**Exhibit 13.2**

 

 

 

**TransAlta Management’s Discussion and Analysis**

 

*December 31, 2009*

 

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***PLANTSUMMARY***

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

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

 

 

1**  |  **TransAltaCorporation

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***MANAGEMENT’S DISCUSSION ANDANALYSIS***

 
| **3****Business Environment  5Strategy 5Capability to Deliver Results6Performance Metrics9Results of Operations10Reported Earnings11Significant Events16Subsequent Events16Discussion of Segmented Results 21Financial Position22Financial Instruments 25Statements of Cash Flows26Liquidity and Capital Resources27Climate Change and the  Environment 292010 Outlook32Risk Management39Critical Accounting Policies and  Estimates43Future Accounting Changes 44Non-GAAP Measures47Forward Looking Statements** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

 
|  

This management’s discussion and  analysis (“MD&A”) should be read in conjunction with the audited 2009  consolidated financial statements. The consolidated financial statements have  been prepared in accordance with Canadian Generally Accepted Accounting  Principles (“Canadian GAAP”). All dollar amounts in the following discussion,  including the tables, are in millions of Canadian dollars unless otherwise  noted. This MD&A is dated Feb. 23, 2010. Additional information  respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us”, or “the  Corporation”), including its Annual Information Form, is available on SEDAR  at www. sedar. com and on our website at www. transalta. com. |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

Management’sDiscussion and Analysis**  |  **2

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***BUSINESS ENVIRONMENT***

 

**Overview of the Business**

 

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

** **

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

 

**Demand**

 

Demand for electricity is a fundamental driver of prices inall of our markets. Economic growth is the main driver of longer-term changesin the demand for electricity. Historically, demand for electricity in allthree of our major markets has grown at an average rate of one to three percent per year; however, the weak economic environment experienced in 2009resulted in zero to negative demand growth in our key markets. In Alberta,demand growth is expected to resume again in 2010 after three years ofstagnation. Cost reductions combined with relatively well-supported oil pricesare expected to result in a modest but sustained increase in oil sandsdevelopment which will, in turn, lead to higher electricity demand. Due to theeconomic recession, the Pacific Northwest has seen demand destruction in 2009.Load in this region is not expected to return to 2008 levels until 2011 or2012. The long-term growth rate in this region is expected to be lower thanhistorical trends because there is a large emphasis on energy efficiency acrossthe region. Demand in Ontario is expected to increase in 2010 as the economyrecovers. In the longer-term, demand in Ontario is expected to remainconstrained as the province’s economy continues to move away from manufacturingand as other energy efficiency policies take hold.

 

**Supply**

 

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

 

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

 

Reserve margins, which measure available capacity in amarket 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 newsupply coming on line. It is expected that reserve margins will begin todecline slowly from current levels as load growth resumes.

 

Green technologies have gained favour with regulators andthe general public, creating increasing pressure to supply power usingrenewable resources such as wind, hydro, geothermal, and solar. The economicfeasibility of solar power is still being debated.

 

While there are many new developments that will likelyimpact the future supply of electricity, the low cost of our base loadoperations still means that our plants are supported in the market.

 

**Transmission**

 

Transmission refers to the bulk delivery system of power andenergy between a generating unit and the distribution system that links towholesale and/or retail customers. Transmission lines themselves serve as thephysical path, transporting electricity from the generating unit to theindividual distribution systems. Transmission systems are designed withsufficient reserve capacity to allow for “real time” fluctuations in bothsupply and demand caused by generation plants or loads coming on and off thetransmission network. 

 

Transmission capacity refers to the ability of thetransmission line, or lines, to transport this bulk supply of electricity in anamount that balances the demand needs with the generating supply, allows for anamount of power required for system integrity and security, and allows forreserve capacity to respond to contingency situations on the system. Mosttransmission businesses in North America are still regulated.

 

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

 

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

 

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

 

**Environmental Legislation and Technologies**

 

Environmental issues and related legislation have, and willcontinue to have, an impact upon our business. Since 2007, we have incurredcosts as a result of GHG legislation in Alberta. Legislation in otherjurisdictions and at different levels of government is in various stages

 

 

3**  |  **TransAltaCorporation

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of maturity and sophistication. Our exposure to increasedcosts as a result of environmental legislation in Alberta is minimized throughchange-in-law provisions in our Power Purchase Arrangements (“PPAs”).

 

Both the Canadian and U.S. federal governments areconsidering cap and trade policies to manage GHG emissions. However, economicuncertainty fueled by financial market volatility, a developing recovery, andCanada’s political environment may delay the adoption of such systems. Forthese reasons, the Canadian government may not implement new environmental legislationuntil the end of 2010 or later. 

 

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

 

**Economic Environment**

 

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

 

**Electricity Prices**

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

 

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

 

In 2009, average spot prices decreased in Alberta, thePacific Northwest, and in Ontario due to lower natural gas prices and weakerdemand for electricity. In Alberta, prices also decreased due to increasedavailability across the province’s thermal coal fleet.

 

During the year, our consolidated power portfolio was over95 per cent hedged at an average price ranging from $60 – $65 per megawatt hour(“MWh”) in Alberta, and an average price ranging from U.S.$50 – $55/MWh in thePacific Northwest. The use of these hedges reduced the impact of lower pricesupon our consolidated financial results.

 

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

 

**Spark Spreads**

 
| Spark spreads measure the potential profit from generating  electricity at current market rates.

 

A spark spread is calculated as the difference between the  market price of electricity and its cost of production. The cost of  production is comprised of the total cost of fuel and the efficiency, or heat  rate, with which the plant converts the fuel source to electricity. For most  markets, a standardized plant heat rate is assumed to be 7,000 British  Thermal Units (“Btu”) per Kilowatt hour (“KWh”).

 

Spark spreads will also vary between different plants due  to their design, the region of the world in which they operate, and the requirements  of the customer and/or market the plant serves. The change in the prices of  electricity and natural gas, and the resulting spark spreads in our three  major markets, affect our Generation and Commercial Operations &  Development (“COD”) business segments. |   | * * |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|----------|

 

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

 

 

Management’sDiscussion and Analysis**  |  **4

----

 

***STRATEGY***

 

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

** **

**Financial****Strategy**

 

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

 

**Contracting Cash Flows**

 

In 2009, demand and prices in our key markets decreasedsignificantly compared to prior years primarily due to the weak economicenvironment. While we are not immune to softening power prices, the impact ofthese lower prices is significantly mitigated because approximately 89 per centof 2010 and approximately 83 per cent of 2011 expected capacity across ourfleet is contracted. It is this low-to-moderate risk contracting strategy thathelps protect our cash flow and our strong financial position through economiccycles.

 

**Operational Strategy**

 

We manage our facilities to achieve operations that are lowcost and predictable. Our target for 2010 is to increase productivity andreturn overall fleet availability to 90 per cent. This increase in availabilityinvolves developing and executing unit-specific maintenance plans that willcreate stability in our operations and reduce overall maintenance costs.

 

**Growth Strategy**

 

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

 

***CAPABILITY TO DELIVER RESULTS***

 

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

 

**Operational Excellence**

 

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

 

**Execution of our Strategy in 2009**
| **Improve base operations** | n | Improved  our cash flows through PPAs and other long-term contracts, which includes a  new contract with the Ontario Power Authority for our Sarnia power plant that  extends to 2025 |
|-----------------------------|---|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                        | n | Completed  Unit 1 boiler modifications at Centralia Thermal                                                                                                                           |
|                        | n | Implemented  productivity and cost reductions                                                                                                                                         |
|                        | n | Revised  our Alberta Thermal plants major maintenance schedule on a unit-by-unit basis  to improve stability and predictability                                                       |
| **Reposition coal**         | n | Partnered  with Alstom Canada, Capital Power Corporation, and the federal and provincial  governments to fund Project Pioneer, our CCS pilot project                                  |
| **Green our portfolio**     | n | Completed  the 66 MW Blue Trail wind farm and have an additional 189 MW of wind energy  under construction that is scheduled to be operational between Q1 2010 and Q1  2011           |
|                        | n | Accelerated  the growth of our renewables portfolio with the acquisition of Canadian Hydro                                                                                            |
|                        | n | Approved  the expansion of Kent Hills and the construction of Bone Creek                                                                                                              |
|                        | n | Continued  our work on the construction of our Ardenville and Summerview 2 wind farms                                                                                                 |
|                        | n | Continued  active involvement in environmental policy discussions with various levels of  government in Canada and the U.S.                                                           |

 

 

*1** **Comparable earnings per share are not defined under Canadian GAAP.Presenting earnings on a comparable basis from period to period providesmanagement and investors with the ability to evaluate earnings trends morereadily in comparison with prior periods’ results. Refer to the Non-GAAPMeasures section of this MD&A for a further discussion of comparableearnings per share, including a reconciliation to net earnings.*

 

 

5  **|**  TransAltaCorporation

----

 

Over the last three years, our average availability has been86.0 per cent, which is below our corporate target of 90 per cent. Thisdecrease in average availability has been primarily due to the acceleratedplanned maintenance undertaken in 2009, higher than normal unplanned outages atour coal-fired plants in 2009 and 2008, and derating at Centralia Thermal in2007. In 2009, we reviewed each unit and developed asset-specific maintenanceplans to achieve our target of 90 per cent availability, which should result inmore predictable performance and stable costs.

 

**Financial Strength**

 

We carefully manage our financial position and cash flows tomaintain financial strength and flexibility throughout all economic cycles.This financial discipline proved invaluable during the economic environment of2009 and will continue to be important during 2010. We continue to maintain$2.1 billion in committed credit facilities, and as of Dec. 31, 2009, $0.7billion was available to us. These strong ratios, available credit, continuedreliable cash flow from operations, and limited debt maturity profile provideus with ample financial flexibility, and as a result we can be selective aboutif and when we go to the capital markets for funding.

 

The funding required for our growth strategy is supported byour financial strength. In 2009, we took advantage of our strong financialposition by completing the acquisition of Canadian Hydro, which includedissuing debt and equity to finance the purchase. The market reacted favourablyto these transactions and we have maintained our investment grade creditratings. Looking forward, we see continued capital market support for projectsthat meet our return requirements and risk profile.

 

**Disciplined Capital Allocation**

 

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

 

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

 

In addition to our greenfield growth plans, we continue ouruprates of existing facilities. These uprates add capability to our existingfleet and provide opportunities for attractive rates of return. In 2009, wecompleted the uprate on Unit 5 of our Sundance facility and in 2010, we willcontinue our work on the uprates of Units 1 and 2 of our Keephills facility.

 

**People**

 

Our experienced leadership team is comprised of seniorbusiness leaders who bring a broad mix of skills in the electricity sector,finance, law, government, regulation, and corporate governance. The leadershipteam’s experience and expertise, our employees’ knowledge and dedication tosuperior operations, and our entire organization’s knowledge of the renewableenergy business has resulted in a long-term proven track record of financialstability and increasing shareholder value.

 

 

***PERFORMANCE METRICS***

 

**We have key measures that, in our opinion, arecritical to evaluating how we are progressing towards meeting our goals. Thesemeasures, which include a mix of operational, risk management, and financialmetrics, are discussed below.**

 

**Availability**

 
| Our plants must be available at all times throughout the  year to meet demand. However, this ability to meet demand is limited by the  requirement to shut down for planned maintenance and unplanned outages, and  reduced production as a result of derates. Our goal is to minimize these  events through regular assessments of our equipment and a comprehensive  review of our maintenance plans. Over the past three years we have achieved  an average availability of 86.0 per cent, which is below our long-term target  of 90 per cent. Our availability in 2009 was 85.1 per cent. |   |  |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--|

 

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

 

Availability for the year ended Dec. 31, 2008 decreaseddue to higher unplanned outages at Alberta Thermal and Genesee 3, and higherplanned outages as a result of equipment modifications at Centralia Thermal,partially offset by lower derates at Centralia Thermal as in 2007 we conductedtest burns of powder river basin (“PRB”) coal.

 

 

Management’sDiscussion and Analysis  **|**  6

----

 

**Production**

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

 

Production for the year ended Dec. 31, 2009 decreased3,155 gigawatt hours (“GWh”) due to higher economic dispatching and higherunplanned outages at Centralia Thermal, higher planned and unplanned outages atAlberta Thermal, lower PPA customer demand at Alberta Thermal and Sheerness,the expiration of the long-term contract at Saranac, and lower hydro volumes,partially offset by higher wind volumes due to the acquisition of CanadianHydro and the commissioning of Kent Hills, lower planned outages at CentraliaThermal, and lower planned and unplanned outages at Genesee 3. 

 

For the year ended Dec. 31, 2008, production decreased1,504 GWh due to higher unplanned outages at Alberta Thermal and Genesee 3,higher planned outages at Centralia Thermal, lower market heat rates at Sarnia,and economic dispatching at Centralia Thermal, partially offset by lowerunplanned outages at Centralia Thermal, higher merchant volumes due to theuprate on Unit 4 at our Sundance facility, and lower derates at CentraliaThermal resulting from test burns of PRB coal in 2007.

 

**Productivity**

 
| Our operations, maintenance, and administration  (“OM&A”) costs reflect the operating cost of our facilities. These costs  can fluctuate due to the timing and nature of planned maintenance activities.  The remainder of OM&A costs reflects the cost of day-to-day operations.  Our target is to offset the impact of inflation in our recurring operating  costs as much as possible through cost control and targeted productivity  initiatives. We measure our ability to maintain productivity on OM&A  based on the cost per installed MWh of capacity. |   |  |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--|

 

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

 

For the year ended Dec. 31, 2008, OM&A costs perMWh increased due to cost escalations, higher planned maintenance costs, andincreased compensation costs.

 

**Safety**

 

Safety is a top priority with all of our staff, contractors,and visitors. Our goal is to improve safety by reducing our Injury FrequencyRate (“IFR”) to 1 over the next five years.

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

 

The IFR increased in 2009 as a result of us not meetingsafety targets while completing the uprate on Unit 5 of our Sundance facility.In 2008, the IFR decreased as a direct result of our continuous efforts toimprove safety.

 

**Sustaining Capital Expenditures**

 
| We are in a long-cycle capital-intensive business that  requires consistent and stable capital expenditures. Our sustaining capital  comprises three components: (1) routine and mine capital,  (2) planned maintenance, and (3) productivity.

 

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

 

In 2008, we spent an additional $14 million on routine andmine capital and an additional $47 million on planned maintenance compared to2007. The increase in both routine and mine capital and planned maintenance wasdue to higher unplanned outages at Alberta Thermal and Genesee 3, equipmentmodifications at Centralia Thermal, and higher planned maintenance activitiesacross the fleet. In 2007, there were no productivity expenditures.

 

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

 

 

7  **|**  TransAltaCorporation

----

 

**Earnings and Cash Flow From Operating Activities**

 

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

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

* *

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

 

In 2009, comparable earnings per share and earnings beforeinterest, taxes, depreciation, and amortization (“EBITDA”) decreased due tohigher planned and unplanned outages at Alberta Thermal, lower hydro volumesand prices, and lower trading margins.

 

In 2008, comparable earnings per share and EBITDA increaseddue to favourable pricing in our core markets, higher merchant volumes due tothe uprate on Unit 4 at our Sundance facility, and strong Energy Tradingresults across all markets, partially offset by higher unplanned outages atAlberta Thermal.

 

In 2009, cash flow from operating activities decreased dueto lower cash earnings, the receipt of an additional PPA payment in 2008,higher inventory balances in 2009, and unfavourable movements in other workingcapital balances.

 

In 2008, cash flow from operating activities increased dueto an increase in cash earnings and favourable changes in working capitalincluding the timing of PPA receipts in 2008.

 

**InvestmentGrade Ratios**

 

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

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

 

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

 

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

 

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

 

We seek to maintain financial flexibility by using multiplesources of capital to finance capital allocation plans effectively, whilemaintaining a sufficient level of available liquidity to support contractingand trading activities. Further, financial flexibility allows our commercialteam to contract our portfolio with a variety of counterparties on terms andprices that are beneficial to our financial results.

 

**ShareholderValue**

 

Our business model is designed to deliver low-to-moderaterisk-adjusted sustainable returns and maintain financial strength andflexibility, which enhances shareholder value in a capital intensive,long-cycle, commodity-based business. Our target is to consistently grow ourcomparable return on capital employed (“ROCE”)(2) andtotal shareholder return (“TSR”)(2) each year.

 

The table below shows our historicalperformance and targets on these measures:

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

 

Comparable ROCE decreased in 2009 due to lower comparableearnings as a result of higher planned and unplanned outages at AlbertaThermal,lower hydro volumes and prices, and lower trading margins. Comparable ROCE in2008 was consistent with 2007.

 

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

 

 

*2**        **These measures are not defined under Canadian GAAP. We evaluate ourperformance and the performance of our business segments using a variety ofmeasures. These measures are not necessarily comparable to a similarly titledmeasure of another company. Comparable ROCE is a measure of the efficiency andprofitability of capital investments and is calculated by taking comparableearnings before net interest expense, non-controlling interests and taxes, anddividing by the average invested capital excluding AOCI. Presenting thiscalculation using comparable earnings before tax provides management andinvestors with the ability to evaluate trends on the returns generated incomparison with other periods. TSR is the total amount returned to investorsover a specific holding period and includes capital gains, capital losses, anddividends.*

 

 

Management’sDiscussion and Analysis  **|**  8

----

 

***RESULTSOF OPERATIONS***

 

**The results of operations are presented ona consolidated basis and by business segment. We have two business segments:Generation and COD. Our segments are supported by a corporate group thatprovides finance, tax, treasury, legal, regulatory, environmental, health andsafety, sustainable development, corporate communications, government and investorrelations, information technology, risk management, human resources, internalaudit, and other administrative support.**

 

**Some of our accounting policies requiremanagement to make estimates or assumptions that in some cases may relate tomatters that are inherently uncertain. Critical accounting policies andestimates include: revenue recognition, valuation and useful life of property,plant, and equipment (“PP&E”), financial instruments, asset retirementobligation (“ARO”), valuation of goodwill, income taxes, and employee futurebenefits. Refer to the Critical Accounting Policies and Estimates section ofthis MD&A for further discussion.**

 

**In this MD&A, the impact of foreignexchange fluctuations on foreign currency denominated transactions and balancesis discussed with the relevant items from the Consolidated Statements ofEarnings and the Consolidated Balance Sheets. While individual line items onthe Consolidated Balance Sheets will be impacted by foreign exchangefluctuations, the net impact of the translation of individual items isreflected in the equity section.**

 

 

***HIGHLIGHTS AND SUMMARY OF RESULTS***

 

The following table depicts keyfinancial results and statistical operating data:

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

* *

*1**        **Gross margin, operating income, and free cash flow are not definedunder Canadian GAAP. Refer to the Non-GAAP Measures section of this MD&Afor further discussion of these items, including reconciliations to netearnings and cash flow from operating activities.*

 

 

9  **|**  TransAltaCorporation

----

 

***REPORTED EARNINGS***

 

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

 
| Net earnings for the year ended Dec. 31, 2007             |       | 309     |       |
|----------------------------------------------------------------|------------|---------|------------|
| Increase in Generation gross  margins                          |       | 7       |       |
| Mark-to-market movements—Generation                       |       | 16      |       |
| Increase in COD gross margins                                  |       | 50      |       |
| Increase in operations,  maintenance, and administration costs |       | (60     | )          |
| Increase in depreciation expense                               |       | (22     | )          |
| Gain on sale of mining equipment in  2007                      |       | (11     | )          |
| Decrease in net interest expense                               |       | 23      |       |
| Increase in equity loss                                        |       | (47     | )          |
| Increase in non-controlling  interests                         |       | (13     | )          |
| Increase in income tax expense                                 |       | (3      | )          |
| Other                                                          |       | (14     | )          |
| Net earnings for the year ended  Dec. 31, 2008            |       | 235     |       |
| Decrease in Generation gross  margins                          |       | (33     | )          |
| Mark-to-market movements—Generation                       |       | 16      |       |
| Decrease in COD gross margins                                  |       | (58     | )          |
| Increase in operations,  maintenance, and administration costs |       | (30     | )          |
| Increase in depreciation expense                               |       | (47     | )          |
| Writedown of mining development  costs                         |       | (16     | )          |
| Increase in net interest expense                               |       | (34     | )          |
| Equity loss recorded in 2008                                   |       | 97      |       |
| Decrease in non-controlling  interests                         |       | 23      |       |
| Decrease in income tax expense                                 |       | 8       |       |
| Other                                                          |       | 20      |       |
| Net earnings for the year ended  Dec. 31, 2009            | ** ** | **181** | ** ** |

 

For the year ended Dec. 31, 2009, Generation grossmargins, net of mark-to-market movements, decreased due to higher plannedoutages at Alberta Thermal, lower hydro volumes and prices, and the expirationof the long-term contract at Saranac, partially offset by lower planned andunplanned outages at Genesee 3, higher wind volumes due to the acquisition ofCanadian Hydro and the commissioning of Kent Hills, favourable foreign exchangerates, and favourable contractual pricing.

 

In 2008, Generation gross margins, net of mark-to-marketmovements, increased due to favourable pricing, lower derates at CentraliaThermal, and higher merchant volumes as a result of the uprate on Unit 4 at ourSundance facility, partially offset by higher unplanned outages at AlbertaThermal and Genesee 3.

 

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

 

In 2008, COD gross margins increased due to all regionsexperienced positive results in 2008, with the increase primarily attributableto successful trading strategies involving regional power demand and pricedifferentials in the eastern region.

 

For the year ended Dec. 31, 2009, OM&A costsincreased primarily due to higher planned outages and unfavourable foreignexchange rates, partially offset by targeted cost savings throughout theCorporation, and lower compensation costs. In 2008, OM&A costs increaseddue to cost escalations, higher planned maintenance costs, and increasedcompensation costs.

 

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

 

In 2008, depreciation expense increased compared to the sameperiod in 2007 due to increased capital spending, the retirement of assets thatwere not fully depreciated as a result of planned maintenance activities, andthe early retirement of certain components as a result of equipmentmodifications made at Centralia Thermal.

 

In 2006, we ceased mining activities at the Centralia minebut continued to develop the option to mine the Westfield site, a coal reservelocated adjacent to Centralia Thermal. With the successful modifications of theboilers at Centralia Thermal and longer-term contracts in place to supply coal,the project to develop the Westfields site has now been placed on holdindefinitely and the costs that have been capitalized were expensed during thefourth quarter of 2009.

 

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

 

 

Management’sDiscussion and Analysis  **|**  10

----

 

In the first quarter of 2008, an equity loss of $97 millionwas recorded to reflect the writedown of our Mexican equity investment that wassold in the fourth quarter of the same year. Equity loss increased for the yearended Dec. 31, 2008 compared to the same period in 2007 due to thewritedown of our Mexican equity investment in the first quarter of 2008,partially offset by a tax expense recorded in 2007 as a result of changes intax law in Mexico.

 

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

 

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

 

 

***SIGNIFICANTEVENTS***

 

Our consolidated financial results include the followingsignificant events:

 

***2009***

 

**Medium-TermNotes Offerings**

 

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

 

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

 

**SeniorNotes Offering**

 

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

 

**Saleof Common Shares**

 

On Nov. 5, 2009, we completed our public offering of20,522,500 Common shares at a price of $20.10 per common share, which resultedin net proceeds of approximately $413 million. The net proceeds from theoffering were used to repay a portion of the indebtedness relating to ouracquisition of Canadian Hydro.

 

**BlueTrail**

 

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

 

**Keephills3**

 

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

 

**CarbonCapture and Storage**

 

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

 

**Acquisitionof Canadian Hydro**

 

On Oct. 5, 2009, we entered into a definitivepre-acquisition agreement with Canadian Hydro to acquire all of their issuedand 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 oftheir issued and outstanding shares. On Nov. 4, 2009, we acquired theremaining 13 per cent. The total cash consideration of the acquisition was $766million. The results of Canadian Hydro are included in our consolidatedfinancial statements from Oct. 23, 2009, when we acquired control.

 

Canadian Hydro operated 694 MW of wind, hydro, and biomassfacilities in Alberta, Ontario, Quebec, and British Columbia. Canadian Hydro’sassets are highly contracted with counterparties of recognized financialstanding. On a combined basis at Dec. 31, 2009, we have 9,199 MW of grossgenerating capacity (1) in operation(8,775 MW net ownership interest). The combined renewables portfolio includesmore than 1,900 MW in operation, or 22 per cent of the total portfolio. Inaddition, there was a combined 424 MW net under construction and over 600 MW inadvanced-stage development at Dec. 31, 2009.

 

 

*1**        **We measure capacity as net maximum capacity (see glossary fordefinition of this and other key items) which is consistent with industrystandards. Capacity figures represent capacity owned and in operation unlessotherwise stated.*

 

 

11  **|**  TransAltaCorporation

----

 

Thefollowing table depicts the impact of Canadian Hydro on our consolidatedoperations portfolio by geographic region and fuel type:

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

* *

*1**        **Excluding Canadian Hydro.*

 

The following tabledepicts the impact of certain Canadian Hydro financial assets and long-termfinancial liabilities on our consolidated financial results:

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

 

*1**        **Excluding Canadian Hydro.*

 

**Sarnia Contract**

 

On Sept. 30, 2009, weentered into a new agreement with the Ontario Power Authority (“OPA”) for ourSarnia regional cogeneration power plant. The contract is capacity based andthe term of the new agreement is from July 1, 2009 through to the end of2025. While the specific terms and conditions of the new agreement areconfidential, the OPA has indicated that the agreement is in line with othersimilar agreements issued by the OPA.

 

**MajorMaintenance Plans**

 

On May 20, 2009,we announced the advancement of a major maintenance outage on Unit 3 of ourSundance facility from the second quarter of 2010 into the second and thirdquarters of 2009. The advancement of the maintenance outage took advantage oflow power prices, optimized preventative maintenance in the short-term, and isexpected to provide an economic cash benefit over the two-year period due toimproved unit availability. As a result of the change in schedule, 2009 lostGWh increased by 396 GWh and net earnings declined by $24 million ($0.12 pershare).

 

**NormalCourse Issuer Bid (“NCIB”) Program**

 

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

 

**ChiefOperating Officer**

 

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

 

Additionally, RichardLanghammer, Executive Vice President of Generation Operations, took on a newassignment as Chief Productivity Officer for the remainder of 2009 with theresponsibility for identifying strategies to create sustainable costs savingsacross the Corporation. Mr. Langhammer formally retired at the end of 2009after 23 years of service.

 

**ArdenvilleWind Power Project**

 

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

 

 

Management’s Discussion and Analysis  **|**  12

----

 

**SundanceUnit 4 Derate**

 

On Feb. 10,2009, we reported the first quarter financial impact of an extended derate onUnit 4 of our Sundance facility (“Unit 4”). The facility experienced anunplanned outage in December 2008 related to the failure of an induceddraft fan. At that time, Unit 4, which has a capacity of 406 MW, had beenderated to approximately 205 MW. The repair of the induced draft fan componentsby 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 ofthe extended derate, first quarter production and net earnings were reduced by328 GWh and $10 million, respectively representing both lost merchant revenueand penalties.

 

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

 

**KeephillsUnits 1 and 2 Uprates**

 

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

 

**DividendIncrease**

 

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

 

***2008***

 

**KentHills Wind Farm**

 

On Dec. 31,2008, our 96 MW Kent Hills Wind Farm, which is located 30 kilometres southwestof Moncton, New Brunswick, began commercial operations. We constructed, own,and operate the Kent Hills facility. Total capital costs for the constructionof Kent Hills were approximately $170 million. Natural Forces Technologies Inc.(“Natural Forces”) exercised their option to purchase a 17 per cent interest inthe 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 priceof $98.45 per $100 of notional amount. The debentures had been issued at afixed interest rate of 5.49 per cent, maturing in 2023, and were redeemable atthe option of the holder in 2008.

 

On Oct. 10,2008, $50 million of debentures issued by TAU were redeemed at a negotiatedprice. The debentures were originally issued at a fixed interest rate of 5.66per 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 formedwholly owned partnership, TransAlta Generation Partnership (“TAGP”), beforeamalgamating with TransAlta Corporation.

 

**ContractNegotiations with the International Brotherhood of Electrical Workers (“IBEW”)**

 

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

 

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

 

**Genesee3**

 

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

 

**MexicanEquity Investment**

 

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

 

 

13  **|**  TransAlta Corporation

----

 

**LSPower and Global Infrastructure**

 

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

 

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

 

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

 

**PotentialBreach of Keephills Ash Lagoon**

 

On July 26,2008, we detected a crack in the dyke wall at our Keephills ash lagoon. Weimmediately notified Alberta Environment and the local authorities, and begantaking measures to control and mitigate the effects of any potential breach andrelease of water from the lagoon. A series of dykes were constructed at the Keephillsash lagoon site and the risk associated with the potential breach wassuccessfully mitigated.

 

**Expansionat Summerview**

 

On May 27, 2008,we announced a 66 MW expansion at our Summerview wind farm located in southernAlberta near Pincher Creek. The total capital cost of the project was $123million and commercial operations commenced on Feb. 23, 2010. Please refer tothe subsequent Events section of this MD&A.

 

**SeniorNotes Offering**

 

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

 

**NormalCourse Issuer Bid Program**

 

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

 

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

 

**Uprateat Sundance Facility**

 

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

 

**GreenhouseGas Emissions**

 

March 31, 2008marked the deadline for the first compliance year with Alberta’s Specified GasEmitters Regulations for GHG reductions. Compliance was required for GHGsemitted from the implementation date of July 1, 2007 to Dec. 31,2007. Affected firms were required to reduce their emissions intensity by 12per cent annually from an emissions baseline averaged over 2003–2005. For ouroperations not covered under PPAs, we complied through the delivery togovernment of purchased emissions offsets, acquired at a competitive cost belowthe $15 per tonne cap. For Alberta plants having PPAs, we were also responsiblefor compliance, and the approach was coordinated with PPA Buyers such that amix of Buyer-supplied offsets and contributions to the Alberta Technology Fundat $15 per tonne were used. The PPAs contain change-in-law provisions thatallow us to recover compliance costs from the PPA customers.

 

**DividendPolicy and Dividend Increase**

 

On Feb. 1, 2008,the Board of Directors declared a quarterly dividend of $0.27 per share oncommon shares. This represented an increase of $0.02 per share to the quarterlydividend 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 policythat targets to pay shareholders an annual dividend in the range of 60 to 70per cent of comparable earnings.

 

**BlueTrail Wind Power Project**

 

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

 

 

Management’sDiscussion and Analysis  **|**  14

----

 

***2007***

 

**TaxRate Change**

 

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

 

**TransAltaPower, L.P.**

 

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

 

**OttawaPower Purchase Agreement**

 

On Oct. 12,2007, we signed an agreement amending our original long-term contract with theOntario Electricity Financial Corporation (“OEFC”) for the Ottawa CogenerationPower Plant. The agreement was entered into to ensure continued plantoperations following the expiry of long-term natural gas supply contracts. Theagreement will be in effect from Nov. 1, 2007 until Dec. 31, 2012.

 

**MexicoTax Reform**

 

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

 

**NCIBProgram**

 

On Sept. 11, 2007, weannounced an expansion of our NCIB program under which we could purchase, forcancellation, up to 20.2 million of our common shares or approximately 10 percent of the 202.0 million common shares issued and outstanding as at April 23,2007. The 2007 NCIB program started on May 3, 2007 and continued untilMay 2, 2008.

 

For the year endedDec. 31, 2007, we purchased 2,371,800 shares at an average price of $31.59per share. Purchases were made on the open market through the Toronto StockExchange at the market price of such shares at the time of acquisition. Thispurchase price was in excess of the weighted average book value of $8.92 pershare, resulting in a reduction to retained earnings of $54 million.

 

**NewBrunswick Power Purchase Agreement**

 

On Jan. 19,2007, we announced a 25-year contract with New Brunswick Power Distribution andCustomer Service Corporation (“New Brunswick Power”) to provide 96 MW of windpower in New Brunswick (“Kent Hills”).

 

**SundanceUnit 4 Uprate**

 

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

 

**GreenhouseGas Emissions Standards**

 

EffectiveJuly 1, 2007, the *Climate Change andEmissions Management Amendment Act* was enacted into law in Alberta.Under the legislation, baselines and targets for GHG emissions intensity areset on a facility by facility basis. The legislation requires a 12 per centreduction in carbon emission intensity over a baseline for the period 2003 to2005, established as at Dec. 31, 2007. New facilities or those inoperation for less than three years are exempt; however, upon the fourth yearof operations, the facility baseline is established and gradually reduces byyear of operation until the eighth year, by which emissions must be 12 per centbelow the established baseline. Emissions over the baseline are subject to acharge that must be paid annually. The PPAs for our Alberta-based coalfacilities contain change-in-law provisions that allow us to recover most compliancecosts from our PPA customers. After flow-through, the net compliance costs wereestimated to be approximately $5 million per year until we are able to meet thetargets for GHG emissions under the Act.

 

**DraglineDeposit**

 

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

 

**Keephills3 Power Plant**

 

On Feb. 26,2007, we announced that we would be building the 450 MW Keephills 3 coal-firedpower plant. The plant is being developed jointly by Capital Power and by us.The capital cost of the project is expected to be approximately $1.9 billion,including associated mine capital, and is anticipated to begin commercialoperations in the second quarter of 2011. We own a 50 per cent interest in thisunit.

 

 

15  **|**  TransAlta Corporation

----

 

***SUBSEQUENT EVENTS***

 

**Summerview 2**

** **

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

** **

**KentHills Expansion**

 

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

 

 

***DISCUSSION OF SEGMENTED RESULTS***

 

GENERATION:**Owns and operates hydro, wind, geothermal, biomass,natural gas- and coal-fired plants, and related mining operations in Canada,the U.S., and Australia. Generation’s revenues are derived from theavailability and production of electricity and steam as well as ancillary servicessuch as system support. At Dec. 31, 2009, Generation had 9,199 MW of grossgenerating capacity in operation (8,775 MW net ownership interest) and 424 MWnet under construction. At Dec. 31, 2009, 1,964 MW net was renewable. Fora full listing of all of our generating assets and the regions in which theyoperate, refer to the Plant Summary section of this MD&A.**

 

**During 2009, we completed the acquisitionof Canadian Hydro, which operates 694 MW of wind, hydro, and biomass facilitiesin Alberta, Ontario, Quebec, and British Columbia. We also completed the uprateon Unit 5 of our Sundance facility and the construction of the Blue Trail windfarm in southern Alberta. Please refer to the Significant Events section ofthis MD&A for further details.**

 

We have strategic alliances with Stanley Power, CapitalPower, ENMAX Corporation (“ENMAX”), MidAmerican Energy Holdings Company(“MidAmerican”), Nexen Incorporated (“Nexen”), and Brookfield Asset ManagementInc. (“Brookfield”). Stanley Power owns the minority interest in TransAltaCogeneration, L.P. (“TA Cogen”). The Capital Power alliance provided theopportunity for us to acquire 50 per cent ownerships in both the 450 MW Genesee3 project and the Taylor Hydro facility, as well as to build the Keephills 3project. ENMAX and our Corporation each own 50 per cent of the partnership inthe McBride Lake wind project. MidAmerican owns the other 50 per cent interestin CE Generation, LLC (“CE Gen”) and Wailuku Holding Company, LLC. Nexen andour Corporation each have a 50 per cent ownership in the Soderglen windproject. Brookfield owns the other 50 per cent interest in our Pingston hydrofacility.

 

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

 

The results of the Generation segment are as follows:

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

 

 

Management’sDiscussion and Analysis  |  16

 

----

 

**GenerationProduction and Gross Margins**

 

Generation’s production volumes, electricity and steamproduction revenues, and fuel and purchased power costs are presented belowbased on geographical regions.

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

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

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

 

**Western Canada**

 

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

 

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

 

Our Wabamun, Genesee 3, a portion of our Poplar Creek andCastle River facilities, four hydro facilities, and nine additional windfacilities sell their production on the merchant spot market. In order tomanage our exposure to changes in spot electricity prices as well as capturevalue, we contract a portion of this production to guarantee cash flows.

 

Due to their close physical proximity, three of ourcoal-fired plants, Sundance, Keephills, and Wabamun, are operated and managedcollectively and are referred to as “Alberta Thermal.” Our Wabamun plant willbe decommissioned in the first quarter of 2010.

 

McBride Lake, Meridian, Fort Saskatchewan, a significantportion of our Poplar Creek and Castle River assets, and three hydro facilitiesearn revenues under long-term contracts for which revenues are derived frompayments for capacity and/or the production of electrical energy and steam aswell as for ancillary services. These contracts are for an original term of atleast 10 years and payments do not fluctuate significantly with changes inlevels of production.

 

Our Grande Prairie biomass facility earns revenues underlong-term contracts based on actual production delivered at a specified priceper MWh.

 

For the year ended Dec. 31, 2009, production decreased1,921 GWh due to higher planned and unplanned outages at Alberta Thermal, lowerPPA customer demand at Alberta Thermal and Sheerness, and lower hydro volumes,partially offset by lower planned and unplanned outages at Genesee 3, andhigher wind volumes due to the acquisition of Canadian Hydro.

 

In 2008, production decreased 1,034 GWh due to higherunplanned outages at Alberta Thermal and Genesee 3, partially offset byincreased merchant production resulting from the Unit 4 uprate at our Sundancefacility.

 

 

17  | TransAlta Corporation

----

 

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

 

In 2008, gross margin decreased $64 million ($1.67 perinstalled MWh) due to higher unplanned outages at Alberta Thermal and Genesee3, and higher coal costs, partially offset by favourable pricing and highermerchant volumes due to the uprate on Unit 4 of our Sundance facility.

 

**EasternCanada**

 

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

 

For the year ended Dec. 31, 2009, production increased539 GWh primarily due to higher wind volumes as a result of the acquisition ofCanadian Hydro and the commissioning of Kent Hills.

 

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

 

For the year ended Dec. 31, 2009, gross marginsincreased $53 million ($3.74 per installed MWh) due to higher wind volumes as aresult of the acquisition of Canadian Hydro and the commissioning of KentHills, and the new agreement with the OPA at our Sarnia regional cogenerationpower plant.

 

In 2008, gross margins were comparable to the same period in2007.

 

**International**

 

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

 

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

 

For the year ended Dec. 31, 2009, production decreased1,773 GWh due to higher unplanned outages and higher economic dispatching atCentralia Thermal, and the expiration of the long-term contract at Saranac,partially offset by lower planned outages at Centralia Thermal. 

 

In 2008, production increased 15 GWh due to lower unplannedoutages and lower derates at Centralia Thermal (in 2007 we conducted test burnsof PRB coal), partially offset by higher planned outages as a result of equipmentmodifications made at Centralia Thermal and economic dispatching at CentraliaThermal in the second quarter.

 

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

 

In 2008, gross margins increased $77 million ($3.97 perinstalled MWh) compared to the same period in 2007 primarily due to favourablepricing and mark-to-market movements.

 

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

 

**Operations,Maintenance, and Administration**

 

For the year ended Dec. 31, 2009, OM&A expensesincreased primarily due to higher planned outages, unfavourable foreignexchange rates, and the acquisition of Canadian Hydro, partially offset bytargeted cost savings.

 

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

 

**Planned Maintenance**

 

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

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

 

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

 

 

Management’s Discussion and Analysis  |  18

 

----

 

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

 

In 2008, total planned maintenance costs increased comparedto 2007 due to the Unit 2 boiler modifications at Centralia Thermal, higherplanned outages across the fleet, and cost escalations.

 

**Depreciation Expense**

 

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

 

In 2008, depreciation expense increased compared to 2007 dueto increased capital spending, the retirement of assets that were not fullydepreciated as a result of planned maintenance activities, and the early retirementof certain components as a result of equipment modifications made at CentraliaThermal.

 

COMMERCIALOPERATIONS & DEVELOPMENT (“COD”):**Derives revenue and earnings from the wholesaletrading of electricity and other energy-related commodities and derivatives.Achieving gross margins while remaining within value at risk (“VaR”) limits isa key measure of COD’s trading activities.**

 

**COD is responsible for the management ofcommercial activities for our current generating assets. COD also managesavailable generating capacity as well as the fuel and transmission needs of theGeneration business by utilizing contracts of various durations for the forwardsales of electricity and for the purchase of natural gas, coal, andtransmission capacity. Further, COD is responsible for developing or acquiringnew cogeneration, wind, geothermal, and hydro generating assets, andrecommending portfolio optimization decisions. The results of all of theseactivities are included in the Generation segment.**

 

Our trading activities utilize a variety of instruments tomanage risk, earn trading revenue, and gain market information. Our tradingstrategies consist of shorter-term physical and financial trades in regionswhere we have assets and the markets that interconnect with those regions. Theportfolio primarily consists of physical and financial derivative instrumentsincluding forwards, swaps, futures, and options in various commodities. Thesecontracts meet the definition of trading activities and have been accounted forat fair value under Canadian GAAP. Changes in the fair value of the portfolioare recognized in earnings in the period they occur.

 

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

 

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

 

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

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

 

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

 

In 2008, gross margins increased due to all regionsexperienced positive results in 2008, with the increase primarily attributableto successful trading strategies involving regional power demand and pricedifferentials in the eastern region.

 

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

 

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

 

 

***NET INTEREST EXPENSE***

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

 

 

19  | TransAlta Corporation

----

 

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

 

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

 

For the year ended Dec. 31, 2008, net interest expensedecreased primarily due to interest income received on the settlement of thetax issue discussed above and higher capitalized interest, partially offset bylower interest income from cash deposits. 

*** ***

*** ***

***OTHER INCOME***

 

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

 

During 2008, mining equipment with a net book value of $2million related to the cessation of mining activities at the Centralia coalmine was sold for proceeds of $7 million.

 

 

***NON-CONTROLLING INTERESTS***

 

**We own 50.01 per cent of TA Cogen,which owns, operates, or has an interest in five natural gas-fired and onecoal-fired generating facility with a total gross generating capacity of 814MW. Stanley Power owns the minority interest in TA Cogen. Our CE Gen jointventure investment includes a 75 per cent ownership of Saranac, a 320 MWnatural gas-fired cogeneration facility in New York. Natural Forces owns a 17per cent interest in our Kent Hills facility, which operates 96 MW of windassets. Since we own a controlling interest in TA Cogen and Kent Hills, weconsolidate the entire earnings, assets, and liabilities in relation to ourownership of those assets. For Saranac, we proportionately consolidate ourshare of the earnings, assets, and liabilities in relation to our ownership.**

 

**Non-controlling interests on theConsolidated Statements of Earnings and Consolidated Balance Sheets relate tothe earnings and net assets attributable to TA Cogen, Saranac, and Kent Hillsthat are not owned by us. On the Consolidated Statements of Cash Flows, cashpaid to the minority shareholders of TA Cogen, Saranac, and Kent Hills is shownas distributions paid to subsidiaries’ non-controlling interests in thefinancing section.**

 

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

 

The earnings attributable to non-controlling interests forthe year ended Dec. 31, 2008 increased due to higher earnings at TA Cogenand CE Gen.

 

 

***EQUITY LOSS***

 

**As required under AccountingGuideline 15, Consolidation of Variable Interest Entities, of the CanadianInstitute of Chartered Accountants (“CICA”), our previously held Mexican operationswere accounted for as an equity investment. On Oct. 8, 2008, wesuccessfully completed the sale of our Mexican operations to InterGen for asale price of $334 million. The sale included the plants and all associatedcommercial arrangements. Refer to the Significant Events section for furtherdetails.**

 

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

 

 

***INCOME TAXES***

 

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

 

**Therefore, when a governmentannounces a change in future income tax rates, it will affect the anticipatedincome tax asset or liability that will appear in our financial statements.**

 

 

Management’s Discussion and Analysis  |  20

----

 

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

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

 

*1  To presentcomparable reconciliations, prior years’ effective tax rate analyses werecalculated based on earnings before income tax, equity loss, and other income.*

 

During 2008 and 2007, we settled certain taxation issueswith the associated taxation authorities. As a result, we recorded a futureincome tax recovery of $15 million and $18 million, respectively, related tothese items.

 

As a result of a reduction in Canadian corporate income taxrates expected to apply to future tax liabilities, income tax expense was reducedby $5 million and $48 million in 2009 and 2007, respectively.

 

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

 

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

 

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

 

 

***FINANCIAL POSITION***

 

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

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

 

 

21  | TransAlta Corporation

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***FINANCIAL INSTRUMENTS***

 

Financial instruments are used to manage our exposure tointerest rates, commodity prices, currency fluctuations, as well as credit andother market risks. We currently use physical and financial swaps, forward saleand purchase contracts, futures contracts, foreign exchange contracts, interestrate swaps and options to achieve our risk management objectives, which aredescribed below. Financial instruments are accounted for using the fair valuemethod of accounting. The initial recognition of fair value and subsequentchanges in fair value can affect reported earnings in the period the changeoccurs if hedge accounting is not elected. Otherwise, these changes in fairvalue will not affect earnings until the financial instrument is settled. Thefair values of those instruments that remain open at the balance sheet daterepresent unrealized gains or losses and are presented on the ConsolidatedBalance Sheets as risk management assets and liabilities.

 

We have two types of financial instruments: (1) thosethat are used in the COD and Generation segments in relation to Energy Tradingactivities, commodity hedging activities, and other contracting activities and(2) those used in the hedging of debt, projects, expenditures, and the netinvestment in self-sustaining foreign operations. The majority of thederivatives traded by the Corporation are not traded on an active exchange orextend beyond the time period for which exchange-based quotes are available.The fair values of these derivatives have been determined using valuationtechniques or models.

 

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

 

Under hedge accounting rules we test for effectivenessat the end of each reporting period to determine if the instruments areperforming as intended and hedge accounting can still be applied. For commoditycontracts, this testing ensures that the amount of electricity we havecontracted to supply or natural gas contracted to buy is still likely to beprovided. For financial instruments related to debt and projects, this testingensures that the amount we have contracted to pay for long-term financing andcapital projects has remained consistent in terms of timing and amounts. Allfinancial instruments are designed to ensure that future cash inflows andoutflows are predictable. Where hedges are effective, that is, it is reasonablethat we will fulfill that contract without having to purchase commodities inthe market, we continue the accounting treatment described above. Where hedgesare ineffective, that is, we will be required to fulfill that contract withcommodities purchased in the market, these hedges, in total or in part, areconsidered ineffective. The ineffective portion is no longer recorded as ahedge and the changes in fair value are recorded in income and no longerthrough OCI.

 

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

 

Our financial instruments are categorized as fair valuehedges, cash flow hedges, net investment hedges or non-hedges. These categoriesand their associated accounting treatments are explained in further detailbelow.

 

**Fair Value Hedges**

 

Fair value hedges are used to offset the impact offluctuations in the foreign currency and interest rates on various assets andliabilities. Interest rate swaps are used to hedge exposures in the fair valueof long-term debt caused by variations in market interest rates by fixing interestrates. Foreign exchange contracts are used to hedge certain foreign currencydenominated assets and liabilities. Based on the fair value of risk managementassets and liabilities at Dec. 31, 2009, approximately six per cent of ourfinancial instruments are fair value hedges.

 

All gains or losses related to fair value hedges arerecorded on the Consolidated Statements of Earnings, which, in turn, arecompletely offset by the value of the gains or losses related to the hedgedrisk of the debt instruments on the foreign currency denominated assets andliabilities.

 

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

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

*1  Optioncontracts may require an upfront cash investment.*

 

**Cash Flow Hedges**

 

Cash flow hedges are categorized as project or commodityhedges and are used to offset foreign exchange and commodity price exposures onlong-term projects as a result of market fluctuations. These contracts have amaximum duration of five years. Based on the fair value of risk managementassets and liabilities at Dec. 31, 2009, approximately 91 per cent of ourfinancial instruments are cash flow hedges.

 

 

Management’s Discussion and Analysis  |  22

----

 

**ProjectHedges**

Foreign currency forward contracts are used to hedge foreignexchange exposures resulting from anticipated contracts and firm commitmentsdenominated in foreign currencies. When project hedges qualify for, and we haveelected to use hedge accounting, the gains or losses related to these contractsin the periods prior to settlement are recorded in OCI with the fair valuebeing reported in risk management assets or liabilities, as appropriate. Uponsettlement of the financial instruments, any gain or loss on the contracts isincluded in the cost of the related asset and depreciated over the asset’sestimated useful life.

 

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

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

*1  Any ineffective portion is recorded in theConsolidated Statements of Earnings.*

 

**CommodityHedges**

Physical and financial swaps, forward sale and purchasecontracts, futures contracts, foreign exchange contracts, and options are usedprimarily to offset the variability in future cash flows caused by fluctuationsin electricity and natural gas prices. When commodity hedges qualify for, andwe have elected to use hedge accounting, the fair value of the hedges isrecorded in risk management assets or liabilities with changes in value beingreported in OCI, up until the date of settlement. The fair value of themajority of our commodity hedges are calculated using adjusted quoted pricesfrom an active market and/or the input is validated by broker quotes. Uponsettlement of these financial instruments, the amounts previously recognized inOCI are reclassified to net earnings.

 

Our physical commodity contracts are designated asall-in-one hedges and result in a net asset or liability position on ourConsolidated Balance Sheets. Upon physical delivery of the commodity, wereceive a gross settlement at the contracted price. Upon receipt of payment,the related net risk management asset or liability is eliminated. If anall-in-one hedge contract cannot be settled by physical delivery of theunderlying commodity, it will be settled financially.

 

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

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

*1  Optioncontracts may require an upfront cash investment.*

*2  Anyineffective portion is recorded in the Consolidated Statements of Earnings.*

 

During the year, the change in the position of financialinstruments to a net asset position is primarily a result of changes in futureprices on contracts in our Generation segment. Refer to the Critical AccountingPolicies and Estimates section of this MD&A for further details regardingfair valuation techniques. Our risk management profile and practices have notchanged materially from Dec. 31, 2008.

 

In limited circumstances, we may enter into commoditytransactions involving non-standard features for which market-observable datais not available. These transactions are defined under Canadian GAAP as LevelIII instruments. Level III instruments incorporate inputs that are notobservable from the market, therefore fair value is determined using valuationtechniques with inputs that are based on historical data such as unit availability,transmission congestion, demand profiles, and/or volatilities and correlationsbetween products derived from historical prices. Where commodity transactionsextend into periods for which market-observable prices are not available, aninternally-developed fundamental price forecast is used in the valuation. Fairvalues are validated by using reasonably possible alternative assumptions asinputs to valuation techniques, and any material differences are disclosed inthe notes to the financial statements. At Dec. 31, 2009, Level IIIinstruments had a net liability carrying value of $26 million. For the yearended Dec. 31, 2009, a realized gain of $1 million was included inearnings before income taxes relating to those Level III instruments.

 

For both project and commodity cash flow hedges, when we donot elect for hedge accounting, or the hedge is no longer effective and doesnot qualify for hedge accounting, the gains or losses as a result of changes inprices or exchange rates related to these financial instruments are recordedthrough the Consolidated Statements of Earnings and Retained Earnings in theperiod the gain or loss occurs.

 

**NetInvestment Hedges**

 

Cross-currency interest rate swaps, foreign currency forwardcontracts, and foreign currency debts can be used to hedge exposure to changesin the carrying values of our net investments in foreign operations havingfunctional currency other than the Canadian dollar. Foreign denominatedexpenses are also used to assist in managing foreign currency exposures onearnings from self-sustaining foreign operations. Based on the fair value ofrisk management assets and liabilities at Dec. 31, 2009, approximately twoper cent of our financial instruments are net investment hedges.

 

 

23**  |  **TransAlta Corporation

----

 

Since net investment hedges qualify for hedge accounting,gains or losses related to net investment hedges are recorded in OCI untilthere is a reduction in the net investment of the foreign operation. Netinvestment hedges are short-term in nature related to the underlyinginvestment, therefore contracts must be routinely renewed. As each of theshort-term contracts mature or is settled, cash inflows or outflows result thatare recorded in investing activities on the Consolidated Statements of CashFlows to reconcile the difference between contracted rates and market rates atthe date of settlement. If there is a reduction in the net investment of theforeign operation, the gains or losses previously recorded in OCI aretransferred to net earnings in that period.

 

A summary of how typical net investment hedges are recordedin 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 exposuresrelated to changes in foreign exchange rates. Financial instruments notdesignated as hedges are used to reduce currency risk on the results of ourforeign operations due to the fluctuation of exchange rates beyond what isnaturally hedged. All gains or losses related to non-hedges are recorded in theConsolidated Statements of Earnings as they do not qualify for, nor have theybeen designated for, hedge accounting. Based on the fair value of riskmanagement assets and liabilities at Dec. 31, 2009, approximately one percent of our financial instruments are non-hedges.

 

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

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

*1  Some contracts may require an initial cashinvestment.*

 

 

***EMPLOYEE SHARE OWNERSHIP***

 

We employ a variety of stock-based compensation plans toalign employee and corporate objectives. On Feb. 1, 2008, one millionstock options were granted at an exercise price of $31.97, being the last saleprice of board lots of the shares on the Toronto Stock Exchange the day priorto the day the options were granted for Canadian employees, and U.S.$31.83,being the closing sale price on the New York Stock Exchange on the same datefor U.S. employees. These options will vest in equal installments over fouryears starting Feb. 1, 2009 and expire on Feb.1, 2019. The conversion ofthese options is not dilutive.

 

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

 

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

 

At Dec. 31, 2008, 1.6 million options to purchase ourcommon shares were outstanding with a weighted average exercise price of$27.06, and 0.6 million were exercisable at the reporting date. For the yearended Dec. 31, 2008, 0.3 million options with a weighted average exerciseprice of $20.52 were exercised resulting in 0.3 million shares issued, and 0.2million options were cancelled with a weighted average exercise price of$27.96.

 

Under the terms of the Performance Share Ownership Plan(“PSOP”), certain employees receive grants which, after three years, make themeligible to receive a set number of common shares or the equivalent value incash plus dividends based upon our performance relative to companies comprisingthe comparator group. After three years, once PSOP eligibility has beendetermined and if common shares are granted, 50 per cent of the common sharesare released to the participant and the remaining 50 per cent are held in trustfor one additional year. The granting of common shares under the PSOP plan isnot dilutive.

 

Under the terms of the Employee Share Purchase Plan, weextend an interest-free loan to our employees below senior manager level for upto 30 per cent of the employee’s base salary for the purchase of our commonshares from the open market. The loan is repaid over a three-year period by theemployee through payroll deductions unless the shares are sold, at which pointthe loan becomes due on demand. At Dec. 31, 2009, accounts receivable fromemployees under the plan totalled $3 million (2008–$3 million). This program isnot available to officers and senior management.

 

 

Management’sDiscussion and Analysis**  |  **24

----

 

***EMPLOYEE FUTURE BENEFITS***

 

We have registered pension plans in Canada and the U.S.covering substantially all employees of the Corporation, its domesticsubsidiaries, and specific named employees working internationally. These planshave defined benefit and defined contribution options. In Canada, there is asupplemental defined benefit plan for Canadian-based defined contributionmembers whose annual earnings exceed the Canadian income tax limit. The definedbenefit option of the registered pension plan ceased for new employees onJune 30, 1998. The latest actuarial valuations of the registered andsupplemental pension plans were as at Dec. 31, 2009.

 

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

 

The supplemental pension plan is an obligation of thecorporation. We are not obligated to fund the supplemental plan but areobligated to pay benefits under the terms of the plan as they come due. We haveposted a letter of credit in the amount of $58 million to secure theobligations under the supplemental plan.

 

 

***STATEMENTS OF CASH FLOWS***

 

The following charts highlight significant changes in theConsolidated Statements of Cash Flows for the year ended Dec. 31, 2009 and2008:

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

 
| **Year ended Dec. 31**                   | ** ** | **2008** |   | **2007** | ** ** | **Explanation of change**                                                                                                                                                                                                                                                                                                  |
|-----------------------------------------------|------------|----------|--------|----------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Cash  and cash equivalents, beginning of year |       | 51       |   | 66       |       |                                                                                                                                                                                                                                                                                                                       |
| Provided  by (used in):                       |       |     |   |     |       |                                                                                                                                                                                                                                                                                                                       |
| Operating  activities                         |       | 1,038    |   | 847      |       | Increase in cash earnings of $47 million and  favourable changes in working capital of $144 million primarily due to the  timing of PPA receipts in 2008.                                                                                                                                                                  |
| Investing  activities                         |       | (581     | )      | (410     | )          | Additional capital spending of $407 million, and a  decrease in realized gains on financial instruments of $55 million, partially  offset by proceeds from the sale of our Mexican equity investment of $332  million.                                                                                                     |
| Financing  activities                         |       | (467     | )      | (444     | )          | Increase in repayments of short-term debt of $532  million and long-term debt of $56 million, and a $55 million increase to  repurchase common shares under the NCIB program, partially offset by the  issuance of $500 million of long-term debt in 2008 and the redemption of  preferred shares of $175 million in 2007. |
| Translation  of foreign currency cash         |       | 9        |   | (8       | )          |                                                                                                                                                                                                                                                                                                                       |
| Cash  and cash equivalents, end of year       |       | 50       |   | 51       |       |                                                                                                                                                                                                                                                                                                                       |

 

 

25**  |  **TransAlta Corporation

----

 

***LIQUIDITY AND CAPITAL RESOURCES***

 

Liquidity risk arises from our ability to meet generalfunding needs, engage in trading and hedging activities, and manage the assets,liabilities and capital structure of the Corporation. Liquidity risk is managedby maintaining sufficient liquid financial resources to fund obligations asthey 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 creditfacilities, and long-term debt issued under our Canadian and U.S. shelfregistrations. Our primary uses of funds are operational expenses, capitalexpenditures, dividends, distributions to non-controlling limited partners, andinterest and principal payments on debt securities. 

 

**Debt**

 

Recourse and non-recourse debt totalled $4.4 billion atDec. 31, 2009 compared to $2.8 billion at Dec. 31, 2008. Totallong-term debt increased from Dec. 31, 2008 primarily due to the debtissued during the fourth quarter of 2009 to fund the acquisition of CanadianHydro and growth expenditures.

 

**CreditFacilities**

 

We have a total of $2.1 billion of committed long-termcredit facilities of which $0.7 billion is not drawn and is available as ofDec. 31, 2009, subject to customary borrowing conditions. At Dec. 31,2009, credit utilized under these facilities is $1.4 billion, which iscomprised of actual drawings of $1.1 billion and of letters of credit of $334million. Amounts drawn on credit facilities increased in 2009 as a result oflower cash earnings, partially offset by an increase in collateral received in2009, which was used to repay credit facility balances.

 

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

 

**ShareCapital**

 

On Feb. 22, 2009, we had 219 million common sharesoutstanding.

 

**NormalCourse Issuer Bid Program**

 

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

 

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

 

**GuaranteeContracts**

 

We have obligations to issue letters of credit and cashcollateral to secure potential liabilities to certain parties including thoserelated to potential environmental obligations, trading activities, hedgingactivities, and purchase obligations. At Dec. 31, 2009, we providedletters of credit totalling $334 million (2008 – $430 million) and cashcollateral of $27 million (2008 – $37 million). The decrease in letters ofcredit and cash collateral is due primarily to lower forward electricity pricesin the Pacific Northwest and reduced trading activity with exchanges. Theseletters of credit and cash collateral secure certain amounts included on ourConsolidated Balance Sheets under “Risk Management Liabilities” and “AssetRetirement Obligation”.

 

**WorkingCapital**

 

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

 

**Capital Structure**

** **

Our capital structure consisted ofthe following components as shown below:

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

 

 

Management’sDiscussion and Analysis**  |  **26

----

 

 

Contractual repayments of fixed pricegas purchase contracts, transmission, operating leases, commitments undermining agreements, commitments under long-term service agreements, long-termdebt and the related interest, and growth project commitments are as follows:

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

*1  Repaymentsof long-term debt include amounts related to our credit facilities that are currentlyscheduled to mature in 2012 and 2013.*

*2  Intereston long-term debt is based on debt currently in place with no assumption as tore-financing an instrument on maturity.*

* *

* *

***OFF-BALANCE SHEET ARRANGEMENTS***

 

Disclosure is required of all off-balance sheet arrangementssuch as transactions, agreements or contractual arrangements withunconsolidated entities, structured finance entities, special purpose entitiesor variable interest entities that are reasonably likely to materially affectliquidity or the availability of, or requirements for, capital resources. Wecurrently have no such off-balance sheet arrangements.

 

 

***CLIMATE CHANGE AND THE ENVIRONMENT***

 

**The varieties of combustible fuelsused to generate electricity all have some impact on the environment. While weare pursuing a climate change strategy that includes, among other elements,investing in renewable energy resources such as wind and hydro, we believe thatcoal and natural gas as fuels will continue to play an important role inmeeting the energy needs of the future. We place significant importance onenvironmental compliance while seeking to deliver low cost electricity.**

 

**Ongoingand Recently Passed Environmental Legislation**

 

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

 

**Canada**

In December 2009, the Copenhagen Accord (“The Accord”)on climate change was negotiated and announced. The Accord is not binding nordoes it stipulate a global target for GHG reductions, but rather countries areleft to determine their individual targets and policies to manage emissions.The federal government’s previously-announced goal of a 17 per cent GHGreduction from a 2005 baseline by 2020 remains the target. However, the federalgovernment has not yet implemented a framework or regulations to achieve thosegoals. At this point, it appears that the details and schedule of the Canadianprogram will depend on the development and direction of the U.S. approach.

 

Separately, the Government of Canada announced its intent todevelop new Canadian air pollutant requirements for sulphur dioxide, nitrogenoxide (“NOx”), and mercury. Stakeholderconsultations involving industry, provincial and federal governments, andenvironmental organizations are underway; however there is currently no defineddate for the finalization and implementation of any recommendations.

 

On Dec. 1, 2009, the Government of Ontario released itsmandatory GHG reporting regulation, requiring industrial facilities with morethan 25,000 tonnes of carbon dioxide (“CO2”) emissions peryear to report annually. The first reporting deadline for 2010 emissions isJune 2011. This regulation is intended to lay the groundwork for anOntario-based GHG regulatory framework to be implemented in 2010.

 

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

 

**UnitedStates**

The American Clean Energy and Security Act was passed inJune 2009, which established a cap and trade system designed to achieve a17 per cent reduction in GHG emissions by 2020. There is significantuncertainty regarding the form and schedule of legislation that will bedeveloped as a result of the cap and trade system designed, or if legislationwill even emerge in 2010.

 

Meanwhile, the U.S. Environmental Protection Agency (“EPA”)is pursuing a separate path to regulate GHGs under the Clean Air Act. InNovember 2009, the U.S. courts upheld the endangerment finding whichdetermines that CO2 is a pollutant and therefore able to beregulated by the EPA under the Clean Air Act. How and when a legislative optionwill develop versus the EPA regulatory approach is uncertain. InSeptember 2009, the EPA separately announced requirements for nationwide GHGreporting beginning in 2010.

 

 

27**  |  **TransAlta Corporation

----

 

In Washington State in May 2009, Governor Gregoiresigned an Executive Order laying out the state’s plan for addressing climatechange related emissions. In the Order the Governor included a directive to theState Department of Ecology to work with us to apply the state’s GHGperformance standard for power generation to the Centralia plant no later than2025. That standard would require emissions reductions of approximately 0.5tonnes/MWh, or about half of what is currently emitted at Centralia.Exploratory discussions are underway with the Department of Ecology to examineopportunities to achieve this reduction in emissions. At this time it is notclear how the state’s target and timeframe will endure should federal GHGlegislation come into effect.

 

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

 

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

n      Reducemercury emissions by 50 per cent from current levels

 

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

 

**LegalImplications**

 

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

 

**TransAltaActivities**

 

We believe that climate change has the potential to impactthe business environment in which we operate. Reducing the environmental impactof our activities has a benefit not only to our operations and financialresults, but also to the communities in which we operate. We expect thatincreased scrutiny will be placed on environmental emissions and compliance,and we therefore have a proactive approach to minimizing risks to our results.

 

Our environment management programs encompass severalelements:

 

n      construction of renewable power sources;

n      environmental controls and efficiencyimprovements;

n      active participation in policydiscussions;

n      clean energy technology developmentincluding CCS; and

n      investment in an offsets portfolio.

 

**RenewablePower**

 

In addition to our acquisition of Canadian Hydro, ourinvestment in renewable power sources continues through the building ofrenewable power resources such as the Summerview 2, Kent Hills, and Ardenvillewind farms. An increased renewable portfolio provides increased flexibility in generationand creates incremental environmental value through renewable energycertificates or, in future, offsets.

 

**EnvironmentalControls and Efficiency**

 

We continue to make operational improvements and investmentsto our existing generating facilities to reduce the environmental impact ofgenerating electricity. We are installing mercury control equipment at ourAlberta Thermal operations in 2010 in order to meet the province’s 70 per centreduction objectives. Our new Keephills 3 plant will use supercriticalcombustion technology to maximize thermal efficiency, as well as sulphurdioxide capture and low NOx combustion technology.

 

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

 

**PolicyParticipation**

 

We are active in policy discussions at a variety of levelsof government. These stakeholder negotiations have allowed us to engage inproactive discussions with governments and industry participants to meetenvironmental requirements over the longer-term.

 

**CCSDevelopment**

 

On Oct. 14, 2009, the governments of Canada and Albertaannounced that Project Pioneer, our CCS project, received committed funding ofmore than $750 million. This funding is provided as part of the Government ofCanada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2billion CCS initiative. The funding will support the undertaking of a FEEDstudy that is expected to be complete in 2010 or early 2011. Once built, theprototype plant will be one of the largest CCS facilities in the world and thefirst to have an integrated underground storage system. The project will pilotAlstom Canada’s proprietary chilled ammonia carbon capture technology and willbe designed to capture one megatonne of CO2 at one of our Alberta Thermal units. The CO2 will be used for enhanced oil recovery as wellas injected into a permanent geological storage site.

 

In addition, we look to advance other clean energy technologiesthrough organizations such as the Canadian Clean Coal Power Coalition whichexamines emerging clean combustion technologies such as gasification. We arealso part of a group of companies participating in the Integrated CO2 Network to develop carbon capture and storagesystems and infrastructure for Canada.

 

**OffsetsPortfolio**

 

TransAlta maintains an offset portfolio with a variety ofinstruments than can be used for compliance purposes or otherwise banked orsold. We continue to examine additional emission offset opportunities that alsoallow us to meet emission targets at a competitive cost. We ensure that anyinvestments in offsets will meet certification criteria in the market in whichthey are to be used.

 

 

Management’s Discussion and Analysis**  |  **28

----

 

**FutureGrowth**

 

In 2009, we estimate that 40 million tonnes of GHGs with anintensity of 0.900 tonnes/MWh (2008–38.5 million tonnes of GHGs with anintensity of 0.893 tonnes/MWh) were emitted as a result of normal operatingactivities(1). Total GHG emissions increased in2009 largely due to more dispatch variability at our Alberta Thermal operationsleading to slightly lower combustion efficiencies. New generation growth andthe related increase in emissions will be partially offset by thedecommissioning of Unit 4 at our Wabamun plant. The various activitiesdiscussed above, including our investment in renewable power and CCStechnology, are designed to minimize the environmental and financial impacts ofthe expected increase in emissions.

 

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

 

 

***2010 OUTLOOK***

 

***BUSINESS ENVIRONMENT***

 

**PowerPrices**

 

In 2010, power prices are expected to remain at or slightlyabove 2009 levels due to the influence of low natural gas prices and minimaldemand growth. In the Alberta market, the longer-term fundamentals of themarket remain strong and the recovery of the oil sands is expected to driveload growth. In the Pacific Northwest, the recovery of natural gas prices isthe main driver behind the recovery of power prices. Natural gas prices are expectedto remain low until 2011.

 

**EnvironmentalLegislation**

 

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

 

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

 

**EconomicEnvironment**

 

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

 

A number of our financial and industrial counterparties haveexperienced credit rating downgrades and we expect 2010 will continue to bechallenging for some of our counterparties. While we had no counterparty lossesin 2009, we continue to monitor counterparty credit risk and act in accordancewith our established risk management policies. We do not anticipate anymaterial change to our existing credit practices and continue to deal primarilywith investment grade counterparties.

 

***OPERATIONS***

 

**Capacity,Production, and Availability**

 

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

 

**CommodityHedging**

 

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

 

 

*1**        **2009 data are estimates based onbest available data at the time of report production. GHGs include watervapour, CO**2**, methane, nitrous oxide,hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHGemissions are comprised of CO**2**.*

 

 

29**  |  **TransAlta Corporation

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**FuelCosts**

 

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

 

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

 

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

 

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

 

**Operations,Maintenance, and Administration Costs**

 

OM&A costs per MWh of installed capacity fluctuate byquarter and are dependent on the timing and nature of maintenance activities.OM&A costs for 2010 are expected to remain flat compared to 2009 as costsrelated to Canadian Hydro are expected to be offset by lower plannedmaintenance, our operational synergies, and productivity measures. OM&Acosts per installed MWh for 2010 are expected to decrease primarily as a resultof lower planned maintenance and an increase in installed capacity due to theacquisition of Canadian Hydro.

 

**EnergyTrading**

 

Earnings from our COD segment are affected by prices in themarket, positions taken, and the duration of those positions. We continuouslymonitor both the market and our exposure to maximize earnings while stillmaintaining an acceptable risk profile. Our 2010 objective is for EnergyTrading to contribute between $50 million and $70 million in gross margin.

 

**Exposureto Fluctuations in Foreign Currencies**

 

Our strategy is to minimize the impact of fluctuations inthe Canadian dollar against the U.S. dollar by offsetting foreign denominatedassets with foreign denominated liabilities and foreign exchange contracts. Wealso have foreign currency expenses, including interest charges, which are usedto largely offset our net foreign currency-denominated earnings.

 

**NetInterest Expense**

 

Net interest expense for 2010 is expected to be highermainly due to higher debt balances and lower interest income. However, changesin interest rates and in the value of the Canadian dollar to the U.S. dollarwill affect the amount of net interest expense incurred.

 

**Liquidityand Capital Resources**

 

If there is increased volatility in power and natural gasmarkets, or if market trading activities increase, there may be the need foradditional liquidity. To mitigate this liquidity risk, we expect to maintain$2.1 billion of committed credit facilities, and will monitor our exposures andobligations to ensure we have sufficient liquidity to meet our requirements.

 

**AccountingEstimates**

 

A number of our accounting estimates, including thoseoutlined in the Critical Accounting Policies and Estimates section of thisMD&A, are based on the current economic environment and outlook. While wedo not anticipate significant changes to these estimates as a result of thecurrent economic environment, market fluctuations could impact, among otherthings, future commodity prices, foreign exchange rates, and interest rates,which could, in turn, impact future earnings and the unrealized gains or lossesassociated with our risk management assets and liabilities. The unrealizedgains or losses related to our risk management assets and liabilities are notexpected to impact our cash flows as they are generally settled at contractedprices.

 

 

Management’s Discussion and Analysis**  |  **30

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***CAPITAL EXPENDITURES***

 

Our major projectsare focused on sustaining our current operations and supporting our growthstrategy.

 

**Growth Capital Expenditures**

 

In 2009, wesuccessfully completed two of our growth capital projects, Blue Trail and theSundance Unit 5 uprate. We have nine significant growth capital projects thatare currently in progress with targeted completion dates between Q4 2010 and Q42012.

 

A summary of each ofthese significant projects is outlined below:

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

*1  Amounts are shown net of jointventure contributions.*

 

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

 

**Sustaining Capital Expenditures**

 

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

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

 

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

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

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

 

 

31 **| **TransAlta Corporation

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**Financing**

 

Financing for thesecapital expenditures is expected to be provided by cash flow from operatingactivities, existing borrowing capacity, and capital markets. The fundsrequired for committed growth and sustaining projects are not expected to beimpacted by the current economic environment due to the highly contractednature of our cash flow, our solid financial position, and the amount ofcapital available to us under existing committed credit facilities.

 

 

***RELATED PARTY TRANSACTIONS***

 

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

 

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

 

CE Gen has enteredinto contracts with related parties to provide administrative and maintenanceservices. The total value of these contracts are U.S.$3 million per year forthe years ending Dec. 31, 2009 and 2010.

 

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

 

 

***RISK MANAGEMENT***

 

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

 

The responsibilitiesof various stakeholders of our risk management oversight structure aredescribed below:

 

THE BOARD OF DIRECTORSprovides stewardship of the Corporation, establishes policies and procedures,defines risk tolerance as established under the Toronto Stock Exchangecorporate governance guidelines, and receives an annual comprehensiveEnterprise Risk Management (“ERM”) review. The ERM reviews consist of aholistic view of the Corporation’s inherent risks, how we mitigate these risks,and residual risks. It defines our risks, discusses who is responsible tomanage each risk, how the risks are inter-related with each other, andidentifies the applicable risk metrics. The Board of Directors also examinesthe ERM review in order to fulfill its requirement to understand the key risksof the Corporation and directs management to address any risk levels with whichit believes are not optimal for shareholder value creation.

 

AUDIT AND RISKCOMMITTEE (“ARC”) established bythe Board of Directors, provides assistance to the Board of Directors infulfilling its oversight responsibility relating to the integrity of ourfinancial statements and the financial reporting process, the systems ofinternal accounting and financial controls, the internal audit function, theexternal auditors’ qualifications, terms and conditions of appointment,including remuneration, independence, performance and reports, and the legaland risk compliance programs as established by management and the Board ofDirectors. The ARC approves our Commodity Risk and Financial ExposureManagement policies and reviews quarterly ERM reporting.

 

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

 

TECHNICAL RISK ANDCOMMERCIAL TEAM (“TRACT”)is a committee chaired by the Vice-President, Project Management Office, and iscomprised of our financial and operations vice presidents. It reviews majorprojects and commercial agreements at various stages through development, priorto submission for executive and Board approval.

 

 

Management’s Discussion and Analysis  **|**  32

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CORPORATE TREASURY is responsible for the identification, management,monitoring, and reporting of financial risks, including: interest rate, foreignexchange, credit, liquidity, and insurable risks. The objective of CorporateTreasury is to maintain a strong financial position and a low cost of capitalby sustaining a well capitalized balance sheet, mitigating earnings volatility,and maintaining ready access to capital markets. Our risk management policyrequires that there be sufficient resources and training available to fulfillthese objectives, including maintaining segregation of duties, all inaccordance with risk management best practices.

 

RISK MANAGEMENT is staffed by experienced risk professionals who areresponsible for ERM reporting to the Board and ARC, participating in riskidentification, analysis, and reporting in major projects, analyzing commercialand environmental risk exposures in our assets and trading operations, as wellas ensuring our daily market price exposure is kept within approved riskmetrics, including VaR, position limits, term limits, and market limits. TheRisk Management group uses a variety of processes and models to perform thisanalysis.

 

***RISK CONTROLS***

 

Our risk controlshave several key components:

 

**EnterpriseTone**

 

Every corporateculture is unique. We strive to be more than unique by fostering beliefs andactions that are true to and respectful of our many stakeholders. We do this byinvesting in communities where we live and work, operating and growingsustainability, putting safety first, and being responsible to the many groupsand individuals with whom we work.

 

**Policies**

 

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

 

**Reporting**

 

We regularly reportrisk exposures to key decision makers including the Board of Directors, seniormanagement, and the EMC. This reporting to the EMC includes analysis of newrisks, existing risk exposures, events that can affect these risks, andrecommendations for any suggested course of action to mitigate the existinglevel of risk. This monthly reporting provides for effective and timely riskmanagement and oversight.

 

**WhistleblowerSystem**

 

We have a system inplace where employees, shareholders, or other stakeholders may report anypotential ethical concerns. These concerns can be submitted anonymously, eitherdirectly to the ARC or to the Vice-President Internal Audit, who engagesCorporate Security, Legal and Human Resources in determining the appropriatecourse of action. These concerns and any actions taken are discussed with theARC.

 

**Valueat Risk and Trading Positions**

 

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

 

VaR is the primarymeasure used to manage COD’s exposure to market risk resulting from tradingactivities. VaR is monitored on a daily basis, and is used to determine thepotential change in the value of our marketing portfolio over a three-dayperiod within a 95 per cent confidence level resulting from normal marketfluctuations. Stress tests are performed weekly on both earnings and VaR tomeasure the potential effects of various market events that could impactfinancial results, including fluctuations in market prices, volatilities ofthose prices and the relationships between those prices. The three day averageVaR for the year ending Dec. 31, 2009 was $3 million compared to $6million for the same period in 2008.

 

We estimate VaR usingthe historical variance/covariance approach. Currently, there are two acceptedenergy industry methodologies for estimating VaR: historical variance/covarianceand monte carlo. An inherent limitation of historical variance/covariance VaRis that historical information used in the estimate may not be indicative offuture market risk. See additional discussion under commodity price risk in theRisk Management section of this MD&A.

 

***RISK FACTORS***

 

Risk is inherent inall business activities and can never be entirely eliminated. However,shareholder value can be protected and enhanced by identifying, mitigating,monitoring, reporting, and where possible, insuring against these risks.

 

The following sectionaddresses some, but not all, risk factors that could affect our future resultsand our activities in mitigating those risks. These risks do not occur inisolation, but must be considered in conjunction with each other.

 

Certain sections willshow the after-tax effect on net earnings and/or cash flows of changes incertain key variables. The analysis is based on business conditions andproduction volumes in 2009. Each item in the sensitivity analysis assumes allother potential variables are held constant. While these sensitivities areapplicable to the period and magnitude of changes on which they are based, theymay not be applicable in other periods, under other economic circumstances, orfor a greater magnitude of changes.

 

 

33 **| **TransAlta Corporation

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**Volume Risk**

 

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

 

Our hydro operations’financial performance is partially dependent upon the availability of water ina given year. The availability of water is difficult to forecast as it isprimarily driven by weather. Such water availability introduces a degree ofvolatility in revenues earned by our hydro operations from year to year. Thisrisk is complicated by obligations imposed within the PPA applicable to ourAlberta hydro facilities. A monthly financial obligation must be paid to thePPA Buyer, based on a predetermined quantity of energy and ancillary servicesat market prices, regardless of our ability to generate such quantities. Wecarefully balance all of these factors together to achieve optimal productivitywith the water resources available.

 

Our wind andgeothermal operations are dependant upon the availability of wind andgeothermal resources.

 

We manage these risksby:

 

**n**            actively managing our assets and their condition through theGeneration and Capital and Asset Reporting groups in order to be proactive inplant maintenance so that they are available to produce when market requires,

**n**            monitoring water resources throughout Alberta to the best ofour ability and optimizing this resource against real-time electricity marketopportunities,

**n**            placing our wind and geothermal facilities in locations thatwe believe to have sufficient resources in order for us to be able to generatesufficient electricity to meet the requirements of our contracts.  However, we cannot guarantee that theseresources will be available when we need them or in the quantities that werequire, and

**n**            monitoring market volumes and liquidity to ensure sufficientvolumes are available to fulfill proprietary trading requirements.

 

Thesensitivities of volumes to our net earnings are shown below:

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

 

**GenerationEquipment and Technology Risk**

 

Our plants areexposed to operational risks such as fatigue cracks in boilers, corrosion inboiler tubing, turbine failures, and other issues that can lead to outages andincreased volume risk. If plants do not meet availability or production targetsspecified in their PPA or other long-term contracts, we must either compensatethe purchaser for the loss in the availability of production or record reducedelectrical or capacity payments. For merchant facilities, an outage can resultin lost merchant opportunities. Therefore, an extended outage could have amaterial adverse effect on our business, financial condition, results ofoperations, or our cash flows.

 

As well, we areexposed to procurement risk for specialized parts that may have long leadtimes. If we are unable to procure these parts when they are needed formaintenance activities, we could face an extended period where our equipment isunavailable to produce electricity. 

 

We manage ourgeneration equipment and technology risk by:

 

**n**            operating our generating facilities within defined andproven operating standards that are designed to maximize the output of ourgenerating facilities for the longest period of time,

**n**            performing preventative maintenance on a regular basis,

**n**            adhering to a comprehensive plant maintenance program andregular turnaround schedules,

**n**            adjusting maintenance plans by facility to reflect theequipment type and age,

**n**            having sufficient business interruption insurance in placein the event of an extended outage,

**n**            having force majeure clauses in the PPAs and otherlong-term  contracts,

**n**            using technology in our generating facilities that isselected and maintained with the goal of maximizing the return on those assets,

**n**            monitoring technological advances and evaluating theirimpact upon our existing generating fleet and related maintenance programs,

**n**            negotiating strategic supply agreements with selectedvendors to ensure key components are available in the event of a significantoutage 

**n**            entering into long-term arrangements with our strategic supply partners to ensure availabilityof critical spare parts, and

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

 

**CommodityPrice Risk**

 

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

 

We manage exposure tofluctuations in gross margin associated with commodity price risk by:

 

**n**            entering into long-term contracts that specify the price at which electricity, steam, and otherservices are provided,

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

**n**            purchasing natural gas coincident with production formerchant plants so spot market spark spreads are adequate to produce and sellelectricity at a profit, and

**n**            ensuring limits and controls are in place for ourproprietary trading activities to ensure they are in line with our VaRmethodologies.

 

In 2009, we hadapproximately 97 per cent of production under short-term and long-termcontracts and hedges (2008 – 97 per cent). In the event of a planned orunplanned plant outage or other similar event, however, we are exposed tochanges in electricity prices on purchases of electricity from the market tofulfill our supply obligations under these short- and long-term contracts.

 

 

Management’s Discussion and Analysis  **|**  34

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We manage fuel pricecommodity risk by:

 

**n**     entering into long-term contracts that specify the price atwhich fuel is to be supplied to our plants, and

**n**     selectively using hedges, where available, to set prices forfuel.

 

We are exposed toincreases in the cost of fuels used in production to the extent such increasesare greater than the increases in the price that we can obtain for theelectricity we produce. In 2009, 79 per cent (2008–82 per cent) of our cost ofgas used in generating electricity was contractually fixed or passed through toour customers and 100 per cent (2008–100 per cent) of our purchased coal costswere contractually fixed.

 

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

 

The sensitivities ofprice changes to our net earnings are shown below:

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

 

**FuelSupply Risk**

 

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

 

At Alberta Thermal,higher input costs, such as diesel, tires, the price of mining equipment,increased amounts of overburden being removed to access coal reserves, andmining operations moving further away from the power plants are allcontributing to increased mining costs. Additionally, the ability of the minesto deliver coal to the power plants can be impacted by weather conditions andlabour relations. At Centralia Thermal, interruptions at our suppliers’ minesand the availability of trains to deliver coal could affect our ability togenerate electricity.

 

We manage fuel supplyrisk by:

 

**n**      ensuring that the majority of the coal used in electricalgeneration is from coal reserves owned by us, thereby limiting our exposure tofluctuations in the supply of coal from third parties.  As at Dec. 31, 2009, approximately 75per cent (2008–70 per cent) of the coal used in generating activities is fromcoal reserves owned by us,

**n**      using longer-term mining plans to ensure the optimal supplyof coal from our mines,

**n**      sourcing the majority of the coal used at Centralia Thermalunder a mix of short-, medium-, and long-term contracts and from multiple minesources to ensure sufficient coal is available at a competitive cost,

**n**      contracting sufficient trains to deliver the coalrequirements at Centralia Thermal,

**n**      ensuring efficient coal handling and storage facilities arein place so that the coal being delivered can be processed in a timely andefficient manner,

**n**      monitoring and maintaining coal specifications, carefullymatching the specifications mined with the requirements of our plants, and

**n**      hedging diesel exposure in mining and transportation costs.

 

We believe adequatesupplies of natural gas at reasonable prices will be available for plants whenexisting supply contracts expire.

 

**EnvironmentalRisk**

 

Environmental risksare risks to our business associated with changes in environmental regulationsor exposures. New emission reduction objectives for the power sector are beingestablished by governments in Canada and the United States. We anticipatecontinued and growing scrutiny by investors relating to sustainabilityperformance. These changes to regulations may affect our earnings by imposingadditional costs on the generation of electricity, such as emission caps,requiring additional capital investments in emission capture technology, orrequiring us to invest in offset credits. It is anticipated that thesecompliance costs will increase due to increased political and public attentionto environmental concerns.

 

We manageenvironmental risk by:

 

**n**      seeking continuous improvement in numerous performancemetrics such as emissions, safety, land and water impacts, and environmentalincidents,

**n**      having an International Organization for Standardization andOccupational Health and Safety Assessment Series-based environmental health andsafety (“EHS”) management system in place that is designed to continuouslyimprove environmental performance,

**n**      committing significant effort to work with regulators inCanada and the United States to ensure regulatory changes are well designed andcost effective,

**n**      developing compliance plans that address how to meet orexceed emission standards for GHGs, mercury, sulphur dioxide and oxides ofnitrogen, which will be adjusted as regulations are finalized,

**n**      purchasing emission reduction offsets outside of ouroperations,

**n**      investing in renewable energy projects, such as windgeneration, and

**n**      investing in clean coal technology development, whichprovides long-term promise for large emission reductions from fossil-firedgeneration.

 

 

35**  |  **TransAltaCorporation

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We strive to maintaincompliance with all environmental regulations relating to operations andfacilities. Compliance with both regulatory requirements and management systemstandards is regularly audited through our performance assurance policy andresults are reported quarterly to our Board of Directors.

 

In 2009, we spent approximately$45 million (2008–$47 million) on environmental management activities, systemsand processes.

 

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

 

**CreditRisk**

 

Credit risk is therisk to our business associated with changes in creditworthiness of entitieswith which we have commercial exposures. This risk is in the ability of acounterparty to either fulfill their financial or performance obligations to usor where we have made a payment in advance of the delivery of a product orservice. The inability to collect cash due to us or to receive products orservices may have an adverse impact upon our net earnings and cash flows.

 

We manage our exposureto credit risk by:

 

**n**      establishing and adhering to policies that define creditlimits based on creditworthiness of counterparties, define contract termlimits, and credit concentration with any specific counterparty,

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

**n**      using security instruments, such as parental guarantees,letters of credit, and cash collateral that can be collected if a counterpartyfails to fulfill their obligation or go over their limits, and

**n**      reporting our exposure using a variety of methods that allowkey decision makers to assess credit exposure by counterparty.  This reporting allows us to assess creditlimits for counterparties and the mix of counterparties based on their creditratings.

 

If established creditexposure limits are exceeded, we take steps to reduce this exposure such asrequesting collateral, if applicable, or by halting commercial activities withthe affected counterparty. However, there can be no assurances that we will besuccessful in avoiding losses as a result of a contract counterparty notmeeting its obligations.

 

We took stepsthroughout 2009 to reduce our counterparty risk by proactively assessing theeffect of the potential changes in the financial markets on counterparty riskand acting on these assessments. While we had no counterparty losses in 2009,we are continuing to keep a close watch on changes and trends in the market andthe impact these changes could have on our trading business and hedgingactivities, and will take appropriate actions as required although no assurancecan be given that we will always be successful.

 

We are exposed tominimal credit risk for Alberta PPAs because under the terms of thesearrangements, receivables are substantially all secured by letters of credit.Our credit risk management profile and practices have not changed materiallyfrom Dec. 31, 2008.

 

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

 

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

 

The maximum creditexposure to any one customer for commodity trading operations, excluding theCalifornia Independent System Operator and California Power Exchange, andincluding the fair value of open trading positions, is $63 million (2008–$105 million).

 

**Currency Rate Risk**

 

We have exposure tovarious currencies as a result of our investments and operations in foreignjurisdictions, the earnings from those operations, and the acquisition ofequipment and services from foreign suppliers. Our exposures are primarily tothe U.S. and Australian currencies. Changes in the values of these currenciesin relation to the Canadian dollar may affect our earnings or the value of ourforeign investments to the extent that these positions or cash flows are nothedged.

 

We manage ourcurrency rate risk by:

 

**n**      hedging our net investments in foreign operations using acombination of foreign-denominated debt and financial instruments.  Our strategy is to offset 90 to 100 per centof all foreign currency exposures.  AtDec. 31, 2009, we have hedged approximately 97 per cent (2008–97 per cent)of our foreign currency net investment exposure, and

**n**      offsetting earnings from our foreign operations as much aspossible by using expenditures denominated in the same foreign currencies.  We use financial instruments to hedge thebalance of our exposure in foreign operations earnings.

 

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

 

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

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

 

 

Management’sDiscussion and Analysis**  |  **36

----

 

**Liquidity Risk**

 

Liquidity riskrelates to our ability to access capital to be used for proprietary tradingactivities, commodity hedging, capital projects, debt refinancing, and generalcorporate purposes. Investment grade ratings support these activities andprovide a more reliable and cost effective means to access capital marketsthrough commodity and credit cycles. We are focused on maintaining a strongbalance sheet and stable investment grade credit ratings.

 

Counterparties enterinto certain electricity and natural gas purchase and sale contracts for thepurposes of asset-backed sales and proprietary trading. The terms andconditions of these contracts require the counterparties to provide collateralwhen the fair value of the obligation pursuant to these contracts is in excessof any credit limits granted. Downgrades in creditworthiness by certain creditrating agencies may decrease the credit limits granted and accordingly increasethe amount of collateral that may have to be provided.

 

We manage liquidityrisk by:

 

**n**      monitoring liquidity on trading positions,

**n**      preparing and revising longer-term financing plans to reflectchanges in business plans and the market availability of capital,

**n**      reporting liquidity risk exposure for proprietary tradingactivities on a regular basis to the EMC, senior management, and Board ofDirectors,

**n**      maintaining investment grade credit ratings, and

**n**      maintainingcommitted credit lines to support potential liquidity requirements.

 

**Interest Rate Risk**

 

Changes in interestrates can impact our borrowing costs and the capacity revenues we receive fromour Alberta PPA plants. Changes in our cost of capital may also affect thefeasibility of new growth initiatives.

 

We manage interestrate risk by:

 

**n**     employing a combination of fixed and floating rate debtinstruments, and

**n**     monitoring the mixture of floating and fixed rate debt andadjusting where necessary to ensure a continued efficient mixture of thesetypes of debt.

 

At Dec. 31,2009, approximately 31 per cent (2008–24 per cent) of our total debt portfoliowas subject to movements in floating interest rates through a combination offloating rate debt and interest rate swaps.

 

The sensitivity ofchanges 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 currentlyworking on seven generating projects, we face risks associated withcost-overruns, delays, and performance.

 

We attempt tominimize these project risks by:

 

**n**      ensuring all projects are vetted by the TRACT Committee sothat projects have been highly scrutinized to see that established processesand policies are followed, risks have been properly identified and quantified,input assumptions are reasonable, and returns are realistically forecastedprior to Executive and Board approvals,

**n**      using a consistent and disciplined project managementmethodology and processes,

**n**      performing detailed analysis of project economics prior toconstruction or acquisition and by determining our asset contracting strategyto ensure the right mix of contracted and merchant capacity prior tocommencement of construction,

**n**      partnering with those who have previously been able todeliver projects economically and on budget. Our partnership with Capital Power on the construction of Keephills 3 isa direct result of this type of partnership,

**n**      developing and following through with comprehensive plansthat include critical paths identified, key delivery points, and backup plans,

**n**      ensuring project closeouts so that any learnings from theproject are incorporated into the next significant project,

**n**      fixing the price and availability of the equipment, foreigncurrency rates, warranties, and source agreements as much as economicallyfeasible prior to proceeding with the project, and

**n**      entering into labour agreements to provide security aroundcost and productivity.

 

**Human Resource Risk**

 

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

 

**n**      potential disruption as a result of labour action at ourgenerating facilities,

**n**      reduced productivity due to turnover in positions,

**n**      inability to complete critical work due to vacant positions,

**n**      failure to maintain fair compensation with respect to marketrate changes, and

**n**      reduced competencies due to insufficient training, failureto transfer knowledge from existing employees, or insufficient expertise withincurrent employees.

 

 

37**  |  **TransAltaCorporation

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We manage this riskby:

 

**n**      monitoring industry compensation and aligning salaries withthose benchmarks,

**n**      using incentive pay to align employee goals with corporategoals,

**n**      monitoring and managing target levels of employee turnover,and

**n**      ensuring new employees have the appropriate training andqualifications to perform their jobs.

 

In 2009, 46 per cent(2008–46 per cent) of our labour force is covered by 11 (2008–11) collectivebargaining agreements. In 2009, five (2008–three) agreements were renegotiated.We anticipate negotiating four additional agreements in 2010. We do notanticipate any significant issues in the renewal of these agreements.

 

**Regulatoryand Political Risk**

 

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

 

We manage these risksby working with governments, regulators, and other stakeholders to resolveissues. We are active in policy discussions at a variety of levels. Thesestakeholder negotiations have allowed us to engage in proactive discussionswith governments over the longer-term.

 

Internationalinvestments are subject to unique risks and uncertainties relating to thepolitical, social, and economic structures of the respective country and suchcountry’s regulatory regime. We mitigate this risk through the use ofnon-recourse financing and insurance.

 

**TransmissionRisk**

 

Access totransmission lines and sufficient capacity in those transmission lines are keyin our ability to deliver power to our customers. However, with the continuedgrowth in demand for electricity coupled with very little transmission capacitybeing added to existing infrastructures, the reduced reliability and capacityon the existing transmission facilities, and the risk associated with theexisting transmission infrastructure in Alberta, Ontario, and the PacificNorthwest continues to increase.

 

**ReputationRisk**

 

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

 

We manage reputationrisk by:

 

**n**      striving as a neighbour and business partner in the regionswhere we operate to build viable relationships based on mutual understandingleading to workable solutions with our neighbours and other communitystakeholders,

**n**      clearly communicating our business objectives and prioritiesto a variety of stakeholders on a routine basis,

**n**      maintaining positive relationships with various levels ofgovernment,

**n**      pursuing sustainable development as a longer-term corporatestrategy,

**n**      ensuring that each business decision is made with integrityand in line with our corporate values, and

**n**      communicating the impact and rationale of business decisionsto stakeholders in a timely manner.

 

We are dedicated tooperating a safe and ethical organization. We have a system in place whereemployees may report any potential ethical concerns. These concerns aredirected to the Vice-President Internal Audit who engages Corporate Security,Legal, and Human Resources in determining the appropriate course of action.These concerns and any actions taken are discussed with the ARC. All employeesand directors are required to sign a corporate code of conduct on an annualbasis.

 

**CorporateStructure Risk**

 

We conduct asignificant amount of business through subsidiaries and partnerships. Ourability to meet and service debt obligations is dependent upon the results ofoperations of our subsidiaries and the payment of funds by our subsidiaries inthe form of distributions, loans, dividends, or otherwise. In addition, oursubsidiaries may be subject to statutory or contractual restrictions that limittheir ability to distribute cash to us.

 

**GeneralEconomic Conditions**

 

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

 

**IncomeTaxes**

 

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

 

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

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

 

 

Management’sDiscussion and Analysis**  |  **38

----

 

The effective taxrate on earnings before income taxes, equity loss, and other items for 2009 was10 per cent. The effective income tax rate can change depending on the mix ofearnings from various countries and certain deductions that do not fluctuatewith earnings.

 

**LegalContingencies**

 

We are occasionallynamed as a party in various claims and legal proceedings which arise during thenormal course of our business. We review each of these claims, including thenature of the claim, the amount in dispute or claimed, and the availability ofinsurance coverage. Although there can be no assurance that any particularclaim will be resolved in our favour, we do not believe that the outcome of anyclaims or potential claims of which we are currently aware will have a materialadverse effect on us, taken as a whole.

 

**OtherContingencies**

 

We maintain a levelof insurance coverage deemed appropriate by management. There were nosignificant changes to our insurance coverage during 2009. Our insurancecoverage may not be available in the future on commercially reasonable terms.There can be no assurance that our insurance coverage will be fully adequate tocompensate for potential losses incurred. In the event of a significanteconomic event, the insurers may not be capable of fully paying all claims.

 

 

***CRITICALACCOUNTING POLICIES AND ESTIMATES***

 

**Theselection and application of accounting policies is an important process thathas developed as our business activities have evolved and as accountingrules and guidance have changed. Accounting rules generally do notinvolve a selection among alternatives, but involve an implementation andinterpretation of existing rules and the use of judgment relative to thecircumstances existing in the business. Every effort is made to comply with allapplicable rules on or before the effective date, and we believe theproper implementation and consistent application of accounting rules iscritical.**

 

**However,not all situations are specifically addressed in the accounting literature. Inthese cases, our best judgment is used to adopt a policy for accounting forthese situations. We draw analogies to similar situations and the accountingguidelines governing them, consider foreign accounting standards, and consultwith our independent auditors about the appropriate interpretation andapplication of these policies. Each of the critical accounting policiesinvolves complex situations and a high degree of judgment either in theapplication and interpretation of existing literature or in the development ofestimates that impact our consolidated financial statements.**

 

Our significantaccounting policies are described in Note 1 to the consolidated financialstatements. The most critical of these policies are those related to revenuerecognition, financial instruments and hedges, PP&E, goodwill, income taxes,employee future benefits, and asset retirement obligation *(Notes 1(D),(F), (J), (K), (N), (O), and (Q),* respectively). Each policyinvolves a number of estimates and assumptions to be made about matters thatare uncertain at the time the estimate is made. Different estimates, withrespect to key variables used for the calculations, or changes to estimates,could potentially have a material impact on our financial position or resultsof operations.

 

We have discussed thedevelopment and selection of these critical accounting estimates with our ARCand our independent auditors. The ARC has reviewed and approved our disclosurerelating to critical accounting estimates in this MD&A.

 

Tables are providedin the following discussion to reflect the sensitivities associated withchanges in key assumptions used in the estimates. The tables reflect anincrease or decrease in the percentage or other factor for each assumption. Theinverse of each change is generally expected to have a similar opposite impact.Each separate item in the sensitivity assumes all other factors remainconstant.

 

These criticalaccounting estimates are described below.

 

**RevenueRecognition**

 

The majority of ourrevenues are derived from the sale of physical power and from energy marketingand trading activities. Revenues under long-term electricity and thermal salescontracts generally include one or more of the following components: fixedcapacity payments for being available, energy payments for generation ofelectricity, availability incentives or penalties for exceeding or not meetingavailability targets, excess energy payments for power generation abovecommitted capacity, and ancillary services. Each of these components isrecognized upon output, delivery, or satisfaction of contractually specifictargets. Revenues from non-contracted capacity are comprised of energy paymentsfor each MWh produced at market prices and are recognized upon delivery.

 

Trading activitiesuse derivatives such as physical and financial swaps, forward sales contractsand futures contracts and options, to earn trading revenues and to gain marketinformation. These derivatives are accounted for using fair value accountingand are presented on a net basis in the Consolidated Statements of Earningswhen hedge accounting is not applied. The initial recognition of fair value andsubsequent changes in fair value affect reported earnings in the period thechange occurs. The fair values of those instruments that remain open at thebalance sheet date represent unrealized gains or losses and are presented onthe Consolidated Balance Sheets as risk management assets or liabilities. Thefair value of derivative contracts receiving hedge accounting treatment open atthe balance sheet date are deferred in the Consolidated Statements ofComprehensive Income and are presented on the Consolidated Balance Sheets asrisk management assets or liabilities.

 

The determination ofthe fair value of Energy Trading contracts and derivative instruments iscomplex and relies on judgments concerning future prices, volatility, andliquidity, among other factors. The majority of derivatives traded by us arenot traded on an active exchange or extend beyond the time period for whichexchange-based quotes are available, requiring us to use internal valuationtechniques or models.

 

 

39**  |  **TransAltaCorporation

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** **

**FinancialInstruments**

 

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

 

**LevelI**

 

Fair values in LevelI are determined using inputs that are unadjusted quoted prices in activemarkets for identical assets or liabilities that the Corporation has theability to access. In determining Level I Energy Trading fair values, theCorporation uses quoted prices for identically traded commodities obtained fromactive exchanges such as the New York Mercantile Exchange (“NYMEX”).

 

**LevelII**

** **

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

 

Energy Trading fairvalues falling within the Level II category are determined through the use ofquoted prices in active markets adjusted for factors specific to the asset orliability, such as basis and location differentials. The Corporation includesover-the-counter derivatives with values based upon observable commodityfutures curves and derivatives with input validated by broker quotes or otherpublicly available market data providers in Level II. Level II fair values alsoinclude fair values determined using valuation techniques, such as optionpricing models and regression or extrapolation formulas, where the inputs arereadily observable, including commodity prices for similar assets orliabilities in active markets, and implied volatilities for options.

 

In determining LevelII fair values of other risk management assets and liabilities, the Corporationuses inputs other than unadjusted quoted prices that are observable for theasset or liability, such as interest rate yield curves and currency rates. Forcertain financial instruments where insufficient trading volume or lack ofrecent trades exists, the Corporation relies on similar interest or currencyrate inputs and other third party information such as credit spreads. In 2009,the majority of our Level I financial instruments were reclassified as LevelII, which is consistent with industry practice for similar valuationtechniques.

 

**LevelIII**

 

Fair values in LevelIII are determined using inputs for the asset or liability that are not readilyobservable.

 

In limitedcircumstances, Energy Trading may enter into commodity transactions involvingnon-standard features for which market-observable data is not available. Inthese cases, Level III fair values are determined using valuation techniqueswith inputs that are based on historical data such as unit availability,transmission congestion, demand profiles, and/or volatilities and correlationsbetween products derived from historical prices. Where commodity transactionsextend into periods for which market-observable prices are not available, aninternally-developed fundamental price forecast is used in the valuation.

 

As a result of theacquisition of Canadian Hydro, we also have various contracts with terms thatextend beyond five years. Valuation of these contracts must be extrapolated asthe lengths of these contracts make reasonably alternate fundamental priceforecasts unavailable.

 

The effect of usingreasonably possible alternative assumptions as inputs to valuation techniquesfrom which the Level III Energy Trading fair values are determined atDec. 31, 2009 is estimated to be +/- $24 million (2008–nil). This estimateis based on a +/- one standard deviation move from the mean where historicaldata is used in the valuation. Where an internally-developed fundamental priceforecast is used, reasonably alternate fundamental price forecasts sourced fromexternal consultants are included in the estimate. For contracts with termsthat extend beyond five years, valuation must be extrapolated as the lengths ofthese contracts make reasonably alternate fundamental price forecasts unavailable.

 

**Valuationof PP&E and Associated Contracts**

 

As at Dec. 31,2009, PP&E makes up 78 per cent of our assets, of which 99 per cent relatesto the Generation segment. On an annual basis, and when indicators ofimpairment exist, we determine whether the net carrying amount of PP&E andassociated contracts are recoverable from future undiscounted cash flows.Factors which could indicate that impairment exists include significantunderperformance relative to historical or projected operating results, significantchanges in the manner or use of the assets, the strategy for our overallbusiness, and significant negative industry or economic trends. In some cases,these events are clear. However, in many cases, a clearly identifiable eventindicating possible impairment does not occur. Instead, a series ofindividually insignificant events occur over a period of time leading to anindication that an asset may be impaired. This can be further complicated insituations where we are not the operator of the facility. Events can occur inthese situations that may not be known until a date subsequent to theiroccurrence.

 

Our businesses, themarkets, and the business environment are routinely monitored, and judgmentsand assessments are made to determine whether an event has occurred thatindicates possible impairment. If such an event has occurred, an estimate ismade of the future undiscounted cash flows from the asset. If the total of theundiscounted future cash flows (excluding financing charges, with the exceptionof plants that have specifically dedicated debt), is less than the carryingamount of the asset, an asset impairment charge must be recognized in ourfinancial statements. The amount of the impairment recognized is calculated bysubtracting 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 currenttransaction between willing parties, and is best estimated by calculating thenet present value of future expected cash flows related to the asset. Both theidentification of events that may trigger impairment and the estimates offuture cash flows and the fair value of the asset require considerablejudgment.

 

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

 

 

Management’s Discussion and Analysis  | 40

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In estimating futurecash flows of the plants, we use estimates of contracted and future marketprices based on expected market supply and demand in the region in which theplant 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 haveeither 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 ourplants. As a result of this review in 2009, there were no changes to assetvalues.

 

**ProjectDevelopment Costs**

 

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

 

**UsefulLife of PP&E**

 

PP&E isdepreciated over its estimated useful life. Estimated useful lives aredetermined based on current facts and past experience, and take intoconsideration the anticipated physical life of the asset, existing long-termsales agreements and contracts, current and forecasted demand, and thepotential for technological obsolescence. Major components of plants aredepreciated over their own useful lives. A component is a tangible asset that canbe separately identified as an asset and is expected to provide a benefit ofgreater than one year.

 

In 2009, depreciationand amortization expense per the Consolidated Statements of Cash Flows was $493million (2008–$451million), of which $40 million (2008–$38 million) relates tomining equipment, and is included in fuel and purchased power.

 

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

 

A five per centchange in the estimated useful life of depreciable assets will result in achange of $23 million in depreciation and amortization expense (2008–$ 22million).

 

**Valuationof Goodwill**

 

We evaluate goodwillfor impairment at least annually or more frequently if indicators of impairmentexist. If the carrying value of a reporting unit, including goodwill, exceedsthe reporting unit’s fair value, any excess represents a goodwill impairmentloss. A reporting unit is a portion of the business for which we can identifyspecific cash flows.

 

Goodwill was recordedon the acquisitions of Canadian Hydro, Merchant Energy Group of theAmericas, Inc., Vision Quest Windelectric Inc., and CE Gen. AtDec. 31, 2009, this goodwill had a total carrying value of $434 million(2008–$142 million). The change in value from Dec. 31, 2008 is mainly dueto the acquisition of Canadian Hydro.

 

We reviewed therecorded value of goodwill prior to year-end and determined that the fairvalues of our reporting units, based on historical cash flows and estimates offuture cash flows, exceeded their carrying values. There were no significantevents that impacted the fair values of the reporting units between the time ofour testing and Dec. 31, 2009. This includes consideration of the currenteconomic environment and related credit crisis, which does not materiallyimpact the fair value of our assets and liabilities of our reporting unitsbecause they are highly contracted. Accordingly, no goodwill impairment chargeswere recorded for the year ended Dec. 31, 2009. 

 

Determining the fairvalue of the reporting units is susceptible to changes from period to period asmanagement is required to make assumptions about future cash flows, productionand trading volumes, margins and fuel and operating costs. Had assumptions beenmade that resulted in fair values of the reporting units declining by 10 percent from current levels, there would not have been any impairment of goodwill.

 

**IncomeTaxes**

 

In accordance withCanadian GAAP, we use the liability method of accounting for future incometaxes and provide future income taxes for all significant income tax temporarydifferences.

 

Preparation of theconsolidated financial statements requires an estimate of income taxes in eachof the jurisdictions in which we operate. The process involves an estimate ofour current tax exposure and an assessment of temporary differences resultingfrom differing treatment of items, such as depreciation and amortization, fortax and accounting purposes. These differences result in future tax assets andliabilities that are included in our Consolidated Balance Sheets.

 

An assessment must also be made to determine the likelihoodthat our future tax assets will be recovered from future taxable income. To theextent that recovery is not considered likely, a valuation allowance must bedetermined. 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 periodearnings will be affected.

 

Future tax assets of $221 million have been recorded on theConsolidated Balance Sheets at Dec. 31, 2009 (2008–$251 million). Theseassets are comprised primarily of unrealized losses from risk managementtransactions, asset retirement obligation costs, and net operating and capitalloss carryforwards. We believe there will be sufficient taxable income andcapital gains that will permit the use of these deductions and carryforwards inthe tax jurisdictions where they exist.

 

 

41 |  TransAlta Corporation

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Future taxliabilities of $694 million have been recorded on the Consolidated BalanceSheets at Dec. 31, 2009 (2008–$610 million). These liabilities arecomprised primarily of unrealized gains from risk management transactions andincome tax deductions in excess of related depreciation of PP&E.

 

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

 

Our tax filings aresubject to audit by taxation authorities. The outcome of some audits may changeour tax liability, although we believe that we have adequately provided forincome taxes in accordance with Canadian GAAP based on all informationcurrently available. The outcome of pending audits is not known nor is thepotential impact on the financial statements determinable.

 

**EmployeeFuture Benefits**

 

We provide selectedpost-retirement benefits to employees. The cost of providing these benefits isdependent upon many factors that result from actual plan experience andassumptions of future experience.

 

The liability forfuture benefits and associated pension costs included in annual compensationexpenses are impacted by employee demographics, including age, compensationlevels, employment periods, the level of contributions made to the plans, andearnings on plan assets.

 

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

 

The plan assets arecomprised primarily of equity and fixed income investments. Fluctuations inactual equity market returns and changes in interest rates may result inincreased or decreased pension costs in future periods.

 

The discount rateused reflects high-quality fixed income securities currently available andexpected to be available during the period to maturity of the pension benefits.We do not expect to make any changes to the rate in 2010.

 

The expectedlong-term rate of return on plan assets is based on past performance andeconomic forecasts for the types of investments held by the plan. For the yearended Dec. 31, 2009, the plan assets had a positive return of $38 millioncompared to a negative return of $55 million in 2008, and a positive return of$10 million in 2007. The 2009 actuarial valuation used the same rate of returnon plan assets (seven per cent) as was used in 2008 and 2007.

 

**AssetRetirement Obligation**

 

We recognize ARO forPP&E in the period in which they are incurred if there is a legalobligation for us to reclaim the plant and/or site and if a reasonable estimateof a fair value can be determined. The fair value of the liability is describedas the amount at which the liability could be settled in a current transactionbetween willing parties. Expected values are probability weighted to deal withthe risks and uncertainties inherent in the timing and amount of settlement ofmany ARO. Expected values are discounted at the risk-free interest rateadjusted to reflect the market’s evaluation of our credit standing.

 

At Dec. 31,2009, the ARO recorded on the Consolidated Balance Sheets was $282 million(2008–$297 million). We estimate the undiscounted amount of cash flow requiredto settle the ARO is approximately $0.8 billion, which will be incurred between2010 and 2072. The majority of the costs will be incurred between 2020 and2030. An average discount rate of eight per cent was used to calculate thecarrying value of the ARO.

 

Sensitivities for the major assumptionsare as follows:

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

 

 

***CURRENTACCOUNTING CHANGES***

 

**FinancialInstruments Disclosures**

 

On Oct. 1, 2009,we adopted amendments to Section 3862, Financial Instruments –Disclosures, to converge with *Improving Disclosuresabout Financial Instruments (Amendments to International Financial ReportingStandard (“IFRS”) 7)*. The amendments expand the disclosures requiredin respect of recognized fair value measurements and clarify existingprinciples for disclosures about the liquidity risk associated with financialinstruments. The implementation of this standard did not have an impact uponour consolidated financial statements as the disclosure requirements arealready provided as part of our existing financial instrument disclosures.

 

**FinancialInstruments–Recognition and Measurement**

 

On July 29,2009, we retrospectively adopted, to Jan. 1, 2009, *Impairmentof Financial Asset*s, amending Section 3855, *Financial Instruments–Recognition and Measurement.* Theamendments changed the categories into which debt instruments could be classifiedand the impairment requirements for certain financial assets. Consequentialamendments to Section 3025, *Impaired Loans,*were made to incorporate these changes. The implementation of this standard didnot have an impact upon our consolidated financial statements.

 

 

Management’s Discussion and Analysis  | 42

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On July 1, 2009,we adopted *Embedded Derivatives on Reclassification ofFinancial Assets,* amending Section 3855, *FinancialInstruments–Recognition and Measurement.* The amendment indicatesthat contracts with embedded derivatives cannot be reclassified out of the heldfor trading category if the embedded derivative cannot be fair valued. Theimplementation of this standard did not have an impact upon our consolidatedfinancial statements.

 

**CreditRisk**

 

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

 

**Deferralof Costs and Internally Developed Intangibles**

 

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

 

**MiningExploration Costs**

 

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

 

 

***FUTUREACCOUNTING CHANGES***

 

**BusinessCombinations and Non-Controlling Interests**

 

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

 

**IFRSConvergence**

 

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

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

 

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

 

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

 

**n**            Additional disclosure reconciling the changes in individualclasses of property, plant, and equipment and accumulated amortization,

**n**            Costs related to major inspection activities beingrecognized as part of the carrying value of property, plant, and equipment anddepreciated over the period until the next major inspection,

**n**            Allowing an entity to recognize as at Jan.  1, 2010,all experience and transitional gains and losses related to employee futurebenefits to retained earnings with subsequent experience gains and losses beingrecorded in other comprehensive income, and

**n**            Certain long-term contracts being deemed finance leases resulting in the associatedproperty, plant, and equipment being removed from the Consolidated Balance Sheets and replaced with a long-term  receivable representing the present value oflease payments  to be received over thelife of the contract.  Payments receivedunder the contract are recorded in revenue and interest income, dependent uponthe interest rate and duration of the contract.

 

 

43  | TransAlta Corporation

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As we prepare for2010 dual reporting, we continue to evaluate the transitional options availableunder IFRS 1, *First-Time Adoption of InternationalFinancial Reporting Standards* as well as the most appropriatelong-term accounting policies available under IFRS.

 

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

 

At this time, it isnot anticipated that any other material new standards or amendments relating tothese projects will be effective on convergence in 2011. However, the progressand recommendations of other IASB projects for financial instruments,post-employment benefits, financial statement presentation, revenue recognition,and leases are being closely monitored to ensure that any potential adverseimpacts to the convergence project can be minimized. As a result, the fullimpact of adopting IFRS on our financial position and future results cannotreasonably be determined at this time.

 

 

***NON-GAAP MEASURES***

 

**We evaluate our performance and the performance of our business segmentsusing a variety of measures. Those discussed below are not defined underCanadian GAAP and therefore should not be considered in isolation or as analternative to or to be more meaningful than net earnings or cash flow fromoperating activities, as determined in accordance with Canadian GAAP, as anindicator of our financial performance or liquidity. These measures are notnecessarily comparable to a similarly titled measure of another company.**

 

Each business unitassumes responsibility for its operating results measured to gross margin andoperating income. Operating income and gross margin provides management andinvestors with a measurement of operating performance that is readilycomparable from period to period.

 

**Net Earnings Reconciliation**

** **

Grossmargin and operating income are reconciled to net earnings below:

 
| **Year ended Dec. 31**                                     | ** ** | **2009**   | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------|------------|------------|------------|----------|------------|----------|------------|
| Revenues                                                        | ** ** | **2770**   |       | 3,110    |       | 2,775    |       |
| Fuel and purchased power                                        | ** ** | **(1,228** | **)**      | (1,493   | )          | (1,231   | )          |
| **Gross margin**                                                | ** ** | **1,542**  |       | 1,617    |       | 1,544    |       |
| Operations, maintenance, and  administration                    | ** ** | **667**    |       | 637      |       | 577      |       |
| Depreciation and amortization                                   | ** ** | **475**    |       | 428      |       | 406      |       |
| Taxes, other than income taxes                                  | ** ** | **22**     |       | 19       |       | 20       |       |
| **Operating  expenses**                                         | ** ** | **1,164**  |       | 1,084    |       | 1,003    |       |
| **Operating  income**                                           | ** ** | **378**    |       | 533      |       | 541      |       |
| Foreign exchange gain (loss)                                    | ** ** | **8**      |       | (12      | )          | 3        |       |
| Writedown of mining development costs                           | ** ** | **(16**    | **)**      | –   |       | –   |       |
| Net interest expense                                            | ** ** | **(144**   | **)**      | (110     | )          | (133     | )          |
| Equity loss                                                     | ** ** | **–** |       | (97      | )          | (50      | )          |
| Other income                                                    | ** ** | **8**      |       | 5        |       | 16       |       |
| **Earnings before  non-controlling interests and income taxes** | ** ** | **234**    |       | 319      |       | 377      |       |
| Non-controlling interests                                       | ** ** | **38**     |       | 61       |       | 48       |       |
| **Earnings  before income taxes**                               | ** ** | **196**    |       | 258      |       | 329      |       |
| Income tax expense                                              | ** ** | **15**     |       | 23       |       | 20       |       |
| **Net earnings**                                                | ** ** | **181**    |       | 235      |       | 309      |       |

 

**Earningson a Comparable Basis**

 

Presenting earningson a comparable basis from period to period provides management and investorswith the ability to evaluate earnings trends more readily in comparison withprior periods’ results. Earnings on a comparable basis are calculated using theweighted average common shares outstanding during the year.

 

In calculatingcomparable earnings for 2009, we have excluded the writedown of miningdevelopment costs, the impact of a future tax rate change, and the settlementof an outstanding commercial issue that has been recorded in other income asthis was related to our previously held Mexican equity investment.

 

In calculatingcomparable earnings for 2008, we have also excluded the writedown of ourMexican equity investment.

 

In calculatingcomparable earnings for 2008 and 2007, we have excluded the impact of futuretax rate changes, recoveries related to tax positions, and the tax law changein Mexico as they do not relate to the earnings in the period in which theyhave been reported. We also excluded the gains recorded on the sale of assetsat the previously operated Centralia coal mine in 2008 and 2007 as we do notnormally dispose of large quantities of fixed assets.

 

The change in life ofcertain component parts at Centralia Thermal was excluded from the calculationof comparable earnings in all three years as it relates to the cessation ofmining activities at the Centralia coal mine and conversion to consuming solelythird party supplied coal.

 

 

Management’sDiscussion and Analysis |  44

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Earnings on a comparable basis are reconciled to netearnings below:

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

 

**Free Cash Flow (Deficiency)**

 

Freecash flow represents the amount of cash generated by our business that isavailable to invest in growth initiatives, repay scheduled principal repaymentsof recourse debt, pay additional common share dividends, or repurchase commonshares.

 

Sustainingcapital expenditures for the year ended Dec. 31, 2009, represents totaladditions to property, plant, and equipment per the Consolidated Statements ofCash Flows less $524 million ($510 million net of joint venture contributions)that we have invested in growth projects. For the same period in 2008, weinvested $541 million ($515 million net of joint venture contributions). In2007, we invested $182 million in growth projects.

 

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

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

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

 

We seek tomaintain sufficient cash balances and committed credit facilities to fundperiodic net cash outflows related to our business.

 

**Earnings before Interest, Taxes, Depreciation, andAmortization (“EBITDA”)**

 

PresentingEBITDA from period to period provides management and investors with a proxy forthe amount of cash generated from operating activities before net interestexpense, non-controlling interests, income taxes, and working capitaladjustments.

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

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

 

 

45  | TransAlta Corporation

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** **

**Comparable Return on Capital Employed**

 

Comparable ROCEmeasures the efficiency and profitability of capital investments and iscalculated by taking comparable earnings before net interest expense,non-controlling interests, and income taxes, and dividing by the averageinvested capital excluding AOCI. Presenting this calculation using comparableearnings before tax provides management and investors with the ability toevaluate trends on the returns generated in comparison with other periods.

 

Thecalculation of comparable earnings before net interest expense, non-controllinginterests, and income taxes is presented below:

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

 

 

***SELECTEDQUARTERLY INFORMATION***

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

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

 

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

 

 

***CONTROLSAND PROCEDURES***

 

As required byRule 13a-15 under the Securities Exchange Act of 1934 (“Exchange Act”),management has evaluated, with the participation of our Chief Executive Officerand Chief Financial Officer, the effectiveness of our disclosure controls andprocedures as of the end of the period covered by this report. Disclosurecontrols and procedures refer to controls and other procedures designed toensure that information required to be disclosed in the reports we file orsubmit under the Exchange Act are recorded, processed, summarized, and reportedwithin the time periods specified in the rules and forms of the Securitiesand Exchange Commission. Disclosure controls and procedures include, withoutlimitation, controls and procedures designed to ensure that informationrequired to be disclosed by us in our reports that we file or submit under theExchange Act are accumulated and communicated to management, including ourChief Executive Officer and Chief Financial Officer, as appropriate to allowtimely decisions regarding our required disclosure. In designing and evaluatingour disclosure controls and procedures, management recognizes that any controlsand procedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement was required to apply its judgment in evaluating and implementingpossible controls and procedures. Management’s evaluation of our internalcontrol over financial reporting did not include an evaluation of the internalcontrols of Canadian Hydro, and management’s conclusion regarding theeffectiveness of our internal control over financial reporting does not extendto the internal controls of Canadian Hydro.

 

There has been nochange in the internal control over financial reporting during the periodcovered by this report that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting. Based on theforegoing evaluation, our Chief Executive Officer and Chief Financial Officerhave concluded that, as of Dec. 31, 2009, the end of the period covered bythis report, our disclosure controls and procedures were effective at areasonable assurance level.

 

 

Management’sDiscussion and Analysis |  46

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*** ***

***FORWARD LOOKING STATEMENTS***

 

This MD&A, thedocuments incorporated herein by reference, and other reports and filings madewith the securities regulatory authorities, include forward looking statements.All forward looking statements are based on our beliefs as well as assumptionsbased on information available at the time the assumption was made and onmanagement’s experience and perception of historical trends, current conditionsand expected further developments as well as other factors deemed appropriatein the circumstances. Forward looking statements are not facts, but onlypredictions and generally can be identified by the use of statements thatinclude phrases such as “may”, “will”, “believe”, “expect”, “anticipate”,“intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or othercomparable terminology. These statements are not guarantees of our futureperformance and are subject to risks, uncertainties and other important factorsthat could cause our actual performance to be materially different from thoseprojected.

 

In particular, thisMD&A contains forward looking statements pertaining to the following:expectations relating to the timing of the completion and commissioning ofprojects under development, including uprates and upgrades, and their attendantcosts; expectations related to future earnings and cash flow from operatingactivities; expectations relating to the timing of the completion of the FEEDstudy regarding CCS and the cost of the study; estimates of fuel supply anddemand conditions and the costs of procuring fuel; our plans to invest inexisting 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 ofgeneration availability and production; expectations in terms of the cost ofoperations and maintenance, and the variability of those costs; our plans toinstall mercury control equipment at our Alberta Thermal operations and ourinitiative to reduce nitrogen oxide and mercury emissions from our CentraliaPlant; expected governmental regulatory regimes and legislation, as well as thecost of complying with resulting regulations and laws; our trading strategy andthe risk involved in these strategies; expectations relating to therenegotiation of certain of the collective bargaining agreements to which weare a party; estimates of future tax rates, future tax expense, and theadequacy of tax provisions; expectations for the outcome of existing orpotential legal claims; and expectations for the ability to access capitalmarkets at reasonable terms.

 

Factors that mayadversely impact our forward looking statements include risks relating to:(i) fluctuations in market prices and availability of fuel supplies requiredto generate electricity and in the price of electricity; (ii) theregulatory 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 includinginterest rates; (v) operational risks involving our facilities, includingunplanned outages at such facilities; (vi) disruptions in the transmissionand distribution of electricity; (vii) effects of weather; (viii) disruptionsin the source of fuels, water, wind or biomass required to operate ourfacilities; (ix) natural disasters; (x) equipment failure; (xi)trading risks; (xii) industry risk and competition; (xiii) fluctuations in thevalue of foreign currencies and foreign political risks; (xiv) need foradditional financing; (xv) structural subordination of securities; (xvi)counterparty credit risk; (xvii) insurance coverage; (xviii) our provision forincome taxes; (xix) legal proceedings involving the Corporation; (xx) relianceon key personnel (xxi) labour relations matters; and (xxii) developmentprojects and acquisitions. The foregoing risk factors, among others, aredescribed in further detail in the Risk Management section of this MD&A andunder the heading “Risk Factors” in our 2009 Annual Information Form.

 

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

 

 

47  | TransAlta Corporation

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