Exhibit 13.2

TransAlta Management’s Discussion and Analysis

December 31, 2010

Plant Summary

				Net capacity
As of		Capacity	Ownership	ownership			Contract
January. 31, 2011	Facility	(MW) 1	(%)	interest (MW) 1	Fuel	Revenue source	expiry date
Western Canada	Sundance, AB 2	2,141	100	2,141	Coal	Alberta PPA /
42 Facilities						Merchant 3	2017, 2020
	Keephills, AB 4	812	100	812	Coal	Alberta PPA /
						Merchant 4	2020
	Keephills 3, AB 5	450	50	225	Coal	Merchant	-
	Genesee 3, AB	450	50	225	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
	Meridian, SK	220	25	55	Gas	LTC	2024
	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	50	6	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 5	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, AB6	44	100	44	Wind	LTC/Merchant	2011
	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	-
	Taylor Wind, AB	3	100	3	Wind	Merchant	-
	Grande Prairie, AB	25	100	25	Biomass	LTC	2019-2024
	Total Western Canada	6,788		5,403
Eastern Canada	Sarnia, ON 7	506	100	506	Gas	LTC	2022-2025
13 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	LTC	2011
	Misema, ON	3	100	3	Hydro	LTC	2027
	Galetta, ON	2	100	2	Hydro	LTC	2011
	Appleton, ON	1	100	1	Hydro	LTC	2011
	Moose Rapids, ON	1	100	1	Hydro	LTC	2011
	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 8	150	83	125	Wind	LTC	2033-2035
	Total Eastern Canada	1,411		1,264
United States	Centralia, WA 9	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, CA 10	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, WA 11	245	100	245	Gas/Diesel	LTC	2013
	Total Australia	355		300
	TOTAL	10,982		8,946

1	Megawatts are rounded to the nearest whole number	8	Includes Kent Hills 54 MW expansion that was completed in Q4 2010
2	Includes a 15 MW uprate on unit 3 expected to be commercial in 2012	9	Centralia Thermal’s NMC has been reduced from 1,404 MW to reflect a lower plant output as a result of its conversion to burning Powder River Basin coal
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 units 1 and 2 expected to be commercial in 2012 as merchant capacity	10 11	Comprised of 10 facilities Comprised of four facilities
5	Facilities currently under development
6	Includes seven individual turbines at other locations
7	Sarnia’s net maximum capacity (NMC) has been adjusted from 575 MW due to decommissioning of equipment at the facility		For more information on TransAlta’s facilities, please visit www.transalta.com/facilities

P l a n t   S u m m a r y 1

Management’s Discussion and Analysis

3	Business Environment	30	Statements of Cash Flows
5	Strategy	30	Liquidity and Capital Resources
6	Capability to Deliver Results	32	Climate Change and the Environment
7	Performance Metrics	34	Forward Looking Statements
10	Results of Operations	35	2011 Outlook
11	Reported Earnings	38	Risk Management
12	Significant Events	46	Critical Accounting Policies and Estimates
18	Discussion of Segmented Results	50	Future Accounting Changes
26	Financial Position	52	Non-GAAP Measures
26	Financial Instruments

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited 2010 consolidated financial statements. Our consolidated financial statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”). All dollar amounts in the following discussion, including the tables, are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Feb. 23, 2011. 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 and on our website at www.transalta.com.

2 T r a n s A l t a   C o r p o r a t i o n

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, geothermal, and biomass. During 2010, we began commercial operations at our Summerview 2, Kent Hills 2, and Ardenville wind farms, which added 189 megawatts (“MW”) of renewable power to our generation portfolio. In 2010, we also decommissioned our 279 MW Wabamun coal plant.

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

Demand

Demand for electricity is a fundamental driver of prices in all of our markets. Economic growth is the main driver of longer-term changes in the demand for electricity. Historically, demand for electricity in all three of our major markets has grown at an average rate of one to three per cent per year; however, the weak economic environment in 2008 and 2009 resulted in zero to negative demand growth in our key markets. Alberta began to experience some demand growth in 2010 and this trend is expected to continue at a rate of approximately three per cent per year for the next three years. Cost reductions combined with relatively well-supported oil prices are expected to result in an increase in oil sands development which will, in turn, lead to higher electricity demand. Due to the economic recession, the Pacific Northwest has seen continued demand destruction in 2010. Demand growth in this region is expected to increase approximately two per cent per year over the next three years due to expectations of a modest economic recovery; however, the long-term growth rate is expected to be lower than historical trends because there is a large emphasis on energy efficiency across the region. Demand in Ontario increased in 2010 coincidental with overall economic growth. In the longer term, demand in Ontario is expected to remain virtually flat and increase less than one per cent per year over the next three years as a result of economic growth being offset by conservation measures.

Supply

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

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

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

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

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

Transmission

Transmission refers to the bulk delivery system of power and energy between generating units and wholesale and/or retail customers. Power lines themselves serve as the physical path, transporting electricity from generating units to customers. Transmission systems are designed with sufficient reserve capacity to allow for “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 generating supply with the demand needs, and allows for contingency situations on the system. Most transmission businesses in North America are still regulated.

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

M a n a g e m e n t ‘ s   D i s c u s s i o n   a n d   A n a l y s i s 3

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. As a result, transmission lines within one of our key markets are expected to be upgraded to become less congested and will therefore be more efficient in meeting the needs of the long-term demand growth for electricity.

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. 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 interregional lines will either be alternating current or direct current high voltage lines.

Environmental Legislation and Technologies

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

While Carbon Capture and Storage (“CCS”) technologies are being developed, these technologies are not sufficiently advanced at this time. A $2 billion provincial fund and a $1 billion federal fund have been dispersed to several large demonstration projects. Project Pioneer, our CCS project, has qualified and received funding commitments of more than $750 million from these government initiatives. Those investments are expected to bring the cost of CCS down over the next 10 years. The outlook for these costs sets a floor price for carbon abatement technologies if regulatory or trading schemes are implemented. The future of carbon regulation remains uncertain.

Economic Environment

The economic environment has shown signs of improvement in 2010 and we expect this trend to continue in 2011 at a slow to moderate pace.

Electricity Prices

Spot electricity prices are important to our business as our merchant natural gas, wind, hydro, and thermal facilities are exposed to these prices. Changes in these prices will affect our profitability as well as any contracting strategy. Our Alberta plants, operating under PPAs, pay penalties or receive payments based upon a rolling 30-day average of spot prices. The PPAs and long-term contracts covering a number of our generating facilities help minimize the impact of spot price changes. The major markets we operate in are Western Canada, the U.S. Pacific Northwest, and Eastern Canada. 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, 2010, average spot prices increased in both Alberta and Ontario, and were comparable in the Pacific Northwest compared to the same period in 2009. In Alberta, demand growth and high prices during the second quarter resulted in a higher annual price. In Ontario, prices increased due to demand recovery. In the Pacific Northwest, marginally higher gas prices were offset by lower weather-related demand.

During the year, our consolidated power portfolio was 95 per cent contracted through the use of PPAs and other long-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 2010 ranging from $60-$65 per megawatt hour (“MWh”) in Alberta, and from U.S.$50-$55 per MWh in the Pacific Northwest.

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”).

4 T r a n s A l t a   C o r p o r a t i o n

Spark spreads will also vary between different plants due to their design, the geographical region in which they operate, and the requirements of the customer and/or market the plant serves. The change in the prices of electricity and natural gas, and the resulting spark spreads in our three major markets, affect our Generation and Energy Trading business segments. For the year ended Dec. 31, 2010, average spark spreads increased in Alberta and Ontario compared to the same periods in 2009 due to demand growth. Average spark spreads decreased in the Pacific Northwest compared to the same periods in 2009 due to lower weather-related demand during the third and fourth quarters, as well as increased generation from hydro and wind in the region.

Strategy

Our goals are to deliver shareholder value by delivering solid returns through dividend yield, and disciplined comparable Earnings Per Share2 (“EPS”) and funds from operations2 growth, while maintaining a low-to-moderate risk profile, balancing capital allocation, and maintaining financial strength. Our comparable EPS and funds from operations growth is 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 and the U.S. We are focusing on these geographic areas as our expertise, scale, and access to numerous fuel resources, including coal, wind, geothermal, hydro, and natural gas, allow us to create expansion opportunities in our core markets. Our strategy to achieve these goals has the following key elements:

Financial Strategy

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

Contracting Cash Flows

In 2010, although we started to see some demand growth, prices in our key markets remained consistent with the lower values experienced in 2009 as compared to prior years primarily due to the ongoing weak economic environment. While we are not immune to lower power prices, the impact of these lower prices is expected to be mitigated because approximately 88 per cent of 2011 and approximately 81 per cent of 2012 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 low cost and balanced with our fleet availability target. Our target for 2011 is to increase productivity and achieve overall fleet availability of 89 to 90 per cent. Over the last three years, our average availability has been 86.6 per cent, which is below our corporate target. The lower average availability has been primarily due to the accelerated planned maintenance undertaken in 2009 and higher than normal unplanned outages at our coal-fired plants in 2009 and 2008. In 2009, we reviewed each unit and developed asset-specific maintenance plans to achieve more predictable performance and stable operations, which were observed in 2010 by achieving overall availability of 88.9 per cent.

Growth Strategy

Our growth strategy is focused upon greening and diversifying our portfolio to reduce our carbon footprint and develop long-term, sustainable power generation. We’ve delivered on this plan in 2010 by completing our Summerview 2, Kent Hills 2, and Ardenville wind projects on time and on budget. We continue to develop opportunities for future sustainable power projects.

2    Comparable EPS and funds from operations are not defined under Canadian GAAP. Presenting earnings on a comparable basis from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of comparable EPS and funds from operations, including a reconciliation to net earnings and cash flow from operating activities.

M a n a g e m e n t ‘ s   D i s c u s s i o n   a n d   A n a l y s i s 5

Capability to Deliver Results

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

Operational Excellence

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

Execution of our Strategy in 2010

Improve base operations	n	Implemented productivity and cost reductions that lowered operating expenses across the fleet
	n	Implemented our revised major maintenance schedule on a unit-by-unit basis, which improved availability to 88.9 per cent in 2010
	n	Began to align plans and capital spend for coal units based on the emerging proposal to reduce
		GHG emissions by their 45th year of operation
	n	Approved a 15 MW efficiency uprate at Unit 3 of our Sundance facility
Reposition coal	n	Participated in the Front End Engineering and Design (“FEED”) study to investigate the feasibility of Project Pioneer, which uses CCS technology and is expected to be completed in 2011
	n	Announced Enbridge as an official partner in the development of Project Pioneer
	n	Signed a Memorandum of Understanding (“MOU”) with the State of Washington and began plans to reduce GHG emissions from the Centralia Thermal plant
	n	Continued active involvement in environmental policy discussions with various levels of government in Canada and the U.S.
Green and diversify our portfolio	n	Added 189 MW of wind generation to our portfolio by completing construction of the Summerview 2, Kent Hills 2, and Ardenville wind farms
	n	Continued our work on the construction of Bone Creek, a 19 MW hydro facility in British Columbia

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 2010 and will continue to be important during 2011. We continue to maintain $2.0 billion in committed credit facilities, and as of Dec. 31, 2010, $1.1 billion was available to us. Our investment grade credit rating, available credit facilities, strong funds from operations, and limited debt maturity profile provide us with financial flexibility, and 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 2010, we took advantage of favourable capital markets by completing a U.S.$300 million 30-year senior notes offering in March and completing the sale of $300 million of preferred shares in December. Both transactions were well received by the markets and were oversubscribed. Looking forward, we expect continued capital market support for projects that meet our return requirements and risk profile.

Disciplined Capital Allocation

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

We continue to grow our diversified generating fleet in order to increase production and meet future demand requirements, with all growth projects having the ability to exceed our targeted rate of return. We currently have 305 MW of capacity under construction, which is comprised of 225 MW of coal-fired generation, 61 MW of uprates to our thermal coal fleet, and 19 MW of hydro. We also have more than 1,400 MW of advanced development wind, hydro, natural gas, and geothermal projects in our development pipeline.

In addition to our greenfield growth plans, we continue our uprates of existing facilities. These uprates add capability to our existing fleet and provide opportunities for attractive rates of return. In 2010, we approved and began work on a 15 MW uprate on Unit 3 of our Sundance plant (“Unit 3”), and in 2011 we will continue our work on the Unit 3 uprate, as well as the uprates of Units 1 and 2 of our Keephills plant.

People

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

6 T r a n s A l t a   C o r p o r a t i o n

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 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, balancing our maintenance costs with optimal availability targets. Over the past three years we have achieved an average availability of 86.6 per cent, which is below our long-term target of 89 to 90 per cent. Our availability in 2010 was 88.9 per cent.

Availability for the year ended Dec. 31, 2010 increased compared to 2009 primarily due to lower planned outages at our Keephills plant, lower planned and unplanned outages at our Sundance plant, and lower unplanned outages at Centralia Thermal, partially offset by higher planned outages at Centralia Thermal.

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

Production

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

Production for the year ended Dec. 31, 2010 increased 2,878 gigawatt hours (“GWh”) compared to 2009 as a result of higher wind and hydro volumes primarily due to the acquisition of Canadian Hydro Developers, Inc. (“Canadian Hydro”), lower planned and unplanned outages at our Sundance plant, lower unplanned outages at Centralia Thermal, lower planned outages at our Keephills plant, and lower economic dispatching at Centralia Thermal, partially offset by the decommissioning of Wabamun, higher planned outages at Centralia Thermal and Genesee 3, and the expiration of the long-term contract at Saranac.

Production for the year ended Dec. 31, 2009 decreased 3,155 GWh due to higher economic dispatching and higher unplanned outages at Centralia Thermal, higher planned and unplanned outages at our Sundance and Wabamun plants, higher planned outages at Keephills, lower PPA customer demand, the expiration of the long-term contract at Saranac, and lower hydro volumes, partially offset by higher wind volumes due to the acquisition of Canadian Hydro and the commissioning of Kent Hills, lower planned outages at Centralia Thermal, lower planned and unplanned outages at Genesee 3, and lower unplanned outages at Keephills.

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, 2010, OM&A costs per installed MWh decreased compared to 2009 due to lower planned outages, favourable foreign exchange rates, and targeted cost savings, combined with higher installed capacity primarily as a result of the acquisition of Canadian Hydro.

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d  A n a l y s i s 7

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

Safety

Safety is a top priority with all of our staff, contractors, and visitors. Our objective is to improve safety by reducing our Injury Frequency Rate (“IFR”) to 1 by 2015. Our ultimate goal is to achieve zero injury accidents.

	2010	2009	2008
IFR	1.19	1.41	1.28

In 2010, the IFR decreased due to fewer injuries at our coal facilities, primarily at the Sundance plant, as a direct result of continuous efforts to improve safety. The IFR increased in 2009 as a result of us not meeting safety targets while completing the uprate on Unit 5 of our Sundance facility.

Sustaining Capital Expenditures

We are in a long-cycle capital-intensive business that requires consistent and stable 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. In 2010, we spent $49 million less on routine and mine capital, $12 million more on planned maintenance, and $35 million less on

productivity compared to 2009. The decrease in routine and mine capital was due to decreased spending on equipment modifications at Centralia Thermal, lower mine capital at the Highvale mine, which supplies coal to both our Keephills and Sundance plants, and lower routine spending at Sarnia. Planned maintenance increased primarily due to higher spending on renewables as a result of the acquisition of Canadian Hydro. The decrease in productivity expenditures was primarily due to lower spend on turbine uprates at Mississauga and Windsor.

In 2009, we spent $86 million less on routine and mine capital, $10 million less on planned maintenance, and an additional $11 million on productivity compared to 2008. The decrease in both routine and mine capital and planned maintenance in 2009 was due to lower mine capital and decreased spending on equipment modifications at Centralia Thermal. The increase in productivity expenditures was for various projects undertaken throughout the Corporation to improve operations and increase efficiencies.

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”), 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.

	2010	2009	2008
Comparable EPS	0.98	0.90	1.46
Comparable EBITDA1	965	888	1,006
Funds from operations	783	729	828

1 Comparable EBITDA is not defined under Canadian GAAP. Presenting comparable EBITDA from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of comparable EBITDA, including a reconciliation to net earnings.

In 2010, comparable EPS and comparable EBITDA increased compared to the same period in 2009 primarily due to higher availability and production, and lower OM&A costs. Comparable EPS also increased in 2010 due to lower depreciation expense.

In 2009, comparable EPS and comparable EBITDA decreased due to higher planned and unplanned outages at our Sundance and Wabamun plants, higher planned outages at Keephills, lower hydro volumes and prices, and lower trading margins.

In 2010, funds from operations increased compared to the same period in 2009 due to higher availability and production, and lower operational expenditures, partially offset by higher interest payments due to the acquisition of Canadian Hydro and lower than historical wind and hydro volumes. In 2009, funds from operations decreased due to lower availability and production, and the receipt of an additional PPA payment in 2008.

8 T r a n s  A l t a   C o r p o r a t i o n

Investment Grade Ratios

Investment grade ratings support contracting activities and provide better access to capital markets through commodity and credit cycles. We are focused on maintaining a strong balance sheet and cash flow coverage ratios to support stable investment grade credit ratings.

	2010	2009	2008
Cash flow to interest coverage (times)	4.3	4.9	7.2
Cash flow to debt (%)	18.3	20.5	31.7
Debt to invested capital (%)	53.6	56.1	48.1

Cash flow to interest coverage decreased in 2010 compared to the same period in 2009 primarily due to higher interest expense. Cash flow to interest coverage decreased in 2009 as a result of lower funds from operations and higher interest expense. Our goal is to maintain this ratio in a range of four to five times.

Cash flow to debt decreased in 2010 compared to the same period in 2009 due to higher average debt levels in 2010. Cash flow to debt decreased in 2009 due to a decrease in funds from operations and higher debt as a result of our issuances of senior and medium-term notes during 2009 to fund the acquisition of Canadian Hydro. 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, 2010 compared to the same date in 2009 due to the favourable impact of a stronger Canadian dollar on our U.S. dollar denominated debt. Debt to invested capital increased in 2009 as a result of the issuance of debt throughout the year to fund growth and for the acquisition of Canadian Hydro. 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 our comparable Return On Capital Employed (“ROCE”)1 and Total Shareholder Return (“TSR”)1 by achieving a return of 10 per cent per year over the long-term.

The table below shows our historical performance and targets on these measures on a five-year rolling average:

	2010	2009	2008
Comparable ROCE (%)2	8.0	8.3	8.9
TSR (%)	2.0	12.3	12.6

2 2008 comparable ROCE is based on a four-year rolling average as we did not begin reporting comparable ROCE until 2005.

The five-year rolling average of comparable ROCE has decreased slightly due to higher debt levels primarily due to the acquisition of Canadian Hydro in 2009, partially offset by increasing comparable earnings year-over-year.

The five-year rolling average of TSR has decreased due to the decline of our stock price, which is a direct result of the economic recession that began in 2008 that has been slow to recover.

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

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 9

Results of Operations

Our results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading1 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. Critical accounting policies and estimates include: revenue recognition, valuation and useful life of Property, Plant, and Equipment (“PP&E”), financial instruments, Asset Retirement Obligation (“ARO”), valuation of goodwill, income taxes, and employee future benefits. Refer to the Critical Accounting Policies and Estimates section of this MD&A for further discussion.

In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is discussed with the relevant items from the Consolidated Statements of Earnings and the Consolidated Balance Sheets. While individual line items on the Consolidated Balance Sheets will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items relating to self-sustaining foreign operations is reflected in the equity section of the Consolidated Balance Sheets.

Highlights and Summary of Results

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

Year ended Dec. 31	2010	2009		2008
Availability (%)	88.9	85.1		85.8
Production (GWh)	48,614	45,736		48,891
Revenues	2,819	2,770		3,110
Gross margin2	1,617	1,542		1,617
Operating income2	497	378		533
Net earnings applicable to common shares	218	181		235
Net earnings per common share, basic and diluted	1.00	0.90		1.18
Comparable EPS	0.98	0.90		1.46
Comparable EBITDA	965	888		1,006
Funds from operations	783	729		828
Cash flow from operating activities	811	580		1,038
Cash flow from operating activities per share2	3.70	2.89		5.22
Free cash flow (deficiency)2	204	(117	)	121
Dividends paid per common share	1.16	1.16		1.08
As at Dec. 31	2010	2009		2008
Total assets	9,893	9,786		7,824
Total long-term liabilities	5,108	5,548		3,645

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

1 Our Energy Trading segment was referred to as “Commercial Operations and Development” in 2009 and 2008.

10 T r a n s A l t a   C o r p o r a t i o n

Reported Earnings

The primary factors contributing to the change in net earnings applicable to common shares for the years ended Dec. 31, 2010 and 2009 are presented below:

Net earnings applicable to common shares for the year ended Dec. 31, 2008	235
Decrease in Generation gross margins	(33	)
Mark-to-market movements - Generation	16
Decrease in Energy Trading gross margins	(58	)
Increase in operations, maintenance, and administration costs	(30	)
Increase in depreciation expense	(47	)
Asset impairment charges	(16	)
Increase in net interest expense	(34	)
Equity loss recorded in 2008	97
Decrease in non-controlling interests	23
Decrease in income tax expense	8
Increase in foreign exchange gain	20
Net earnings applicable to common shares for the year ended Dec. 31, 2009	181
Increase in Generation gross margins	36
Mark-to-market movements - Generation	45
Decrease in Energy Trading gross margins	(6	)
Decrease in operations, maintenance, and administration costs	33
Decrease in depreciation expense	16
Asset impairment charges	(73	)
Increase in net interest expense	(34	)
Decrease in other income	(8	)
Decrease in non-controlling interests	18
Decrease in income tax expense	14
Other	(4	)
Net earnings applicable to common shares for the year ended Dec. 31, 2010	218

For the year ended Dec. 31, 2010, Generation gross margins, excluding the impact of mark-to-market movements, increased compared to the same period in 2009 due to higher wind and hydro volumes primarily as a result of the acquisition of Canadian Hydro, lower planned and unplanned outages at our Sundance plant, and lower planned outages at our Keephills plant, partially offset by unfavourable pricing, the expiration of the long-term contract at Saranac, the decommissioning of Wabamun, and unfavourable foreign exchange rates.

In 2009, Generation gross margins, excluding the impact of mark-to-market movements, decreased due to higher planned outages at our Sundance and Wabamun plants, higher planned outages at Keephills, lower hydro volumes and prices, and the expiration of the long-term contract at Saranac, partially offset by lower planned and unplanned outages at Genesee 3, lower unplanned outages at Keephills, higher wind volumes due to the acquisition of Canadian Hydro and the commissioning of Kent Hills, favourable foreign exchange rates, and favourable contractual pricing.

Mark-to-market movements increased for the year ended Dec. 31, 2010 primarily due to the recognition of unrealized gains resulting from certain power hedging relationships being deemed ineffective for accounting purposes.

For the year ended Dec. 31, 2010, Energy Trading gross margins decreased compared to the same period in 2009 primarily due to reduced margins resulting from reduced market demand and narrowing inter-season spreads in the western region.

In 2009, Energy Trading gross margins decreased due to a reduction in industrial demand, gas price uncertainty, and the change in the California market, which resulted in reduced pricing spreads and smaller margins.

For the year ended Dec. 31, 2010, OM&A costs decreased compared to the same period in 2009 due to lower planned outages, favourable foreign exchange rates, and targeted cost savings, partially offset by the acquisition of Canadian Hydro.

In 2009, OM&A costs increased primarily due to higher planned outages and unfavourable foreign exchange rates, partially offset by targeted cost savings throughout the Corporation and lower compensation costs.

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 11

For the year ended Dec. 31, 2010, depreciation expense decreased compared to the same period in 2009 due to a change in the estimated useful lives of certain coal generation facilities and mining assets, a reduction in the estimated costs associated with decommissioning our Wabamun plant, lower depreciation at Saranac following the expiration of its long-term contract, and favourable foreign exchange rates, partially offset by an increased asset base primarily due to the acquisition of Canadian Hydro.

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

During the fourth quarter of 2010, we recorded pre-tax asset impairment charges of $89 million related to certain coal and natural gas facilities. Refer to the Asset Impairment section of this MD&A for further details.

In 2006, we ceased mining activities at the Centralia mine but continued to develop the option to mine the Westfield site, a coal reserve located adjacent to Centralia Thermal. With the successful modifications of the boilers at Centralia Thermal and longer-term contracts in place to supply coal, the project to develop the Westfield site was placed on hold indefinitely and in 2009, the costs that had been capitalized were expensed.

For the year ended Dec. 31, 2010, net interest expense increased compared to the same period in 2009 due to higher debt levels, partially offset by interest income related to the resolution of certain outstanding tax matters, higher capitalized interest, favourable foreign exchange, and lower interest rates.

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

In 2009, we settled an outstanding commercial issue that was recorded as a pre-tax gain of $7 million in other income as it related to our previously held Mexican equity investment. We also recorded a pre-tax gain of $1 million on the sale of a 17 per cent interest in our Kent Hills wind farm. The sale of a 17 per cent interest in our Kent Hills 2 wind farm expansion project in 2010 did not have a significant impact on net earnings.

For the year ended Dec. 31, 2010, non-controlling interests decreased compared to the same period in 2009 due to lower earnings resulting from the expiration of the long-term contract at our Saranac facility and an asset impairment charge related to the pending sale of our Meridian facility, partially offset by higher earnings at TA Cogeneration, L.P. (“TA Cogen”).

In 2009, non-controlling interests decreased primarily due to lower earnings resulting from the expiration of the long-term contract at Saranac.

For the year ended Dec. 31, 2010, income tax expense decreased compared to the same period in 2009 as a result of the resolution of certain outstanding tax matters, partially offset by higher pre-tax earnings.

In 2009, income tax expense decreased due to lower pre-tax earnings and the recovery recorded for a change in future tax rates related to tax liabilities recorded in prior periods, partially offset by the income tax recovery related to tax positions recorded in 2008.

Significant Events

Our consolidated financial results include the following significant events:

2010

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. As a result, all associated assets and liabilities have been classified as held for sale under the Generation segment. The sale is effective Jan. 1, 2011 and is expected to close in early 2011. The impact of this transaction on net earnings is not expected to be significant.

Purchase Price Allocation Adjustment

During the fourth quarter of 2010, management updated the preliminary purchase price allocation related to our acquisition of 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 future income taxes.

Sundance Unit 1 and 2 Outage

On Dec. 16, 2010 and Dec. 19, 2010, Unit 1 and Unit 2, respectively, of our Sundance facility were shut down due to conditions observed in the boilers at both units. As a result, all 560 MW from both units were unavailable as inspections were carried out to determine the scope of repairs that may be needed. The units cannot be restarted without inspection and approval from the Alberta Boiler Safety Association. As a result of the outage, production was reduced by 182 GWh for the year ended Dec. 31, 2010.

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Under the terms of the PPA for these units, we have notified the PPA Buyer and the Balancing Pool of a force majeure event. Under force majeure, we are entitled to receive our PPA capacity payments and are protected from having to pay penalties for the units’ lack of availability, to the extent the event meets the force majeure criteria set out in the PPA.

On Feb. 8, 2011, we announced that we had issued a notice of termination for destruction on our Sundance 1 and 2 coal-fired generation units under the terms of the PPA. This action was based on our determination that the physical state of the boilers is such that the units cannot be economically restored to service under the terms of the PPA. Under the PPA, termination for destruction permits the recovery of the net book value specified in the PPA.

On Feb. 18, 2011, the PPA Buyer has provided notice that it intends to dispute our 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.  Although no assurance can be given as to the ultimate outcome of these matters, we believe that they will be resolved in our favour. We remain committed to continuing to work with the PPA Buyer and the Balancing Pool under the processes established within the PPA.

Resolution of Tax Matters

During 2010, we recognized a $30 million income tax recovery related to the resolution of certain outstanding tax matters, which was received in 2010. 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 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 their 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, and an additional $2 million of proceeds related to costs expected in 2011. 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. (“Enbridge”) 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.

Chief Financial Officer

On June 18, 2010, we announced that Brett Gellner was appointed chief financial officer, succeeding Brian Burden, who made a personal decision to retire from the Corporation. Mr. Burden assisted Mr. Gellner with the transition through Sept. 30, 2010.

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. As a result, the expected capability levels for Unit 3 were reduced. Unit 3 returned to service at the reduced expected capability levels on June 23, 2010. The unit continues to operate at these reduced levels and no assurance can be given as to whether it will return to normal operating levels prior to the completion of major maintenance currently scheduled for the middle of 2012. As a result of the outage and subsequent derate, production was reduced by 480 GWh for the year ended Dec. 31, 2010.

In response to this event, we gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the PPA. During the second quarter, we recorded an after-tax charge of $13 million, or 50 per cent of the penalties to June 30, 2010, representing the amount of penalties we are required to pay to the PPA Buyers pending a resolution of this matter. No additional penalties relating to this event were incurred during the year.

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 13

On Oct. 20, 2010, the Balancing Pool confirmed it agreed with our determination that the mechanical failure meets the requirements of a HILP event under the PPA. While this decision neither constitutes a determination of a force majeure event, nor provides a definitive resolution to the dispute, management believes this strengthens our position with regards to financial protection from the event.

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.

Centralia Thermal MOU

On April 26, 2010, we announced that we signed an MOU with the State of Washington to enter discussions to develop an agreement to significantly reduce GHG emissions from the Centralia Thermal plant, and to provide replacement capacity by 2025. The MOU also recognizes the need to protect the value that Centralia Thermal brings to our shareholders. Discussions are ongoing and details on the results of these discussions will be provided as they become available.

Decommissioning of Wabamun Plant

On March 31, 2010, we fully retired all units of the Wabamun plant as part of our previously announced shutdown. 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 asset retirement 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 the same period in 2009.

Any other adjustments resulting from the review of the balance of the fleet will be reflected in future periods.

2009

Medium-Term Notes Offerings

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

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

Senior Notes Offering

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

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Sale of Common Shares

On Nov. 5, 2009, we completed our public offering of 20,522,500 common shares at a price of $20.10 per common share, which resulted in net proceeds of approximately $396 million. The net proceeds from the offering were used to repay a portion of the indebtedness relating to our acquisition of Canadian Hydro.

Blue Trail

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

Keephills 3

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

Carbon Capture and Storage

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

Acquisition of Canadian Hydro

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

Canadian Hydro operated 694 MW of wind, hydro, and biomass facilities in Alberta, Ontario, Quebec, and British Columbia. Canadian Hydro’s assets are highly contracted with counterparties of recognized financial standing. On a combined basis at Dec. 31, 2009, we had 9,199 MW of gross generating capacity1 in operation (8,775 MW net ownership interest). The combined renewables portfolio included more than 1,900 MW in operation, or 22 per cent of our total portfolio at that time. In addition, there was a combined 424 MW net under construction and over 600 MW in advanced-stage development at Dec. 31, 2009.

The following table depicts the impact of Canadian Hydro on our consolidated operations portfolio by geographic region and fuel type at Dec. 31, 2009:

Net Capacity Ownership Interest (MW)
			TransAlta
Dec. 31, 2009	Canadian Hydro	TransAlta2	consolidated
Western Canada	183	5,059	5,242
Eastern Canada	511	707	1,218
International	-	2,315	2,315
	694	8,081	8,775
Coal	-	4,967	4,967
Natural Gas	-	1,843	1,843
Biomass	25	-	25
Geothermal	-	164	164
Wind	583	300	883
Hydro	86	807	893
	694	8,081	8,775

2  Excluding Canadian Hydro.

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

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 15

Sarnia Contract

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

Major Maintenance Plans

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

Normal Course Issuer Bid (“NCIB”) Program

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

Chief Operating Officer

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

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

Ardenville Wind Power Project

On April 28, 2009, we announced plans to design, build, and operate Ardenville, a 69 MW wind power project in southern Alberta. The capital cost of the project was approximately $135 million. Included in the capital cost of the project was the purchase of an already operational 3 MW turbine at Macleod Flats. Commercial operations of the Ardenville wind project began on Nov. 10, 2010.

Sundance Unit 4 Derate

On Feb. 10, 2009, we reported the first quarter financial impact of an extended derate on Unit 4 of our Sundance facility (“Unit 4”). The facility experienced an unplanned outage in December 2008 related to the failure of an induced draft fan. At that time, Unit 4, which has a capacity of 406 MW, had been derated to approximately 205 MW. The repair of the induced draft fan components by the original equipment manufacturer took longer than planned, and therefore, Unit 4 did not return to full service until Feb. 23, 2009. As a result of the extended derate, 2009 first quarter production and net earnings were reduced by 328 GWh and $10 million, respectively, representing both lost merchant revenue and penalties.

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

Keephills Units 1 and 2 Uprates

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

Dividend Increase

On Jan. 28, 2009, our Board of Directors declared a quarterly dividend of $0.29 per share on common shares, an increase of $0.02 per share, which on an annual basis will yield $1.16 per share versus $1.08 per share in 2008.

16 T r a n s A l t a   C o r p o r a t i o n

2008

Kent Hills Wind Farm

On Dec. 31, 2008, our 96 MW Kent Hills Wind Farm, which is located 30 kilometres southwest of Moncton, New Brunswick, began commercial operations. We constructed, own, and operate the Kent Hills facility. Total capital costs for the construction of Kent Hills were approximately $170 million. Natural Forces exercised their option to purchase a 17 per cent interest in the Kent Hills project subsequent to the commencement of commercial operations.

Debentures

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

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

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

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

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

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

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

Genesee 3

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

Mexican Equity Investment

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

LS Power and Global Infrastructure

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

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

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

Potential Breach of Keephills Ash Lagoon

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

Expansion at Summerview

On May 27, 2008, we announced a 66 MW expansion at our Summerview wind farm located in southern Alberta near Pincher Creek. The total capital cost of the project was approximately $118 million and commercial operations commenced on Feb. 23, 2010.

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 17

Senior Notes Offering

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

Normal Course Issuer Bid Program

On May 5, 2008, we announced plans to renew our NCIB program until May 5, 2009. We received the approval to purchase, for cancellation, up to 19.9 million of our common shares representing 10 per cent of our 199 million common shares issued and outstanding as at April 23, 2008.

For the year ended Dec. 31, 2008, we purchased 3,886,400 shares (2007 - 2,371,800 shares) at an average price of $33.46 per share (2007 - $31.59 per share). Purchases were made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition. The shares were purchased for an amount higher than their weighted average book value of $8.95 per share (2007 - $8.92 per share) resulting in a reduction of retained earnings of $95 million (2007 - $54 million).

Uprate at Sundance Facility

On April 21, 2008, we announced a 53 MW efficiency uprate at Unit 5 of our Sundance facility. The total capital cost of the project was approximately $77 million. Commercial operations commenced in the fourth quarter of 2009.

Greenhouse Gas Emissions

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

Dividend Policy and Dividend Increase

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

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

Blue Trail Wind Power Project

On Feb. 13, 2008, we announced plans to design, build, and operate Blue Trail, a 66 MW wind power project in southern Alberta. The capital cost of the project was $113 million. Commercial operations commenced in the fourth quarter of 2009.

Discussion of Segmented Results

GENERATION: Owns and operates hydro, wind, geothermal, biomass, natural gas- and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation’s revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support. At Dec. 31, 2010, Generation had 9,109 MW of gross generating capacity in operation (8,676 MW net ownership interest) and 305 MW (net ownership interest) under construction. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of this MD&A.

During 2010, we began commercial operations at our Summerview 2, Kent Hills 2, and Ardenville wind farms, which added 189 MW of renewable power to our generation portfolio. In 2010, we also decommissioned our 279 MW Wabamun plant. Please refer to the Significant Events section of this MD&A for further details.

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

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are usually incurred in the second and third quarters when electricity prices are expected to be lower, as electricity prices generally increase in the winter months in the Canadian market. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Canadian and U.S. markets.

18 T r a n s A l t a   C o r p o r a t i o n

The results of the Generation segment are as follows:

Year ended Dec. 31			2010		2009		2008
				Per installed		Per installed		Per installed
			Total	MWh	Total	MWh	Total	MWh
Revenues			2,778	34.90	2,723	36.37	3,005	40.63
Fuel and purchased power			1,202	15.10	1,228	16.40	1,493	20.18
Gross margin			1,576	19.80	1,495	19.97	1,512	20.45
Operations, maintenance, and administration			549	6.90	550	7.35	487	6.58
Depreciation and amortization			438	5.50	453	6.05	409	5.53
Taxes, other than income taxes			27	0.34	22	0.29	19	0.26
Intersegment cost allocation			5	0.06	32	0.43	30	0.41
Operating expenses			1,019	12.80	1,057	14.12	945	12.78
Operating income			557	7.00	438	5.85	567	7.67
Installed capacity (GWh)			79,591		74,866		73,969
Production (GWh)			48,614		45,736		48,891
Availability (%)			88.9		85.1		85.8
Generation Production and Gross Margins
Generation’s production volumes, revenues, fuel and purchased power costs, and gross margins based on geographical regions and fuel type are presented below.
Year ended Dec. 31, 2010	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh	Fuel & purchased power per installed MWh	Gross margin per installed MWh
Coal	25,025	31,325	813	335	478	25.95	10.69	15.26
Gas	3,981	4,866	232	76	156	47.68	15.62	32.06
Renewables	2,506	11,120	142	10	132	12.77	0.90	11.87
Total Western Canada	31,512	47,311	1,187	421	766	25.09	8.90	16.19
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	12,053	773	470	303	64.13	38.99	25.14
Gas	2,063	6,736	140	56	84	20.78	8.31	12.47
Renewables	1,299	1,486	117	5	112	78.73	3.36	75.37
Total International	11,956	20,275	1,030	531	499	50.80	26.19	24.61
	48,614	79,591	2,778	1,202	1,576	34.90	15.10	19.80
Year ended Dec. 31, 2009	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh	Fuel & purchased power per installed MWh	Gross margin per installed MWh
Coal	24,517	32,833	838	349	489	25.52	10.63	14.89
Gas	4,035	4,744	228	79	149	48.06	16.65	31.41
Renewables	1,891	8,757	116	7	109	13.25	0.80	12.45
Total Western Canada	30,443	46,334	1,182	435	747	25.51	9.39	16.12
Gas	3,377	6,570	388	224	164	59.06	34.09	24.97
Renewables	452	1,686	40	1	39	23.72	0.59	23.13
Total Eastern Canada	3,829	8,256	428	225	203	51.84	27.25	24.59
Coal	7,450	12,053	767	476	291	63.63	39.49	24.14
Gas	2,637	6,736	213	82	131	31.62	12.17	19.45
Renewables	1,377	1,486	133	10	123	89.50	6.73	82.77
Total International	11,464	20,275	1,113	568	545	54.89	28.01	26.88
	45,736	74,865	2,723	1,228	1,495	36.37	16.40	19.97

M a n a g e m e n t ’ s   D i s c u s s i o n   a n d   A n a l y s i s 19

Year ended Dec. 31, 2008	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh	Fuel & purchased power per installed MWh	Gross margin per installed  MWh
Coal	26,327	32,788	856	374	482	26.11	11.41	14.70
Gas	3,875	4,718	291	145	146	61.68	30.73	30.95
Renewables	2,162	8,590	167	6	161	19.44	0.70	18.74
Total Western Canada	32,364	46,096	1,314	525	789	28.51	11.39	17.12
Gas	3,290	7,194	501	351	150	69.64	48.79	20.85
Total Eastern Canada	3,290	7,194	501	351	150	69.64	48.79	20.85
Coal	8,753	12,327	756	467	289	61.33	37.88	23.45
Gas	3,152	6,861	298	111	187	43.43	16.18	27.25
Renewables	1,332	1,491	136	39	97	91.21	26.16	65.05
Total International	13,237	20,679	1,190	617	573	57.55	29.84	27.71
	48,891	73,969	3,005	1,493	1,512	40.63	20.18	20.45

Western Canada

Our Western Canada assets consist of four coal plants, three natural gas-fired facilities, 20 hydro facilities, 12 wind farms, and one biomass facility with a total gross generating capacity of 5,384 MW (5,098 MW net ownership interest). In 2010, we decommissioned our 279 MW Wabamun plant and also began commercial operations at Ardenville, a 69 MW wind farm, and Summerview 2, a 66 MW wind farm. We are currently constructing Keephills 3, a 450 MW (225 MW net ownership interest) merchant coal plant, under a joint venture with Capital Power, which is scheduled to enter commercial production in 2011. We are currently performing uprates of 23 MW each on Unit 1 and Unit 2 of our Keephills plant, which are scheduled to be completed by the fourth quarter of 2012. We are also currently constructing Bone Creek, a hydro facility in British Columbia, which will have a generating capacity of 19 MW and is scheduled to enter commercial production in 2011.

Our Sundance, Keephills, and Sheerness plants, and 13 hydro facilities operate under PPAs with a gross generating capacity of 4,083 MW (3,888 MW net ownership interest). Under the PPAs, we earn monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for our plants and mines. We also earn energy payments for the recovery of predetermined variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability, and an excess energy payment for power production above committed capacity. Additional capacity added to these units that is not included in capacity covered by the PPAs is sold on the merchant market.

Our Genesee 3 plant, 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, Meridian, Fort Saskatchewan, 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.

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

For the year ended Dec. 31, 2010, production increased 1,069 GWh compared to the same period in 2009 primarily due to lower planned and unplanned outages at our Sundance plant, lower planned outages at our Keephills plant, and higher wind and hydro volumes primarily due to the acquisition of Canadian Hydro, partially offset by the decommissioning of Wabamun.

In 2009, production decreased 1,921 GWh due to higher planned and unplanned outages at our Sundance and Wabamun plants, higher planned outages at Keephills, lower PPA customer demand, and lower hydro volumes, partially offset by lower planned and unplanned outages at Genesee 3, lower unplanned outages at Keephills, and higher wind volumes due to the acquisition of Canadian Hydro.

Gross margin for the year ended Dec. 31, 2010 increased $19 million ($0.07 per installed MWh) compared to the same period in 2009 primarily due to lower planned and unplanned outages at our Sundance plant, higher wind and hydro volumes as a result of the acquisition of Canadian Hydro, and lower planned outages at our Keephills plant, partially offset by unfavourable pricing and the decommissioning of Wabamun.

20 T r a n s A l t a   C o r p o r a t i o n

In 2009, gross margin decreased $42 million ($1.00 per installed MWh) due to higher planned outages at our Sundance and Wabamun plants, higher planned outages at Keephills, and lower hydro volumes and prices, partially offset by lower planned and unplanned outages at Genesee 3, lower unplanned outages at Keephills, an adjustment to prior period indices, lower penalties due to lower spot prices, and higher wind volumes due to the acquisition of Canadian Hydro.

Eastern Canada

In 2010, we began commercial operations at Kent Hills 2, a 54 MW expansion of our Kent Hills wind farm in New Brunswick. Natural Forces exercised their option to purchase a 17 per cent interest in the Kent Hills 2 project subsequent to the commencement of commercial operations.

Our Eastern Canada assets consist of four natural gas-fired facilities, five hydro facilities, and five wind farms with a total gross generating capacity of 1,410 MW (1,263 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, 2010, production increased 1,317 GWh compared to the same period in 2009 due to higher wind and hydro volumes primarily as a result of the acquisition of Canadian Hydro, and market conditions at our natural gas-fired facilities.

In 2009, production increased 539 GWh primarily due to higher wind and hydro volumes as a result of the acquisition of Canadian Hydro and the commissioning of Kent Hills.

For the years ended Dec. 31, 2010 and 2009, gross margin increased $108 million ($1.32 per installed MWh) and $53 million ($3.74 per installed MWh), respectively, due to higher wind and hydro volumes primarily as a result of the acquisition of Canadian Hydro, and market conditions at our natural gas-fired facilities.

International

Our international assets consist of natural gas, coal, hydro, and geothermal assets in various locations in the United States with a generating capacity of 2,015 MW and natural gas- and diesel-fired assets in Australia with a generating capacity of 300 MW. 385 MW of our United States assets are operated by CE Gen, a joint venture in which we have a 50 per cent interest.

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

For the year ended Dec. 31, 2010, production increased 492 GWh compared to the same period in 2009 primarily due to lower unplanned outages and lower economic dispatching at Centralia Thermal, partially offset by higher planned outages at Centralia Thermal and the expiration of our long-term contract at Saranac in the second quarter of 2009.

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

For the year ended Dec. 31, 2010, gross margins decreased $46 million ($2.27 per installed MWh) compared to the same period in 2009 primarily due to the expiration of the long-term contract at Saranac and unfavourable foreign exchange rates, partially offset by favourable mark-to-market movements and favourable pricing primarily related to purchased power.

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

During the fourth quarter of 2010, unrealized pre-tax gains of $43 million were recorded in earnings due to certain power hedging relationships 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 were 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 occur during the second quarter of 2011. While future reported earnings will be lower, the expected cash flows from these contracts will not change.

The long-term contract between our Saranac facility and New York State Electric and Gas expired in June 2009. The facility now operates under a combined capacity and merchant dispatch contract, resulting in lower production and gross margin for the year ended Dec. 31, 2010. As a portion of the facility is owned by a third party, there is also a decrease in earnings attributable to non-controlling interests. The net pre-tax earnings impact of the expiration of this contract is a decrease of approximately $10 million for the year ended Dec. 31, 2010.

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 21

Operations, Maintenance, and Administration

For the year ended Dec. 31, OM&A expenses decreased compared to the same period in 2009 due to lower planned outages, favourable foreign exchange rates, and targeted cost savings, partially offset by information system costs directly attributable to our operations previously borne by the Corporate segment now being directly charged to the Generation segment in 2010 and the acquisition of Canadian Hydro.

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

Planned Maintenance

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

Year ended Dec. 31	2010	2009	2008
Capitalized	127	115	125
Expensed	70	118	68
	197	233	193
GWh lost	2,739	3,732	3,478

For the year ended Dec. 31, 2010, total planned maintenance costs decreased $36 million compared to the same period in 2009 due to lower planned outages across the fleet. In 2010, production lost as a result of planned maintenance decreased 993 GWh compared to the same period in 2009 primarily due to lower planned outages at our Sundance plant and Centralia Thermal.

In 2009, total planned maintenance costs increased $40 million due to higher planned outages across the fleet and cost escalations. Production lost as a result of planned maintenance increased by 254 GWh primarily due to the uprate on Unit 5 at our Sundance plant.

Depreciation Expense

For the year ended Dec. 31, 2010, depreciation expense decreased compared to the same period in 2009 due to a change in the estimated useful lives of certain coal generation facilities and mining assets, a reduction in the estimated costs associated with decommissioning our Wabamun plant, lower depreciation at Saranac following the expiration of its long-term contract, and favourable foreign exchange rates, partially offset by an increased asset base primarily due to the acquisition of Canadian Hydro.

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

Asset Impairment Charges

During the fourth quarter of 2010, we completed our annual comprehensive impairment assessment based on fair value estimates derived from our long-range forecast and market values evidenced in the marketplace. As a result, we recorded pre-tax asset impairment charges of $89 million ($79 million after deducting the amount that is attributable to the non-controlling interest) on certain Generation assets, comprised of a $65 million charge against our natural gas fleet and a $24 million charge against our coal fleet. The natural gas fleet impairment reflects lower forecast pricing at one of our merchant facilities and the pending sale of our 50 per cent interest in our Meridian facility, which had no impact to consolidated earnings as the impairment was attributable to the non-controlling interest. The coal fleet impairment relates to Units 1 and 2 at our Sundance facility and primarily reflects our shift in 2010 to managing our coal-fired generation facilities on a unit pair basis, resulting in the impairment assessment now being performed on a unit pair basis.

In 2006, we ceased mining activities at the Centralia mine but continued to develop the option to mine the Westfield site, a coal reserve located adjacent to Centralia Thermal. With the successful modifications of the boilers at Centralia Thermal and longer-term contracts in place to supply coal, the project to develop the Westfield site was placed on hold indefinitely and in 2009, the costs that had been capitalized were expensed.

22 T r a n s A l t a   C o r p o r a t i o n

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.

Energy Trading manages available generating capacity, as well as the fuel and transmission needs, of the Generation business by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas 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 Canadian GAAP. Changes in the fair value of the portfolio are recognized in earnings in the period they occur.

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

A portion of OM&A costs incurred within 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. During 2010, certain support costs previously borne by the Energy Trading segment and recovered through the intersegment fee started being directly charged to the Generation segment.

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

Year ended Dec. 31	2010		2009		2008
Gross margin	41		47		105
Operations, maintenance, and administration	17		31		53
Depreciation and amortization	2		4		3
Intersegment cost allocation	(5	)	(32	)	(30	)
Operating expenses	14		3		26
Operating income	27		44		79

For the year ended Dec. 31, 2010, Energy Trading gross margins decreased compared to the same period in 2009 primarily due to reduced margins resulting from reduced market demand and narrowing inter-season spreads in the western region.

In 2009, Energy Trading gross margins decreased due to a reduction in industrial demand, gas price uncertainty, and the change in the California market, which resulted in reduced pricing spreads and smaller margins.

For the year ended Dec. 31, 2010, OM&A costs and the intersegment fee decreased compared to the same period in 2009 as a result of the change in how we record certain support costs between the Energy Trading and Generation segments, as described above.

For the year ended Dec. 31, 2009, OM&A expenses decreased due to a reduction in both discretionary expenditures and staff compensation costs. The intersegment fee in 2009 was comparable to 2008.

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 23

CORPORATE:Our Generation and Energy Trading business 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	2010	2009	2008
Operations, maintenance, and administration	68	86	97
Depreciation and amortization	19	18	16
Operating expenses	87	104	113

OM&A costs for the year ended Dec. 31, 2010 decreased compared to the same period in 2009 primarily due to information system costs directly attributable to our operations previously borne by the Corporate segment now being directly charged to the Generation segment in 2010.

In 2009, OM&A costs decreased primarily due to a reduction in staff compensation costs.

Net Interest Expense

Year ended Dec. 31	2010		2009		2008
Interest on debt	243		183		177
Capitalized interest	(48	)	(36	)	(21	)
Interest income from the resolution of certain outstanding tax matters	(14	)	-		(30	)
Interest income	(3	)	(6	)	(16	)
Other	-		3		-
Net interest expense	178		144		110

Net interest expense for the year ended Dec. 31, 2010 increased compared to the same period in 2009 due to higher debt levels, partially offset by interest income related to the resolution of certain outstanding tax matters, higher capitalized interest, favourable foreign exchange, and lower interest rates.

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

Other Income

In 2009, we settled an outstanding commercial issue that was recorded as a pre-tax gain of $7 million in other income as it related to our previously held Mexican equity investment. We also recorded a pre-tax gain of $1 million on the sale of a 17 per cent interest in our Kent Hills wind farm. The sale of a 17 per cent interest in our Kent Hills 2 wind farm expansion project in 2010 did not have a significant impact on net earnings.

Non-Controlling Interests

We own 50.01 per cent of TA Cogen, which owns, operates, or has an interest in five natural gas-fired and one coal-fired generating facility with a total gross generating capacity of 814 MW. Stanley Power owns the minority interest in TA Cogen. Our CE Gen joint venture investment includes a 75 per cent ownership of Saranac, a 320 MW natural gas-fired cogeneration facility in New York. Natural Forces owns a 17 per cent interest in our Kent Hills facility, which operates 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. For Saranac, we proportionately consolidate our share of the earnings, assets, and liabilities in relation to our ownership.

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

The earnings attributable to non-controlling interests for the year ended Dec. 31, 2010 decreased compared to the same period in 2009 due to lower earnings at CE Gen as a result of the expiration of the long-term contract at our Saranac facility and an asset impairment charge related to the pending sale of our Meridian facility, partially offset by higher earnings at TA Cogen.

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

24 T r a n s  A l t a   C o r p o r a t i o n

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 future 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 future income tax assets or liabilities is recognized in earnings in the period the new rates are substantively enacted.

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

Year ended Dec. 31	2010		2009		2008
Earnings before income taxes	220		196		258
Asset impairment charges	79		16		-
Unrealized gains related to ineffectiveness in certain power hedging relationships	(43	)	-		-
Settlement of commercial issue	-		(7	)	-
Change in life of Centralia parts	-		2		18
Gain on sale of assets at Centralia	-		-		(6	)
Writedown of Mexican equity investment	-		-		97
Comparable earnings1 before income taxes	256		207		367
Income tax expense	1		15		23
Income tax recovery on asset impairment charges	25		6		-
Income tax expense related to ineffectiveness in certain power hedging relationships	(15	)	-		-
Income tax recovery related to the resolution of certain outstanding tax matters	30		-		-
Income tax expense on settlement of commercial issue	-		(1	)	-
Income tax recovery on change in life of Centralia parts	-		1		6
Income tax recovery related to change in future tax rates	-		5		-
Income tax expense on gain on sale of assets at Centralia	-		-		(2	)
Income tax recovery recorded on the sale of our Mexican equity investment	-		-		35
Income tax recovery related to tax positions	-		-		15
Income tax expense excluding non-comparable items	41		26		77
Effective tax rate on comparable earnings before income taxes (%)	16		13		21

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

Income tax expense excluding non-comparable items increased for the year ended Dec. 31, 2010 compared to the same period in 2009 as a result of higher comparable earnings before income taxes.

In 2009, the income tax expense excluding non-comparable items decreased due to lower pre-tax earnings and the recovery recorded for a change in future tax rates related to tax liabilities recorded in prior periods, partially offset by the tax recovery related to tax positions recorded in 2008.

The effective tax rate increased for the year ended Dec. 31, 2010 and decreased for the year ended Dec. 31, 2009 primarily due to certain deductions that do not fluctuate with earnings and a change in the mix of jurisdictions where pre-tax income is earned.

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 25

Financial Position

The following chart outlines significant changes in the Consolidated Balance Sheets from Dec. 31, 2009 to Dec. 31, 2010:

	Increase/
	(decrease)		Primary factors explaining change
Cash and cash equivalents	(24	)	Improved cash management
Income taxes receivable	(20	)	Recovery of tax prepayments and overpayments
Inventory	(37	)	Higher production at coal facilities
Long-term receivable	(49	)	Resolution of certain outstanding tax matters
Risk management assets (current and long-term)	105		Price movements
Property, plant, and equipment, net	18		Capital additions, partially offset by depreciation, the Canadian Hydro purchase price allocation adjustment, asset impairment, and foreign exchange
Assets held for sale	60		Meridian assets
Goodwill	83		Canadian Hydro purchase price allocation adjustment
Intangible assets	(40	)	Canadian Hydro purchase price allocation adjustment and amortization expense
Accounts payable and accrued liabilities	(18	)	Timing of payments, combined with lower operational expenditures
Collateral received	40		Collateral collected from counterparties as a result of a change in forward prices
Dividends payable	69		Timing of Q1 2011 quarterly cash dividend declaration
Long-term debt (including current portion)	(208	)	Repayment of long-term debt, partially offset by the issuance of U.S.$300 million senior notes
Risk management liabilities (current and long-term)	35		Price movements
Asset retirement obligation (including current portion)	(40	)	Revised cost estimate of the decommissioning of our Wabamun plant and foreign exchange
Deferred credits and other long-term liabilities	22		Timing of deferred revenues and commitments
Non-controlling interests	(43	)	Distributions and hedging losses in excess of earnings attributable to non-controlling interest and increased investment in Kent Hills
Shareholders’ equity	248		Issuance of preferred shares, net earnings, and movements in AOCI, partially offset by dividends declared

Financial Instruments

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

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 self-sustaining foreign operations. 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.

The majority of our financial instruments and physical commodity contracts are recorded under normal purchase/normal sale accounting or qualify for, and are recorded under, hedge accounting rules. As a result, for those contracts for which we have elected hedge accounting, no gains or losses are recorded through the Consolidated Statements of Earnings as a result of differences between the contract price and the current forecast of future prices. We record the changes in fair value of these contracts through the Consolidated Statements of Comprehensive Income. When these contracts are settled, the value previously recorded in Other Comprehensive Income (“OCI”) is reversed and we receive the contracted cash amount for those contracts.

Under hedge accounting rules we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting can still be applied. 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 is recognized in OCI, as discussed above, while any ineffective portion is recognized in net earnings.

26 T r a n s A l t a   C o r p o r a t i o n

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

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

Fair Value Hedges

Fair value hedges are used to offset the impact of fluctuations in the foreign currency and interest rates on various assets and liabilities. Interest rate swaps are used to hedge exposures in the fair value of long-term debt caused by variations in market interest rates by fixing interest rates. Foreign exchange contracts are used to hedge certain foreign currency denominated assets and liabilities.

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

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract1	-	-	-	-
Reporting date (marked-to-market)	ü	-	ü	-
Settle contract	ü	-	ü	ü

1  Option contracts may require an upfront cash investment.

Cash Flow Hedges

Cash flow hedges are categorized as project or commodity hedges and are used to offset foreign exchange and commodity price exposures on long-term projects as a result of market fluctuations. These contracts have a maximum duration of five years.

Project Hedges

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

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract1	-	-	-	-
Reporting date (marked-to-market)2	-	ü	ü	-
Roll-over into new contract	-	ü	ü	ü
Settle contract	-	ü	ü	ü

1    Option contracts may require an upfront cash investment.

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

Commodity Hedges

Physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, and options are used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. When commodity hedges qualify for, and we have elected to use hedge accounting, the fair value of the hedges is recorded in risk management assets or liabilities with changes in value being reported in OCI, up until the date of settlement. The fair value of the majority of our commodity hedges are calculated using adjusted quoted prices from an active market and/or the input is validated by broker quotes. Upon settlement of these financial instruments, the amounts previously recognized in OCI are reclassified to net earnings.

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 27

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract1	-	-	-	-
Reporting date (marked-to-market)2	-	ü	ü	-
Settle contract	ü	ü	ü	ü

1    Option contracts may require an upfront cash investment.

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

During the year, the change in the position of financial instruments to a net asset position is primarily a result of changes in future prices on contracts in our Generation segment. Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding fair valuation techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2009.

In limited circumstances, we may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under Canadian GAAP as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, therefore fair value is determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles, and/or volatilities and correlations between products derived from historical prices. Where commodity transactions extend into periods for which market-observable prices are not available, an internally developed fundamental price forecast is used in the valuation. Fair values are validated by using 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, 2010, Level III instruments had a net liability carrying value of $20 million.

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

Net Investment Hedges

Cross-currency interest rate swaps, foreign currency forward contracts, and foreign currency debts can be used to hedge exposure to changes in the carrying values of our net investments in foreign operations having functional currency other than the Canadian dollar. Foreign denominated expenses are also used to assist in managing foreign currency exposures on earnings from self-sustaining foreign operations.

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.

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

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

Non-Hedges

We use natural hedges as much as possible, such as U.S. interest rates on our U.S. denominated long-term debt, to offset any exposures related to changes in foreign exchange rates. Financial instruments not designated as hedges are used to reduce currency risk on the results of our foreign operations due to the fluctuation of exchange rates beyond what is naturally hedged. All gains or losses related to non-hedges are recorded in the Consolidated Statements of Earnings as they either do not qualify for, or have not been designated for, hedge accounting.

28 T r a n s A l t a   C o r p o r a t i o n

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

		Consolidated
	Consolidated	Statements of	Consolidated	Consolidated
	Statements of	Comprehensive	Balance	Statements of
Event	Earnings	Income	Sheets	Cash Flows
Enter into contract1	-	-	ü	-
Reporting date (marked-to-market)	ü	-	ü	-
Roll-over into new contract	ü	-	ü	ü
Settle contract	ü	-	ü	ü
Divest contract	ü	-	ü	ü

1    Some contracts may require an initial cash investment.

Employee Share Ownership

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

Under the terms of our Stock Option Plans, employees below manager level receive grants that vest in equal installments over four years, and expire after 10 years.  The conversion of these options does not materially affect the calculation of the total weighted average number of common shares outstanding.

Under the terms of the Performance Share Ownership Plan (“PSOP”), certain employees receive grants which, after three years, make them eligible to receive a set number of common shares or the equivalent value in cash plus dividends based upon our performance relative to companies comprising the comparator group. After three years, once PSOP eligibility has been determined and if common shares are granted, 50 per cent of the common shares are released to the participant and the remaining 50 per cent are held in trust for one additional year 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 senior manager level for up to 30 per cent of the employee’s base salary for the purchase of our common shares from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2010, accounts receivable from employees under the plan totalled $2 million (2009 - $3 million). This program is not available to officers and senior management.

Employee Future Benefits

We have registered pension plans in Canada and the U.S. covering substantially all employees of the Corporation, its domestic subsidiaries, and specific named employees working internationally. These plans have defined benefit and defined contribution options. In Canada, there is a supplemental defined benefit plan for Canadian-based defined contribution members whose annual earnings exceed the Canadian income tax limit. The defined benefit option of the registered pension plan ceased for new employees on June 30, 1998. The latest actuarial valuations for accounting purposes of the registered and supplemental pension plans were as at Dec. 31, 2010.

We provide other health and dental benefits to the age of 65 for both disabled members and retired members (other post-retirement benefits). The last actuarial valuation of these plans was conducted at Dec. 31, 2010.

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 $62 million to secure the obligations under the supplemental plan.

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 29

Statements of Cash Flows

The following charts highlight significant changes in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2010 and 2009:

Year ended Dec. 31	2010		2009		Explanation of change
Cash and cash equivalents, beginning of year	82		50
Provided by (used in):
Operating activities	811		580		Higher cash earnings of $54 million and favourable changes in working capital of $177 million due to the timing of operational payments, favourable inventory movements, and the timing of certain tax-related recoveries.
Investing activities	(720	)	(1,598	)	Acquisition of Canadian Hydro, net of cash acquired, for $766 million in 2009 and a decrease in 2010 capital spending of $114 million, partially offset by a decrease in collateral received from counterparties of $40 million.
Financing activities	(113	)	1,053		Increase of $818 million in proceeds from the issuance of long-term debt and $397 million from the issuance of common shares in 2009, and a net increase in the repayment of debt of $255 million, partially offset by proceeds of $291 million from the issuance of preferred shares in 2010.
Translation of foreign currency cash	(2	)	(3	)
Cash and cash equivalents, end of year	58		82
Year ended Dec. 31	2009		2008		Explanation of change
Cash and cash equivalents, beginning of year	50		51
Provided by (used in):
Operating activities	580		1,038		Decrease in cash earnings of $99 million and unfavourable changes in working capital of $359 million.
Investing activities	(1,598	)	(581	)	Acquisition of Canadian Hydro, net of cash acquired, for $766 million and the sale of our Mexican equity investment in 2008 for $332 million, partially offset by a decrease in capital spending of $102 million and an increase in collateral received from counterparties of $87 million.
Financing activities	1,053		(467	)	Increase in draws on credit facilities of $863 million, increase in proceeds from the issuance of long-term debt of $617 million, increase in proceeds from the issuance of common shares of $382 million, and the purchase of common shares under the NCIB program in 2008 of $130 million, partially offset by a $488 million increase in the repayment of long-term debt.
Translation of foreign currency cash	(3	)	9
Cash and cash equivalents, end of year	82		50

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.

30 T r a n s A l t a   C o r p o r a t i o n

Debt

Recourse and non-recourse debt totalled $4.2 billion at Dec. 31, 2010 compared to $4.4 billion at Dec. 31, 2009. Total long-term debt decreased from Dec. 31, 2009 primarily due to the issuance of preferred shares and favourable foreign exchange movements, partially offset by growth capital expenditures.

Credit Facilities

At Dec. 31, 2010, we had a total of $2.0 billion (2009 - $2.1 billion) of committed credit facilities of which $1.1 billion (2009 - $0.7 billion) is not drawn and is available, subject to customary borrowing conditions. At Dec. 31, 2010, the $0.9 billion (2009 - $1.4 billion) of credit utilized under these facilities is comprised of actual drawings of $0.6 billion (2009 - $1.1 billion) and of letters of credit of $0.3 billion (2009 - $0.3 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility, which matures in 2012, with the remainder comprised of bilateral credit facilities that mature between the fourth quarter of 2012 and the third quarter of 2013. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

In addition to the $1.1 billion available under the credit facilities, we also have $58 million of cash.

Share Capital

At Dec. 31, 2010, we had 220.3 million (2009 - 218.4 million) common shares issued and outstanding. During the year ended Dec. 31, 2010, 1.9 million (2009 - 20.8 million) common shares were issued for $42 million (2009 - $408 million), of which $37 million (2009 - nil) was issued under the terms of the DRASP plan.

During the year ended and as at Dec. 31, 2010, 12.0 million (2009 - nil) first preferred shares were issued for $239 million (2009 - nil).

On Feb. 23, 2011, we had 221.2 million common shares and 12.0 million first preferred shares outstanding.

NCIB Program

For the year ended Dec. 31, 2010, no shares were acquired or cancelled under the NCIB program prior to its expiry on May 6, 2010. In 2009, no shares were acquired or cancelled under the NCIB program.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, energy trading activities, hedging activities, and purchase obligations. At Dec. 31, 2010, we provided letters of credit totalling $297 million (2009 - $334 million) and cash collateral of $27 million (2009 - $27 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Balance Sheets under risk management liabilities and asset retirement obligation.

Working Capital

At Dec. 31, 2010, the excess of current liabilities over current assets is $246 million (2009 - $10 million). The excess of current liabilities over current assets increased $236 million compared to 2009 due to an increase in the current portion of long-term debt and a decrease in collateral received from counterparties, partially offset by an increase in net risk management assets, lower operational expenditures and the timing of related payments, favourable inventory movements, and the timing of certain tax recoveries.

Capital Structure

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

	2010		2009
As at Dec. 31	Amount	%	Amount	%
Debt, net of cash and cash equivalents	4,177	54	4,360	56
Non-controlling interests	435	6	478	6
Shareholders’ equity	3,177	41	2,929	38
Total capital	7,789	100	7,767	100

M a n a g e m e n t ' s   D i s c u s s i o n   a n d   A n a l y s i s 31

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			Coal supply	Long-term		Interest on	Growth
	gas purchase		Operating	and mining	service	Long-term	long-term	project
	contracts	Transmission	leases	agreements	agreements	debt1	debt2	commitments	Total
2011	8	1	14	55	19	253	237	106	693
2012	8	6	13	55	18	674	214	36	1,024
2013	9	7	12	55	17	629	194	-	923
2014	8	7	11	55	17	231	157	-	486
2015	8	7	10	60	9	681	127	-	902
2016 and thereafter	22	12	52	320	3	1,769	960	-	3,138
Total	63	40	112	600	83	4,237	1,889	142	7,166

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.

Off-Balance Sheet Arrangements

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

Climate Change and the Environment

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 and hydro, 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 business.

Canada

On June 23, 2010, the Government of Canada announced plans to regulate GHG emissions from the coal-fired power sector. The proposal, if passed into law, would become effective in 2015 and require existing coal-fired plants to meet a natural gas emissions performance standard by their 45th year of operation, or the end of their PPA term, whichever is later. If the plants subject to the regulation do not meet the required performance standard by that time, they would be required to cease operations. Until then, the plants would not be subject to any federal GHG compliance costs.

The federal government continues with the drafting of the above regulations, and has stated its intention to release draft regulations by April 2011. The draft regulations would then be subject to consultations with provinces, industry, and the public. We are in discussions with both the Governments of Canada and Alberta about the design of the proposed regulation.

The above development would provide regulatory clarity for future capital decision-making. There are some issues that will have to be resolved, including how transition costs are recovered by generators, standards for emission requirements for natural gas-fired facilities, and how CCS will continue to be supported. The effect of this proposal on the Alberta deregulated market and PPA structure must also be considered.

Additionally, work has continued on the development of a national Clean Air Management System (“CAMS”) for air pollutants. Development work is being done through collective efforts of federal and provincial governments, industry, and environmental organizations, with the goal of constructing an acceptable national structure for managing pollutants such as sulphur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulates. Conceptually the system would establish baseline ambient air quality standards, industry emission standards, and mechanisms to address areas of non-compliance. It is expected that the CAMS model would default to provincial jurisdiction unless air quality problems remain unresolved. This process is expected to take several more years to complete. We are involved in the working groups. The impact of CAMS on our operations, if implemented, is not evident at this time.

32 T r a n s A l t a   C o r p o r a t i o n

In Ontario, the provincial government continues to develop its plans for a GHG regulatory framework consistent with the Western Climate Initiative (“WCI”) model. The WCI model is a cap and trade design being developed jointly between several Canadian provinces and U.S. states, including California, to establish similar reduction targets and a common emissions trading market. Details of the Government of Ontario’s proposed design have not yet been released.

In Alberta, mercury capture technology was installed by the end of the year and began operating at our coal-fired plants in order to achieve compliance with the Alberta requirement to reduce mercury emissions by 70 per cent by Jan. 1, 2011. To date, the mercury reduction requirements at these plants have been met.

In British Columbia, the provincial government is in the process of developing regulations for emissions trading and an offsets system under the Greenhouse Gas Reduction (Cap and Trade) Act. The system would be compatible with the WCI model. Consultations are underway regarding its design, with finalization of the regulations expected in 2011. Given our low-carbon operations in British Columbia, this regulatory initiative is not expected to have any material impact on the Corporation.

United States

In the absence of legislative action, the administration is moving to regulate greenhouse gases under the Clean Air Act. Under the “tailoring rule” adopted in 2010, on July 1, 2011, the Environmental Protection Agency (“EPA”) will require new plants, or major modifications to existing plants, to acquire permits for GHGs. After that point, new or modified plants that otherwise would trigger major source preconstruction permit thresholds would be required to employ best available technology to reduce their GHG emissions. The EPA began implementing these rules on Jan. 2, 2011. The definition of best available technology has not yet been determined. This EPA regulation is expected to face legal challenges as well as some opposition from Congress, and may be subject to further refinement in other rulemakings.

Further, at the end of December in 2010, the EPA stated its intentions to implement New Source Performance Standards for GHGs for power plants and refineries. These proposed regulations would cover emissions from both new and existing sources, and are expected to be completed by the end of 2012. The EPA does not expect existing sources would be affected until 2015 or 2016. These proposed regulations have not yet been developed so their impact is unclear. Again, this initiative is expected to face legal hurdles.

In Washington, we have been working with the state government to develop a plan to reduce GHG emissions from our Centralia Thermal plant, consistent with the Governor’s Executive Order to reduce emissions by approximately 50 per cent of current levels by 2025. Discussions with Washington State and other stakeholders are ongoing.

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 affect 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.

In 2010, we estimate that 37 million tonnes of GHGs with an intensity of 0.976 tonnes per MWh (2009 - 36 million tonnes of GHGs with an intensity of 0.980 tonnes per MWh) were emitted as a result of normal operating activities1. Increased energy production from our fossil-based assets and the related increase in emissions were partially offset by the decommissioning of Unit 4 at our Wabamun plant, which represents a reduction of approximately two million tonnes per year of GHGs. The various activities discussed above, including our investment in renewable power and CCS technology, are designed to minimize the environmental and financial impacts of the expected increase in emissions.

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

Our environmental management programs encompass the following elements:

Renewable Power

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

1    2010 data are estimates based on best available data at the time of report production. GHGs include water vapour, CO2 , methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO2 emissions from stationary combustion.

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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 3 plant will use 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 our Genesee 3 plant.

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

CCS Development

On Oct. 14, 2009, the governments of Canada and Alberta announced that Project Pioneer, our CCS project, received funding commitments of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding supports a FEED study that is expected to be completed in 2011. Once built, the prototype plant will be one of the largest integrated CCS power facilities in the world. The project will be designed to capture one megatonne of carbon dioxide (“CO2”) per year from our new 450 MW (225 MW net ownership interest) Keephills 3 coal plant. The CO2 will be used for enhanced oil recovery as well as injected into a permanent geological storage site. Additionally, on Nov. 28, 2010, Project Pioneer was awarded $5 million from the Global Carbon Capture and Storage Institute to enhance knowledge transfer from the project both nationally and globally.

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

Offsets Portfolio

TransAlta maintains an offset portfolio with a variety of instruments than can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet emission targets at a competitive cost. We ensure that any investments in offsets will meet certification criteria in the market in which they are to be used.

Forward Looking Statements

This MD&A, the documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities, include forward looking statements. All forward looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management’s experience and perception of historical trends, current conditions, and expected further developments, as well as other factors deemed appropriate in the circumstances. Forward looking statements are not facts, but only predictions, and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from 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 upgrades, and their attendant costs; expectations related to future earnings and cash flow from operating activities; expectations relating to the timing of the completion of the FEED study regarding CCS and the cost of the study; estimates of fuel supply and demand conditions and the costs of procuring fuel; our plans to invest in existing and new capacity, and the expected return on those investments; expectations for demand for electricity in both the short term and long term, and the resulting impact on electricity prices; expectations in respect of generation availability and production; expectations in terms of the cost of operations and maintenance, and the variability of those costs; our plans to install mercury control equipment at our Alberta Thermal operations and our initiative to reduce nitrogen oxide and mercury emissions from Centralia Thermal; expected governmental regulatory regimes and legislation, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; expectations relating to the renegotiation of certain of the collective bargaining agreements to which we are a party; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; expectations for the outcome of existing or potential legal claims; and expectations for the ability to access capital markets at reasonable terms.

34 T r a n s A l t a   C o r p o r a t i o n

Factors that may adversely impact our forward looking statements include risks relating to: (i) fluctuations in market prices and availability of fuel supplies required to generate electricity and in the price of electricity; (ii) the regulatory and political environments in the jurisdictions in which we operate; (iii) environmental requirements and changes in, or liabilities under, these requirements; (iv) changes in general economic conditions including interest rates; (v) operational risks involving our facilities, including unplanned outages at such facilities; (vi) disruptions in the transmission and distribution of electricity; (vii) effects of weather; (viii) disruptions in the source of fuels, water, wind, or biomass required to operate our facilities; (ix) natural disasters; (x) equipment failure; (xi) trading risks; (xii) industry risk and competition; (xiii) fluctuations in the value of foreign currencies and foreign political risks; (xiv) need for additional financing; (xv) structural subordination of securities; (xvi) counterparty credit risk; (xvii) insurance coverage; (xviii) our provision for income taxes; (xix) legal proceedings involving the Corporation; (xx) reliance on key personnel; (xxi) labour relations matters; and (xxii) development projects and acquisitions. The foregoing risk factors, among others, are described in further detail in the Risk Management section of this MD&A and under the heading “Risk Factors” in our 2010 Annual Information Form.

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

2011 Outlook

In 2011, we anticipate modest comparable EPS growth based upon the factors that are discussed below.

Business Environment

Power Prices

In 2011, power prices are expected to remain at 2010 levels due to the influence of low natural gas prices. In the Alberta market, the longer-term fundamentals of the market remain positive and the recovery of the oil sands is expected to drive load growth. In the Pacific Northwest, the recovery of natural gas prices is the main driver behind any recovery of power prices. Natural gas prices are expected to remain low until 2012.

Environmental Legislation

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

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

Economic Environment

The economic environment has shown signs of improvement in 2010 and we expect this trend to continue through 2011 at a slow to moderate pace.

We had no counterparty losses in 2010, 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.

Operations

Capacity, Production, and Availability

Generating capacity is expected to increase in 2011 due to the start of commercial operations at Keephills 3 and Bone Creek. Overall production is expected to increase in 2011 due to the start of commercial operations at Keephills 3 and Bone Creek, lower planned and unplanned outages, and higher customer demand. Overall fleet availability is expected to be approximately 89 to 90 per cent in 2011 due to lower planned and unplanned outages.

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Commodity Hedging

Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 75 per cent of our capacity is contracted over the next seven years. On an aggregated portfolio basis 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 2010, approximately 88 per cent of our 2011 capacity was contracted. The average price of our short-term physical and financial contracts in 2011 ranges from $65-$70 per MWh in Alberta, and from U.S.$55-$60 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 mines are minimized through the application of standard costing. Coal costs for 2011, on a standard cost basis, are expected to be consistent with 2010.

Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel for 2011 is expected to be consistent with 2010.

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 going forward.

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 2011 are expected to be lower as a result of certain planned maintenance costs that had been expensed under Canadian GAAP being capitalized under International Financial Reporting Standards (“IFRS”) in 2011, and lower OM&A costs related to our Poplar Creek base plant. In 2011, we will no longer operate the Poplar Creek base plant resulting in reduced OM&A expenditures and associated cost recoveries. The impact of no longer operating the Poplar Creek base plant is not expected to be significant to net earnings.

Energy Trading

Earnings from our Energy Trading segment are affected by prices in the market, positions taken, and the duration of those positions. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2011 objective is for Energy Trading to contribute between $45 million and $65 million in gross margin.

Exposure to Fluctuations in Foreign Currencies

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

Net Interest Expense

Net interest expense for 2011 is expected to be higher than 2010 mainly due to higher debt balances, higher variable interest rates, lower capitalized interest, and lower interest income. 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 we will monitor our exposures and obligations to ensure we have sufficient liquidity to meet our requirements.

Accounting Estimates

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

Income Taxes

The effective tax rate for 2011 is expected to be approximately 17 to 22 per cent.

36 T r a n s A l t a   C o r p o r a t i o n

Capital Expenditures

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

Growth Capital Expenditures

In 2010, we spent a total of $470 million on growth capital expenditures, net of any joint venture contributions received. In 2010, we successfully commenced commercial operations at Summerview 2, Ardenville, and Kent Hills 2. We have five additional significant growth capital projects that are currently in progress with targeted completion dates between Q1 2011 and Q4 2012.

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

	Total Project		2010	2011	Target
	Estimated	Spend	Actual	Estimated	completion
Project	spend	to date1	spend1	spend	date	Details
Keephills 3	988	928	221	50-60	Q2 2011	A 450 MW (225 MW net ownership interest) supercritical coal-fired plant and associated mine capital in a partnership with Capital Power
Keephills Unit 1 uprate	34	4	3	10-20	Q4 2012	A 23 MW efficiency uprate at our Keephills plant
Keephills Unit 2 uprate	34	6	5	20-30	Q4 2012	A 23 MW efficiency uprate at our Keephills plant
Bone Creek	48	54	50	-	Q1 2011	A 19 MW hydro facility in British Columbia
Sundance Unit 3 uprate	27	3	3	10-15	Q4 2012	A 15 MW efficiency uprate at our Sundance plant
Total growth expenditures	1,131	995	282	90-125

1  Represents amounts spent as of Dec. 31, 2010. In 2010, we also spent a combined total of $188 million on Summerview 2, Ardenville, and Kent Hills 2.

Amounts disclosed in the above chart are shown net of any joint venture contributions received.

The total estimated spend for Bone Creek is less than the amount incurred to date due to the timing of project spend and estimated recoveries in 2011.

Sustaining Capital Expenditures

Certain costs related to planned maintenance that have been expensed under Canadian GAAP in 2010 will be capitalized under IFRS in 2011. Our estimate for total sustaining capital expenditures in 2011, net of any contributions received, is allocated among the following:

		Spend	Expected
Category	Description	in 2010	cost
Routine capital	Expenditures to maintain our existing generating capacity	147	120-135
Productivity capital	Projects to improve power production efficiency	9	10-20
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	25	25-30
Planned maintenance	Regularly scheduled major maintenance	127	180-210
Total sustaining expenditures		308	335-395

Details of the 2011 planned maintenance program are outlined as follows:

		Gas and	Expected
	Coal	Renewables	cost
Capitalized	105-130	75-80	180-210
Expensed	-	0-5	0-5
	105-130	75-85	175-200

		Gas and
	Coal	Renewables	Total
GWh lost	1,480-1,490	630-640	2,110-2,130

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Financing

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

Related Party Transactions

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

On Dec. 16, 2006, predecessors of TAGP, a firm owned by the Corporation and one of its subsidiaries, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the coal-fired plant. The joint venture project is held in a partnership owned by Keephills 3 Limited Partnership (“K3LP”), a wholly owned subsidiary of the Corporation, and Capital Power Corporation. TAGP will supply coal until the earlier of the permanent closure of the Keephills 3 facility or the early termination of the agreement by TAGP and the partners of the joint venture. As at Dec. 31, 2010, TAGP had received $61 million from K3LP for future coal deliveries. Commercial operation of the Keephills plant is scheduled to commence in the second quarter of 2011. Payments received prior to that date for future coal deliveries are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply agreement when TAGP starts delivering coal for commissioning activities.

TAGP operates and maintains three combined-cycle power plants in Ontario, a combined-cycle power plant in Fort Saskatchewan, Alberta, and a cogeneration plant in Lloydminster, Alberta on behalf of TA Cogen, which is a subsidiary of TransAlta. TAGP also provides management services to the Sheerness thermal plant, which is operated by Canadian Utilities Limited.

For the period November 2002 to October 2012, TA Cogen entered into various transportation swap transactions with TransAlta Energy Marketing Corporation (“TEMC”). The business purpose of these transportation swaps is to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline transportation for two of its plants over the period of the swap. The notional gas volumes in the swap transactions are equal to the total delivered fuel for each of the facilities. Exchange amounts are based on the market value of the contract.

For the period October 2010 to October 2011, TA Cogen entered into physical gas purchase transactions with TEMC for volumes to be consumed by one of its plants.

For the period November 2012 to October 2017, TA Cogen entered into financial and foreign currency swap transactions with TEMC to mitigate the natural gas price exposure at one of its plants.

TEMC has entered into offsetting contracts and therefore has no risk other than counterparty risk.

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, establishes policies and procedures, defines risk tolerance as established under the Toronto Stock Exchange corporate governance guidelines, and receives an annual comprehensive Enterprise Risk Management (“ERM”) review. The ERM 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 inter-related 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.

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The Exposure Management Committee (“EMC”) is chaired by our Chief Financial Officer and is comprised of the Chief Operating Officer, Vice-President Controller and Treasurer, Vice-President Corporate Planning and Analysis, Vice-President Operations Finance, and Vice-President Internal Audit and Risk. The EMC is responsible for reviewing and monitoring compliance within approved financial and commodity exposure management policies.

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.

Reporting

On a regular basis, risk exposures are reported to key decision makers including the Board of Directors, senior management, and the EMC. Reporting to the EMC 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 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 at Dec. 31, 2010 associated with our proprietary energy trading activities was $5 million (2009 - $3 million).

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 weekly 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. 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 2010. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of changes.

Volume Risk

Volume risk relates to the variances from our expected production. For example, the financial performance of our hydro, wind, and geothermal operations are partially dependant 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.

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

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

We manage our generation equipment and technology risk by:

§	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 life cycles of our existing facilities and/ or replacement of selected generating assets.

Commodity Price Risk

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

We manage 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- 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.

40 T r a n s A l t a   C o r p o r a t i o n

In 2010, we had approximately 95 per cent of production under short-term and long-term contracts and hedges (2009 - 97 per cent). In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfill our supply obligations under these short- and long-term contracts.

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 2010, 81 per cent (2009 - 79 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2009 - 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	8
Natural gas price	$0.10/GJ	1
Coal price	$1.00/tonne	14

Fuel Supply Risk

We buy natural gas and some of our coal to supply the fuel needed to operate our facilities. Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under contracts and for merchant sale opportunities.

At 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, 2010, approximately 75 per cent (2009 - 75 per cent) of the coal used in generating activities is from coal reserves owned by us,
§	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.

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.

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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-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 2010, we spent approximately $55 million (2009 - $45 million) on environmental management activities, systems, and processes.

We are a founder of the Canadian Clean Power Coalition, which is an industry consortium developed to assess and develop clean combustion technologies. On Oct. 14, 2009, the federal and provincial governments announced that Project Pioneer, our CCS project, has received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative.

In October 2010, the Canadian Securities Administrators (“CSA”) 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 is in the ability of a counterparty to either fulfill their financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.

We manage our exposure to credit risk by:

§	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 their obligation or go over their 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.

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, 2009. We had no counterparty losses in 2010, 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.

42 T r a n s A l t a   C o r p o r a t i o n

A summary of our credit exposure for our energy trading operations and hedging activities at Dec. 31, 2010 is provided below:

Counterparty credit rating	Net exposure
Investment grade	349
Non-investment grade	-
No external rating, internally rated as investment grade	26
No external rating, internally rated as non-investment grade	1

The maximum credit exposure to any one customer for commodity trading operations, excluding the California Independent System Operator and California Power Exchange, and including the fair value of open trading positions, is $43 million (2009 - $63 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 from foreign suppliers, and our U.S. denominated debt. Our exposures are primarily to the U.S. and Australian currencies. Changes in the values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments to the extent that these positions or cash flows are not hedged 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, 2010, we have hedged approximately 95 per cent (2009 - 97 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.

Translation gains and losses related to the carrying value of our foreign operations and any hedges in respect thereof are included in AOCI in shareholders’ equity until such a time there is a permanent reduction in our investment.

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. or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter, and is shown below:

		Approximate impact
Factor	Increase or decrease	on net earnings
Exchange rate	$0.06	3

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 balance sheet and stable investment grade credit ratings.

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

We manage liquidity risk by:

§	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 EMC, senior management, and Board of Directors,
§	maintaining investment grade credit ratings, and
§	maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.

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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, 2010, approximately 25 per cent (2009 - 31 per cent) of our total debt portfolio was subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.

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

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

Project Management Risk

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

We attempt to minimize these 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 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.

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 2010, 46 per cent (2009 - 46 per cent) of our labour force is covered by 11 (2009 - 11) collective bargaining agreements. In 2010, four (2009 - five) agreements were renegotiated. We anticipate negotiating three agreements in 2011. We do not anticipate any significant issues in the renewal of these agreements.

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Regulatory and Political Risk

Regulatory and political risk describes the risk to our business associated with existing regulatory structures and the political influence upon those structures. This risk can come from market re-regulation, increased oversight and control, or other unforeseen influences. We are not able to predict whether there will be any changes in the regulatory environment or the ultimate effect of changes in the regulatory environment on our business.

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

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

Transmission Risk

Access to transmission lines and sufficient capacity 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.

We are dedicated to operating a safe and ethical organization. We have a system in place where employees may report any potential ethical concerns. These concerns are directed to the 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. All employees and directors are required to sign a corporate code of conduct on an annual basis.

Corporate Structure Risk

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

General Economic Conditions

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

Income Taxes

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

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

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

The effective tax rate on comparable earnings before income taxes for 2010 was 16 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.

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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. Although there can be no assurance that any particular claim will be resolved in our favour, we do not believe that the outcome of any claims or potential claims of which we are currently aware will have a material adverse effect on us, taken as a whole.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during 2010. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims.

Critical Accounting Policies and Estimates

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

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

Our significant accounting policies are described in Note 1 to the consolidated financial statements. The most critical of these policies are those related to revenue recognition, financial instruments and hedges, PP&E, goodwill, income taxes, employee future benefits, and asset retirement obligation. 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 below.

Revenue Recognition

The majority of our revenues are derived from the sale of physical power 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 being available, energy payments for generation of electricity, availability incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each of these components is recognized upon output, delivery, or satisfaction of contractually specific targets. Revenues from non-contracted capacity are comprised of energy payments for each MWh produced at market prices and are recognized upon delivery.

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 balance sheet date represent unrealized gains or losses and are presented on the Consolidated Balance Sheets as risk management assets or liabilities. The fair value of derivative contracts receiving hedge accounting treatment open at the balance sheet date are deferred in AOCI and are presented on the Consolidated Balance Sheets as risk management assets or liabilities.

The determination of the fair value of energy trading contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility, and liquidity, among other factors. The majority of derivatives traded by us are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or models.

46 T r a n s A l t a   C o r p o r a t i o n

Financial Instruments

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

Level I

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

Level II

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

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

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

Level III

Fair values in Level III 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, and/or volatilities and correlations between products derived from historical prices. Where commodity transactions extend into periods for which market-observable prices are not available, an internally developed fundamental price forecast is used in the valuation.

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

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, 2010 is estimated to be +/- $14 million (2009 - +/- $24 million). This estimate is based on a +/- one standard deviation move from the mean where historical data is used in the valuation. Where an internally developed fundamental price forecast is used, reasonable alternate fundamental price forecasts sourced from external consultants are included in the estimate.

Valuation of PP&E and Associated Contracts

As at Dec. 31, 2010, PP&E makes up 77 per cent of our assets, of which 99 per cent relates to the Generation segment. On an annual basis, and when indicators of impairment exist, we determine whether the net carrying amount of PP&E and associated contracts are recoverable from future undiscounted cash flows. Factors that could indicate that impairment exists include significant underperformance relative to historical or projected operating results, significant changes in the manner or use of the assets, the strategy for our overall business, and significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

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

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

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

On an annual basis, or more frequently if events indicate, we perform an impairment review of our plants. As a result of this review in 2010, pre-tax asset impairment charges of $89 million were recorded related to certain natural gas and coal facilities. Refer to the Asset Impairment section of this MD&A for further details.

Project Development Costs

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

Useful Life of PP&E

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

In 2010, depreciation and amortization expense per the Consolidated Statements of Cash Flows was $490 million (2009 - $493 million), of which $42 million (2009 - $40 million) relates to mining equipment, and is included in fuel and purchased power.

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

Valuation of Goodwill

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

Goodwill was recorded on the acquisitions of Canadian Hydro, Merchant Energy Group of the Americas, Inc., Vision Quest Windelectric Inc., and CE Gen. At Dec. 31, 2010, this goodwill had a total carrying value of $517 million (2009 - $434 million). The change in value from Dec. 31, 2009 is primarily due to the Canadian Hydro purchase price allocation adjustment.

We reviewed the recorded value of goodwill prior to year-end and determined that the fair values of our reporting units, based on historical cash flows and estimates of future cash flows, exceeded their carrying values. There were no significant events that impacted the fair values of the reporting units between the time of our testing and Dec. 31, 2010. Accordingly, no goodwill impairment charges were recorded for the year ended Dec. 31, 2010.

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

48 T r a n s A l t a   C o r p o r a t i o n

Income Taxes

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

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

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

Future tax assets of $240 million have been recorded on the Consolidated Balance Sheets at Dec. 31, 2010 (2009 - $234 million). These assets are comprised primarily of unrealized losses from risk management transactions, asset retirement obligation costs, and net operating and capital loss carryforwards. We believe there will be sufficient taxable income and capital gains that will permit the use of these deductions and carryforwards in the tax jurisdictions where they exist.

Future tax liabilities of $707 million have been recorded on the Consolidated Balance Sheets at Dec. 31, 2010 (2009 - $707 million). These liabilities are comprised primarily of unrealized gains from risk management transactions and income tax deductions in excess of related depreciation of PP&E.

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

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

Employee Future Benefits

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

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

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

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

The discount rate used 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, 2010, the plan assets had a positive return of $28 million, compared to $38 million in 2009, and a negative return of $55 million in 2008. The 2010 actuarial valuation used the same rate of return on plan assets (seven per cent) as was used in 2009 and 2008.

Asset Retirement Obligation

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

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At Dec. 31, 2010, the ARO recorded on the Consolidated Balance Sheets was $242 million (2009 - $282 million). We estimate the undiscounted amount of cash flow required to settle the ARO is approximately $0.8 billion, which will be incurred between 2011 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 ARO was eight per cent.

Sensitivities for the major assumptions are as follows:

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

Future Accounting Changes

IFRS Convergence

On Jan. 1, 2011, we adopted IFRS for publicly accountable enterprises as required by the Accounting Standards Board. Our project to convert to IFRS consisted of the following phases:

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

A steering committee continues to monitor the progress of the transition to IFRS and will continue to meet regularly until our March 31, 2011 first interim report under IFRS is completed. This committee includes representatives from Finance, Information Technology, Treasury, Investor Relations, Human Resources, and Operations. Quarterly updates are provided to the Audit and Risk Committee.

While IFRS uses a conceptual framework similar to Canadian GAAP and has many similarities to Canadian GAAP, there are several significant differences in accounting policies that have been addressed as part of our conversion project. Overall, these differences are expected to have a relatively modest impact on our consolidated financial results. The more significant impacts of IFRS to us are as follows:

PP&E

§	Key change in accounting: Major inspection costs, which are currently expensed, will be capitalized and depreciated over the period until the next major inspection.
§	Income statement impact: Earnings will likely be less volatile.
§	Balance sheet impact upon transition to IFRS: Net increase in PP&E of $115 million as previously expensed major inspection costs will be capitalized.
§	Cash flow statement impact: Major inspection costs will be recorded as cash flows used in investing activities instead of as cash flows used in operating activities.
§	Other differences: Additional disclosures reconciling the changes in cost and accumulated depreciation for individual classes of PP&E will be required.

Employee Benefits

§	Key change in accounting: All actuarial gains and losses related to defined benefit plans will be recognized in other comprehensive income.
§	Income statement impact: Expenses associated with defined benefit plans will differ. The impact on net earnings is not expected to be significant.
§	Balance sheet impact upon transition to IFRS: Recognition of net cumulative actuarial losses of $78 million (after-tax) in opening retained earnings.
§	Cash flow statement impact: None.

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Joint Arrangements

§	Key change in accounting: Interests in joint ventures classified as jointly controlled entities can be recognized using either the proportionate consolidation or equity method. We have chosen to account for these entities using the equity method instead of the proportional consolidation method as required by Canadian GAAP. Prior to March 31, 2011, the International Accounting Standards Board is expected to issue a new standard on the accounting for joint ventures that eliminates the option of proportionate consolidation. The new standard is expected to come into effect Jan. 1, 2013, with early adoption permitted. If we decide to early adopt this new standard effective Jan. 1, 2011, no additional changes are expected.
§	Income statement impact: Revenues and expenses will be recorded as equity earnings or loss, a single line item on the Consolidated Statement of Earnings. There is no impact on net earnings.
§	Balance sheet impact upon transition to IFRS: Our share of assets and liabilities will be removed from the various line items on the Statement of Financial Position and the corresponding net amount of $202 million will be recorded as an investment.
§	Cash flow statement impact: Our proportionate share of cash from equity accounted joint ventures will not be reflected on the Consolidated Statement of Cash Flow. Only contributions to and distributions from investments accounted for using the equity method will be reflected in the cash flow statement as an investing activity.

Provisions, Contingent Liabilities, and Contingent Assets

§	Key change in accounting: AROs are revalued at the end of each quarterly and annual reporting period using current market-based interest rates instead of using historic rates.
§	Income statement impact: Accretion expense will be classified as a finance (interest) cost under IFRS as opposed to an operating expense under Canadian GAAP, and may fluctuate more often due to the impact of the period-end revaluations.
§	Balance sheet impact upon transition to IFRS: Due to differences in discount rates, the opening balance of the provisions for ARO will increase by $34 million.
§	Cash flow statement impact: None.

Arrangements Containing a Lease

§	Key change in accounting: All contractual arrangements will be evaluated to determine if they contain a finance or operating lease.
§	Income statement impact: For those contracts that are determined to be finance leases, a portion of payments received under the contract will be recorded as finance (interest) income. For those contracts that are determined to be operating leases, the timing of recognition of revenue may differ. The impact on net earnings in either case is not expected to be significant.
§	Balance sheet impact upon transition to IFRS: For certain long-term contracts that are deemed to be finance leases, the associated PP&E of $30 million will be removed from the Consolidated Balance Sheets and replaced with a long-term receivable of $50 million, representing the present value of lease payments to be received over the life of the contract.
§	Cash flow statement impact: Payments received under the contract for finance leases will be recorded as cash flows from financing activities instead of cash flows from operating activities.

Asset Impairment

§	Key change in accounting: Asset impairment testing no longer utilizes undiscounted future cash flows to initially assess for impairment. Instead, an asset’s carried amount is compared to the greater of its value in use or fair value less normal costs to sell. Asset impairment charges can be reversed if the conditions creating the impairment reverse.
§	Income statement impact: Depreciation expense for any impaired assets will be lower over the useful life of the asset.
§	Balance sheet impact upon transition to IFRS: Impairment charges of $98 million will reduce PP&E, opening retained earnings, and non-controlling interests, as well as increase provisions.
§	Cash flow statement impact: None.

A number of elections were available to us under IFRS 1, First-Time Adoption of International Financial Reporting Standards that assisted with our transition to IFRS. We have made use of several of these elections as follows:

§	Cumulative unrealized losses on translating self-sustaining foreign operations, net of hedges and tax, of $63 million, will be reset to zero;
§	Share-based payment guidance under IFRS will only be applied to equity instruments outstanding at transition that were granted on or after Nov. 7, 2002, and which had not vested by the transition date;
§	Business combinations that occurred prior to Jan. 1, 2010 will continue to be measured and recorded at the Canadian GAAP amounts;
§	We will use a simplified method to recalculate the cost of decommissioning assets included in PP&E; and
§	We will not adjust interest previously capitalized as part of PP&E under Canadian GAAP.

In addition, various presentation changes are required under IFRS that have no impact on opening retained earnings.

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Non-GAAP Measures

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

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

Net Earnings Reconciliation

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

Year ended Dec. 31	2010		2009		2008
Revenues	2,819		2,770		3,110
Fuel and purchased power	1,202		1,228		1,493
Gross margin	1,617		1,542		1,617
Operations, maintenance, and administration	634		667		637
Depreciation and amortization	459		475		428
Taxes, other than income taxes	27		22		19
Operating expenses	1,120		1,164		1,084
Operating income	497		378		533
Foreign exchange gain (loss)	10		8		(12	)
Asset impairment charges	(89	)	(16	)	-
Net interest expense	(178	)	(144	)	(110	)
Other income	-		8		5
Equity loss	-		-		(97	)
Earnings before non-controlling interests and income taxes	240		234		319
Non-controlling interests	20		38		61
Earnings before income taxes	220		196		258
Income tax expense	1		15		23
Net earnings	219		181		235
Preferred share dividends	1		-		-
Net earnings applicable to common shares	218		181		235

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 for 2010, we excluded asset impairment charges, as well as unrealized gains related to certain power hedging relationships 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 comparable earnings in the period that they settle, the majority of which will settle during the second quarter of 2011. In addition, we 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.

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

In 2009 and 2008, the change in life of certain component parts at Centralia Thermal was excluded from the calculation of comparable earnings as it relates to the cessation of mining activities at the Centralia coal mine and conversion to consuming solely third-party supplied coal.

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In calculating comparable earnings for 2008, we excluded the impact recoveries related to certain tax positions as they do not relate to the earnings in the period in which they have been reported. We also excluded the gains recorded on the sale of assets at the previously operated Centralia coal mine in 2008 as we do not normally dispose of large quantities of fixed assets. We have also excluded the writedown of our Mexican equity investment.

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

Year ended Dec. 31	2010		2009		2008
Net earnings applicable to common shares	218		181		235
Asset impairment charges, net of tax	54		10		-
Unrealized gains related to ineffectiveness in certain power hedging relationships, net of tax	(28	)	-		-
Income tax recovery related to the resolution of certain outstanding tax matters	(30	)	-		-
Gain on sale of assets at Centralia, net of tax	-		-		(4	)
Change in life of Centralia parts, net of tax	-		1		(12	)
Settlement of commercial issue, net of tax	-		(6	)	-
Tax rate change	-		(5	)	-
Recovery related to tax positions	-		-		(15	)
Writedown of Mexican equity investment, net of tax	-		-		62
Earnings on a comparable basis	214		181		290
Weighted average number of common shares outstanding in the year	219		201		199
Earnings on a comparable basis per share	0.98		0.90		1.46

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	2010		2009		2008
Operating income	497		378		533
Asset retirement obligation accretion per the Consolidated Statements of Cash Flows	21		24		22
Depreciation and amortization per the Consolidated Statements of Cash Flows1	490		493		451
EBITDA	1,008		895		1,006
Unrealized gains related to ineffectiveness in certain power hedging relationships, pre-tax	(43	)	-		-
Settlement of commercial issue, pre-tax	-		(7	)	-
Comparable EBITDA	965		888		1,006

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

Funds from Operations and Cash Flow from Operating Activities per Share

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

	2010	2009		2008
Funds from operations	783	729		828
Change in non-cash operating working capital balances	28	(149	)	210
Cash flow from operating activities	811	580		1,038
Weighted average number of common shares outstanding in the year	219	201		199
Cash flow from operating activities per share	3.70	2.89		5.22

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Free Cash Flow (Deficiency)

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

Sustaining capital expenditures for the year ended Dec. 31, 2010, represents total additions to PP&E per the Consolidated Statements of Cash Flows less $482 million ($470 million net of joint venture contributions) that we have invested in growth projects. For the same period in 2009, we invested $524 million ($510 million net of joint venture contributions). In 2008, we invested $541 million ($515 million net of joint venture contributions).

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

Year ended Dec. 31	2010		2009		2008
Cash flow from operating activities	811		580		1,038
Add (deduct):
Sustaining capital expenditures	(308	)	(380	)	(465	)
Cash dividends paid on common shares	(216	)	(226	)	(212	)
Distribution to subsidiaries’ non-controlling interests	(62	)	(58	)	(98	)
Non-recourse debt repayments1	(21	)	(25	)	(28	)
Other income	-		(8	)	-
Timing of contractually scheduled payments	-		-		(116	)
Cash flows from equity investments	-		-		2
Free cash flow (deficiency)	204		(117	)	121

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

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

Comparable 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 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	2010		2009		2008
Earnings before income taxes per the Consolidated Statements of Earnings	220		196		258
Net interest expense	178		144		110
Non-controlling interests	20		38		61
Non-comparable items
Asset impairment charges, pre-tax	89		16		-
Unrealized gains related to ineffectiveness in certain power hedging relationships, pre-tax	(43	)	-		-
Change in life of Centralia parts, pre-tax	-		2		18
Settlement of commercial issue, pre-tax	-		(7	)	-
Writedown of Mexican equity investment, pre-tax	-		-		97
Gain on sale of assets at Centralia, pre-tax	-		-		(6	)
Comparable earnings before net interest expense, non-controlling interests, and income taxes	464		389		538
Average invested capital excluding AOCI	7,645		6,659		5,588
Comparable ROCE	6.1		5.8		9.6

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Selected Quarterly Information

	Q1 2010	Q2 2010		Q3 2010	Q4 2010
Revenues	726	582		700	811
Net earnings applicable to common shares	67	51		38	62
Basic and diluted earnings per common share	0.31	0.23		0.17	0.28
Comparable earnings per common share	0.31	0.10		0.17	0.40
	Q1 2009	Q2 2009		Q3 2009	Q4 2009
Revenues	756	585		666	763
Net earnings (loss) applicable to common shares	42	(6	)	66	79
Basic and diluted earnings (loss) per common share	0.21	(0.03	)	0.34	0.37
Comparable earnings (loss) per common share	0.18	(0.03	)	0.34	0.40

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

Controls and Procedures

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

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, 2010, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

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