabilities. The new requirements address the problem of volatility in net earnings arising from an issuer choosing to measure a liability at fair value and require that the portion of the change in fair value due to changes in the entity’s own credit risk be presented in OCI, rather than within net earnings.

In December 2011, the IASB amended the effective date of these requirements, which are now effective for annual periods beginning on or after Jan. 1, 2015, and must be applied on a modified retrospective basis. Earlier adoption is permitted. The December amendment also provided relief from restating comparative periods and from the associated disclosures required under IFRS 7 Financial Instruments: Disclosures. We are currently assessing the impact of adopting these amendments on the consolidated financial statements.

Stripping Costs in the Production Phase of a Surface Mine

In October 2011, the International Financial Reporting Standards Interpretations Committee issued Interpretation 20 Stripping Costs in the Production Phase of a Surface Mine (“IFRIC 20”), which clarifies the requirements for accounting for stripping costs in the production phase of a surface mine. Stripping costs are costs associated with the process of removing waste from a surface mine in order to gain access to mineral ore deposits. The Interpretation clarifies when production stripping should lead to the recognition of an asset and how that asset should be measured, both initially and in subsequent periods. The Interpretation is effective for annual periods beginning on or after Jan. 1, 2013, with earlier application permitted. We are currently assessing the impact of adopting IFRIC 20 on the consolidated financial statements.

Offsetting Financial Assets and Liabilities

In December 2011, the IASB issued amendments to IAS 32 Financial Instruments: Presentation. The amendments are intended to clarify certain aspects of the existing guidance on offsetting financial assets and financial liabilities due to the diversity in application of the requirements on offsetting. The IASB also amended IFRS 7 to require information about all recognized financial instruments that are set off in accordance with IAS 32. The amendments also require disclosure of information about recognized financial instruments subject to enforceable master netting arrangements and similar agreements even if they are not set off under IAS 32.

The amendments to IAS 32 are effective for annual periods beginning on or after Jan. 1, 2014. However, the new offsetting disclosure requirements are effective for annual periods beginning on or after Jan. 1, 2013 and interim periods within those annual periods. The amendments need to be provided retrospectively to all comparative periods. We are currently assessing the impact of adopting these amendments on the consolidated financial statements.

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63	2011 Annual Report	Management’s Discussion and Analysis

Non-IFRS Measures

We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These 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 which is readily comparable from period to period.

Reconciliation to Net Earnings Attributable to Common Shareholders

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

Year ended Dec. 31	2011	2010

Revenues	2,663	2,673
Fuel and purchased power	947	1,185

Gross margin	1,716	1,488

Operations, maintenance, and administration	545	510
Depreciation and amortization	482	464
Taxes, other than income taxes	27	27

Operating expenses	1,054	1,001

Operating income	662	487

Finance lease income	8	8
Equity income	14	7
Gain on sale of assets	16	-
Other income	2	-
Foreign exchange (loss) gain	(3)	8
Asset impairment charges	(17)	(28)
Reserve on collateral	(18)	-
Net interest expense	(215)	(178)

Earnings before income taxes	449	304
Income tax expense	106	24

Net earnings	343	280
Non-controlling interests	38	24

Net earnings attributable to TransAlta shareholders	305	256
Preferred share dividends	15	1

Net earnings attributable to common shareholders	290	255

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 results from prior periods. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the year. In calculating comparable earnings, we exclude the impact related to certain hedges deemed ineffective for accounting purposes, as these transactions are unusual in nature and have not historically been a normal occurrence in the course of operating our business. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in net earnings in the period in which they settle. As these gains have already been recognized in earnings in the current period, future reported earnings will be lower, however, the expected cash flows from these contracts will not change.

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Management’s Discussion and Analysis	2011 Annual Report	64

In calculating comparable earnings for 2011, we have also excluded the gain on the sale of facilities and development projects, the writeoff of acquired wind development costs, the writedown of certain capital spares, asset impairment charges, and reserve on collateral, as these items are not considered regular business activities.

In calculating comparable earnings for 2010, we also excluded the impact of an income tax recovery related to the resolution of certain outstanding tax matters as they do not relate to the earnings in the period in which they have been reported.

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

Year ended Dec. 31	2011		2010

Net earnings attributable to common shareholders	290		255
Impacts associated with certain de-designated and ineffective hedges, net of tax	(81	)	(28	)
Gain on sale of facilities and development projects, net of tax	(12	)	-
Writeoff of wind development costs, net of tax	4		-
Writedown of capital spares, net of tax	3		-
Asset impairment charges, net of tax	13		16
Reserve on collateral, net of tax	13		-
Income tax recovery related to the resolution of certain outstanding tax matters	-		(30	)

Earnings on a comparable basis	230		213

Weighted average number of common shares outstanding in the year	222		219

Earnings on a comparable basis per share	1.04		0.97

Comparable EBITDA

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

Year ended Dec. 31	2011		2010

Operating income	662		487
Depreciation and amortization per the Consolidated Statements of Cash Flows 1	532		511

EBITDA	1,194		998
Impacts associated with certain de-designated and ineffective hedges, pre-tax	(127	)	(43	)
Writeoff of wind development costs, pre-tax	6		-
Writedown of capital spares, pre-tax	4		-

Comparable EBITDA	1,077		955

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

Funds From Operations and Funds From Operations per Share

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

Year ended Dec. 31	2011	2010

Cash flow from operating activities	694	838
Change in non-cash operating working capital balances	115	(33	)

Funds from operations	809	805
Weighted average number of common shares outstanding in the year	222	219

Funds from operations per share	3.64	3.68

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65	2011 Annual Report	Management’s Discussion and Analysis

Free Cash Flow

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

Sustaining capital expenditures for the year ended Dec. 31, 2011, represents total additions to PP&E and intangibles per the Consolidated Statements of Cash Flows less $125 million ($123 million net of joint venture contributions) that we have invested in growth projects. In 2010, we invested $482 million ($470 million net of joint venture contributions).

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

Year ended Dec. 31	2011		2010

Cash flow from operating activities	694		838
Add (deduct):
Changes in working capital	115		(33	)
Sustaining capital expenditures	(361	)	(355	)
Dividends paid on common shares	(191	)	(216	)
Dividends paid on preferred shares	(15	)	-
Distributions paid to subsidiaries’ non-controlling interests	(61	)	(62	)

Free cash flow	181		172

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

Comparable Return on Capital Employed (“ROCE”)

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 Accumulated Other Comprehensive (Loss) Income (“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 ROCE is presented below:

Year ended Dec. 31	2011		2010

Net earnings attributable to common shareholders before income taxes per the Consolidated Statements of Earnings	449		304
Net interest expense	215		178
Non-comparable items
Impacts associated with certain de-designated and ineffective hedges, pre-tax	(127	)	(43	)
Gain on sale of facilities and development projects, pre-tax	(16	)	-
Writeoff of wind development costs, pre-tax	6		-
Writedown of capital spares, pre-tax	4		-
Asset impairment charges, pre-tax	17		28
Reserve on collateral, pre-tax	18		-

Comparable earnings before net interest expense, non-controlling interests, and income taxes	566		467
Average invested capital excluding AOCI	7,554		7,357

Comparable ROCE	7.5		6.3

	TransAlta Corporation	66
Management’s Discussion and Analysis	2011 Annual Report	66

Selected Quarterly Information

	Q1 2011	Q2 2011	Q3 2011	Q4 2011

Revenue	818	515	629	701
Net earnings attributable to common shareholders	204	12	50	24
Net earnings per share attributable to common shareholders, basic and diluted	0.92	0.05	0.22	0.11
Comparable earnings per share	0.34	0.29	0.27	0.13


	Q1 2010	Q2 2010	Q3 2010	Q4 2010

Revenue	696	547	651	779
Net earnings attributable to common shareholders	60	63	40	92
Net earnings per share attributable to common shareholders, basic and diluted	0.27	0.29	0.18	0.42
Comparable earnings per share	0.27	0.15	0.18	0.36

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

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.

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, 2011, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.