Let us tell you how we create long-term shareholder
value.



We have the discipline, the resourcefulness and the focus to achieve our long-term goals.



The people of TransAlta ensure our success.



HERES HOW WE DO IT.













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EXPECT THE UNEXPECTED





Canadian and U.S. generally accepted accounting principles (GAAP) require us to deconsolidate our Mexican operations (see
Note 1R, page
77). As a result, pages 31115 exclude details of our Mexican operations. To get a view of the company including Mexico, read our discussion of the company from pages 130.

(left) Nick Oke and Anita Stocker, Cycle Chemist, Wabamun Lake Water Treatment Plant, at the weir.

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Acting Decisively as a Competitive Advantage
THE CALL CAME AT 5:30 A.M.A Canadian National Railway
(CN) train had derailed at Lake Wabamun, Alberta, spilling oil into the lake. TransAlta employees acted immediately,
volunteering with cleanup efforts and assessing any impact to the companys power plants. Oil could impair operations, making it impossible for TransAlta to generate power.
We knew it was just a matter of time before the oil would reach our facilities,says Nick
Oke, Environmental Specialist at TransAltas Wabamun power plant. With two of our
plants using lake water for operations, we had some urgent decisions to make. Within hours, TransAlta employees shut down the 279 megawatt (MW) Wabamun power plant to protect it from oil contamination.
Across the lake, the 2,020 MW Sundance power plant, which supplies about 20 per cent of the provinces power, was still in jeopardy.
We knew we had to do something to stop the oil from entering the Sundance plant, explains
Oke. An existing canal normally served as both the intake location for the plant and also
as the discharge point for the Wabamun Lake Water Treatment Plant. The engineers and operations teams considered building a weir across the mouth of the canal that would be two feet higher than lake elevation. This barrier would stop oil from
entering the facility, and ensure the plant would have the clean water it needed to continue to operate. But prompt action was needed. TransAlta and its partner Luscar rallied people on the site. In just eight hours, 14 people moved 2,100 tonnes of
soil and rock to build the weir.
This stronghold remains in operation today, protecting the Sundance power plant from residual oil and, ultimately protecting the provinces power supply.
This wasnt the only unexpected challenge TransAlta people faced in 2005. A fire at the Suncor facility in Fort McMurray halted operations at our Poplar Creek plant. Mother Nature sent a
different challenge our way with heavy rains and flooding in southern Alberta impacting hydro operations. Our people responded quickly and effectively in every situation.
Past performance is a pretty good indicator of how a company will perform in the future. We have the strategy and over 2,600 dedicated people like Nick Oke and Anita Stocker who work hard to
ensure TransAlta continues to be a low-cost producer. TransAlta employees have the expertise to safeguard the companys assets and your investment. Our track record of operational excellence proves we can be counted on to produce power, no
matter what challenges we face year after year.
      Day after day, we produce power for people in four different countries Canada, the United States, Mexico and Australia.
In 2005, our plants were available
89.7%
of the time,
producing
54,561
gigawatt hours of electricity,
and generating approximately
$3.1billion
in revenue.


|FUEL TYPES
TransAlta fuels its plants 
 from diverse sources. 
 This protects the company 
 from a sudden, unexpected 
 increase in the cost 
 of any one fuel or the 
 unpredictable nature of 
 water flows and wind. |     |       |            | 
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | --- | ----- | ---------- | 
|58%                                                                                                                                                                                                                     | 29% | 9%    | 4%        
|COAL                                                                                                                                                                                                                    | GAS | HYDRO | RENEWABLES



2005 ANNUAL
      REPORT         3


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(left) Sid Nowicki inside one of TransAltas coal-fired plants in Alberta.

REWRITE THE RULEBOOK

PLANNED MAINTENANCE SPENDING OF $200 MILLION TO:
        Improve productivity initiatives.
          Improve technical programs (parts refurbishment versus replacement).
          Develop strategic supplier relationships.
          Extend outage intervals (comprehensive parts analysis determines remaining life in parts).
          Enhance long-range planning.


|4         
      TRANSALTA CORPORATION | 
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Engineering Excellence as a Competitive Advantage
AS ONE OF THE FEW PURE POWER GENERATORS,TransAlta has learned how to operate plants safely, reliably and with a commercial mindset. In fact,
employees are challenging conventional ways of maintaining power plants. What theyre discovering is that the standards they are starting to follow are becoming the guidelines their own teams are setting.
Who knows our operations better than us? says Sid
Nowicki, Outage Manager. We know what it takes to keep our plants running well. Weve got the
engineering expertise and the operational experience to rewrite the rulebook. Case in point: as part of regular maintenance, one unit at the 766 MW Keephills power plant was scheduled to have a chemical clean. This procedure removes built-up
residue inside the boiler. According to the industry standard, this procedure should be done every six to eight years and takes about four days to perform. During this time, the plant is shut down. But the outage team did a detailed investigation of
the plaque on the boiler. It was far less than the industry standard predicted. Why?
Over the years, our operations team has been diligent in making sure the boiler was brushed and flossed regularly, says Mike
Bartel, Vice-President,
Engineering Services. As a result, we concluded we could defer this procedure for another three years. This allowed us to save on immediate maintenance expense, avoid paying for replacement power and gain four days of revenue. The
combination of disciplined maintenance and engineering expertise allowed TransAlta to make a smart call. Diagnostic assessments, like the one that facilitated the deferral of the chemical clean, will continue at other TransAlta plants.
Increasingly, TransAlta employees are challenging old assumptions, asking tough questions and making decisions to safely and cost-effectively maintain our plants. We will
continue to develop better standards. We will continue to evaluate the overall lifecycle of our plants when short- and long-term maintenance decisions are made. This comprehensive approach will pay off for shareholders in the short and long
term.


OUR APPROACH TO MAINTENANCEEngineering
	Long-range
	Short-range
	Turnaround
	TurnaroundPlanning
	Planning
	Execution and
	EvaluationClose-out0 to
	18 months to
	418 months
	4 months to
	30 daysplant life
	plant life
	
	30 days Condition assessment
	 Investment decisions
	 Leverage suppliers
	 Reduce duration
	 Lessons learned Technical plans
	 Strategic partners
	 Productivity innovation
	 Real-time productivity
	 Updated equipment condition Reliability programs
	 Links to asset plans
	 Detailed plans
	 Cost management Risk management
strategies
	
	 Cost estimates


| | 2005 ANNUAL
      REPORT         5
| | ----------------------------------

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MAKE SMART MOVES IN
CHANGING MARKETSKelvin Koay and Mark Kruzel on TransAlta's trading floor.

|6         
      TRANSALTA CORPORATION | 
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Commercial Expertise as a Competitive Advantage

WHAT DO YOU GET WHEN YOU CROSS A WEATHERMAN WITH A FORTUNE TELLERwho has a knack for numbers? Mark Kruzel is a trader in TransAltas energy marketing business. His day
starts at 5 a.m., when he gathers facts to determine how TransAlta can gain advantage in buying and selling power. These facts help him realize his goal: maximize TransAltas gross margin. Some of the questions Mark might ask: Which way is that
hurricane headed? How long will the heat wave last? What are natural gas prices doing today? The answers will give Mark a clearer picture of the supply and demand for both electricity and natural gas markets.

By 7 a.m., Mark talks with Kelvin
Koay, Western U.S. Regional Portfolio Optimization Manager, to find out the availability of our plants. What power plants are down for scheduled maintenance in
our markets? How many megawatts do we have available to sell from Centralia? How much power do we think customers and industry will need? Armed with Kelvins asset recommendations, Mark and the trading team make smart, disciplined decisions to
buy and sell power for the next five minutes to the next five years.

This controlled approach and thorough understanding of the market allowed TransAltas asset teams to make some key decisions in 2005 that significantly added to the bottom-line. For
example, in January 2005, our market analysts forecasted a dry spring in the Pacific Northwest resulting in lower hydro power production. This meant there would be a reduction in the supply of electricity and therefore higher prices. With that view
in mind, our Centralia asset team, drawing on operations, maintenance and commercial expertise, decided to advance Centralias planned major maintenance outage two weeks ahead of schedule. Moving a 30-day outage is not easy, especially
considering the amount of manpower, parts and materials involved. But when the asset team compared the increased costs of moving the maintenance with the higher margin to be captured by selling Centralias megawatts in an even better market,
the decision was clear. The move paid off, contributing to Generation Operating Income in 2005.

| | 2005 ANNUAL
      REPORT         7
| | ----------------------------------

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GROW
MEGAWATTS
PROFITABLY AND CLEANLY

Innovation as a Competitive Advantage

IN MAY 2002, TRANSALTA JOINED EPCOR UTILITIES INC.

(EPCOR) as co-owners of the 450 MW Genesee 3 (G3) power plant, the most technologically advanced coal-fired plant in Canada. Already under construction, the plant was expected to be up and running by
2005.

We knew a power crunch was on the horizon and Albertans would need more electricity, says Gary
MacPherson, Commercial Management Director. We also knew Alberta
has plenty of coal, so developing a coal-fired plant to meet this demand made sense. Still, coal-fired generation costs big bucks to build. Teaming up with EPCOR allowed TransAlta to share the market risk, accelerate the development of
electricity generation in Alberta and grow the business.

G3 is just one example of how TransAlta is looking at innovative ways today to improve the bottom line tomorrow and increase shareholder value over the long term. When Western
Australians faced power shortages, TransAltas Parkeston Power Station was

ready to pump spare megawatts into the grid. The problem? The regional transmission lines didnt have the capacity for Parkeston to export into the grid. Moving quickly, TransAlta and its partner,
Newmont Mining, entered into a four-year deal that encouraged the government utility, Western Power, to build the required transmission line. By January 2005, the Parkeston facility was providing much-needed power, keeping customers homes cool
while TransAltas capacity and revenues increased.

TransAlta continues to keep an eye on growing the company  looking for interesting opportunities and smart partnerships that leverage our operational and commercial
expertise, minimize risk and support the balance sheet. We know the key to sustainable success is thinking outside the box, tackling new challenges when opportunities arise to create innovative solutions.

OUR MARKETS

We see opportunity for growth in our existing markets, where we have the expertise in bidding, building and operating plants and selling the output. Our market diversity (represented by the following percentages) and
varied fuel mix allow us to approach these opportunities in a prudent, disciplined manner.

ALBERTA  58%

- Small, deregulated market  peak load of 9,500 MW
- Demand growing at 2.5% per year
- Long term, oil sands and clean coal technology provide growth opportunities

ONTARIO  8%

- Large, hybrid market  peak load of 26,000 MW
- Requires additional capacity
- Short-term opportunities in renewables

UNITED STATES  25%

- Participate mostly in the Pacific Northwest
- Large, hybrid market  peak load of 28,000 MW
- Demand growing at 1.6% per year
- Opportunities for expansion of geothermal assets

MEXICO  6%

- Large, fully regulated market  peak load of 33,000 MW
- Strong demand growth near 5% per year
- Opportunities for acquisitions and new gas development

AUSTRALIA  3%

- We limit ourselves to a niche market, doing cogeneration projects with resource companies in Western Australia.
- Our customers power needs are growing as demand from Asia for natural resources increases dramatically.

|8         
      TRANSALTA CORPORATION | 
|-------------------------------------- | 

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G3THE MOST TECHNOLOGICALLY ADVANCED COAL-FIRED

POWER PLANT IN CANADA

- $90 million in clean air technologies
- More than 11,500 fabric filters stop 99.8% of particulate matter from reaching the atmosphere
- Low nitrous oxide burners reduce nitrous oxide emissions by 54%
- Flue gas desulphurization unit brings sulphur dioxide emissions significantly below Albertas emission standard and carbon dioxide
emissions 18% lower than the average coal-fired plant



| | 2005 ANNUAL
      REPORT         9
| | ----------------------------------

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SUSTAINABILITY IS A BIG DEALSustainable Development as a Competitive Advantage

MORE THAN A DECADE AGO,TransAlta recognized that sustainable development would be a key element of business in the future. We were convinced then that operating in a manner that
is economically rewarding and ethically, socially and environmentally responsible would be the way wed conduct our business. We still believe this today.

Sustainable success at TransAlta is about thinking long term and ensuring that what we do meets the needs of today with a look to the future. Here are some of the ways our employees contribute
to our sustainable development performance:

- Reduce and recycle waste.
- Implement safety processes.
- Manage stakeholder issues.
- Reclaim mined land and create wetlands.
- Control NOXand SO2emissions.
- Improve plant production efficiency.
- Protect fish in lakes and rivers where we operate.
- Participate in the United Way.
- Volunteer in various non-profit organizations.
- Improve Aboriginal relations.

In 2005, our sustainable development performance
was recognized by a number of external organizations including:

- Corporate KnightsGlobal 100 Most
    Sustainable Corporations in the World, second consecutive year
- Dow Jones Sustainability IndexWorlds Most
    Sustainable Companies, seventh consecutive year
- FTSE4Good Global IndexLondon-based
    sustainability index, third consecutive year
- Jantzi Social IndexIndex of top 60 socially
    screened Canadian companies
- KLD Global Climate 100 IndexBoston-based
    sustainability index
- The Globe and Mail NewspaperTop five best
    governed companies
- PricewaterhouseCoopersTrends 2006:
    Good Practices in Corporate Reporting, one of six Canadian companies listed
- Clarkson Centre for Business Ethics and
    Board EffectivenessTop five per cent for
    corporate governance
- Canadian Institute of Chartered AccountantsGold award for excellence in corporate
    reporting, sixth consecutive year



|10         
      TRANSALTA CORPORATION | 
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(above) Eileen Stanley, a.k.a. Blinkie sharing her time with youth in the community.

In 2005, TransAlta donated more than

$3.6 million

to community investment programs

GO THE EXTRA MILE

Active Employee Engagement in Community Partnerships

EILEEN STANLEY KNOWS A THING OR TWOabout bringing a smile to peoples faces. As a member of the TransAlta Community Transformers (TACT)
donation committee in Fort McMurray, Alberta, she helps make decisions that make people happy. It just so happens that shes also Blinkie the Clown, whose humorous antics create joy for young and old alike.

Through TACT, Eileen connects with her community, responding to local needs and priorities. TACT donations have helped organizations like the Fort McMurray Soup Kitchen and the
Childrens Centre. Blinkie sometimes makes the trip to these organizations events. I find that as a clown, I am able to reach out to people and even the smallest thing can make a big difference in someones
day, says Eileen.

Eileen is one of about 40 TransAlta employees in Fort McMurray, Centralia, Sarnia and Wabamun who decide where to donate more than $120,000 to strengthen their communities.
Together with other TransAlta employees and the POWER (Projects Organized With Energetic Retirees) group, they

volunteered a combined total of approximately 10,500 hours in 2005.

Whether its participating in the United Way campaign, or reaching out to victims of the Asian Tsunami and Hurricane Katrina, employees and retirees are actively engaged in
TransAltas community investment program. Theyre also key to TransAlta community partnerships like the Calgary Stampede, Hull Child and Family Services, Southern Alberta Institute of Technology, the TransAlta Tri Leisure Centre, Fringe
Theatre Adventures in Edmonton, Centralia College, Tri Community Festival of Trees, and Sarnia Celebration of Lights.

TransAltas community investment focuses on a small number of initiatives where we can have the most meaningful impact over the long-term. In 2005, TransAlta invested over
$3.6 million in communities where we live and work. That brings a lot of smiles.

| | 2005 ANNUAL
      REPORT         11
| | -----------------------------------

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TransAlta is a power generation and wholesale marketing company focused on creating long-term shareholder value. We maintain a low-risk profile by operating a highly contracted portfolio of assets in Canada, the United
States, Mexico and Australia. Our focus is to efficiently operate our coal-fired, gas-fired, hydro and renewable facilities in order to provide our customers with a reliable, low-cost source of power. For nearly 100 years, weve been a
responsible operator and a proud contributor to the communities where we work and live.









14
	Progress Against Our Six Key Measures
	31
	Managements Discussion & Analysis15
	Message to Shareholders
	69
	Consolidated Financial Statements23
	Letter from the Chair
	110
	Eleven-year Financial & Statistical Summary24
	Corporate Governance
	112
	Shareholder Information25
	Board of Directors
	114
	Corporate Information27
	At A Glance
	115
	Glossary


---

In 2005, we did what we said wed do. Our employees delivered tangible financial results. They performed with dedication, prudently allocating our resources, capturing market opportunities and finding ways to grow our
megawatts safely, cleanly and profitably. Each of the previous stories offers an inside look at how TransAlta was able to succeed.







| | 13
| | --

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PROGRESS AGAINST OUR SIX KEY
MEASURES

1AVAILABILITY AND PRODUCTION

|             |        |        |        | Long-term
|------------ | ------ | ------ | ------ | ---------
|             | 03     | 04     | 05     | target   
|Availability |        |        |        |          
|(%)          | 90.6   | 89.1   | 89.7   | 90+      
|Production   |        |        |        |          
|(GWh)        | 53,134 | 54,560 | 54,561 | Growth   

Many of our contractual agreements have availability and/or production of
electricity as key factors in determining revenue. Running at 100 per cent availability means the plant is ready to run at full output every hour of every
day throughout the year. However, plants need maintenance, and occasionally break down, so 100 per cent availability over an extended period of time
is not achievable. Production is the amount of electricity we produce and is measured in gigawatt hours.

2CONTRACTS

|           |    |    |    | Long-term
|---------- | -- | -- | -- | ---------
|(%)        | 03 | 04 | 05 | target   
|Contracted |    |    |    |          
|production | 91 | 84 | 83 | >75      

Electricity prices can vary dramatically by the hour and year-over-year.
To reduce our exposure to swings in market prices, we have chosen to
contract a large percentage of our output through contracts with terms of one year or more. The weighted average remaining life of our current
contracts is 12 years.

3MARGIN AND PRODUCTIVITY

|        |       |       |       | Long-term
|------- | ----- | ----- | ----- | ---------
|($/MWh) | 03    | 04    | 05    | target   
|Margin  | 25.52 | 25.83 | 27.82 | Increase 
|OM&A    | 10.53 | 10.50 | 11.31 | Decrease 

We produce a commodity product in a long-term, capital-intensive business.
Growing gross margin and increasing the productivity of our assets are essential for success. Fuel is a key cost driver, but it is largely recovered
through contract terms and does not overly impact gross margin except for our merchant energy. Operations, maintenance and administration (OM&A)
costs, together with production, drive our productivity, which is measured as dollars per megawatt hour. Productivity declined in 2005 from 2004 due
to many factors. Productivity will be an area of focus for us in 2006.

4CAPITAL EXPENDITURES

|                |     |     |     | Long-term
|--------------- | --- | --- | --- | ---------
|($ in millions) | 03  | 04  | 05  | target   
|Growth          | 421 | 142 | 42  | Variable 
|Sustaining      | 137 | 224 | 296 | 150175  

We make capital expenditures to both grow and sustain the business,
including maintaining our plants. Our growth is discretionary so expenditures will
vary over time. Our goal with sustaining capital is to make it as predictable as possible.

5CASH FLOW*

|                |     |     |     | Long-term
|--------------- | --- | --- | --- | ---------
|($ in millions) | 03  | 04  | 05  | target   
|Cash flow       | 527 | 613 | 640 | 550650  

Our cash requirements include maintaining our equipment, meeting debt
repayment and non-controlling interest obligations and, of course, paying a dividend. Our goal is to exceed the cash requirements in every phase of our
business and industry cycles in order to have cash available to invest in new growth, further reduce debt or return it to shareholders.

* Cash flow as shown above is a non-GAAP measure as it includes the
Mexico entities. Please refer to pg. 73 for cash flow from operating activities calculated in accordance with GAAP.

6FINANCIAL RATIOS

|                  | 03   | 04   | 05   | Target
|----------------- | ---- | ---- | ---- | ------
|Cash flow to      |      |      |      |       
|interest (times)  | 3.3  | 4.1  | 4.6  | 4.2   
|Cash flow to      |      |      |      |       
|total debt (%)    | 17.2 | 18.5 | 23.0 | 28    
|Debt to           |      |      |      |       
|total capital (%) | 47.7 | 47.4 | 43.3 | 45    

Financial ratios measure our overall financial strength. There are three we focus
on: cash flow to interest; cash flow to total debt; and debt to total capital. Financial strength provides continued access to capital and greater flexibility
in contracting the output of our plants. The credit rating agencies also use the financial ratios when evaluating the
company. In the long term, our financial condition will dictate our ability to grow. Building new generation plants or acquiring existing operations requires
the capacity to take on new debt or to issue new equity. Our objective is to hold a strong investment grade credit rating.

TARGET ACHIEVED




|14         
      TRANSALTA CORPORATION | 
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MESSAGE TO
SHAREHOLDERS





In 2005, our employees exhibited spirit, professionalism and real grit. They overcame a series of potential major setbacks  the shutdown of half of our Poplar Creek plant due to a fire at
Suncor, the six-week closure
of our Lake Wabamun plant due to the CN oil spill, and once-in-50-year flooding in Alberta affecting our hydro facilities. Every time, employees responded quickly and with dedication. Then they went out and found offsets. I am very proud of what
they accomplished in the year.     You met some of these employees in the front of this book. They reflect the qualities that define our success: a clear focus on the fundamentals, a commitment to safety, operational discipline,
and bottom-line results.

So how did we do?In 2005 we delivered. We achieved $1.01 in reported earnings per share versus $0.88 in 2004, a 15 per cent increase. Our comparable earnings, reflecting the ongoing performance of our plants and trading operations,
delivered $0.88 of earnings per share versus $0.66 in 2004, a 33 per cent increase. Our cash flow is strong. It increased to $640 million, up from $613 million in 2004, $527 million in 2003 and $399 million in 2002. We have
used this cash to maintain our plants, meet our debt obligations and pay dividends. In 2005, part of our remaining free cash was used to reduce $263 million in short- and long-term debt. We also spent $28 million to complete the
investment of 225 megawatts (MW) of new capacity with the addition of Genesee 3 to our fleet, a joint venture with
EPCOR.For our shareholders, these efforts delivered a total shareholder return of 45 per cent for the year.     Our results were positively affected by improved market conditions in the Pacific Northwest and in Alberta. We benefited from reduced interest expense. A third factor in our improved results
was our continuing progress in more effectively allocating our capital to maintain our plants.     These performance drivers are among six key factors that will determine our future success: contracting production; managing capital expenditures; achieving availability and production targets;
driving higher margins and increased productivity; increasing our cash flow; and strengthening our balance sheet. (see Progress Against Our Six Key Measures on opposite page.)









| | MESSAGE TO SHAREHOLDERS         15
| | ----------------------------------

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I described two key events in last years letter that would potentially be important contributors to our earnings  recontracting some of Centralias output and contracting power from our Sarnia plant in
Ontario.During the year, our marketing team succeeded in signing contracts so that approximately 90 per cent of Centralias output is contracted through 2006. And as of this writing, 85 per cent
of its output is contracted for 2007.     We were also successful with Sarnia. In February of this year, we signed a five-year capacity contract for an average of 400 MWs with the Ontario Power Authority. Success on these two key
issues will help drive our 2006 earnings improvement.     On a total plant portfolio basis, we will have approximately 83 per cent of our 8,468 MWs contracted for 2006 and 2007. That exceeds our target of having no less than 75 per cent of our total
capacity contracted.

MANAGING CAPITAL EXPENDITURESIn last years letter, I described our progress in changing the way we maintain our plants. In 2003, we began shifting from a reactive plan to a proactive multi-year plan for each of our generating plants.
     Our capital spending on major maintenance had been increasing. In 2003, we spent $35 million. In 2005, we spent $132 million. These increasing costs reflected the way we previously
planned maintenance, the age of our plants and the growth in our fleet. Starting in 2006, and, as a direct result of the shift in plant maintenance, capital spending will decline to between $115 to $130 million. Further reductions will occur
in 2007 and beyond. In simple terms, our new maintenance planning allows us to spend more efficiently and sustain plant performance.

ACHIEVING AVAILABILITY AND PRODUCTION TARGETSOur plant availability in 2005 remained strong at 89.7 per cent, just shy of our 90 per cent target and slightly better than 2004. Production was also slightly higher at 54,561 gigawatt hours. Thats a great feat when
you consider the downtime our plants experienced due to external factors like the CN spill and the Suncor fire mentioned earlier. As well, the decommissioning of our Wabamun plant units one and two limited our production. Still, the higher
production at our hydro facilities due to higher than normal rainfall and the addition of Genesee 3 helped offset the impact of these factors.High availability is a key success factor for us. Our power purchase arrangements
(PPAs) use availability as a key metric for payment. We cant inventory our product so we must also move
quickly to sell our surplus power into spot markets. A defining factor for our continuing success is the ability of



|16         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

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our cross-functional asset teams to convert our market intelligence and strong plant performance into selling opportunities that strengthen our bottom line. You can see how this works on page 7.

REALIZING HIGHER GROSS MARGINS AND INCREASED PRODUCTIVITY

Because we produce a commodity product in a long-term, capital-intensive business, growing gross margins (revenue less fuel costs and purchased power) and increasing productivity of our assets are essential for our success.
During 2005, our gross margins increased by eight per cent.However, our productivity declined during the year as OM&A costs per megawatt hour
(MWh) increased from $10.50 in 2004 to $11.31 in 2005 due to: 
 1. lower production due to plant
outages beyond our control such as: 
     a. the fire at Suncors facility in Fort McMurray. 
     b. the shutdown last summer at our Wabamun coal-fired plant due to the CN train derailment at Lake
Wabamun.2. higher costs due to: 
     a. the addition of our new Genesee 3 coal-fired plant. 
     b. higher fleet equipment repairs. 
     c. a tough inflationary environment in Alberta.
Incentive compensation costs also went up reflecting both our improved share price and financial results.While many of these factors are beyond our control, we can improve our performance. I have formed a senior level team to review every line item of our cost structure. We will look for areas to
improve in 2006 and beyond.

STRENGTHENING OUR BALANCE SHEETOur financial goal is to maintain the flexibility and stability necessary to thrive through all industry cycles. This starts with cash flow. In 2005, we continued to generate sufficient cash from operations to reinvest in
our plants, meet our debt obligations and pay our dividend. After meeting our obligations, we still had cash remaining  what we call free cash flow.In 2005 we used this free cash, over $250 million, to retire additional debt, which in turn decreased our interest costs. As I discussed last year, when we added new capacity in 1999 
2004, our debt and interest costs went up. In fact, interest expense grew from $94 million in 1999 to $222 million in 2004. As these plants were commissioned and started to generate cash, we paid down debt. In 2005, our interest costs were
reduced to $203 million, down $19 million from 2004. I expect a further reduction of $20 million in 2006.

| | MESSAGE TO SHAREHOLDERS         17
| | ----------------------------------

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This discipline further improved the financial ratios that determine our credit ratings. We made progress on our goal to meet the targets we believe necessary for a BBB+ rating. We achieved a
cash flow to interest ratio of 4.6 times, cash flow to debt of 23 per cent and debt to capital of 43.3 per cent. These efforts are having results. In February 2006, Standard & Poors upgraded our rating from BBB- to BBB. And Dominion Bond
Rating Service recognized our efforts by removing the negative trend on our BBB rating late last year. These ratings are important to us as they allow us to cost-effectively support our contracting strategy and finance future growth.

We are also disciplined in managing our assets. Long-term investors remember that we have sold assets that no longer fit our portfolio requirements. This freed up underperforming capital.
Weve never lost sight of one of our key operating principles: Cash is King.

SUSTAINABLE DEVELOPMENTThere is continued pressure on our industry to reduce our environmental
footprint, specifically with respect to greenhouse gas
(GHG), mercury, NOX
and SO2 emissions. The Canadian government is still working through the
Kyoto Protocol regulatory requirements, so its difficult for us at this time to estimate the full impact it will have on our Canadian operations. 
Provisions in the PPAs for our Alberta coal-fired plants will allow us to recover compliance costs from the PPA customers.
  Long-term investors will recall we invested $US200 million in our Centralia coal-fired plant to reduce
SO2 and NOX. This plant is environmentally compliant in the
United States under existing regulations.Still, we believe proactive, voluntary actions to lower costs and exposure to increasingly stringent environmental regulations are a prudent risk management strategy for our shareowners.    Our investment in renewable generation, through our geothermal and wind facilities, as well as our improvements in plant performance have reduced our emissions impact. Even though weve
increased our generation by over 77 per cent, weve reduced our worldwide greenhouse gas intensity by 11 per cent from 1990 levels.     As well, weve continued to pursue an emissions offset strategy to mitigate future climate change costs. TransAlta was the first Canadian company to purchase international greenhouse gas
credits in 2000,

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building a portfolio of credits that has positioned TransAlta and its shareholders well as regulations intensify and the price of credits steadily rises.     As a founding member of the Canadian Clean Power Coalition, weve also been exploring the development of clean fuel technology. Well substantially step up these efforts in 2006.     Were proud to be recognized for our environmental efforts, listed for the seventh consecutive year on the Dow Jones Sustainability Index and for the third consecutive year by FTSE4Good
Global Index. TransAlta is also one of only five Canadian companies on the Corporate Knights list of the worlds 100 most sustainable companies.

OutlookAfter three to four years of turmoil in our industry, some positive indicators are emerging in the markets where we operate. We see reserve ratios (the amount of excess supply relative to peak demand) starting to decrease
in some regions. As a result, prices are generally rising, although not dramatically. And new capacity will be needed over the next decade. We do see challenges emerging. In addition to increasing fuel expense, we are faced with increased commodity prices. These
are particularly noticeable in our coal production costs. We use a lot of diesel fuel in our truck fleet. This fuel doubled in price in 2005. A shortage of the huge tires used on our coal hauling trucks forced up tire prices. Limited availability of
rail cars in the United States is affecting our ability to efficiently manage coal inventory. An increasingly complicated process to obtain mining permits is slowing down our efforts to develop more cost-effective coal reserves at the Centralia
mine. I will address each of the challenges directly later in my comments.     We also see growth opportunities. We do not need to enter new markets or experiment with new technologies to find them.     New supply is needed in Alberta by 2010 and the expansion of the oil sands remains a big opportunity for generators. Ontario and the East Coast want wind development. In the United States, our
geothermal assets have excellent, unexploited reserves and a strong market to sell into. All our customers in Australia are growing. Similarly, in Mexico, our customer, the Comisión Federal de Electricidad, is looking to contract more plants.
I can assure you we will be very, very disciplined in our investment decisions. Our goals are simple: improve our overall return on equity, maintain a strong balance sheet and mitigate volatility as best we can to consistently grow our earnings and
cash flow.



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Four pillars of performanceOur response to these challenges and our strategic focus is based on what I call four pillars of performance. Collectively, these pillars create the sustainable competitive advantages we need to consistently grow our
earnings.

I. OPERATIONAL EXCELLENCEThe first pillar is our day-to-day operations where we must effectively manage labour and fuel that represent 65 per cent of our operating costs. Key performance measures are in place or being established for all critical
operations. Driving down our costs across our company remains a key priority for our management team. Richard Langhammer, Executive Vice-President, Generation Operations and his team are aggressively working on plans to achieve annual productivity
savings equal to inflation.For example, our Centralia coal operators extend the lives of our hauling truck tires by reducing the air pressure on the tires. The coal permitting team is making progress on obtaining new
permits to mine richer coal seams that are closer to our plants. While we have sufficient alternate reserves to last until 2009, we will open the new seams whenever we get the permits and can exit from the older ones. We are building our capacity to
handle more purchased coal in anticipation of better availability in the future.     Some of the Centralia issues may not be resolved until 2008 or 2009. In the meantime, our coal teams are doing everything they can to reduce costs in 2006 and 2007. Increasing power prices and
improved margins at Centralia are helping offset these higher coal prices. I should note here that while fuel expenses at our Alberta coal-fired plants are passed through in our PPA contracts, our Alberta coal team is still very focused on
containing costs.

II. PLANT MAINTENANCEThe second pillar involves on-going cyclical maintenance. Our goal is to drive down unplanned outages and drive up total availability while spending less capital and OM&A. We are achieving this goal by using our
innovative predictive maintenance techniques, improving our equipment assessment capabilities and implementing our strategic supplier programs. By developing longer-term relationships with our key suppliers, we can more effectively take advantage of
their capabilities to help us reduce costs. Continuous improvement is our focus now.

III. LIFECYCLE PLANNINGIn 2006  2008, we will be shifting more of our efforts onto our last two pillars  lifecycle planning and portfolio management. Lets talk first about the former. We will invest a lot of money in cyclical
maintenance over the life of our plants to keep them running at peak performance. Like a car, every plant is different in its characteristics, operating patterns and history. Over time, for every invested dollar, some plants tend to be more reliable
than others. The better we are at predicting future costs and reliability

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for our plants, the better well be able to plan for long-term capital spending and operating expenses. We want to spend just enough money, and no more, to extract value until we decide to close or sell a plant.     Linda Chambers, Executive Vice-President, Generation Technology & Supply Chain Management, and her team are developing the tools and the science we need to properly lifecycle plan for our
plants. They are currently assessing our entire fleet and having their work verified by some top-notch experts in this field. By the end of 2006, well have our whole fleet analysis complete. That will allow us to make better fix/close/sell
decisions. The savings over the next 20 years could be hundreds of millions of dollars in reduced capital spending.

IV. PORTFOLIO MANAGEMENT AND GROWTHJust like investors who want to create a diversified investment portfolio to produce steady and predictable earnings, we have assembled a diversified portfolio of generating plants. The fuel and geographic diversity we
enjoy reduces the risk of wide swings in our earnings. It has helped mitigate the impact of unpredictable events like the sharp increase in natural gas prices in 2005. It has allowed us to sustain our cash flow as we faced unresolved issues like the
changing rules for merchant plants in Ontario. Our multi-year marketing strategy creates a portfolio of contracts that further supports our goals to reduce volatility and risk.     The cornerstone of all this work is commercial discipline  matching market analysis to plant costs. We rank our plants based on returns, comparing short-term opportunities to potentially
longer-term challenges. We work hard to layer in our power contracts on the basis of output and the length of contracts so we can minimize the potential volatility in our cash flows. This is where we make our long-term risk mitigation strategies
work.     Balancing fuel and geographic diversification with contracting length takes years of advance planning. By properly managing our fleet of assets, well be able to use our fleet to help take
out the lumpiness inherent in our industry. Tom Rainwater, Executive Vice-President, Corporate Development & Marketing, and his team are on top of this opportunity adding their market knowledge to our life-cycle analysis to determine the best
mix for our fleet.     Its already helped us plan for the 2009  2011 period. Now their sights are set on 2012 and beyond. This team is developing the models and skills that will allow us to wisely invest
our capital in all our plants.



| | MESSAGE TO SHAREHOLDERS         21
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Your teamTransAltas management team and Board remain focused and disciplined. Each quarter we check our progress against our short-term goals as well as our five-year plan. I report to you on them twice a year. We revisit our
strategy constantly and adjust it to match changing environments. Our Board ensures all the proper linkages are in place. Our senior teams long-term compensation plan remains focused on share ownership (not stock options) and sustained
performance. We benchmark our share performance against the TSX over a three-year period. And, we have mandatory stock ownership guidelines for the senior team.

Our Board continued to provide strong, on-going guidance. TransAlta is regularly recognized for its excellent corporate governance practices. The Board is involved in setting our strategies and
risk profiles. They are actively engaged in learning our business and monitoring our progress, setting high standards, demanding results and offering support wherever needed. Their stewardship has ensured that TransAlta has not only survived the
turbulence of the last few years but is well positioned to take advantage of improving better forward-looking markets.

Our management team, the Board and our employees will continue to be disciplined and deliver results for you, our shareowners in 2006.

STEPHEN G. SNYDERPresident & Chief Executive OfficerMarch 3, 2006







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LETTER FROM
DONNA SOBLE KAUFMANCHAIR OF THE BOARD



Having served on the TransAlta Board for 16 years, I was honoured and delighted to be elected Chair in 2005. We have a very committed Board, we have great management, and I am happy to say the company had a good
year.
     Over the years on the TransAlta
Board, I have seen many changes, both in the industry and in the company. The Board has kept a strong focus on oversight through a number of challenges, including deregulation, early growth, price volatility, and factors
beyond TransAltas control, always with our shareholders and other stakeholders in mind. We have also pursued many opportunities: development in new markets, commercial advancement of wind power, and entry into energy trading. Through all of
this, we have maintained the dividend.     Your Board of Directors has a proven record of protecting shareholder interests. We are firmly committed to an ethical culture and good corporate governance. We constantly determine proper risk
parameters, and engage management in setting and implementing appropriate strategies. This will continue to be our task as we go forward.     TransAlta is fortunate to have strong representation on its Board. Some have joined the Board in recent years, most recently Gord Lackenbauer, whom we welcomed to his first meeting in the third
quarter of 2005. He brings a wealth of experience in banking and business, which will serve the Board
well. Lou Hyndman, who has served the shareholders of the company for 20 years as a director, retires from the Board this year. He has been a valued colleague and his contribution was significant, driven by his vast
experience in both politics and law.
     Your Board consists of members
from various regions of Canada and the world, which gives us a truly international perspective as TransAlta grows. We have broad experience in finance, risk management, operations, government relations, law and current
governance practices. This knowledge, combined with managements considerable skill, helped put in place the structures and processes that provide the transparency investors expect. I am proud to say these efforts have been recognized:
TransAlta was chosen by KPMG as one of Canadas top 10 most respected companies; The Globe and Mails Report on Business ranked it among the best governed corporations in 2005; and it was given top honours by the Canadian Institute of
Chartered Accountants for financial and corporate reporting for the sixth consecutive year.     Our Board recognizes the ever-growing emphasis on good governance and corporate responsibility. We have always believed in both, and they are a consistent theme in our dialogue with
management.     A major focus of your Board is the building of a sustainable company  a company that will continue to drive toward profitable growth for you

| | LETTER FROM THE CHAIR         23
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over time. This is not a new theme. It began many years ago, continues today, and is our goal for the future. To have a sustainable company, we must anticipate issues, assess risks, encourage the development of management
talent, and ultimately decide what best serves our shareholders and the communities we serve.     I well remember my initial reaction when the notion of sustainability, as it relates to environment issues, was introduced to the TransAlta Board in the early 90s. What will this mean? As
directors of an energy company, we were intrigued by the notion of sustainability because we knew environmental issues would become increasingly important. We believed if TransAlta took proactive steps then, it would benefit not only our
shareholders and other stakeholders, but the environment as well. This was something of a leap of faith, but we believed it was
the right thing to do, and that conviction has proven correct many years later.     TransAltas Board of Directors remains convinced that approaching business oversight from three perspectives  economic, environmental and social  creates competitive
advantages. We recognize that our shareholders entrust this duty to us and we are determined to continue to earn that trust. After a strong year in 2005, we have turned our attention to 2006 and beyond, with your interests foremost in our
minds.
     Thank you for placing your confidence in us.

DONNA SOBLE KAUFMANChair of the Board



CORPORATE
GOVERNANCE

TransAltas directors are experienced business leaders representing varied geographic and professional backgrounds, including business, finance, law and public service. On behalf of TransAltas
shareholders, the Board of Directors is responsible for the stewardship of the corporation, establishing overall policies and standards and reviewing strategic plans. During 2005, the directors met on 10 occasions, including one special meeting
devoted exclusively to TransAltas corporate strategy and direction.

After a detailed examination of the relationships between each of the directors and TransAlta, the Board determined that 10 of the existing 11 board members are independent excluding only Stephen Snyder, President
and CEO of the company. All of the members of each of the committees of the Board are independent. The Board established three committees, which are briefly described as follows, to assist the Board in the performance of its obligations. Further
detailed information with respect to TransAltas approach to corporate governance is contained in the 2005 Management Proxy Circular.

AUDIT AND ENVIRONMENT COMMITTEEThe committee is responsible for reviewing financial reporting, financial controls, internal audit matters, financial risks inherent in the business and environmental risks and regulation affecting the
corporations activities. This committee met eight times in 2005. Committee chair: William D. Anderson. Members: Stanley J. Bright, Timothy W. Faithfull, Michael M. Kanovsky and Donna Soble Kaufman (as an ex-officio member).

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BOARD OF
DIRECTORS

TransAlta's Board of Directors at their annual strategy session in Ghost River, Alberta (July 2005).
Standing, left to right:
Tim Faithfull, Luis Vázquez
Senties, Louis Hyndman, Stanley Bright, Gordon GiffinSitting, left to right:Michael
Kanovksy, William Anderson, Donna Soble Kaufman, Stephen Snyder, Kent JespersenMissing: Gordon Lackenbauer, who joined the Board in September 2005.


BOARD OF DIRECTORS

William D. AndersonDirector since 2003 and resident of Montreal, Que. Mr. Anderson was President of BCE Ventures, a subsidiary of BCE Inc., from 2000 to 2005 and
CFO of BCE Inc. from 1998 to 2000. He is a director of Bell Canada International Inc., the Four Seasons Hotels Inc. and Sears Canada Inc. He is a member of the Institute of Chartered Accountants of Ontario.

Stanley J. BrightDirector since 1999 and resident of Vero Beach, Fla. Mr. Bright was Chair and CEO of MidAmerican Energy Company, a Des Moines, Iowa-based
electric and gas utility company. He served as a director of MidAmerican Energy Holdings Company,
a subsidiary of Berkshire Hathaway Inc., from 1999 to February 2006 and has been a director of MidAmerican Energy predecessor companies since 1987.

Timothy W. FaithfullDirector since 2003 and resident of Oxford, United Kingdom. Mr. Faithfull was President and CEO of Shell Canada Limited from 1999 to 2003,
when he completed a 36-year international oil and gas career with the Royal Dutch/Shell Group. He is a director of Canadian Pacific Railway Limited, the Canada-United Kingdom Colloquia, Shell Pension Trust Limited and AMEC plc in the United
Kingdom.





HUMAN RESOURCES COMMITTEE

The committee is responsible for reviewing and recommending executive compensation programs, succession plans, and the CEOs compensation and performance, and acting as steward for the corporate pension plan.
This committee met eight times in 2005. Committee chair: Stanley J. Bright. Members: Timothy W. Faithfull, C. Kent Jespersen, Luis Vázquez Senties and Donna Soble Kaufman (as an ex-officio member).

NOMINATING AND CORPORATE GOVERNANCE COMMITTEE

The committee is responsible for reviewing the composition and compensation of the Board of Directors and for developing the companys approach to governance issues. This committee met three times in 2005.
Committee chair: Gordon D. Giffin. Members: C. Kent Jespersen, Michael M. Kanovsky, Gordon S. Lackenbauer, Louis D. Hyndman and Donna Soble Kaufman (as an ex-officio member).

2005 CHANGES

Jack Donald and John Ferguson retired from the Board in April 2005. Gordon Lackenbauer joined the Board in September 2005.

| | MESSAGE TO SHAREHOLDERS         25
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Gordon D. GiffinDirector since 2002 and resident of Atlanta, Ga. Mr. Giffin is a Senior Partner of McKenna Long & Aldridge LLP. He is a director of Bowater,
Inc., Canadian National Railway Company, Canadian Imperial Bank of Commerce and Canadian Natural Resources Ltd. He is a member of the Council of Foreign Relations, an advisory board member of the Canadian-American Business Council and serves on the
Board of Trustees for the Carter Center in Georgia. Mr. Giffin served as United States Ambassador to Canada from 1997 to 2001.

Louis D. Hyndman,Q.C. Director since 1986 and resident of Edmonton, Alta. Mr. Hyndman is a Senior Partner of Field LLP. He is a director of Canadian Urban Ltd.,
EllisDon Inc., Enbridge Inc., Melcor Developments Ltd. and Meloche Monnex Inc.

C. Kent JespersenDirector since January 2004 and resident of Calgary, Alta. Mr. Jespersen worked with NOVA Corporation for over 20 years in various management
positions, including president of NOVA International. He is Chair and CEO of La Jolla Resources International Ltd., Chair and a director of Geac Computer Corporation Limited and CCR Technologies Ltd. and a director of Matrikon Inc. and Axia NetMedia
Corporation.

Michael M. KanovskyDirector since January 2004 and resident of Victoria, B.C. Mr. Kanovsky is President of Sky Energy Corporation. He has been involved in
investment banking and the oil, gas and power industries for over 30 years. He is a director of Accrete Energy Corporation, Devon Energy Corporation, ARC Energy Trust, Bonavista Energy Trust and Pure Technologies Inc.

Donna Soble KaufmanDirector since 1989 and resident of Toronto, Ont. Mrs. Kaufman is Chair of the Board of TransAlta Corporation. She was Chair and CEO of
Selkirk Communications Ltd. from 1988 to 1989 and a partner of the law firm Stikeman Elliott from 1985 to 1997. Mrs. Kaufman is a director of BCE Inc., Bell Canada, Telesat Canada, Hudsons Bay Company, Historica, a Canadian historical society,
and Baycrest, a centre for elderly and specialized care.

Gordon S. LackenbauerDirector since September 2005 and resident of Calgary, Alta. Mr. Lackenbauer was Deputy Chairman of BMO Nesbitt Burns Inc. from 1990 to
2004. He has been a director of Tembec Inc. since 1973 and Chair since 2005. Mr. Lackenbauer is also a Governor of Mount Royal College.

Stephen G. SnyderDirector since 1996 and resident of Calgary, Alta. Mr. Snyder has been President and CEO of TransAlta Corporation since 1996. He is Chair of the
Conference Board of Canada, the Calgary Zoological Society, the Calgary Stampede Foundation and a director of the Calgary Exhibition and Stampede and the Canadian Imperial Bank of Commerce.

Luis Vázquez SentiesDirector since 2001 and resident of Mexico City, Mexico. He is President and CEO and Chair of Group Diavaz, an oilfield services and
natural gas distribution company he founded with partners in 1973. Mr. Vázquez is Chair of Compania Mexicana de Gas, S.A. de C.V. and of the Mexican Natural Gas Association.

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AT A GLANCEFINANCIAL HIGHLIGHTSin millions of Canadian dollars, except per common share data

Year ended Dec. 31
	
	2005
	
	2004
	
	2003Revenues1
	$
	3,108.6
	$
	2,838.3
	$
	2,520.9Earnings from continuing operations2
	$
	186.8
	$
	160.6
	$
	234.2Net earnings
	$
	198.8
	$
	170.2
	$
	234.2Cash flow1
	$
	640.0
	$
	613.4
	$
	526.9RatiosReturn on common shareholders equity (%)
	
	7.3
	
	6.5
	
	10.3Debt to invested capital (%)
	
	43.3
	
	47.4
	
	47.7Cash flow to interest coverage (times)
	
	4.6
	
	4.1
	
	3.3Per common share dataEarnings from continuing operations
	$
	0.95
	$
	0.83
	$
	1.26Net earnings
	$
	1.01
	$
	0.88
	$
	1.26Dividends
	$
	1.00
	$
	1.00
	$
	1.00


1 Revenues and cash flow shown are non-GAAP measures as they include the Mexico entities. Please refer to pages 31 to 115 for financial information prepared in accordance with GAAP.

2 Applicable to common shareholders.



| | AT A GLANCE         27
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AT A GLANCEOUR OUTLOOK AND FOCUS

GENERATIONProfile
	Industry Outlook
	Our Focus8,468* MW of capacity
  54,561 GWh produced at an average plant availability of 89.7%
  49 facilities in four geographies: Canada; the United States; Mexico; and Australia
  Three surface coal mines: Highvale and Whitewood (Alberta, Canada); Centralia (Washington, United States.)
  Fuel mix of coal (58%), gas (29%), hydro (9%) and renewables (4%)  18.6 million tonnes of coal mined  100.4 million gigajoules (GJ) of  gasconsumed
	Capacity oversupply in many regionsis slowly being absorbed by annual load growth.
  Current conditions continue to favour low-cost producers with strong balance sheets.
  Spark spread profitability varies by regional power market fundamentals.
  Environmental pressures continue to drive industry focus towards gas, renewables and clean coal technology.
  Continued government
    oversight/intervention causes uncertainty in some markets where we operate.
	Set the highest safety standards.
  Continue to concentrate on achieving operational excellence while integrating new capacity.
  Reduce overall fuel costs/MWh.
  Drive top decile performance in major maintenance through lifecycle planning.
  Continue to diversify our fuel mix while
    capitalizing on opportunities that match our commercial and operational strengths.
  Grow our expertise in more environmentally
    sustainable generation through involvement in CE Gen, Vision Quest and the Canadian Clean Power Coalition.
  Grow our renewable capacity to 10% of
    our portfolio by 2010, with a short-term focus on wind.* Not including plants in developmentENERGY MARKETINGProfile
	Industry Outlook
	Our Focus115,682 GWh of electricity and 413.8 million GJ of natural gas traded
  Trading focuses on enhancing returns of generation assets through disciplined approach to asset optimization and capitalizing on short-term market 
opportunities.
  Trading involves matching buyers and sellers, arranging for transmission capacity and scheduling movement of
the commodity.
  Development and marketing focuses on selling long-term contracts, designing new products for customers and identifying strategic growth opportunities.
	The real-time nature of the commodity continues to call for active management of buying, selling and moving power and natural gas.
  Liquidity varies regionally and remained low in medium- and long-term markets in 2005, but short-term and real-time  markets will continue to be active.
  Financially backed players are entering  the business, enhancing liquidity in the  forward power markets.
	Maximize margins on non-contracted generation production.
  Reduce cost of replacement power for plant outages.
  Reduce our exposure to any one market by continuing to focus our growth in our key geographies.
  Provide critical market knowledge to help identify growth opportunities and support corporate investment decisions.FINANCIALProfile
	Industry Outlook
	Our FocusDebt ratings: BBB (DBRS); BBB (S&P); Baa2 (Moodys)
  43.3% debt to invested capital
  $1 per share dividend
  Interest coverage at 4.6 times
  Cash flow to debt ratio: 23%
	Prudent fiscal management continues  to be critical in medium term and long term.
  Consolidation of key players in the United States.
  Continued focus on balance sheet strength.
	Maximize cash flow from operating activities.
  Achieve BBB+ credit metrics by 2007.


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INTERNATIONAL OPERATIONS



| | AT A GLANCE         29
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AT A GLANCEPLANT SUMMARY

Capacity ownedCapacity
	Ownership
	TransAlta
	or operated
	
	
	ContractFacility
	(MW)
	(%)
	operated
	(MW)
	Fuel
	Revenue source*
	expiry dateGenesee 3
	450
	50
	No
	225
	Coal
	Merchant
	Keephills
	766
	100
	Yes
	766
	Coal
	Alberta PPA
	2020Keephills 31,2
	450
	100
	Yes
	450
	Coal
	Merchant
	Sheerness
	770
	25
	No
	193
	Coal
	Alberta PPA
	2020Sundance
	2,020
	100
	Yes
	2,020
	Coal
	Alberta PPA
	2017, 2020Wabamun
	279
	100
	Yes
	279
	Coal
	Merchant
	Fort Saskatchewan
	118
	30
	Yes
	35
	Gas
	Long-termcontract (LTC)
	2019Meridian
	220
	25
	Yes
	55
	Gas
	LTC
	2024Poplar Creek
	356
	100
	Yes
	356
	Gas
	LTC & Merchant
	2024Hydro assets3
	801
	100
	Yes
	801
	Hydro
	Alberta PPA
	20132020Castle River4
	46
	100
	Yes
	46
	Wind
	LTC
	2011McBride Lake
	75
	50
	Yes
	38
	Wind
	LTC
	2022Summerview
	68
	100
	Yes
	68
	Wind
	Merchant
	ALBERTA TOTAL
	6,419
	
	
	5,332Mississauga
	108
	50
	Yes
	54
	Gas
	LTC
	2017Ottawa
	68
	50
	Yes
	34
	Gas
	LTC
	2012Sarnia
	575
	100
	Yes
	575
	Gas
	LTC & Merchant
	2022Windsor-Essex
	68
	50
	Yes
	34
	Gas
	LTC & Merchant
	2016ONTARIO TOTAL
	819
	
	
	697Centralia
	1,404
	100
	Yes
	1,404
	Coal
	Merchant
	Binghamton
	47
	100
	Yes
	47
	Gas
	Merchant
	Centralia Gas5
	248
	100
	Yes
	248
	Gas
	Merchant
	Power Resources
	200
	50
	No
	100
	Gas
	Merchant
	Saranac
	240
	37.5
	No
	90
	Gas
	LTC
	2009Yuma
	50
	50
	No
	25
	Gas
	LTC
	2024Imperial Valley6geothermal assets
	327
	50
	No
	163
	Geothermal
	LTC & Merchant
	20162035Salton Sea VI1
	180
	50
	No
	90
	Geothermal
	Merchant
	Skookumchuck
	1
	100
	Yes
	1
	Hydro
	Merchant
	UNITED STATES TOTAL
	2,697
	
	
	2,168Campeche
	252
	100
	Yes
	252
	Gas
	LTC
	2028Chihuahua
	259
	100
	Yes
	259
	Gas
	LTC
	2028MEXICO TOTAL
	511
	
	
	511Parkeston
	110
	50
	Yes
	55
	Gas
	LTC
	2016Southern Cross
	245
	100
	Yes
	245
	Gas & Diesel
	LTC
	2016AUSTRALIA TOTAL
	355
	
	
	300TOTAL
	10,801
	
	
	9,008


1 These facilities are currently under development
2 Formerly referred to as Centennial
3 Comprised of 13 facilities
4 Includes eight individual turbines at other locations, one of which moved from testing to production
5 Formerly referred to as Big Hanaford
6 Comprised of 10 facilities
* Merchant includes both contracted and spot sales

Details as of Jan.1 2006

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MANAGEMENT'S
DISCUSSION AND ANALYSIS



This managements discussion and analysis (MD&A) should be read in conjunction with the consolidated financial statements included in this Annual Report. The consolidated financial statements
have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The effect of significant differences between Canadian and U.S. GAAP has been disclosed inNote
25to the consolidated financial statements. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Feb. 16, 2006.
Additional information respecting TransAlta Corporation (TransAlta or the corporation), including its annual information form, is available on SEDAR at www.sedar.com.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         31
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RESULTS OF OPERATIONSThe results of operations are presented on a consolidated basis and by business segment. TransAlta has two business segments: Generation and Energy Marketing. TransAltas segments are supported by a corporate
group that provides finance, treasury, legal, information technology, human resources and other administrative support. The costs of the corporate group are allocated to the business segments unless these costs are directly attributable to
discontinued operations.

Some of TransAltas accounting policies require management to make estimates or assumptions that in some cases may relate to matters that are inherently uncertain. Critical accounting policies and estimates
include: revenue recognition; valuation and useful life of property, plant and equipment (PP&E); asset retirement obligations; valuation of goodwill; income taxes; and employee future benefits. See additional discussion under Critical Accounting
Policies and Estimates in this MD&A.

In this MD&A, the impact of foreign exchange fluctuations on foreign currency transactions and balances is discussed with the relevant income statement and balance sheet items. While individual balance sheet line
items will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items is reflected in the cumulative translation account on the consolidated balance sheet.

HIGHLIGHTS AND SUMMARY OF RESULTSDuring 2005, the corporation:

- Generated net earnings of $198.8 million compared to $170.2 million for 2004 and $234.2 million for 2003.
- Generated earnings on a comparable basis of $173.8 million compared to $128.1 million for 2004 and $128.7 million for 2003. Earnings on a comparable basis is not
defined under GAAP. Refer to the Non-GAAP Measures section on page 66 of this MD&A for a further discussion of earnings on a comparable basis, including a reconciliation to net earnings.
- Generated cash flow from operations of $619.4 million compared to $591.2 million in 2004 and $474.3 million in 2003.
- Invested $325.5 million in new and existing plants versus $345.7 million in 2004 and $434.4 million in 2003.
- Made net repayments of short- and long-term debt of $262.9 million compared to $367.4 million in 2004 and $226.7 million in 2003.
- Settled several outstanding tax positions resulting in $25.0 million in income tax recoveries.
- Signed a four-year agreement to deliver 375 megawatts (MW) of electricity per year from our Centralia coal-fired plant. This contract replaces a number of prior contracts
that have expired in recent periods. The pricing terms of this new contract are considerably higher than those that have expired.
- Had its credit rating trend upgraded by Dominion Bond Rating Service (DBRS) from BBB Negative trend to BBB Stable trend and its Standard &
Poors (S&P) credit rating upgraded from BBB- Stable to BBB Stable.
    The following table depicts key financial results and statistical operating data:

|Year ended Dec. 31                                   |         | 2005                                  |        | 2004    |        | 2003   
|---------------------------------------------------- | ------- | ------------------------------------- | ------ | ------- | ------ | -------
|                                                     |         | (Restated, Note 1) (Restated, Note 1)
|Availability (%)                                     |         | 89.4                                  |        | 89.2    |        | 90.5   
|Production (GWh)                                     |         | 51,810                                |        | 51,396  |        | 51,519 
|Electricity trading volumes (GWh)                    | 115,682 |                                       | 84,404 |         | 89,833
|Gas trading volumes (million GJ)                     |         | 413.8                                 |        | 430.4   |        | 270.2  
|Revenue                                              | $       | 2,838.5                               | $      | 2,586.2 | $      | 2,413.5
|Gross margin                                         | $       | 1,462.6                               | $      | 1,356.8 | $      | 1,325.3
|Operating income 1                                   | $       | 441.2                                 | $      | 470.9   | $      | 558.7  
|Earnings from continuing operations 2                | $       | 186.8                                 | $      | 160.6   | $      | 234.2  
|Earnings from discontinued operations, net of tax  3 |         | 12.0                                  |        | 9.6     |        |       
|Net earnings applicable to common shareholders       | $       | 198.8                                 | $      | 170.2   | $      | 234.2  
|Basic earnings per common share:                     |         |                                       |        |         |        |        
|Earnings from continuing operations                  | $       | 0.95                                  | $      | 0.83    | $      | 1.26   
|Earnings from discontinued operations                |         | 0.06                                  |        | 0.05    |        |       
|Net earnings                                         | $       | 1.01                                  | $      | 0.88    | $      | 1.26   
|Diluted earnings per common share:                   |         |                                       |        |         |        |        
|Earnings from continuing operations                  | $       | 0.95                                  | $      | 0.83    | $      | 1.26   
|Earnings from discontinued operations                |         | 0.06                                  |        | 0.05    |        |       
|Net earnings                                         | $       | 1.01                                  | $      | 0.88    | $      | 1.26   
|Cash flow from operating activities                  | $       | 619.4                                 | $      | 591.2   | $      | 474.3  

1 Operating income is not defined under GAAP. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of operating income,
including a reconciliation to net earnings.
2 Continuing operations include the Generation and Energy Marketing segments plus corporate costs not directly attributable to discontinued
operations.
3 Discontinued operations consist of the Transmission operation which was sold on April 29, 2002 and the Alberta Distribution and Retail operations
which was sold on Aug. 31, 2000.

|32         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
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STRATEGY AND KEY MEASURES

Our business is to invest in long-term electricity assets and consistently create value. Our goal is to deliver 10 per cent average total shareholder returns over time. We have six key measures with long-term targets
that are critical to meeting our goal. These key measures include a mix of operational, risk management and financial metrics against which we can measure our performance.

1. Availability and Production

Our plants must be available to meet the requirements of customers who have contracted our capacity or to sell production into merchant markets to capture opportunities. Our long-term target is to have our plants
available 90 per cent or more of the time.

Availability can be limited by the requirement to perform planned maintenance at regular intervals or by outages and de-rates caused by minor mechanical problems. While we expect there will be a certain number of these
unplanned outages, our goal is to minimize these events through constant equipment monitoring and assessment, rolling maintenance plans and the formation of strategic relationships with suppliers. Over the past three years, we have achieved an
average availability of 89.7 per cent, which is in line with our long-term target of 90 per cent availability.

Production is affected by our total generating capacity, the availability of our equipment and market conditions. During 2005, production increased as Genesee 3 was commissioned and we received a full year of
production from the Summerview wind farm. The increase was partially offset by the decommissioning of units one and two of the Wabamun plant in December 2004. Production was negatively impacted by shutdowns caused by the Canadian National Railway
(CN) train derailment at Lake Wabamun and a fire at a Suncor plant in Fort McMurray that impacted the production from our Poplar Creek plant. Production decreased in 2004 as incremental production from the Sarnia plant, which was commissioned during
2003, was more than offset by lower production from our Centralia coal-fired plant.

2. Contracts

Our strategy is to contract a minimum of 75 per cent of our available output in any year to minimize our exposure to electricity and gas price swings in the markets in which we operate. This strategy allows us to
achieve a balance between cash flow stability and the ability to capture short-term opportunities in the markets.

Contracts can be structured as capacity commitments (Alberta Power Purchase Arrangements (PPA), and contracts for our Australia and Mexico plants), which allow TransAlta to minimize fuel cost risks by passing the
majority of these costs on to the customer. We also have contracts that combine production, availability and other services, where we are compensated for availability, electricity and steam production (Ontario and Alberta gas plants) and long-term
bilateral contracts directly with our customers (Centralia coal-fired plant). The remainder of our production is sold into markets as spot sales or under contracts with terms less than one year.

During 2005, approximately 82 per cent of the Generation segments revenues were derived from contracts with terms greater than one year. This percentage is lower than prior years as we have increased our merchant
generating capacity with the addition of the Genesee 3 plant. On Feb. 15, 2006, we signed a five-year contract with the Ontario Power Authority to be available to supply an average of 400 MW of electricity to the Ontario market. This contract is
effective Jan. 1, 2006.

A further discussion of these contracting strategies is provided, beginning on page 41 of this MD&A.

3. Margin and Productivity

Together with our increasing production base, growing our gross margin is essential for our success. We manage margins through our contracting strategy and fuel cost management. In our key markets in Alberta and the
Pacific Northwest, electricity prices have been driven by fluctuating gas costs and the availability of water for hydro production, particularly in the Pacific Northwest.

Gross margins at our contracted gas plants are generally managed by passing fuel costs on to customers or by signing long-term gas contracts that match the terms of the electricity and thermal sales. At our Centralia
operations, our mine and major maintenance strategy is to minimize fuel costs and maximize availability in order to capture margin. At our merchant gas plants, the margins are driven by the ratio of gas prices to electricity prices in that market
(market heat rates) and our ability to produce electricity at heat rates that are better than the market heat rates.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         33
| | ---------------------------------------------------

---

During 2005, our margins increased due to higher gas prices in the North American markets, which in turn influenced electricity prices. These higher electricity prices had a significant impact on the margins from our
coal-fired plants. In addition, merchant capacity from the newly commissioned Genesee 3 plant and increased hydro production also contributed to higher margins. These increases were partially offset by higher fuel costs at the coal-fired
plants.

In 2004, gross margin increased due to higher merchant capacity and lower planned maintenance outages. Similar to 2005, revenues were offset by higher fuel costs. 2003 also included a loss from trading in Transmission
Congestion Contracts (TCCs).

In 2005, gross margin per megawatt hour (MWh) increased over 2004 due to higher hydro production and higher merchant capacity from the coal-fired plants that benefited from higher electricity prices. These gains were
partly offset by higher coal costs. Margins in 2004 were similar to 2003 as higher prices from coal plants were offset by increased fuel costs. In addition, the 2003 margins included a loss from TCCs in our Energy Marketing Segment.

We will continue to focus on increasing our margins by increasing plant availability to capture market opportunities, matching revenues and fuel cost contracts at our gas plants and developing long-term fuel plans for
our coal-fired plants.

During 2005, our operations, maintenance and administration (OM&A) costs increased from $547.5 million to $596.0 million due to the addition of Genesee 3 and higher salary, contracting and material costs
due to market demand for labour and commodities. Labour costs also increased from the impact of our increasing share price on stock-based compensation.

In 2004, OM&A costs increased over 2003 as a result of the Sarnia plant commissioned in March 2003.

4. Capital ExpendituresWe are in a long-cycle capital intensive business. Since our growth in 2000-2003, our capital expenditures have declined significantly. Despite an increase in capital spending on planned maintenance activities in 2005,
capital expenditures have declined as a result of lower capital spending on growth initiatives.

5. Cash FlowOur goal is to generate $550-$650 million of cash flow from operating activities to meet the requirements of maintaining our equipment, reducing our debt, maintaining our dividend and having cash available to
invest in growth initiatives.

In 2005, cash flow from operating activities improved to $619.4 million compared to $591.2 million in 2004. Improved net earnings, coupled with higher depreciation expense, contributed to the increase. In 2004,
cash flow from operating activities improved $116.9 million compared to 2003, due primarily to improved non-cash operating working capital balances and increased earnings.

6. Financial RatiosTransAlta is focused on maintaining a strong balance sheet and investment-grade credit rating. Financial strength provides us with continued access to capital and greater flexibility in contracting the output of our
plants.

In the long term, our financial condition will dictate our ability to grow. Our objective is to maintain an investment-grade rating to give us the capacity to take on new debt or issue equity.

At Dec. 31, 2005, our total debt (including non-recourse debt) to invested capital was 43.6 per cent (39.8 per cent excluding non-recourse debt) compared to Dec. 31, 2004 of 46.4 per cent and Dec. 31, 2003 of 46.2 per
cent. Cash flow to interest increased to 4.8x compared to 4.3x in 2004 and 3.4x in 2003. Cash flow to total debt increased to 23.5 per cent from 19.1 per cent in 2004 and 17.1 per cent in 2003.



|34         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
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COMPARABLE EARNINGS

In 2005, comparable earnings increased to $173.8 million compared to $128.1 million in 2004 and $128.7 million in 2003 as shown below:

|Comparable earnings for the year ended Dec. 31, 2003                             | $ | 128.7 
|-------------------------------------------------------------------------------- | - | ------
|Decreased Generation gross margins                                               |   | (19.6)
|Decreased lost margins due to planned maintenance                                |   | 15.6  
|Increased Energy Marketing gross margins                                         |   | 35.5  
|Increase in operational and administrative costs                                 |   | (6.7) 
|Increased depreciation                                                           |   | (27.7)
|Increase in earnings attributable to non-controlling interest                    |   | (11.8)
|Lower interest expense                                                           |   | 4.7   
|Lower income taxes                                                               |   | 8.4   
|Other                                                                            |   | 1.0   
|Comparable earnings for the year ended Dec. 31, 2004                             | $ | 128.1 
|Increased Generation gross margins                                               |   | 107.1 
|Increased lost margins due to planned maintenance                                |   | (11.4)
|Increased Energy Marketing gross margins                                         |   | 10.1  
|Increase in operational and administrative costs                                 |   | (48.5)
|Increased depreciation                                                           |   | (10.4)
|Increase in earnings attributable to non-controlling interest, net of impairment |   | (8.7) 
|Lower interest expense                                                           |   | 18.8  
|Higher income taxes                                                              |   | (11.3)
|Comparable earnings for the year ended Dec. 31, 2005                             | $ | 173.8 

For the year ended Dec. 31, 2005, our gross margins were $105.8 million higher than in 2004 due to the addition of Genesee 3, higher hydro production, higher electricity prices captured by our Centralia and Alberta
coal-fired facilities, higher contract prices at some of our gas plants and higher trading margins from our Energy Marketing segment. These increases were partially offset by increased coal costs in both our Alberta and Centralia coal-fired plants,
increased net penalties at our Alberta coal-fired plants as a result of our major maintenance activities and the decommissioning of units one and two of the Wabamun plant. In 2004, our gross margins increased $31.5 million compared to 2003. In
2003, the results of our Energy Marketing segment were negatively impacted by losses on TCCs in the amount of $33.3 million.

OM&A costs increased $48.5 million due to the addition of Genesee 3, equipment repairs, escalations of material costs, increased incentive compensation costs and increased labour costs. These increases were
partially offset by lower planned maintenance expenses. Our OM&A costs in 2004 were $6.7 million higher than in 2003 due to the addition of our Sarnia plant, partially offset by reduced planned maintenance expenses.

Depreciation and amortization increased by $10.4 million due primarily to the addition of Genesee 3. In 2004, depreciation and amortization increased $27.7 million compared to 2003 due to the addition of the
Sarnia plant, increased depreciation at the Ottawa, Windsor and Mississauga plants and depreciation of increased capital spending on major maintenance.

Interest expense declined in 2005 by $18.8 million compared to 2004 as we redeemed $300.0 million in preferred securities early in 2005. Interest expense declined from 2003 to 2004 by $4.7 million due to
overall debt reductions.

Non-controlling interests decreased to $18.5 million in 2005. Included in this amount is $36.2 million related to the impairment of the Ottawa facility discussed later in Significant Events. Excluding this
amount, non-controlling interests increased in 2005 as we disposed of our remaining interest in TransAlta Power, L.P. (TA Power) in 2004. In 2004, non-controlling interests increased $11.8 million due to the disposition of our Sheerness
Generating Station to TransAlta Cogeneration, L.P. (TA Cogen) in July 2003.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         35
| | ---------------------------------------------------

---

EARNINGS PER SHARE AND CASH FLOWEarnings from continuing operations for 2005 were $186.8 million ($0.95 per common share), compared to $160.6 million ($0.83 per common share) for 2004 and $234.2 million ($1.26 per common
share) in 2003. The increase in 2005 was driven by increased spark spreads (the margin between the price of electricity and the price of natural gas consumed to produce power) and pricing in all markets, the commissioning of Genesee 3 and higher
hydro reservoir levels, offset by higher coal costs. The variance from 2004 to 2003 was due primarily to the $145.8 million after-tax gain on the sale of the Sheerness Generating Station and the $59.0 million after-tax turbine impairment
charge in 2003. See Significant Events below for further discussion.

SIGNIFICANT EVENTSOur consolidated financial results include the following significant events. All gains and losses discussed below are presented as pre-tax (after-tax) amounts, unless otherwise noted.

2005Commissioning of Genesee 3On March 1, 2005, we, jointly with EPCOR Utilities Inc. (EPCOR), commissioned the third unit of the Genesee coal-fired facility. We own a 50 per cent interest in this third unit.

Wabamun OutageOn Aug. 3, 2005, a CN train derailment resulted in an oil spill at Lake Wabamun, Alberta. We were forced to shut down unit four of our Wabamun coal-fired plant as a result. The facility was restored to full operations
on Sept. 11, 2005. We estimate that we lost between $15 million and $18 million in operating income as a result of this incident.

Impairment of the Ottawa FacilityIn the fourth quarter of 2005, after completing our impairment reviews, we concluded that the carrying value of the Ottawa cogeneration facility exceeded its fair value in the accounts of TA Cogen. Consequently, TA
Cogen recorded an impairment provision of $78.3 million in the fourth quarter of 2005. In the accounts of the corporation, however, the carrying value of the Ottawa facility is lower than that of TA Cogen. TA Cogen purchased this facility from
the corporation at a price that was higher than the cost the corporation paid to construct it. We have recognized a $36.2 million charge in the accounts to reflect the difference in carrying values between the accounts of the corporation and
those of TA Cogen. This charge is offset by a reduction in the earnings attributable to the non-controlling interests in our consolidated statement of earnings. The net result is that the impairment of the plant in the accounts of TA Cogen has had
no impact on the net earnings of TransAlta Corporation.

2004Decommissioning of Wabamun PlantIn the fourth quarter of 2002, we implemented a phased decommissioning of the Wabamun facility by removing the 139 MW unit three from service in 2002 and decommissioning units one and two (62 MW and 57 MW,
respectively) on Dec. 31, 2004. We plan to retire unit four (279 MW) in 2010 when its operating licence expires. The PPA for the plant expired on Dec. 31, 2003. Production in 2004 was sold on the spot market. The costs of decommissioning will reduce
the Asset Retirement Obligation on the consolidated balance sheet.

Sale of Meridian Cogeneration FacilityOn Dec. 1, 2004, we completed the sale of our 50 per cent interest in the 220 MW Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TA Cogen for its fair value of $110.0 million. TA Cogen
financed the acquisition through the use of $50.0 million of cash on hand, by issuance of $30.0 million of units to each of TA Power and TransAlta Energy Corporation (TEC) and the issue of an advance to TEC for $30.0 million. We recorded
a gain of $17.7 million ($11.5 million) or $0.06 per common share on an after-tax basis.

Sale of TransAlta Power UnitsOn Dec. 3, 2004, we sold our remaining 7.1 million units of TA Power at $9.00 each for net proceeds of $64.0 million, resulting in a gain of $20.6 million ($13.4 million) including a dilution gain of
$11.6 million. We purchased these units in connection with our sale of the Sheerness Generating Station to TA Cogen in 2003.

Summerview Wind FarmIn the third quarter of 2004, we commissioned the 68 MW Summerview wind farm.

|36         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
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Prior Period Regulatory DecisionAt Dec. 31, 2000, we provided US$28.8 million to account for potential refund liabilities relating to energy sales in California. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative
Law Judge issued proposed findings of fact that recommended we refund US$9.0 million for electricity sales made to the California Independent System Operator (CAISO) and US$13.0 million for electricity sales made to the California Power
Exchange (CALPX). In March 2003, FERC ordered the CAISO to review reference power and gas prices that are used to determine mitigated market clearing prices and refund obligations. On March 17, 2004, the CAISO released its preliminary adjusted
prices. Based on these prices, the estimated refund liability we owed was US$46.0 million, being US$27.6 million to the CAISO, US$17.9 million to the CALPX and US$0.5 million to the Automated Power Exchange. Therefore, in March 2004,
we recorded an additional pre-tax provision of US$17.2 million (Cdn$22.9 million). The after-tax impact was Cdn$14.9 million. The final adjusted prices were released in October 2004 and were substantially the same as those released on
March 17, 2004.

FERC provided us with an opportunity to petition for relief from refund obligations. To be successful in such a petition for relief we were required to demonstrate that, as a result of the refund methodology, we
suffered operating losses in respect of California transactions during the refund period. On Aug. 8, 2005, FERC issued an order detailing the methodology for a petition for relief from refund obligations. TransAlta prepared a petition for relief
from the refund obligation and filed it with FERC. The CAISO and CALPX reviewed and commented on our petition and TransAlta replied to the CAISO and CALPX comments on Oct. 17, 2005. On Jan. 26, 2006, FERC conditionally accepted TransAltas
petition for relief, subject to modification. This revised compliance filing was due on Feb. 10, 2006. The outcome of this filing cannot be determined at this time. We will account for this only at the time that it is obtained from FERC.

The impact of prior period regulatory decisions relating to prior reporting periods are recorded when the effect of such decisions are known, without adjustment to the financial statements of prior periods.

2006 OUTLOOKThe following factors will be influenced by, but not limited to, certain risks and uncertainties. For further discussion, see Risk Factors and Risk Management in this MD&A.

Production, Availability and Capacity
Based on our current operations, production capacity in 2006 is expected to be similar to 2005.

For 2006, we expect production to increase as a result of a full year of production from Genesee 3, Poplar Creek and unit four of the Wabamun plant. Availability is expected to increase slightly due to reduced planned
maintenance primarily at our gas facilities.

Heavy rainfall in the Pacific Northwest experienced early in 2006 is affecting Centralia mine operations and power production in the short term. The impact of the abnormal rainfall on our ability to deliver coal to the
plant to produce electricity is being partially offset by increasing coal imports, de-rating the plant when required, purchasing replacement power and running Centralia Gas when economically feasible. We are anticipating between 650 GWh to 950 GWh
of lower production at the Centralia coal-fired plant during the first quarter of 2006.

Exposure to volatility in electricity prices and spark spreads is substantially mitigated through firm-price, long-term electricity sales contracts and hedging arrangements. For 2006, approximately 83 per cent of
output is contracted, of which a significant portion relates to the Alberta PPAs, which are based on achieving specified availability rates. TransAlta continues to manage future price exposure as market liquidity exists.

Our existing production contracts have remaining terms ranging from one to 30 years with a weighted average remaining term of 12 years. Contracted production, as a percentage of potential production from existing
assets, is shown for the next five years in the chart to the right.

If certain plants do not meet the availability or production targets specified in the PPAs or other long-term contracts, then the corporation must either compensate the purchaser for the loss in the availability of
production or suffer a reduction in electrical or capacity payments. Consequently, an extended outage could have a material adverse effect on the business, financial condition, results of operations or cash flows of the corporation.

Production and gross margins from our merchant gas plants are subject to the changes in spark spreads discussed in the Power Prices section. TransAlta has not entered into fixed commodity contracts for gas for these
merchant plants as gas will be purchased coincident in markets where spark spreads are adequate to profitably produce and sell electricity.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         37
| | ---------------------------------------------------

---

Power PricesElectricity spot prices for 2006 are expected to be comparable to those experienced in 2005 in all markets. Our assumption is that 2006 gas prices will be similar to those achieved in 2005. Alberta and the Pacific
Northwest markets should see minimal supply additions and good demand growth. Average hydro reservoir levels in the Pacific Northwest should keep power prices in both markets relatively unchanged year over year. In Ontario, additional nuclear supply
should offset organic demand growth and leave prices and heat rates comparable year over year. Warm weather conditions during the summer could also impact demand. Overall, in 2006, spark spreads should remain relatively unchanged across all markets
relative to 2005.

Spark spreads may not be completely correlated to natural gas prices due to the type and composition of generation that exists in the respective markets. Lower spark spreads are forecast to continue in Alberta and
Ontario, while spark spreads are expected to remain relatively steady in the Pacific Northwest in 2006.

Fuel CostsMining coal is subject to cost increases due to inflation and diesel commodity prices, which the corporation seeks to mitigate through diesel hedges. Seasonal variations in coal mining are minimized through the
application of standard costing.

The coal mines continue to be exposed to increasing input costs, higher amounts of overburden being removed and mining operations moving further away from the power plants. We expect these conditions to continue at
Centralia until new areas of the mine are opened.

Exposure to gas costs for facilities under long-term sales contracts are minimized to the extent possible through long-term gas purchase contracts or corresponding offsets within revenues. Merchant gas facilities are
exposed to the changes in spark spreads, discussed in the Power Prices section above. TransAlta has not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased coincident with spot pricing.

OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per MWh in 2006 are expected to be consistent with 2005.

Capital and Maintenance ExpendituresCapital expenditures for 2006 are expected to be approximately $260 million to $275 million (excluding Mexico), of which approximately $110 million will be spent on major maintenance (excluding CE
Generation LLC (CE Gen)) and $45 million will be spent on the Alberta and Centralia mines. The remainder will be spent at CE Gen and on productivity-related investments. Financing for these expenditures is expected to be provided by cash flow
from operating activities.

Planned MaintenanceDuring 2006, we expect to spend between $165 million and $185 million on planned maintenance as outlined in the following table (excluding CE Gen):

Coal
	Gas and hydro
	TotalCapitalized
	$ 7075
	$
	3035
	$100110Expensed
	6570
	
	05
	6575$135145
	$
	3040
	$165185GWh lost
	2,2502,300
	
	200225
	2,4502,525


We also expect to lose approximately 2,500 GWh of production due to planned maintenance during 2006.

|38         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
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Energy MarketingEnergy Marketings trading activities are focused on real-time and short-term forward markets. Short-term forward markets show indications of increased volatility in the North American natural gas market. We will
continue to prudently manage our risk profile utilizing value at risk (VAR) and other measures.

Our objective is for proprietary trading to contribute between $20 million and $40 million in annual operating income. In 2005, our Energy Marketing segment contributed $31.4 million of operating income
(2004  $8.1 million). Included in 2004 operating income is $22.9 million of provisions related to a prior period regulatory decision.

Net Interest ExpenseNet interest expense for 2006 is expected to decline slightly compared to 2005 as a result of lower debt levels.

Income Tax RateIncome tax rates in 2006 are expected to be consistent with 2005 levels. Assuming a similar geographic distribution of earnings and no material changes in tax rates, the corporation anticipates an effective tax rate
for 2006 to be between 25 and 30 per cent.

Non-controlling InterestsEarnings attributable to non-controlling interests are expected to be slightly higher in 2006 due to lower depreciation charges as a result of the impairment of the Ottawa plant. Cash distributions are expected to be
similar to 2005 levels.

Cash RequirementsIn 2006, cash will be provided by a combination of cash flow from operations and utilization of various credit facilities. Cash will be required for maintenance, additions to PP&E, dividend payments and repayment
of short-term and maturing senior debt.

Liquidity and Capital ResourcesWith the increased volatility in power and gas markets, market trading opportunities are expected to increase, which can potentially cause the need for additional liquidity. To mitigate this liquidity risk, the
corporation maintains $1.8 billion of credit facilities and monitors exposures to determine any liquidity requirements.

Climate ChangeWe are positioning the company to meet the requirements of a Canadian climate change program should one be implemented by the Canadian Government. In addition to increasing production from renewable sources, we will
manage climate change regulations through the continued investment in emission offset credits, development of clean coal technology, and internal efficiency improvements. We have reduced our worldwide greenhouse gas intensity by 11 per cent from
1990 levels while increasing our generating capacity by over 77 per cent. We also have a longer-term strategy to seek emission reduction opportunities as our existing plants are retired and as new combustion and environmental technology is developed
to further reduce emissions.

As Canadas climate change program is not clear, we are not yet able to estimate the impact on our operations. However, the PPAs for our coal-fired plants in Alberta contain Change of Law provisions
that will provide for the recovery of compliance costs from our PPA customers.

The Kyoto Protocol is not expected to impact our U.S., Mexican or Australian operations.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         39
| | ---------------------------------------------------

---

SEGMENTED BUSINESS RESULTS

GenerationOwns and operates hydro, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the United
States, and Australia. At Dec. 31, 2005, Generation had 8,339 MW of gross generating capacity in operation (7,937 MW net ownership interest) and 540 MW under development.

TransAlta has strategic alliances with EPCOR, ENMAX Corporation (ENMAX) and MidAmerican Energy Holdings Company (MidAmerican). The EPCOR alliance provided the opportunity for TransAlta to acquire a 50 per cent
ownership in the 450 MW Genesee 3 project. TransAlta and ENMAX each own 50 per cent of the partnership in the McBride Lake wind farm. MidAmerican owns the other 50 per cent interest in CE Gen.

The results of the Generation segment were as follows:

2005
	
	
	2004
	
	
	2003Year ended Dec. 31
	Total
	Per MWh
	Total
	
	Per MWh
	Total
	
	Per MWh(Restated, Note 1)
	
	(Restated, Note 1)Revenues
	$ 2,607.5
	$ 50.33
	$ 2,341.7
	$
	45.56
	$ 2,304.8
	$
	44.74Fuel and purchased power
	(1,201.8)
	(23.20)
	(1,031.7)
	
	(20.07)
	(990.8)
	
	(19.23)Gross margin
	1,405.7
	27.13
	1,310.0
	
	25.49
	1,314.0
	
	25.51Operations, maintenance and administration
	507.1
	9.79
	476.0
	
	9.26
	461.5
	
	8.96Depreciation and amortization
	354.9
	6.85
	343.5
	
	6.68
	312.4
	
	6.06Taxes, other than income taxes
	21.3
	0.41
	20.5
	
	0.40
	22.9
	
	0.45Operating expenses
	883.3
	17.05
	840.0
	
	16.34
	796.8
	
	15.47Gain on sale of Meridian cogeneration facility
	
	
	17.7
	
	0.34
	
	
	Gain on sale of TransAlta Power partnership units
	
	
	44.8
	
	0.87
	15.2
	
	0.30Gain on sale of Sheerness Generating Station
	
	
	
	
	
	191.5
	
	3.72Gain on sale of Seebe land
	
	
	
	
	
	10.5
	
	0.20Asset impairment charges
	(36.2)
	(0.70)
	
	
	
	(90.3)
	
	(1.76)Operating income before corporate allocations
	486.2
	9.38
	532.5
	
	10.36
	644.1
	
	12.50Corporate allocations
	(76.4)
	(1.47)
	(69.7)
	
	(1.36)
	(69.9)
	
	(1.36)Operating income
	$ 409.8
	$ 7.91
	$ 462.8
	$
	9.00
	$ 574.2
	$
	11.14Production (GWh)
	51,810
	
	51,396
	
	
	51,519Availability (%)
	89.4%
	
	89.2%
	
	
	90.5%


For the year ended Dec. 31, 2005, our availability was marginally improved at 89.4 per cent compared to 89.2 per cent in 2004, and lower than the 90.5 per cent recorded in 2003. The higher availability in 2003 was a
result of higher availability at our Poplar Creek and Centralia facilities.

For the year ended Dec. 31, 2005, 82 per cent of our total production was subject to contracted prices (2004  83 per cent, 2003  91 per cent), with the remaining production subject to market pricing.
Revenues received under contractual arrangements are not subject to short-term fluctuations in the spot price for electricity.

Generations revenues are derived from the production of electricity and steam as well as ancillary services such as system support. In 2005, gas- and coal-fired facilities had exposure to market fluctuations in
energy commodity prices representing 29 per cent and 4 per cent of our total generating capacity, respectively. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various
physical and financial instruments to hedge our assets and operations from such price risk. These contracts are designated as effective hedge positions of future cash flows or fair values of the output and production of our owned assets. Under
Canadian GAAP, settlement accounting is used for transactions that qualify for hedge accounting. Under U.S. GAAP, hedging activities are accounted for in accordance with Financial Accounting Standards Board (FASB) Statement 133.

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

|40         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

Generation segment revenues are generated from the following revenue streams:

Alberta PPAsare long-term arrangements that apply to the previously regulated Alberta generation plants. Under the terms of a PPA, a single customer has the rights
to the entire production of a plant or unit for the length of the PPA. All of our Alberta coal-fired and hydroelectric facilities operated under PPAs during 2005, except for the Wabamun and Genesee 3 plants. The PPA for the Wabamun plant expired on
Dec. 31, 2003.

PPAs establish committed capacity and electrical energy generation requirements and availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants,
and the pricing formula at which capacity and power would be supplied. We bear the risk or retain the benefit of volume variances (except for those arising from events considered to be force majeure), and any change in costs required to maintain and
operate the facilities. A component of the PPA capacity payment represents fixed operating, maintenance and fuel costs and is escalated annually based on certain indices published by Statistics Canada. The component of the capacity payment
representing debt interest and a return on equity invested is subject to changes in the Canadian long-term bond rate.

Under the PPAs, we earn monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for our plants and mines. We also earn energy payments for the recovery of predetermined
variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability and an excess energy payment for power production above committed capacity.

Our hydroelectric facilities are contracted in a single Alberta PPA that provides for energy and ancillary services revenues based on hourly targets. These targeted amounts are met by TransAlta through physical
delivery or third party purchases.

Long-term contractsare similar to PPAs. We define a long-term contract as having an original term between 10 and 25 years. Long-term contracts are typically for
gas-fired cogeneration plants and have between one and four customers per plant. Revenues are derived from payments for capacity and/or the production of electrical energy and steam.

Merchantrevenue is derived from the sale of production only, with multiple customers per plant. Production is sold via: medium-term contract sales (typically two
to 10 years); short-term asset-backed trading; and spot or short-term (less than one year) forward markets.

CE Genearns revenues from 10 geothermal plants and three gas-fired facilities. Eight of the geothermal plants sell their output under long-term contracts expiring
between 2016 and 2035. One facility is partially contracted while the remaining facility sells its output on the spot market but has an option to sell output under a 35-year contract based on market prices. The gas-fired facilities sell their output
under fixed-price contracts ranging from three to 18 years of remaining contract life, with expiration dates of 2009 and 2024. All three facilities have gas supply arrangements in place for the duration of the electricity sales contracts.

Our production volumes, electricity and steam production revenues and fuel and purchased power costs are presented below:

Fuel &Fuel &
	
	
	purchased
	GrossProduction
	
	purchased
	Gross
	Revenue
	power
	marginYear ended Dec. 31, 2005
	(GWh)
	Revenue
	power
	margin
	per MWh
	per MWh
	per MWhAlberta PPAs
	25,279
	$ 682.1
	$ 201.6
	$ 480.5
	$ 26.98
	$ 7.97
	$ 19.01Long-term contracts
	6,947
	647.9
	392.7
	255.2
	93.26
	56.53
	36.73Merchant
	16,630
	983.2
	535.2
	448.0
	59.12
	32.18
	26.94CE Gen
	2,954
	294.3
	72.3
	222.0
	99.63
	24.48
	75.1551,810
	$ 2,607.5
	$ 1,201.8
	$ 1,405.7
	$ 50.33
	$ 23.20
	$ 27.13Fuel &Fuel &
	
	
	purchased
	GrossProduction
	
	purchased
	Gross
	Revenue
	power
	marginYear ended Dec. 31, 2004 (Restated, Note 1)
	(GWh)
	Revenue
	power
	margin
	per MWh
	per MWh
	per MWhAlberta PPAs
	25,836
	$ 679.2
	$ 187.9
	$ 491.3
	$ 26.29
	$ 7.27
	$ 19.02Long-term contracts
	7,183
	581.9
	341.9
	240.0
	81.01
	47.60
	33.41Merchant
	15,676
	799.5
	435.2
	364.3
	51.00
	27.76
	23.24CE Gen
	2,701
	281.1
	66.7
	214.4
	104.07
	24.69
	79.3851,396
	$ 2,341.7
	$ 1,031.7
	$ 1,310.0
	$ 45.56
	$ 20.07
	$ 25.49


| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         41
| | ---------------------------------------------------

---

Fuel &Fuel &
	
	
	purchased
	GrossProduction
	
	purchased
	Gross
	Revenue
	power
	marginYear ended Dec. 31, 2003(Restated, Note 1)
	(GWh)
	Revenue
	power
	margin
	per MWh
	per MWh
	per MWhAlberta PPAs
	28,295
	$ 758.8
	$ 191.3
	$ 567.5
	$26.82
	$ 6.76
	$ 20.06Long-term contracts
	6,923
	552.8
	324.2
	228.6
	79.85
	46.83
	33.02Merchant
	13,683
	684.2
	394.9
	289.3
	50.00
	28.86
	21.14CE Gen
	2,618
	309.0
	80.4
	228.6
	118.03
	30.71
	87.3251,519
	$ 2,304.8
	$ 990.8
	$ 1,314.0
	$ 44.74
	$ 19.23
	$ 25.51


Production for the year ended Dec. 31, 2004 decreased by 2,459 GWh compared to 2003, primarily due to the Wabamun plant now being classified as merchant (2,940 GWh) and higher unplanned outages at the remaining Alberta
Thermal plants (168 GWh), partially offset by reduced planned maintenance (642
GWh).

Revenues for 2005 were essentially flat compared to 2004, as the higher pricing experienced in 2005 was offset by the net penalties paid during both planned and unplanned outages.

Revenues for the year ended Dec. 31, 2004 decreased by $79.6 million compared to the same period in 2003 due to the Wabamun plant now being classified as merchant ($92.2 million) and by higher unplanned outages
($34.2 million), partially offset by reduced penalties related to planned maintenance at the remaining Alberta Thermal plants ($53.0 million).

On a per MWh basis, revenues were consistent between 2005, 2004 and 2003.

Our fuel cost per MWh increased $0.70 to $7.97 per MWh in 2005. This increase is primarily a result of escalations in diesel pricing related to mine operations, the majority of which is ultimately recovered
from our PPA customers through escalation mechanisms in the PPAs.

For the year ended Dec. 31, 2004, fuel costs increased by $0.51 per MWh compared to the same period in 2003 due to higher diesel prices, increased overburden removal costs and decreased coal volumes. Substantially
all of the coal used for production under Alberta PPAs is from coal reserves owned by TransAlta.

Long-term ContractsLong-term contract volumes declined 236 GWh to 6,947 GWh in 2005 due to planned maintenance and reduced customer demand at certain of our gas-fired facilities. In the year ended Dec. 31, 2004, production increased by
260 GWh compared to the same period in 2003 due to increased production at Sarnia and our wind farms and lower unplanned outages at the Mississauga, Ottawa and Windsor-Essex plants.

In 2005, our revenue per MWh increased $12.25 per MWh. Higher natural gas prices drove fuel and purchased power per MWh to $56.53, an increase of $8.93 per MWh, and had a positive impact on our realized
electricity prices.

Revenues increased by $1.16 per MWh in 2004 compared to 2003, primarily due to increased natural gas costs that were passed on to the customer. Fuel and purchased power increased by $0.77 per MWh due to higher
market prices for natural gas.

On an overall basis, our margins increased $15.2 million in 2005 due to increased thermal volumes at Sarnia and revised contract pricing at some of our gas plants. On a per MWh basis, margins increased
$3.32.

For the year ended Dec. 31, 2004, gross margin increased by $11.4 million compared to the same period of 2003, primarily due to increased indices at Australia. On a per MWh basis, a modest increase of $0.39 was
realized.

Merchant ProductionRecord high natural gas prices in 2005 had a favourable impact on pricing and spark spreads in all regions. In 2004, electricity spot prices in the Alberta and Ontario markets decreased while the Mid-Columbia price
increased compared to 2003. Spark spreads decreased in 2004 compared to 2003 in both Alberta and the Ontario markets, but increased in the Pacific Northwest market.

Merchant production increased 954 GWh to 16,630 GWh due to the commissioning of Genesee 3, increased hydro production due to higher rainfall in 2005 and low reservoir levels in 2004 and incremental production from unit
four at our Wabamun plant, which underwent a major maintenance outage in 2004. These increases were partially offset by the lost production

|42         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

due to the CN train derailment, the decommissioning of units one and two of our Wabamun plant and reduced customer demand and major maintenance at Poplar Creek.

For the year ended Dec. 31, 2004, merchant production was 15,676 GWh, of which 6,718 GWh was contracted. For the same period in 2003, merchant production was 13,683 GWh, of which 8,996 GWh was contracted. The increase
was due to the PPA at our Wabamun plant expiring in 2003 and the production from this facility being sold on the merchant market and incremental production from Sarnia in the first quarter, partially offset by decreased production at Centralia and
lower dispatching from the merchant gas plants.

Merchant revenues were significantly impacted by increases in natural gas prices in 2005. The combination of this price impact and increased production drove revenues $183.7 million higher in 2005. Offsetting this
in gross margins is the impact of rising costs of fuel and purchased power of $100.0 million. The net impact on our margins was $83.7 million. The commissioning of Genesee 3, incremental margins from unit four of Wabamun, net of the CN train
derailment, increased hydro production and pricing and recontracting at our Centralia coal-fired facility were partially offset by the decommissioning of units one and two at Wabamun. At our Centralia coal-fired facility, higher pricing had a
favourable impact on revenues, however, the impact of diesel escalations, tire shortages and delays in permitting had a negative impact on fuel and purchased power. Merchant revenues increased to $59.12 per MWh from $51.00 in 2004. On a per
MWh basis, fuel and purchased power increased from $27.76 to $32.18 in 2005.

In 2004, merchant revenues increased by $115.3 million, fuel and purchased power increased by $40.3 million and gross margins increased by $75.0 million compared to the same period in 2003. These gross
margin increases were due to incremental production from the Wabamun plant partially offset by lower production and shrinking spark spreads at Centralia and Poplar Creek. Merchant revenues increased by $1.00 per MWh while fuel and purchased
power decreased by $1.10 per MWh compared to the same period in 2003.

CE GenDuring 2005, production from CE Gen increased by 253 GWh to 2,954 GWh due primarily to increased availability from the Imperial Valley and Saranac facilities. As a result, revenues and cost of fuel also increased. On a
per MWh basis, however, the impact of the devaluation of the U.S. dollar relative to the Canadian dollar drove revenue per MWh to $99.63 from $104.07 and cost of fuel and purchased power to $24.48 from $24.69.

TransAltas share of CE Gens production for 2004 increased by 83 GWh compared to 2003. This was the result of increased availability due to reduced planned maintenance and increased production at Imperial
Valley partially offset by decreased production at the Power Resources facility following the expiration of the long-term contract in September 2003.

In 2004, revenues decreased by $13.96 per MWh compared to the same period in 2003 due to the expiration of the Power Resources facilitys long-term contract and the strengthening of the Canadian dollar
compared to the U.S. dollar. In 2004, fuel and purchased power decreased by $6.02 per MWh compared to the same period in 2003 primarily due to the gas remarketing arrangement at the Saranac plant in the first quarter of 2004 and the
strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased fuel prices at the Yuma and Saranac facilities in 2004.

OM&A ExpenseOur OM&A costs increased $31.1 million or $0.53 per MWh, in 2005 to $507.1 million or $9.79 per MWh, due to the addition of Genesee 3, certain cost escalations that pass through to our customers
under the PPAs, increased compensation costs related to incentives and cost escalations related to materials.

For the year ended Dec. 31, 2004 OM&A increased by $14.5 million ($0.30 per MWh) due in part to incremental operating costs related to our Sarnia plant. Additionally, in 2003, OM&A costs were reduced as
a result of the reversal of a pension over-accrual and a decrease in expected performance share ownership plan payouts due to market conditions.

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

|            |   | 2005  |                                       | 2004  |   | 2003 
|----------- | - | ----- | ------------------------------------- | ----- | - | -----
|            |   |       | (Restated, Note 1) (Restated, Note 1)
|Capitalized | $ | 119.1 | $                                     | 88.1  | $ | 35.2 
|Expensed    |   | 68.3  |                                       | 73.0  |   | 76.1 
|            | $ | 187.4 | $                                     | 161.1 | $ | 111.3



| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         43
| | ---------------------------------------------------

---

The increase in capitalized maintenance of $31.0 million in 2005 relates to the completion of four C inspections completed on our gas units during the year.

In 2004, capitalized maintenance increased by $52.9 million while operating maintenance decreased by $3.1 million as compared to the same period in 2003 due to spending on capital replacement activities rather
than repair activities in coal outages and gas outages with no comparable amounts in 2003 for gas outages due to recent additions to the gas fleet.

Annually, we purchase long lead materials for future years outages as lead times on these items can extend well beyond one year. In 2005, $6.2 million was spent on such items, compared to $19.8 million in
2004. These items are not included in the planned maintenance chart.

Depreciation and Amortization

Depreciation and amortization increased by $11.4 million in 2005 due to the addition of Genesee 3 and equipment retired during planned maintenance activities.

In 2004, depreciation expense increased by $31.1 million, primarily due to incremental depreciation from our Sarnia plant, increased depreciation from CE Gen, increased depreciation from our Ottawa, Mississauga and
Windsor-Essex plants and increased capital spending on planned maintenance.

Taxes Other than Income Taxes

In 2005, taxes other than income taxes were consistent with both 2004 and 2003.

Energy MarketingDerives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and
derivatives not supported by TransAlta-owned generation assets. Energy Marketing also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available
generating capacity and fuel and transmission needs on behalf of Generation. These results are included in the Generation segment. Key performance indicators for Energy Marketings proprietary trading include trading volumes, margins and
VAR.

Energy Marketing is vital to delivering sustainable revenues. Energy Marketing acts to maximize margins from the production and sale of electricity, minimize the cost of natural gas used to generate electricity and
steam and reduce the risk to the corporation from unplanned outages by acquiring replacement power at the lowest possible price.

Energy Marketing uses commodity derivatives to manage risk, earn trading revenue and gain market information. The portfolio consists of physical and financial derivative instruments including forwards, swaps, futures
and options in various commodities. These contracts meet the definition of trading activities and have been accounted for using fair values for both Canadian and U.S. GAAP. Changes in the fair values of the portfolio are recognized in income in the
period they occur.

In compliance with FASB Emerging Issues Task Force (EITF) 03-11,
Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement 133, Accounting
for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes
as defined in Issue No. 02-3, we have concluded that energy trading contracts settled in the real-time physical markets
meet the definition of derivative contracts held for delivery and therefore revenues from these contracts are reported on a gross basis (trading revenues and trading purchases are shown separately) in the consolidated statement of
earnings.

The results of the Energy Marketing segment are as follows:

Year ended Dec. 31
	
	2005
	
	2004
	
	2003Revenues
	$
	231.0
	$
	244.5
	$
	108.7Trading purchases
	
	(174.1)
	
	(197.7)
	
	(97.4)Gross margin
	
	56.9
	
	46.8
	
	11.3Operations, maintenance and administration
	
	12.5
	
	5.3
	
	14.9Depreciation and amortization
	
	1.7
	
	2.0
	
	3.1Prior period regulatory decision
	
	
	
	22.9
	
	Operating income before corporate allocations
	
	42.7
	
	16.6
	
	(6.7)Corporate allocations
	
	(11.3)
	
	(8.5)
	
	(8.8)Operating income
	$
	31.4
	$
	8.1
	$
	(15.5)


Gross margins increased $10.1 million in 2005 due primarily to strong results from trading activities in our Western region and gains on our gas positions throughout the year.

|44         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

Gross margin increased by $35.5 million in 2004 compared to the same period in 2003. In the second quarter of 2003, Energy Marketing realized a $33.3 million (US$20.0 million) pre-tax loss on
TCCs.

As a result of the increased margins generated during 2005, our OM&A costs have increased due to higher incentive compensation costs as well as project consulting expenses incurred during the year.

A $9.6 million reduction in OM&A was realized in 2004 compared to 2003 as we consolidated our Annapolis office with Calgary, resulting in lower staffing levels.

Depreciation and amortization was relatively consistent with 2004. The reduction in 2004 over 2003 is a result of the closure of the Annapolis office.

VAR is a measure to manage earnings exposure for Energy Marketing activities. The average daily VAR in fiscal 2005 was approximately $3.6 million compared to $3.8 million in 2004. See additional discussion
under commodity price risk in Risk Factors and Risk Management.

At Dec. 31, 2005, we had a US$51.4 million receivable relating to energy sales in California. As previously discussed in Significant Events, a provision of US$28.8 million to account for potential refund
liabilities was recorded in December 2000. On March 17, 2004, the CAISO released its preliminary adjusted prices indicating that our refund liability is now US$46.0 million. Based on these preliminary refund estimates, in the first quarter of
2004 we increased our provision for potential refund liabilities by US$17.2 million (Cdn$22.9 million) to US$46.0 million. The final adjusted prices were released in October 2004 and were substantially the same as those released on March
17, 2004. Based on an Aug. 8, 2005 FERC order, TransAlta prepared a petition for relief from the refund obligation and filed it with FERC. On Jan. 26, 2006, FERC conditionally accepted TransAltas petition for relief, subject to modification.
This revised compliance filing was due on Feb. 10, 2006.

TransAltas fixed price trading positions were as follows:

|                                                      | Electricity | Natural gas
|----------------------------------------------------- | ----------- | -----------
|Units (000s)                                          | (MWh)       | (GJ)       
|Fixed price payor, notional amounts, Dec. 31, 2005    | 19,315      | 11,126     
|Fixed price payor, notional amounts, Dec. 31, 2004    | 14,029      | 13,422     
|Fixed price receiver, notional amounts, Dec. 31, 2005 | 19,047      | 12,158     
|Fixed price receiver, notional amounts, Dec. 31, 2004 | 13,558      | 12,277     
|Maximum term in months, Dec. 31, 2005                 | 24          | 12         
|Maximum term in months, Dec. 31, 2004                 | 24          | 12         



Proprietary trading encompasses a range of contractual terms spanning from short-term speculative trading of one to 24 months to longer-term marketing transactions with potential terms greater than 24 months. Changes
in trading positions from Dec. 31, 2004 to Dec. 31, 2005 are due to changing market conditions and corresponding regional strategy positioning.

Gross physical and financial settled sales of proprietary trading transactions are as follows:

|Year ended Dec. 31 |         |        |       
|------------------ | ------- | ------ | ------
|Electricity (GWh)  | 2005    | 2004   | 2003  
|Physical           | 58,016  | 61,165 | 55,506
|Financial          | 57,666  | 23,239 | 34,327
|                   | 115,682 | 84,404 | 89,833
|Year ended Dec. 31 |         |        |       
|Gas (million GJ)   | 2005    | 2004   | 2003  
|Physical           | 86.9    | 122.4  | 100.1 
|Financial          | 326.9   | 308.0  | 170.1 
|                   | 413.8   | 430.4  | 270.2 

In 2005, the emergence of additional counterparties in the financial markets greatly increased market liquidity and thus our financial volumes of electricity and gas increased considerably over 2004. Our trading
activities continue to be subject to the prudent controls and procedures they have been subject to in prior years, as described in Commodity Price Risk on page 56 of this MD&A.

Physical electricity volumes were consistent with those in 2004. Fluctuations in physical gas volumes traded are a result of price volatility in 2005.

In 2004, financial electricity volumes were lower than the same period in 2003 due to the elimination of trading in New York TCCs in 2003. Physical electricity volumes were higher in 2004 compared to the same period in
2003 due to the

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         45
| | ---------------------------------------------------

---

development of Eastern region real-time markets. Our power trading strategies consist of shorter-term physical and financial trades in regions where we have assets and the markets that interconnect with those
regions.

In accordance with EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities, physical transmission and physical gas in storage are accounted for using accrual accounting. At Dec. 31, 2005, TransAlta recorded prepaid transmission contract assets of $0.8 million
compared to approximately $1.5 million at Dec. 31, 2004. The transmission contracts relate to the period from April 2005 to March 2006 and are amortized over this period. Physical transmission is widely used in the California market with a
maximum contract term of 12 months. At Dec. 31, 2005, physical gas in storage was recorded at $5.2 million. Forward power and gas transactions utilizing physical transmission and gas in storage are accounted for on a mark-to-market basis. While
the physical and forward positions economically offset, some unrealized earnings exposure may result in the interim period prior to settlement.

PRICE RISK MANAGEMENTOur price risk management assets and liabilities represent the value of unsettled (unrealized) proprietary trading transactions and certain asset backed trading transactions accounted for on a fair value basis. With
the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All transmission
contracts are accounted for in accordance with EITF 02-03. The following tables show the balance sheet classifications for price risk management assets and liabilities as well as the changes in the fair value of the net price risk management assets
for the period:

Year ended Dec. 31
	
	2005
	
	2004Balance SheetPrice risk management assetsCurrent
	$
	63.8
	$
	41.9Long term
	
	13.8
	
	11.3Price risk management liabilitiesCurrent
	
	(58.3)
	
	(27.7)Long term
	
	(8.6)
	
	(10.0)Net price risk management assets outstanding
	$
	10.7
	$
	15.5


Fair valueChange in fair value of net assetsNet price risk management assets outstanding at Dec. 31, 2004
	$
	15.5Contracts realized, amortized or settled during the year
	
	(24.4)Changes in values attributable to market price and other market changes
	
	6.1New contracts entered into during the current calendar year
	
	13.5Net price risk management assets outstanding at Dec. 31, 2005
	$
	10.7


For the year ended Dec. 31, 2005, our net price risk management assets and liabilities decreased $4.8 million compared to the same period in 2004 primarily due to contracts settled during the year offset partially
by new contracts entered in 2005 and value changes associated with contracts in existence at both year ends. Changes in net price risk management assets and liabilities are generally reflected within the gross margin of both Energy Marketing and
Generation business segments.

The source of the valuations of the above contracts and maturities over each of the next five calendar years and thereafter is as follows:

2011 and2006
	
	2007
	
	2008
	
	2009
	
	2010
	thereafter
	
	TotalPrices actively quoted
	$
	1.6
	$
	1.0
	$
	2.1
	$
	1.3
	$
	0.8
	$
	
	$
	6.8Prices based on models
	
	3.9
	
	
	
	
	
	
	
	
	
	
	
	3.9$
	5.5
	$
	1.0
	$
	2.1
	$
	1.3
	$
	0.8
	$
	
	$
	10.7


Our proprietary trading activities are mainly short-term transactions under 24 months in duration, thereby limiting credit risk and maintaining low working capital requirements. Transactions extending past 2006 are
Generation asset-backed contracts that do not qualify for hedge accounting and have a low risk profile including long-term fixed for floating power swaps and a heat rate swap.



|46         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

NET INTEREST EXPENSE

|Year ended Dec. 31                         |   | 2005  |                                       | 2004   |   | 2003  
|------------------------------------------ | - | ----- | ------------------------------------- | ------ | - | ------
|                                           |   |       | (Restated, Note 1) (Restated, Note 1)
|Interest on recourse and non-recourse debt | $ | 184.2 | $                                     | 192.8  | $ | 222.8 
|Interest on preferred securities           |   | 16.5  |                                       | 44.5   |   | 36.8  
|Interest income                            |   | (8.7) |                                       | (9.9)  |   | (4.5) 
|Capitalized interest                       |   | (3.4) |                                       | (20.0) |   | (43.0)
|Net interest expense                       | $ | 188.6 | $                                     | 207.4  | $ | 212.1 

Our net borrowing costs were lower in 2005 than 2004. In the first quarter of 2005, we redeemed $300.0 million of our preferred securities and replaced this with lower interest rate borrowings. Capitalized interest
has been reduced as a result of the commissioning of Genesee 3 in March 2005.

Our 2004 borrowing costs were lower than 2003 due to reductions in overall debt levels and lower interest rates. The interest on preferred securities includes the $7.6 million charge we recognized in 2004 related
to the redemption of the $300.0 million noted above at the time we made the decision to redeem these securities. Capitalized interest decreased in 2004 due to the commencement of operations at the Sarnia facility in 2003, offset by interest on
the construction of the Summerview wind farm and Genesee 3. Interest income is primarily from interest earned on deposits with various taxation authorities.

EQUITY LOSS

|Year ended Dec. 31 |   | 2005  |   | 2004  |   | 2003 
|------------------ | - | ----- | - | ----- | - | -----
|Equity loss        | $ | (0.9) | $ | (8.5) | $ | (6.0)

As discussed in the New Accounting Standards section of this MD&A on page 61, we no longer consolidate the results of our Mexican plants, Campeche and Chihuahua.

The equity loss realized on the Mexican plants declined from $8.5 million in 2004 to $0.9 million in 2005. Capacity payments increased in 2005 compared to 2004 as a result of lower unplanned outages at the
Chihuahua facility. Production, however, declined by approximately 13 per cent as production at the Chihuahua plant was curtailed at the request of the Comisión Federal de Electricidad (CFE). The curtailment of production does not
significantly impact earnings as gas costs are passed through to the CFE and we continue to receive our capacity payments. The devaluation of the U.S. dollar compared to the Canadian dollar partially offset the benefit of the higher availability.
Interest expense on the non-recourse debt at the Campeche facility declined due to scheduled debt repayments.

The equity loss increased from $6.0 million in 2003 to $8.5 million in 2004 as a result of a full year of interest expense related to the non-recourse debt at the Campeche facility and a full year of
depreciation expense at both facilities, which were commissioned in 2003.

INCOME TAXES

|Year ended Dec. 31     |   | 2005 |   | 2004 |   | 2003
|---------------------- | - | ---- | - | ---- | - | ----
|Income tax expense     | $ | 47.4 | $ | 49.1 | $ | 64.3
|Effective tax rate (%) |   | 20.2 |   | 23.4 |   | 21.5

Income tax expense for 2005 was $47.4 million, consistent with 2004. Included in income tax expense is $13.0 million related to a favourable settlement of outstanding disputes with income tax authorities.
Included in income tax expense for 2004 is $6.8 million related to a tax settlement at our New Zealand operations. Income tax expense for 2003 includes the impact of the taxation on the sale of the Sheerness Generating Station, the recognition
of deferred gain and impairment charges. Adjusting for these items, our effective income tax rate was 26 per cent for 2005, compared to 27 per cent in 2004 and 29 per cent in 2003.

We constantly monitor our outstanding tax positions and are in regular contact with various income tax authorities.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         47
| | ---------------------------------------------------

---

NON-CONTROLLING INTERESTS

|Year ended Dec. 31        |   | 2005 |   | 2004 |   | 2003
|------------------------- | - | ---- | - | ---- | - | ----
|Non-controlling interests | $ | 18.5 | $ | 46.0 | $ | 34.2

Included in non-controlling interests in 2005 is a $36.2 million recovery related to the impairment of the Ottawa facility that is attributable to the non-controlling interests. Adjusting for this amount,
non-controlling interests increased to $54.7 million. The increase is attributable to our disposition of our remaining 7.1 million units of TA Power, acquired on the disposition of the Sheerness Generating Station to TA Cogen in 2003.

The $11.8 million increase in non-controlling interests from 2003 to 2004 is a result of the disposition of the Sheerness Generating Station to TA Cogen in the third quarter of 2003.

CONSOLIDATED BALANCE SHEETS

The following chart outlines significant changes in the consolidated balance sheets between Dec. 31, 2005 and Dec. 31, 2004:

Increase/(decrease)
	ExplanationCash and cash equivalents
	$
	(21.9)
	Refer to Consolidated Statements of Cash Flows.Accounts receivable
	
	170.9
	Increased Energy Marketing trading and increasedGeneration and CE Gen activity mainly due to increasedprices and incremental revenues from Genesee 3.Price risk management assets (current)
	
	21.9
	Fluctuations in the volumes of power contractsreceivable and an increase in prices.Prepaid expenses
	
	23.5
	Increase in deferred stripping costs.Property, plant and equipment,net of accumulated depreciation
	
	(157.1)
	Decrease due to depreciation offset bycapital additions.Intangible assets
	
	(42.5)
	Amortization of the CE Gen sales contracts andchange in foreign exchange rates.Other assets (including current portion)
	
	(289.8)
	Decrease in mark-to-market changes onhedging derivatives.Short-term debt
	
	(21.3)
	Net decrease of short-term debt.Accounts payable and accrued liabilities
	
	147.7
	Increase in trading activity in Energy Marketing,timing of planned maintenance projects andpension accruals.Dividends payable
	
	31.2
	Increase due to timing of payment of dividends.Price risk management liabilities (current)
	
	30.6
	Fluctuations in the volumes of power contractspayable and an increase in prices.Recourse long-term debt (including current portion)
	
	(236.7)
	Repayment of long-term debt, redemption of$300.0 million preferred securities, lower debtbalances due to foreign exchange rate changes,partially offset by $200.0 million bond issue.Non-recourse long-term debt
	
	(59.5)
	Repayment of long-term debt and changes to(including current portion)
	
	
	foreign exchange rates.Deferred credits and other long-term liabilities(including current portion)
	
	(267.1)
	Decrease is mainly due to scheduled maturitiesof net investment hedge contracts.Net Future income tax assets and liabilities(including current portions)
	
	23.3
	Increase in income tax deductions in excess ofrecorded depreciation of PP&E, offset by increasein unused tax losses that are expected to berecovered in future years.Non-controlling interests
	
	(57.8)
	Decrease is due mainly to impairment of theOttawa facility.Shareholders equity
	
	73.1
	Issuance of common shares offset by dividenddeclarations and tax provisions on hedginggains/losses.


|48         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

CONSOLIDATED CASH FLOW STATEMENTS

The following chart outlines significant changes in the consolidated cash flow statements between Dec. 31, 2005 and Dec. 31, 2004:

Year ended Dec. 31
	
	2005
	
	2004
	Explanation(Restated, Note 1)Cash and cash equivalents,beginning of period
	$
	101.2
	$
	123.8Provided by (used in):Operating activities
	
	619.4
	
	591.2
	Increased earnings offset by higher workingcapital requirements.Investing activities
	
	(242.1)
	
	(57.4)
	Net capital expenditures of $323.9 million and anincrease in the Mexican investment were partiallyoffset by realized gains on foreign exchange forwardsand intercompany loans of $90.0 million.In 2004, capital expenditures of $268.1 millionrelating primarily to the construction of theSummerview wind farm, the Genesee 3 project,and major maintenance, partially offset by proceedsfrom the exercise of TA Power warrants ($61.7 million)and the collection of the $90.8 million Zinc Recoverylong-term receivable.Financing activities
	
	(396.3)
	
	(549.3)
	Issuance of $200 million of senior unsecured notes,common share issuances of $20.0 million, and repay-ments on an advance to TA Power of $24.0 millionwere used to fund redemption of preferred securitiesof $300.0 million, repayment of short- and long-termborrowings of $163.0 million, non-controlling interestdistributions of $78.0 million, and dividend paymentsof $99.2 million.In 2004, net repayment of short-term debt of$72.9 million, net repayment of long-term debt of$135.1 million, cash dividends on common sharesof $102.6 million, and non-controlling interestdistributions of $33.5 million.Translation of foreign currency cash
	
	(2.9)
	
	(7.1)Cash and cash equivalents,
	$
	79.3
	$
	101.2end of period


| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         49
| | ---------------------------------------------------

---

The following chart outlines significant changes in the consolidated balance sheets between Dec. 31, 2004 and Dec. 31, 2003:

Year ended Dec. 31
	
	2004
	
	2003
	ExplanationRestated, Note 1
	Restated, Note 1Cash and cash equivalents,beginning of period
	$
	123.8
	$
	137.2Provided by (used in):Operating activities
	
	591.2
	
	474.3
	In 2004, improved non-cash working capital balancesand increased cash earnings.In 2003, increased cash earnings and the collectionof commodity tax receivables in Mexico and theU.S. of US$79.0 million.Investing activities
	
	(57.4)
	
	(315.0)
	In 2004, capital expenditures of $345.7 millionincluding completion of Summerview wind farmand the Genesee 3 plant and major maintenance,partially offset by $116.5 million in proceedsfrom the sale of TA Power partnership units, thecollection of the $90.8 million Zinc Recoverylong-term receivable and $47.8 million in realizedgains on net investment hedges.In 2003, capital expenditures of $434.4 million relatedto the construction of Genesee 3, the acquisition ofCE Gen for $323.4 million (net of cash acquired of$43.2 million), offset by $194.1 million in realized gainson net investment hedges, proceeds on sale of theSheerness plant ($149.9 million), the Goldfields pipeline($21.6 million), the head office building ($65.8 million),the Seebe land ($11.0 million) and exercise of TA Powerwarrants ($37.2 million). The remainder of the cash flowwas primarily related to the reduction of restricted cashFinancing activities
	
	(549.3)
	
	(165.5)
	In 2004, repayment of short-term debt of $85.4 million,net repayment of long-term debt of $282.0 million,cash dividends on common shares of $135.4 millionand minority interest distributions of $48.4 million.In 2003, repayment of short-term debt of$170.2 million, net repayment of long-term debt of$56.5 million, cash dividends on common sharesof $158.3 million (net of dividend reinvestments of$54.6 million) and minority interest distributions of$38.9 million were partially offset by net proceedson the issuance of common shares of $265.0 million.Translation of foreign currency cash
	
	(7.1)
	
	(7.2)Cash and cash equivalents, end of period
	$
	101.2
	$
	123.8


LIQUIDITY AND CAPITAL RESOURCESAt the corporate level, we raise substantially all external capital to be invested in the various business units and affiliated or subsidiary companies as required. This strategy allows us to gain access to sufficient
capital at the lowest overall cost to finance growth opportunities and provide financial flexibility. Historically, external financing has been obtained from borrowings under credit facilities, proceeds from the disposal of non-core assets and the
issuance of debt, preferred securities and equity. Internally, capital is also raised through operations. A summary of cash flows is as follows:

Year ended Dec. 31
	
	2005
	
	2004
	
	2003(Restated, Note 1) (Restated, Note 1)Cash and cash equivalents, beginning of year
	$
	101.2
	$
	123.8
	$
	137.2Cash flow from (used in):Operating activities
	
	619.4
	
	591.2
	
	474.3Investing activities
	
	(242.1)
	
	(57.4)
	
	(315.0)Financing activities
	
	(396.3)
	
	(549.3)
	
	(165.5)Translation of foreign currency cash
	
	(2.9)
	
	(7.1)
	
	(7.2)Cash and cash equivalents, end of year
	$
	79.3
	$
	101.2
	$
	123.8


|50         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

In the first quarter of 2005, we redeemed $300.0 million in preferred securities, which carried an average interest rate of 7.77 per cent. This redemption was financed through short-term borrowings. In the fourth
quarter of 2005, we repaid $83.4 million of long-term debt. This repayment was funded with short-term debt. Also in the fourth quarter, the maturity date of $141.1 million of bonds was extended to 2030 at an interest rate of 6.9 per
cent.

In the fourth quarter of 2005, we issued $200.0 million of two-year, 4.20 per cent senior unsecured notes.

In November 2005, we renewed our $1.0 billion medium-term note shelf registration. We also increased our committed bank credit facility to $1.5 billion from $1.2 billion in July 2003 in order to increase
our liquidity. We maintain approximately $330 million of uncommitted credit facilities. At Dec. 31, 2005, we had approximately $1.2 billion of credit available from our committed and uncommitted credit facilities.

In November 2003, we issued US$300.0 million of 10-year senior notes under a US$1.0 billion shelf registration statement filed May 14, 2002. The notes bear interest at 5.75 per cent per annum. Proceeds from the
issuance were primarily used to refinance bonds that matured in 2003. In July 2004, we renewed this US$1.0 billion shelf registration.

Operating ActivitiesOperating activities after changes in non-cash working capital provided cash of $619.4 million in 2005 compared to $591.2 million in 2004 and $474.3 million in 2003. The increase in 2005 is due primarily to
increased cash earnings. The increase in 2004 is primarily due to increased cash earnings and lower working capital requirements.

Investing ActivitiesInvesting activities used cash of $242.1 million in 2005 compared to $57.4 million in 2004 and $315.0 million in 2002.

In 2005, we added $325.5 million to our capital assets through planned maintenance, the completion of Genesee 3 and additions to our fleet of mining equipment.

In 2004, additions to capital assets totaled $345.7 million and consisted primarily of completion of the Summerview wind farm, continuing construction of the Genesee 3 project and capitalized planned maintenance.

Cash provided by disposals and the sale of capital assets in 2005 was $1.6 million. In 2004, $116.5 million of proceeds from the sale of TA Power partnership units, $24.2 million received on the sale of the
Meridian Cogeneration Facility and $11.7 million from the sale of other capital assets was provided.

Cash provided by disposals and the sale of capital assets in 2003 was $285.5 million, comprised of $149.9 million received from the sale of the Sheerness Generating Station, $65.8 million of proceeds from
the sale of the head office building, $37.2 million of proceeds from the sale of TA Power partnership units, $21.6 million of proceeds from the sale of the Goldfields pipeline and $11.0 million of proceeds from the sale of the Seebe
land.

Financing ActivitiesFinancing activities used cash of $396.3 million compared to $549.3 million in 2004 and $165.5 million in 2003.

In 2005, we repaid $162.9 million of debt, redeemed $300.0 million in preferred securities and issued $200.0 million in two-year 4.20 per cent notes. We paid cash dividends of $99.2 million in 2005 and
distributed $77.5 million to our subsidiaries non-controlling interests. Our cash dividends for 2005 include only three quarters of payment as the fourth quarter dividend, although declared in the fourth quarter, was not paid until January
2006.

In 2004, we reduced long-term debt by $282.0 million, reduced short-term debt by $85.4 million, paid cash dividends on common shares of $135.4 million and non-controlling interest distributions of $48.4
million, some of which were funded from cash flow from operating activities.

In 2003, net proceeds on the issuance of common shares of $265.0 million were more than offset by net long-term debt repayment of $56.5 million, net repayment of short-term debt of $170.2 million, cash
dividends on common shares of $158.3 million, and non-controlling interest distributions of $38.9 million, some of which were funded from cash flow from operating activities.

In 2003, TransAlta repaid $350.0 million of senior secured debt of TransAlta Utilities Corporation.

In 2005, under the terms of the Normal Course Issuer Bid, the corporation purchased no common shares for cancellation (2004  143,500; 2003  nil).

TransAltas dividends per common share were $1.00 in 2005, 2004 and 2003.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         51
| | ---------------------------------------------------

---

Financing Arrangements

TransAlta raises capital in the Canadian and U.S. markets. TransAlta has the following financing arrangements in
place:

- US$1.0 billion shelf registration program; no amount has been issued since its renewal in July 2004. This program remains valid until August 2006 and is expected to be
renewed;
- $1.0 billion medium-term note program; $200.0 million was drawn under this program in December 2005. This program remains valid until December 2007;
- A $200.0 million commercial paper program of which $12.5 million was issued at Dec. 31, 2005;
- $1.5 billion committed syndicated bank credit facility, with $433.4 million utilized at Dec. 31, 2005. This facility was renewed in April 2005 and expires in June 2008; and
- $332.0 million of additional bank credit facilities, with $261.2 million utilized at Dec. 31, 2005. All of these facilities are non-committed.

At Dec. 31, 2005, the corporation had approximately $1.2 billion of credit available from its committed and uncommitted credit facilities.

In addition to the above, the corporation has US$121.5 million of non-recourse project financing for the Campeche project. This amount is not included in long-term debt on our consolidated balance sheet as our
Mexican operations are Variable Interest Entities (VIE). See page 61 for a discussion of the change in this accounting standard. It is the corporations expectation that future financing requirements, including financing requirements in foreign
jurisdictions, will be met primarily through raising capital at the TransAlta Corporation level.

At Dec. 31, 2005, TransAlta had a working capital ratio of 0.81 compared to 0.76 at Dec. 31, 2004. This increase is attributable to a decrease in the current portion of long-term debt of $300.0 million representing
the portion of the preferred securities which were redeemed in February 2005. TransAlta expects to have sufficient sources of internal and external capital to finance operations and growth in the short and long term.

In 2006, cash will be provided by a combination of cash flow from operations and utilization of various credit facilities. Cash requirements include planned maintenance, additions to capital assets, dividend payments
and repayment of short-term and maturing senior debt. Cash provided by operations in 2005 was $619.4 million and at Dec. 31, 2005, there were approximately $1.2 billion available under credit facilities. In 2006, capital expenditures are
expected to be $260.0 million to $275.0 million and $396.4 million of existing debt is scheduled to be repaid in 2006.

Long-term funding is provided through the maintenance of investment grade credit ratings and a carefully managed capital structure, which together create a strong balance sheet and ready access to capital markets at
competitive rates. Our objective is to manage the maturities of the various securities on issue such that no more than 15 per cent of the total outstanding securities mature in any one year. Our target is to maintain a capital structure and coverage
ratios consistent with investment grade credit ratings. Our capital structure consisted of the following components at Dec. 31, 2005, 2004 and 2003:

|                                                   |           | 2005 |           | 2004                |           | 2003              
|-------------------------------------------------- | --------- | ---- | --------- | ------------------- | --------- | ------------------
|                                                   |           |      |           | (Restated, Note 1 ) |           | (Restated, Note 1)
|Debt, net of cash and interest-earning investments | $ 2,538.8 | 43%  | $ 2,534.4 | 42%                 | $ 2,964.4 | 47%               
|Preferred securities                               | 175.0     | 3%   | 475.0     | 8%                  | 475.0     | 7%                
|Other non-controlling interests                    | 558.6     | 10%  | 616.4     | 10%                 | 477.9     | 8%                
|Common shareholders equity                        | 2,543.1   | 44%  | 2,470.0   | 40%                 | 2,450.5   | 38%               
|                                                   | $ 5,815.5 | 100% | $ 6,095.8 | 100%                | $ 6,367.8 | 100%              

At Dec. 31, 2005, our total debt (including non-recourse debt) to invested capital ratio was 43.6 per cent (39.8 per cent excluding non-recourse debts) compared to the Dec. 31, 2004 ratio of 46.4 per cent and the Dec.
31, 2003 ratio of 46.2 per cent.

Additional key financial ratios were as follows:

|                          | 2005  | 2004                                  | 2003 
|------------------------- | ----- | ------------------------------------- | -----
|                          |       | (Restated, Note 1) (Restated, Note 1)
|Cash flow to interest 1   | 4.8   | 4.3                                   | 3.4  
|Cash flow to total debt 2 | 23.5% | 19.1%                                 | 17.1%

1 Cash flow from operations before changes in working capital plus net interest expense divided by interest on recourse and non-recourse debt
less interest income.2 Cash flow from operations before changes in working capital divided by two-year average of total debt.

|52         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

Contractual repayments of long-term debt, commitments under operating leases, fixed price purchase contracts and commitments under mining agreements are as follows:

|                                   |         |   |       |   |       |   |       |   |      | 2011 and   |          
|---------------------------------- | ------- | - | ----- | - | ----- | - | ----- | - | ---- | ---------- | ---------
|                                   | 2006    |   | 2007  |   | 2008  |   | 2009  |   | 2010 | thereafter | Total    
|Long-term debt 1                   | $ 396.4 | $ | 249.4 | $ | 157.6 | $ | 239.7 | $ | 29.4 | $ 1,707.5  | $ 2,780.0
|Operating leases                   | 12.8    |   | 11.3  |   | 10.3  |   | 9.6   |   | 9.3  | 86.6       | 139.9    
|Fixed price purchase contracts     | 55.8    |   | 56.5  |   | 58.3  |   | 35.2  |   | 13.4 | 127.0      | 346.2    
|Mining agreements                  | 61.6    |   | 44.9  |   | 34.1  |   | 20.1  |   | 19.9 | 297.7      | 478.3    
|Total contractual cash obligations | $ 526.6 | $ | 362.1 | $ | 260.3 | $ | 304.6 | $ | 72.0 | $ 2,218.8  | $ 3,744.4

In addition, we have entered into a number of long-term power sales, gas purchase and transportation agreements in the normal course of operations as hedges of our operations.

In the normal course of operations, TransAlta and certain of our subsidiaries enter into agreements to provide financial or performance assurances to third parties. This includes guarantees, letters of credit and
surety bonds which are entered into to support or enhance creditworthiness in order to facilitate the extension of sufficient credit for Energy Marketing trading activities, treasury hedging, Generation construction projects, equipment purchases and
mine reclamation obligations.

At Dec. 31, 2005, the corporation had letters of credit outstanding of $216.9 million and US$415.3 million. The letters of credit were issued to counterparties that have credit exposure to the corporation or
certain subsidiaries. If the corporation or a subsidiary does not meet the obligations under the contract, the counterparty may present its claim for payment to the financial institution, which in turn will request payment from the corporation. The
letters of credit are generally issued under the corporations committed $1.5 billion credit facility and any amounts payable by the corporation upon presentation of a letter of credit by a counter party are repayable under the terms of the
credit facility in May 2008.

The corporation has arranged for the issuance of a surety bond in the amount of US$192.0 million in support of future mine reclamation obligations at the Centralia mine. The surety bond is issued for the full
period of time necessary to complete the required reclamation and is non cancelable. In the event that the corporation does not complete the reclamation obligations in accordance with regulations then the company that issued the surety bond will
complete the necessary reclamation obligations and seek recovery of the costs from the corporation. The surety bond is secured by a letter of credit for US$96.0 million and a corporate indemnity. A provision for retirement obligations is
included in deferred credits and other long-term liabilities (Note 11to the consolidated financial statements).

We have provided guarantees of subsidiaries obligations under contracts that facilitate physical and financial transactions in various derivatives. To the extent liabilities related to these guaranteed contracts
exist for trading activities, they are included in the consolidated balance sheet. To the extent liabilities exist related to these guaranteed contracts for hedges, they are not recognized on the consolidated balance sheet. The guarantees provided
for under all contracts facilitating physical and financial transactions in various derivatives at Dec. 31, 2005 totaled $1.83 billion. In addition, the corporation has a number of unlimited guarantees. The fair value of the trading and hedging
positions under contracts where TransAlta has a net liability at Dec. 31, 2005, under the limited and unlimited guarantees, was $559.6 million as compared to $345.2 million at Dec. 31, 2004.

TransAlta has also provided guarantees of subsidiaries obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at Dec. 31, 2005 was $645.3 million,
as compared to $662.5 million at Dec. 31, 2004. To the extent actual obligations exist under the performance guarantees at Dec. 31, 2005, they are included in accounts payable and accrued liabilities.

The corporation has approximately $1.2 billion of undrawn collateral available to secure these exposures.

During construction and until certain conditions were met, the corporation provided a guarantee to the lenders of the Campeche plant. On April 5, 2004 the guarantee was released and the US$133.6 million of debt
related to the plant became non-recourse to the corporation.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         53
| | ---------------------------------------------------

---

At Feb. 16, 2005, the credit ratings for the corporations various securities as determined by S&P, DBRS and Moodys Rating Services (Moodys) were as follows:

|Credit Ratings                  | S&P  | DBRS       | Moodys
|------------------------------- | ---- | ---------- | -------
|TransAlta Corporation           |      |            |        
|Issuer rating                   | BBB  |            | Baa2   
|Commercial paper                |      | R-2 (high) |        
|Secured commercial paper        |      | R-1 (low)  |        
|Senior unsecured debentures     | BBB  | BBB        | Baa2   
|Preferred securities/stock      | BB+  | Pfd-3y     |        
|TransAlta Utilities Corporation |      |            |        
|Issuer rating                   | BBB  |            |        
|Secured debt                    | BBB+ | A (low)    |        

In November 2005, DBRS confirmed TransAltas credit ratings of R-2 (high), BBB and Pfd-3y to the corporations commercial paper, senior unsecured debentures and preferred securities, respectively; and revised
the trend from negative to stable. In November 2005, DBRS assigned a rating of R-1 (low) to TransAltas secured commercial paper program. In July 2004, Moodys confirmed TransAltas credit rating of Baa2 with a negative outlook. In
February 2006, S&P upgraded TransAltas credit rating to BBB from BBB- and to BB+ from BB on the corporations unsecured debentures and preferred securities, respectively.

On Feb.16, 2006, we had approximately 199.5 million common shares outstanding, plus outstanding employee stock options to purchase 2.9 million shares.

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

Under Canadian GAAP, most derivatives used in hedging relationships are not recorded on the balance sheet
(Note 1(O)) to the
consolidated financial statements.) Gains or losses during the term of the hedge are deferred and recognized in earnings in the same period and financial statement caption as the hedged exposure (settlement accounting). The fair values of these
derivatives are disclosed in Note 18 to the consolidated financial statements. We also enter into long-term electricity purchase and sale, gas purchase and
transportation agreements in the normal course of operations. These contracts are not recorded on the balance sheet under Canadian GAAP. Under U.S. GAAP, some of these contracts meet the definition of a derivative, and would require mark-to-market
accounting, but are eligible for the normal purchase and sale exemption under FASB Statement 133. This exemption is available as electricity cannot be stored in significant quantities and due to the requirement for electricity generators to maintain
sufficient capacity to meet customers demands, and is also available for physically settled commodity contracts if certain criteria are met.

Information regarding guarantees has been disclosed in the Liquidity and Capital Resources section.

As discussed in the New Accounting Standards section of this MD&A we no longer consolidate our Mexican plants, Campeche and Chihuahua. As a result, $133.2 million (2004  $149.1 million) in
non-recourse debt related to the Campeche plant is not included in long-term debt in our consolidated balance sheets.

RELATED PARTY TRANSACTIONSOn March 8, 2005, TA Cogen entered into an agreement with TEC whereby TEC provided a financial fixed-for-floating price swap to TA Cogen during planned maintenance at Sheerness in the second quarter of 2005.

As previously discussed in Significant Events, on Dec. 1, 2004, we completed the sale of our 50 per cent interest in the 220 MW Meridian Cogeneration Facility located in Lloydminster, Saskatchewan, to TA Cogen for fair
value of $110.0 million. TA Cogen financed the acquisition through the use of $50.0 million of cash on hand and by the issuance of $30.0 million of units to each of TA Power and TEC. TA Cogen also issued an advance to TEC for $30.0
million. We recorded a gain of $11.5 million after-tax or $0.06 per common share.

On July 31, 2003, we completed the sale of our 50 per cent interest in the two-unit, 756 MW coal-fired Sheerness Generating Station to TA Cogen for $630.0 million. The exchange amount was at fair value and was
determined based on an estimate of the future net cash flows of the plant and approved by the independent directors of TA Cogen. There are no ongoing

|54         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

contractual commitments or arrangements resulting from this sale apart from the provision of operational and management services under normal commercial terms for the Sheerness plant.

The obligation to purchase all of TA Powers interest in TA Cogen on Dec. 31, 2018 (resulting from the 1998 sale of an interest in three Ontario cogeneration plants held by TA Cogen to TA Power) was removed as
part of the Sheerness transaction. Accordingly, the unamortized portion of the 1998 deferred gain was recognized in 2003. In addition, the management agreements between TransAlta, TA Power and TA Cogen were amended to remove the mechanism for the
deferral of management fees and remove the obligation for TA Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the amendments, TransAlta received $1.0 million from TA Power and $5.0 million from TA
Cogen.

In February 2003, we entered into an agreement with CE Gen whereby we purchase available power from certain CE Gen subsidiaries under normal commercial terms. In addition, CE Gen has entered into contracts with related
parties to provide administrative and maintenance services.

For the period November 2002 to November 2007, TA Cogen entered into a transportation swap transaction with a wholly-owned subsidiary of TransAlta, TEC. TEC operates and maintains TA Cogens three combined-cycle
power plants in Ontario and a plant in Fort Saskatchewan, Alberta. The business purpose of the transportation swap was to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline transportation for
two of its plants over the period of the swap. This stabilizes cash distributions in TA Cogen and thereby preserves the value of the limited partnership as a financing vehicle of TransAlta. The notional gas volume in the transaction was the total
delivered fuel for both facilities. Exchange amounts are based on the market value of the contract. TransAlta entered into an offsetting contract with an external third party, therefore we have no risk other than counterparty risk.

TA Cogen entered into a fixed-for-floating gas swap transaction with TEC for a 61-month period starting Dec. 1, 2000. The swap transaction provides TA Cogen with fixed price gas for both the Mississauga and Ottawa
plants over the period. The floating prices associated with the Mississauga and Ottawa cogen plants long-term fuel supply agreements were transferred to TECs account. The notional gas volume in the transaction was the total delivered
fuel for both facilities. As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales. At Dec. 31, 2005, the portion of the
contract related to the non-controlling interest had a fair value liability of $1.6 million (2004  $4.9 million).

EMPLOYEE SHARE OWNERSHIPWe employ a variety of stock-based compensation plans to align employee and corporate objectives. At Dec. 31, 2005, 2.9 million options to purchase our common shares were outstanding, with 1.6 million exercisable at
the reporting date. At Dec. 31, 2004, 2.9 million options to purchase our common shares were outstanding, with 2.0 million exercisable at the reporting date.

Under the terms of the Performance Share Ownership Plan (PSOP), certain employees receive awards which, after three years, make them eligible to receive a set number of common shares or cash equivalent plus dividends
thereon based upon the performance of the corporation relative to companies comprising the S&P/TSX composite index. After three years, once PSOP eligibility has been determined, 50 per cent of the common shares may be released to the
participant, while the remaining 50 per cent will be held in trust for one additional year. At Dec. 31, 2005, there were 1.2 million PSOP awards outstanding.

Under the terms of the Employee Share Purchase Plan, we will extend an interest-free loan to our employees below executive level of up to 30 per cent of the employees base salary for the purchase of common shares
of the corporation from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2005, 0.6 million shares had been
purchased by employees under this program.

EMPLOYEE FUTURE BENEFITSWe have registered pension plans in Canada and the United States covering substantially all employees of the corporation, its domestic subsidiaries and specific named employees working internationally. These plans have
defined benefit and defined contribution options and in Canada, there is a supplemental defined benefit plan for Canadian based defined contribution members whose annual earnings exceed the Canadian income tax limit. The defined benefit option of
the registered pension plan ceased for new employees on June 30, 1998. The latest actuarial valuations of the registered and supplemental pension plans were as at Dec. 31, 2005.

We provide other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation of these
other plans was as at Dec.31, 2004.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         55
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The supplemental pension plan is an obligation of the corporation. We are not obligated to fund the supplemental plan but are obligated to pay benefits under the terms of the plan as they come due. We have posted a
letter of credit in the amount of $41.8 million to secure the obligations under the supplemental plan.

RISK FACTORS AND RISK MANAGEMENTTransAlta uses a multi-level risk management oversight structure to manage the corporations various risk and energy trading exposures.

The Audit and Environment (A&E) Committee provides assistance to the Board of Directors in fulfilling its oversight responsibility relating to the integrity of the corporations financial statements and the
financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors qualifications, independence, performance and reports; and the legal and environmental compliance
programs as established by management and the Board of Directors. The A&E Committee approves our Commodity Risk and Financial Exposure Management policies.

Our Exposure Management (EM) Committee is chaired by our Chief Financial Officer and is comprised of the Directors of Financial Operations for each business unit, the Executive Vice-President of Corporate Development
and Marketing, Vice-President and Treasurer, Vice-President and Comptroller and the Director of Risk Management. The EM Committee is responsible to review, monitor and report on compliance with our approved financial and commodity risk exposure
management policies.

The following addresses some, but not all, risk factors that could affect TransAltas future results. A discussion of critical estimates made in the application of accounting policies is provided in the Critical
Accounting Policies and Estimates section that follows.

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

Our Alberta coal-fired and hydroelectric facilities operate under the Alberta government mandated PPAs which, among other things, establish the price at which power will be supplied. In addition to the Alberta PPAs, we
have entered into a variety of short- and long-term contracts to minimize our exposure to short-term fluctuations in electricity prices. In 2005, we had approximately 68 per cent of production under long-term contracts (2004  69 per cent) and
82 per cent (2004  83 per cent) of production was contracted for terms greater than one year. In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in electricity prices on purchases of
electricity from the market to fulfill our supply obligations under these short- and long-term contracts. We actively seek to mitigate this exposure through continued and proper maintenance of our electricity generating plants, force majeure clauses
negotiated in our contracts, trading activities and insurance.

We buy natural gas and some of our coal to supply the fuel needed to operate our facilities. We have exposure to increases in the cost of such fuels to the extent such increases are greater than the increases in the
price we can obtain for the electricity we produce. A significant portion of the coal used in electricity generation is from coal reserves owned by TransAlta, thereby limiting our exposure to fluctuations in the market price of coal. In 2005, 67 per
cent (2004  70 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2004  100 per cent) of our purchased coal costs were contractually fixed.

Higher input costs, such as diesel and tires, increased amounts of overburden being removed to access coal reserves and mining operations moving further away from the power plants are all contributing to increased
mining costs. Additionally, the ability of the mines to deliver coal to the power plants can be impacted by weather conditions and labour relations. At Centralia, high amounts of rainfall can cause localized flooding and reduced equipment
utilization. Diesel price variations are minimized through the use of diesel hedges and seasonal variations in coal mining costs and production are stabilized through the application of standard costing.

Our fuel supply and fuel costs for our gas-fired plants are managed with short-, medium- and long-term gas supply contracts, hedging transactions and contractual agreements that provide for the flow-through of gas
costs. We believe adequate supplies of natural gas at reasonable prices will be available for plants when existing supply contracts expire.

Production and gross margins from our merchant gas plants are subject to changes in spark spreads. We have not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased
concurrent with spot market spark spreads being adequate to produce and sell electricity.

Our proprietary trading of gas and electricity is limited, strictly controlled and managed through the use of VAR methodologies.

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VAR is the most commonly used metric employed to track the risk of trading positions. A VAR measure gives, for a specific confidence level, an estimated maximum loss over a specified period of time.

VAR is the primary measure used to manage Energy Marketings exposure to market risk resulting from trading activities. VAR is monitored on a daily basis, and is used to determine the potential change in the value
of the corporations marketing portfolio over a three-day period within a 95 per cent confidence level resulting from normal market fluctuations. Stress tests are performed weekly on both earnings and VAR to measure the potential effects of
various market events that could impact financial results, including fluctuations in market prices, volatilities of those prices and the relationships between those prices.

We estimate VAR using the historical variance/covariance approach. Currently, there is no uniform energy industry methodology for estimating VAR. An inherent limitation of historical variance/covariance VAR is that
historical information used in the estimate may not be indicative of future market risk.

Another method of looking at VAR is based on a 95 per cent confidence interval over a three-day holding period. For comparison purposes, the following table provides this average daily VAR of the corporations
marketing portfolio for 2005 and 2004:

|                                         |   | 2005 |   | 2004
|---------------------------------------- | - | ---- | - | ----
|3-day average VAR  95% confidence level | $ | 3.6  | $ | 3.8 

Currency Rate ExposureWe have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations and the acquisition of equipment and services from foreign suppliers. We
have exposures primarily to the U.S., Mexican and Australian currencies. We limit our exposure to movements in these currencies in two ways. We hedge our net investments in foreign operations using a combination of foreign-denominated debt and
financial instruments. The earnings from our foreign operations are substantially offset by expenditures denominated in the foreign currencies.

At Dec. 31, 2005, we have hedged approximately 96.8 per cent (2004  98.7 per cent) of our foreign currency translation exposure. Our strategy is to offset 90-100 per cent of all foreign currency exposures.

Translation gains and losses related to the carrying value of our foreign operations are deferred and included in the cumulative translation account in shareholders equity. At Dec. 31, 2005, the balance in this
account was a $67.0 million loss compared to a $52.2 million loss at the end of 2004.

Credit RiskIf the counterparties to our contracts are unable to meet their obligations, our revenues could be adversely affected. We actively manage our exposure to credit risk by assessing the ability of counterparties to
fulfill their obligations under the related contracts prior to entering into such contracts. We set strict credit limits for each counterparty and the mix of coun-terparties based on their credit ratings. Counterparty exposures for trading
activities are monitored daily. If the limits are exceeded, we take steps to reduce additional credit exposure by requesting collateral, if applicable, or by halting trading activity. However, there can be no assurances that we will be successful in
identifying creditworthy counterparties or monitoring trading activities.

We are exposed to minimal credit risk for Alberta PPAs because under the terms of these arrangements all receivables are secured by letters of credit.

A summary of our credit risk exposure for trading operations at Dec. 31, 2005, including asset-backed trading, is provided below:

NetNumber of
	exposure ofExposure
	
	
	
	
	counterparties counterpartiesbefore credit
	
	Credit
	
	Net
	greater
	
	greaterRating
	
	collateral
	
	collateral
	
	exposure
	than 10%
	
	than 10%Investment grade
	$
	126.7
	$
	0.9
	$
	125.8
	2
	$
	51.8Non-investment grade
	
	
	
	
	
	
	
	
	No external rating, internally rated  investment grade
	
	44.7
	
	
	
	44.7
	1
	
	28.9No external rating, internally rated  non-investment grade
	
	2.3
	
	
	
	2.3
	
	
	$
	173.7
	$
	0.9
	$
	172.8
	3
	$
	80.7


The maximum credit exposure to any one customer, excluding the California Independent System Operator and California Power Exchange Corp. discussed earlier in the Energy Marketing Segment and including the fair value
of open trading positions, is $34.2 million receivable.

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Liquidity RiskWe are exposed to liquidity risk under certain electricity and natural gas purchase and sale contracts entered into for the purposes of asset-backed sales and proprietary trading. Liquidity risk relates to our
commitments to meet margin and collateral requirements under these contracts. The terms and conditions of these contracts may require us to provide collateral when the fair value of these contracts is both negative (out-of-the-money) and in excess
of any credit limits granted by our counterparties. The fair value of these contracts changes due to changes in commodity prices and foreign exchange rates. These contracts are out-of-the-money in these circumstances: (i) for purchase agreements,
when forward commodity prices are less than contracted prices; and (ii) for sales agreements, when forward commodity prices exceed contracted prices. Downgrades in our creditworthiness may decrease the credit limits granted by our
counterparties.

In the absence of any credit limits granted by our counterparties, TransAltas maximum collateral requirements would have been $559.6 million at Dec. 31, 2005. Collateral available was approximately $1.2
billion.

Interest Rate ExposureChanges in interest rates can impact our borrowing costs and the capacity revenues we receive from our PPA plants. While these two streams represent a natural hedge against movements in interest rates, we also address
this risk by employing a combination of fixed and floating rate debt instruments. Carrying a portion of our debt that is exposed to floating interest rates also allows us to take advantage of changes in the market. At Dec. 31, 2005, approximately
28.9 per cent (2004  23.9 per cent) of the corporations total debt portfolio was subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.

Hydro RiskOur hydro operations financial performance is partially dependent upon the availability of water in a given year. The availability of water is difficult to forecast as it is primarily driven by weather and volume,
timing and location of precipitation throughout the province of Alberta. Such water availability introduces a degree of volatility in revenues earned by our hydro operations from year to year. This risk is complicated by obligations imposed within
the PPA applicable to the corporations hydro plants. A monthly financial obligation must be paid to the PPA buyer, based on a predetermined quantity of energy and ancillary services at market prices, regardless of our ability to generate such
quantities. We manage these risks on a real-time basis by monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities. We also play an important role in the
management of water flows and levels in several key areas of Alberta, including two major cities. We carefully balance all of these factors together to achieve optimal productivity with the water resources available.

Operational RiskOur plants are exposed to operational risks such as fatigue cracks in boilers, corrosion in boiler tubing, turbine failures and other issues that can lead to outages. A comprehensive plant maintenance program and
regular turnarounds reduce this exposure. If the plants do not meet the availability or production targets specified in the PPAs or other long-term contracts, then we must either compensate the purchaser for the loss in the availability of
production or suffer a reduction in electrical or capacity payments. Consequently, an extended outage could have a material adverse effect on our business, financial condition, results of operations or our cash flows. Insurance and force majeure
clauses in the PPAs and other long-term contracts further mitigate this exposure.

The construction and development of generating facilities and acquisition activities are subject to various environmental, engineering and construction risks relating to cost-overruns, delays and performance. We
attempt to minimize these risks by performing detailed analysis of project economics prior to construction or acquisition and by securing favourable power sales agreements.

The mines require permits from various governmental authorities to allow continued operation as well as commencement of operations in undeveloped areas. These permits are subject to change in various circumstances and
there can be no guarantee that we will be able to obtain or maintain all the permits that may be required to develop or operate the mines and related facilities economically. We endeavour to be in compliance with all permit requirements at all
times.

In Alberta, we have control of or own the land required to access the existing coal reserves and do not anticipate any issues in permitting these reserves. The existing permitted reserves at Centralia are nearing end
of life and we are in the process of developing new resources that will provide sufficient coal, at current production levels, for the next 17 years. We are working closely with the regulators to ensure development of the new resources proceeds on
schedule.

Of the corporations labour force, 58 per cent is covered under 12 collective bargaining agreements. Two agreements were renegotiated in 2005 and we anticipate the renewal of four agreements in 2006. We do not
anticipate any significant issues in the renegotiations of these agreements.

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Environmental, Health and Safety RiskTransAltas approach to managing its environmental, health and safety (EHS) risk has three elements:

- Compliance-based activities, such as permitting and reporting,
- ISO-based EHS Management systems and programs, such as safety programs and auditing,
- Longer-term strategic initiatives, including climate change and government policy development.

These elements are integrated into our corporate-wide operations and management systems. They are designed to mitigate risks of our activities to employees, the public and the environment, and to address potential
competitive risks from future changes in environmental policy. They are also supportive of our corporate commitment to sustainability.

We strive to maintain compliance with all environmental regulations relating to operations and facilities. Quarterly reports on all EHS regulatory changes are provided to each facility to ensure compliance is
maintained. We produce and distribute quarterly and annual public reports on our performance. We seek continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts and environmental incidents.

We have implemented an ISO-based EHS management system designed to continuously improve environmental and safety performance. All of our plants have implemented the system, with one plant having an equivalent variation
as required by our partner. Compliance with both regulatory requirements and management system standards is regularly audited through our Performance Assurance policy and results are reported quarterly to our Board of Directors.

TransAlta commits significant effort to work with regulators in Canada and the United States to ensure regulatory changes are well-designed and cost-effective. New emission reduction objectives for the power sector are
being established by governments in Canada and the United States. We have compliance plans over the next decade for greenhouse gases, mercury, sulphur dioxide and oxides of nitrogen, which will be adjusted as regulations are finalized. Where capital
investment for control equipment may be required, we have technology review processes underway.

Specifically on climate change, TransAlta has implemented a four-component strategy that manages future risk associated with climate change regulation and develops competitive business advantages. The cornerstones of
the strategy are:

1. Internal operational improvements that lower the emissions of our generation operations. These include plant upgrades, intensive equipment maintenance, efficiency improvements and fuel decision choices.
2. Purchase of emission reduction offsets outside our operations. TransAlta has been a Canadian leader in this area and has created an offsets portfolio that will allow us to meet emission targets at competitive
costs.
3. Renewable energy investments, particularly in the wind area, which reduce our emissions intensity and diversify our fuel mix.
4. Investments in clean coal technology development that provide long-term promise for large emission reductions from fossil-fired generation. TransAlta is a founder and active member of the Canadian Clean Power
Coalition, an industry consortium developed to build Canadas first clean coal power plant.

We anticipate continued and growing scrutiny by investors relating to sustainability performance. Our reputation as a leader in this area is important, more so because in our opinion it represents both good management
and competitive positioning. The Dow Jones Sustainability Index has again recognized TransAlta as one of the worlds best utility companies in terms of sustainability performance. In 2005, we were also recognized as one of the worlds top
100 sustainable companies in the Global 100 ranking of the World Economic Forum.

Mercury control requirements are being drafted in Canada and the United States and will impact coal-fired generation plants. In Alberta, TransAlta anticipates its coal-fired plants will require some form of mercury
capture technology in the next five to seven years. The exact technology and performance requirements have not yet been finalized; however, TransAlta is maintaining engineering readiness. Our PPAs will also provide an opportunity to recover these
costs under Change of Law provisions. In the United States, TransAltas Centralia coal-fired plant may or may not be subject to mercury reduction requirements by 2010, depending on Washington State determinations, which are expected
by the end of 2006.

Regulatory and Political RiskCertain of the markets in which the corporation operates are subject to significant regulatory oversight and control. The corporation is not able to predict whether there will be any changes in the regulatory
environment or the ultimate effect of changes in the regulatory environment on its business. TransAlta manages these risks by working with governments, regulators and other stakeholders to attempt to resolve issues. In Ontario, new legislation was
passed in December 2004 outlining a new electricity market structure. The new market design provides for a mix of: i) regulated assets, ii) unregulated assets and iii) government-backed long-term contracts. TA Cogens assets have retained their
existing government contracts in the restructured market. On Feb. 14, 2006, TransAlta signed a five-year contract with the Ontario Power Authority for its Sarnia cogeneration plant. Under the terms of the contract, the plant will be available to
supply an average of 400 MW

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      ANALYSIS         59
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of power to the Ontario electricity market. In Alberta, a wholesale market review task force and a retail market review were initiated in 2004 to evaluate the functioning of the electricity market and consider market
design changes. A market design policy recommendation is expected in 2006. TransAlta continues to work with the task force to ensure any regulatory changes are well-designed and cost-effective. If regulations were to change however, the operational
and financial impact on all Alberta plants and trading operations would need to be assessed. Outcomes may include, but are not limited to: increased compliance, operating or capital costs; reduced operational flexibility; or reduced power prices and
volatility.

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

Transmission RisksIn August 2003, a blackout cut off electricity to millions of residents in the Northeastern United States and Eastern Canada. This type of event, although extremely unusual, is an ongoing risk for electric companies.
This risk is mitigated through force majeure clauses in the Alberta PPAs and power sales contracts and access to multiple transmission lines.

Corporate StructureWe conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent upon the results of operations of our subsidiaries and the payment of
funds by such subsidiaries to the corporation in the form of distributions, loans, dividends or otherwise. In addition, TransAltas subsidiaries may be subject to statutory or contractual restrictions which limit their ability to distribute
cash to the ultimate shareholder, the corporation.

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

Income TaxesThe corporations operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. The corporations tax
filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes based on all information currently available.

Legal ContingenciesThe corporation is occasionally named as a defendant in various claims and legal actions. Exposure to these claims is mitigated through levels of insurance coverage considered appropriate by management and active
management of these claims. Except as disclosed inNote 22to the consolidated financial statements, the corporation does not expect the outcome of the claims or
potential claims to have a materially adverse effect on the corporation as a whole.

Other ContingenciesThe corporation maintains a level of insurance coverage deemed appropriate by management. There were no significant changes to TransAltas insurance coverage during 2005. The corporations insurance coverage
may not be available in the future on commercially reasonable terms. There can be no assurance that insurance proceeds received by the corporation for any loss or damage will be sufficient.

Sensitivity AnalysisThe following table shows the effect on net earnings and cash flows of changes in certain key variables. The analysis is based on business conditions and production volumes in 2005. Each separate item in the
sensitivity assumes the others are held constant. While these sensitivities are applicable to the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for
greater magnitude of changes.

Approximate impactEarningsFactor
	Change
	Cash flow
	(after-tax)Electricity price
	$1.00/MWh increase
	$ 10.8
	$ 10.8Natural gas price
	$0.1/GJ increase
	(1.1)
	(1.1)Availability/production
	1% increase
	13.8
	13.8Exchange rate (US$ per Cdn$)
	US$0.01 decrease
	(0.2)
	(0.2)Interest rate
	1% increase
	(10.7)
	(7.0)Tax rate
	1% increase
	(2.3)
	(2.3)


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The impact of a $1.00 per MWh change in electricity prices has minimal impact on our cash flow and after-tax earnings, as approximately 82 per cent of output is at contractually fixed prices. A change in natural
gas prices also has minimal impact as the majority of gas costs have been contractually fixed or flow through to customers under terms of agreements

The calculation of the impact of a one per cent change in availability assumes that production levels will change by an equiv alent amount at the contracted plants. An increase in availability at the merchant gas
plants would not result in increased production.

Our hedging strategies have minimized the impact of changes in exchange rates and interest rates as our net investments in foreign operations have been hedged and interest rates on 71.1 per cent of our debt have been
fixed.

The income tax rate can change depending on the mix of earnings from various countries. Increased operating income will incur income tax expense at a rate of approximately 35 per cent compared to the forecasted overall
rate of approximately 25 per cent.

NEW ACCOUNTING STANDARDSEffective Jan. 1, 2005, we adopted the Canadian Institute of Chartered Accountants (CICA) Accounting Guideline 15 Consolidation of Variable Interest Entities. The guideline establishes that a VIE is to be
consolidated based upon the deter mination of who will receive the majority of a VIEs expected losses, expected residual returns, or both, defined as a variable interest, rather than solely based on the voting interests. Variable interests are
ownership interests or contractual relation ships that enable the holder to share in the financial risks and rewards resulting from the activities of a VIE.

The accounting guideline specifies that an entity is a VIE if either of the following criteria are met:

1. total equity invested is insufficient to finance the entity without additional subordinated finance;
or
2. the equity investment does not provide the shareholders the right to make decisions or absorb the risks and returns of the entity.

We have considered the provisions of the guideline for all subsidiaries and their related power purchase, power sale or tolling agreements. Factors we considered in this analysis include the duration of the agreements,
how capacity and energy payments are determined, source of payment terms for fuel, as well as responsibility and payment for operating and main tenance expenses.

As a result of this review, we determined that our wholly-owned subsidiaries that hold our interests in the Campeche and Chihuahua power plants are each considered VIEs. We have determined that the nature of the fuel
purchase and power sale contract relating to the wholly-owned Mexican operation insulates us from significant variability in the cash flows relating to the assets. Therefore, we are not the primary beneficiary of the VIE and do not consolidate these
wholly-owned subsidiaries Accordingly, the subsidiaries owning the Campeche and Chihuahua plants are presented as equity investments rather than as consolidated subsidiaries in our consolidated financial statements. All results from operations of
the plant are presented as equity income in our consolidated income statement. There was no impact to net earnings as a result of adoption of this interpretation. We have restated prior periods to reflect this change in accounting
standard.

The following is summary information about the subsidiaries holding our Campeche and Chihuahua plants:

Dec. 31
	
	2005
	
	2004Campeche
	Chihuahua
	Campeche
	ChihuahuaTotal assets
	$ 276.9
	$ 302.6
	$ 280.1
	$ 318.3Total liabilities
	184.1
	7.2
	187.7
	8.4Maximum exposure to loss
	93.7
	307.9
	89.7
	328.6Capacity (MW)
	252
	259
	252
	259Annual production (GWh)
	1,683
	1,067
	1,742
	1,422


In March 2004, the U.S. Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) reached a consensus on EITF Issue No. 04-02,
Whether Mineral Rights are
Tangible or Intangible Assets, that mineral rights, as defined in the Issue, are tangible assets. As a result of this decision, we account for coal rights under both Canadian and U.S. GAAP as tangible
assets. Prior period amounts have been reclassified from intangible assets to tangible assets (Dec. 31, 2003  $58.5 million). There was no effect on our net earnings as a result of the reclassification.



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      ANALYSIS         61
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules have changed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before
the effective date, and we believe the proper implementation and consistent application of accounting rules is critical. However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used
to adopt a policy for accounting for these situations. This is accomplished by analogizing to similar situations and the accounting guidelines governing them, considering foreign accounting standards and consulting with our independent auditors
about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the
development of estimates that impact the corporations consolidated financial statements.

Our significant accounting policies are described in
Note 1to the consolidated financial statements. The most critical of these
policies are those related to revenue recognition, PP&E, goodwill, asset retirement obligations, income taxes and employee future benefits
(Notes 1(C), (F), (G), (I), (L) and (M),
respectively). Each policy involves a number of estimates and assumptions to be made by our management about matters that are highly uncertain at the time the estimate is made. Different estimates, with
respect to key variables we used for the calculations, or changes to estimates could potentially have a material impact on our financial position or results of operations. These critical accounting estimates are described below.

We have discussed the development and selection of these critical accounting estimates with our A&E Committee and our independent auditors. The A&E Committee has reviewed and approved our disclosure relating to
critical accounting estimates in this MD&A.

Tables are provided in the following discussion to reflect the sensitivities associated with changes in key assumptions used in the estimates. The tables reflect an increase or decrease in the percentage or other
factor for each assumption. The inverse of each change is generally expected to have a similar opposite impact. Each separate item in the sensitivity assumes all other factors remain constant.

Revenue RecognitionThe majority of our revenues are derived from the sale of physical power and from energy marketing and trading activities. Revenues under long-term electricity and thermal sales contracts generally include one or more
of the following components: fixed capacity payments for being available; energy payments for generation of electricity; availability incentives or penalties for exceeding or not meeting availability targets; excess energy payments for power
generation above committed capacity; and ancillary services. Each is recognized upon output, delivery or satisfaction of specific targets, as specified by contractual terms. Revenues from non-contracted capacity are comprised of energy payments for
each MWh produced at market prices, and are recognized upon delivery.

Trading activities use derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn trading revenues and to gain market information. These derivatives
are accounted for using fair value accounting. Derivatives, other than real-time physical contracts, are presented on a net basis in the statements of earnings. The initial recognition of fair value and subsequent changes in fair value affect
reported earnings in the period the change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as price risk management assets and
liabilities. Non-derivative contracts are accounted for using the accrual method. To be consistent with the EITF 03-11, TransAlta has concluded that real-time physical contracts meet the definition of derivative contracts held for delivery and
therefore realized gains and losses are reported gross in the statement of earnings.

The determination of the fair value of energy trading contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors. The majority of
derivatives traded by TransAlta have quoted market prices or over-the-counter quotes available from brokers. However, some derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are
available. These derivatives require the use of internal valuation techniques or models (mark-to-model accounting).

Mark-to-model accounting is currently used for physical and financial forward contracts and option contracts on transmission and transmission congestion. Accrual accounting is used for transmission rights acquired to
sell production from our plants, and physical transmission rights used by the Energy Marketing segment. Changes in fair value of derivatives subsequent to inception are recorded on the balance sheet as price risk management assets or liabilities,
with the offset recorded in revenues. The values can be favourable or unfavourable, and depending on current market conditions, values can fluctuate significantly, with the effect of changes being recorded through earnings in the period of the
change. Modeling

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techniques require the corporation to model future prices, price correlation, market volatility, liquidity and other forecasted market intelligence, as well as the use of mathematical extrapolation techniques. Where
appropriate, the estimates used to derive fair value reflect the potential impact for uncertainties in the modeling process, the potential impact of liquidating the corporations position in an orderly manner over a reasonable period of time
under present market conditions and operational risk. We validate our mark-to-model results by comparing against settled data. The amounts reported in the financial statements may change as estimates are revised to reflect actual results or new
information, changes in market conditions or other factors, many of which are beyond our control, and may be material.

Key variables used in the models are uncertain. The estimated value of these contracts at Dec. 31, 2005 using mark-to-model methodology was $3.9 million. Sensitivities of the valuation, which would have been
recorded in earnings in the current year, are as follows:

Impact onChange in
	
	pre-taxAssumption
	assumption
	
	earningsChange in volatility
	1%
	$
	(0.5)Change in commodity price
	1%
	
	3.6


There have been no significant changes to the modeling techniques in the past three years.

Valuation of PP&E

PP&E makes up 71.6 per cent of our assets, of which 99 per cent relates to the Generation segment. On an annual basis, and when indicators of impairment exist, we determine whether the net carrying amount of
PP&E is recoverable from future undiscounted cash flows. Factors which could indicate that an impairment exists include significant underperformance relative to historical or projected operating results, significant changes in the manner or use
of the assets, the strategy for the corporations overall business and significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment
does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not the operator of the facility.
Events can occur in these situations that may not be known until a date subsequent to their occurrence.

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

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

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

On an annual basis, or as events indicate, TransAlta performs an impairment review of its plants. As a result of this review, we have determined that the Ottawa plant was impaired in the accounts of TA Cogen. A
fundamental shift in the gas markets and forecast increases in the cost of natural gas have lowered expected margins from the Ottawa plant as TA Cogen does not have a gas supply contract in place for the period 2008  2012 to match the contract
to provide electricity under predetermined prices to the Ontario Electricity Financial Corporation (OEFC). Based upon the current view of gas costs and market conditions for that period and the likelihood that the plant will not operate as
extensively beyond 2012, a reduction in the carrying value was required and a charge of $36.2 million was recognized in the fourth quarter of 2005. The discussion of Significant Events discloses our treatment of this item.

Had assumptions been made that resulted in future cash flows of the plants declining by 10 per cent, certain of TransAltas plants would have been impaired at Dec. 31, 2005.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         63
| | ---------------------------------------------------

---

During 2003, our Binghamton plant did not run on a regular basis. This indicated that an impairment may have existed; therefore the plant was reviewed for impairment. The Binghamton plant sells electricity to the New
York area at spot market rates when such prices exceed its marginal operating costs of producing electricity. We determined that undiscounted expected future cash flows from the Binghamton plant were less than the carrying value of the asset,
therefore a pre-tax impairment charge of $5.6 million was recognized in the fourth quarter of 2003.

The fair value of the Binghamton plant was calculated from the expected present value of future cash flows. Management was required to make several estimates of future results and events. The range of pre-tax
impairment charges resulting from managements estimates was from $3.1 million to $8.1 million.

In the second quarter of 2003, we determined that future growth would be slower than previously anticipated. This reduction in expansion plans, combined with an unsuccessful bid for the Valladolid project in Mexico,
indicated that an impairment of our turbine inventory may exist. As a result, our turbine inventory was reviewed for impairment. We concluded that the carrying amount of our turbine inventory was not recoverable and the fair value of the turbines
was less than the carrying value of the assets; therefore an $84.7 million asset impairment charge was recognized. Fair value was estimated using market prices for the same or similar turbines.

Asset Retirement ObligationsWe recognize asset retirement obligations for PP&E in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The fair value of the liability is described as the amount at
which the liability could be settled in a current transaction between willing parties. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many asset retirement
obligations. Expected values are discounted at the risk-free interest rate adjusted to reflect the markets evaluation of the entitys credit standing. Determining asset retirement obligations requires estimating the life of the related
asset and the costs of activities such as demolition, dismantling, restoration and remedial work based on present day methods and technologies.

At Dec. 31, 2005, the asset retirement obligations recorded on the consolidated balance sheet were $249.2 million. We estimate the undiscounted amount of cash flow required to settle the asset retirement
obligations is approximately $1.2 billion, which will be incurred between 2007 and 2072. The majority of the costs will be incurred between 2020 and 2030. A discount rate of eight per cent was used to calculate the carrying value of the asset
retirement obligations.

Sensitivities for the major assumptions are as follows:

Impact onChange in
	
	pre-taxAssumption
	assumption
	
	earningsDiscount rate
	1%
	$
	2.5Undiscounted asset retirement obligations
	1%
	
	0.2


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

Depreciation and amortization expense was $400.9 million in 2005, of which $49.9 million relates to mining equipment, and is included in fuel and purchased power.

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

A five per cent change in the estimated useful life of depreciable assets will result in a change of $17.6 million in depreciation and amortization expense.

Valuation of GoodwillWe evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying value of a reporting unit including goodwill exceeds the reporting units fair value,
any excess represents the impairment loss.

Goodwill was recorded on the acquisitions of Merchant Energy Group of the Americas (MEGA), Vision Quest Windelectric and CE Gen. At Dec. 31, 2005, this goodwill had a total carrying value of $137.6
million.

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We reviewed the goodwill in the fourth quarter of 2005 in connection with our annual impairment tests. To test for impairment, the fair value of the reporting units to which the goodwill relates were compared to the
carrying values of the reporting units. We determined that the fair values of our reporting units, based on historical cash flows and estimates of future cash flows, exceeded their carrying values; therefore, no impairment charges were
recorded.

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

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

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

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

Future tax assets of $173.7 million have been recorded on the consolidated balance sheet at Dec. 31, 2005. This is comprised primarily of unrealized losses on electricity trading contracts, asset retirement
obligation costs and net operating and capital loss carryforwards. We believe there will be sufficient taxable income and capital gains that will permit the use of these deductions and carryforwards in the tax jurisdictions where they
exist.

Future tax liabilities of $758.5 million have been recorded on the consolidated balance sheet at Dec. 31, 2005. The liability is comprised primarily of unrealized gains on electricity trading contracts and income
tax deductions in excess of related depreciation of PP&E.

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

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

Employee Future BenefitsAs explained in Note 17 to the consolidated financial statements, we provide post-retirement benefits to employees. The cost of
providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The liability for future benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of
contributions made to the plans and earnings on plan assets. Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including
anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

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

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions:

Impact on
	
	Impact onprojected
	pension costChange in
	
	benefit
	
	reportedActuarial assumption
	assumption
	
	obligation
	in earningsDiscount rate
	1%
	$
	47.7
	$
	2.4Rate of return on plan assets
	1%
	
	
	
	3.4


| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         65
| | ---------------------------------------------------

---

The discount rate used represents high-quality fixed income securities currently available and expected to be available during the period to maturity of the pension benefits. We do not expect to make any changes to the
rate in 2006.

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. For the year ended Dec. 31, 2005, the plan assets had a return of
$43.9 million compared to a return of $33.4 million in 2004 and $35.9 million in 2003. The 2005 actuarial valuation used the same rate of return on plan assets (7.0 per cent) as was used in 2004 and 2003.

As a result of our plan asset return experience for the U.S. registered pension plan, at Dec. 31, 2005, the corporation was required under U.S. GAAP to recognize an additional minimum liability
(Note 25 to the consolidated financial statements). The liability was recorded as a reduction in common equity through a charge to other comprehensive income (OCI), and did not affect net
income for 2005.

The amount of the additional pension liability recognized for U.S. GAAP depended on a number of factors, including the discount rate and asset returns experienced, contributions made by the corporation and any
resulting change in managements assumptions. Pension cost and cash funding requirements could increase in future years.

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

Each business unit assumes responsibility for its operating results measured to operating income. Operating income is a measure of financial performance used by TransAltas analysts and investors to analyze and
compare companies on the basis of operating performance.

Gross margin less operating expenses and operating income provide us with a measurement of operating performance that is readily comparable from period to period.

Gross margin less operating expenses and operating income are reconciled to net earnings below:

Year ended Dec. 31
	2005
	2004
	2003(Restated, Note 1) (Restated, Note 1)Gross margin
	$ 1,462.6
	$ 1,356.8
	$ 1,325.3Operating expenses
	(985.2)
	(925.5)
	(893.5)477.4
	431.3
	431.8Gain on sale of Sheerness Generating Station
	
	
	191.5Gain on sale of Meridian Cogeneration Facility
	
	17.7
	Gain on sale of TA Power partnership units
	
	44.8
	15.2Gain on sale of land
	
	
	10.5Asset impairment charges
	(36.2)
	
	(90.3)Prior period regulatory decision
	
	(22.9)
	Operating income
	441.2
	470.9
	558.7Other expense
	
	
	(3.2)Foreign exchange gain (loss)
	1.0
	0.7
	(4.7)Net interest expense
	(188.6)
	(207.4)
	(212.1)Equity loss
	(0.9)
	(8.5)
	(6.0)Earnings before non-controlling interests and income taxes
	252.7
	255.7
	332.7Non-controlling interests
	18.5
	46.0
	34.2Earnings before income taxes
	234.2
	209.7
	298.5Income tax expense
	47.4
	49.1
	64.3Earnings from continuing operations
	186.8
	160.6
	234.2Gain on disposal of discontinued operations, net of tax
	12.0
	9.6
	Net earnings
	$ 198.8
	$ 170.2
	$ 234.2


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Presenting earnings on a comparable basis from period to period provides us with the ability to evaluate earnings trends more readily in comparison with prior periods results. To do so the following items, which
we believe would otherwise affect the comparability of our operating results from period to period, are excluded from net earnings: gains on sale of the Sheerness Generating Station, TA Power units, the Meridian Cogeneration Facility and land, asset
impairment charges, prior period regulatory decisions, and earnings from discontinued operations, net of tax.

Earnings presented on a comparable basis from period to period is reconciled to net earnings below:

|Year ended Dec. 31                                         |   | 2005  |                                       | 2004   |   | 2003) 
|---------------------------------------------------------- | - | ----- | ------------------------------------- | ------ | - | ------
|                                                           |   |       | (Restated, Note 1) (Restated, Note 1)
|Earnings on a comparable basis                             | $ | 173.8 | $                                     | 128.1  | $ | 128.7 
|Tax settlement on deferred receivable                      |   | 13.0  |                                       |       |   |      
|Gain on sale of Sheerness Generating Station, net of tax   |   |      |                                       |       |   | 145.8 
|Gain on sale of Meridian Cogeneration facility, net of tax |   |      |                                       | 11.5   |   |      
|Gain on sale of TA Power units, net of tax                 |   |      |                                       | 29.1   |   | 10.1  
|Gain on sale of land, net of tax                           |   |      |                                       |       |   | 8.6   
|Asset impairment charges, net of tax                       |   |      |                                       |       |   | (59.0)
|Prior period regulatory decision, net of tax               |   |      |                                       | (14.9) |   |      
|New Zealand tax settlement                                 |   |      |                                       | 6.8    |   |      
|Gain from discontinued operations, net of tax              |   | 12.0  |                                       | 9.6    |   |      
|Net earnings                                               | $ | 198.8 | $                                     | 170.2  | $ | 234.2 
|Weighted average common shares outstanding in the period   |   | 196.8 |                                       | 192.7  |   | 185.3 
|Earnings on a comparable basis per share                   | $ | 0.88  | $                                     | 0.66   | $ | 0.69  

SELECTED QUARTERLY FINANCIAL INFORMATION

|2005 Quarters                       |   | First |   | Second |   | Third |   | Fourth
|----------------------------------- | - | ----- | - | ------ | - | ----- | - | ------
|Revenue                             | $ | 684.3 | $ | 621.2  | $ | 722.9 | $ | 810.1 
|Earnings from continuing operations |   | 51.7  |   | 24.8   |   | 52.1  |   | 58.2  
|Net earnings                        |   | 51.7  |   | 24.8   |   | 52.1  |   | 70.2  
|Basic earnings per common share:    |   |       |   |        |   |       |   |       
|Continuing operations               |   | 0.27  |   | 0.13   |   | 0.27  |   | 0.29  
|Net earnings                        |   | 0.27  |   | 0.13   |   | 0.27  |   | 0.35  
|Diluted earnings per common share:  |   |       |   |        |   |       |   |       
|Continuing operations               |   | 0.26  |   | 0.13   |   | 0.27  |   | 0.29  
|Net earnings                        |   | 0.26  |   | 0.13   |   | 0.27  |   | 0.35  
|                                    |   |       |   |        |   |       |   |       
|2004 Quarters (Restated, Note 1)    |   | First |   | Second |   | Third |   | Fourth
|Revenue                             | $ | 655.0 | $ | 592.9  | $ | 678.2 | $ | 660.1 
|Earnings from continuing operations |   | 47.2  |   | 15.5   |   | 35.8  |   | 62.1  
|Net earnings                        |   | 47.2  |   | 25.1   |   | 35.8  |   | 62.1  
|Basic earnings per common share:    |   |       |   |        |   |       |   |       
|Continuing operations               |   | 0.25  |   | 0.08   |   | 0.18  |   | 0.32  
|Net earnings                        |   | 0.25  |   | 0.13   |   | 0.18  |   | 0.32  
|Diluted earnings per common share:  |   |       |   |        |   |       |   |       
|Continuing operations               |   | 0.24  |   | 0.08   |   | 0.18  |   | 0.32  
|Net earnings                        |   | 0.24  |   | 0.13   |   | 0.18  |   | 0.32  

Our results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected
to be lower as electricity prices generally increase in the winter months in the Canadian market. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring run-off and rainfall in the
Canadian and U.S. markets. Our results reflect the completion, acquisition, and disposition of plants and facilities throughout 2003, 2004 and 2005 as described previously within this MD&A.

| | MANAGEMENT'S DISCUSSION &
      ANALYSIS         67
| | ---------------------------------------------------

---

CERTIFICATIONTransAltas President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer have filed with the Securities and Exchange Commission (SEC) certifications regarding the quality of
TransAltas public disclosures relating to its fiscal 2005 reports filed with the SEC.

As at Dec. 31, 2005, our Management, together with our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, has evaluated the effectiveness of the design and operation of
our disclosure controls and procedures. Based upon this evaluation, our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer have concluded that our disclosure controls and procedures are
effective.

There were no changes in our internal controls over financial reporting during the fiscal year that have materially affected or are reasonably likely to materially affect our internal controls over financial
reporting.

FORWARD-LOOKING STATEMENTSThis MD&A contains forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta. In some cases, forward-looking statements can be identified by terms
such as may, will, believe, expect, potential, enable, continue or other comparable terminology. These statements are not guarantees of TransAltas future
performance and are subject to risks, uncertainties and other important factors that could cause the corporations actual performance to be materially different from those projected. Some of the risks, uncertainties, and factors include, but
are not limited to: legislative and regulatory developments that could affect revenues, costs, and the speed and degree of competition entering the market; global capital markets activity; timing and extent of changes in commodity prices, prevailing
interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where TransAlta operates; results of financing efforts; changes in counterparty risk; and the impact of accounting policies issued by
Canadian and U.S. standard setters. Given these uncertainties, the reader should not place undue reliance on these forward-looking statements. See additional discussion under Risk Factors and Risk Management in this MD&A.

TransAlta measures capacity as net maximum capacity (see Glossary for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation
unless otherwise stated.

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MANAGEMENT'S
RESPONSIBILITY

TransAltas management is responsible for presentation and preparation of the annual consolidated financial statements, managements discussion and analysis (MD&A) and all other information in this annual
report.

The accompanying consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and the requirements of the Securities and Exchange Commission (SEC) in the
United States, as applicable.

The MD&A has been prepared in accordance with the requirements of securities regulators including National Instruments 44-101 and 51-102 of the Canadian Securities Administrators as well as Item 303 of Regulation
S-K of the Securities Exchange Act, and their related published requirements.

The consolidated financial statements and information in the MD&A necessarily include amounts based on informed judgments and estimates of the expected effects of current events and transactions with appropriate
consideration for materiality. In addition, in preparing financial information, the corporation must interpret the requirements described above, make determinations as to the relevancy of information to be included, and make estimates and
assumptions that affect reported information. The MD&A also includes information regarding the estimated impact of current transactions and events, sources of liquidity and capital resources, operating trends, risks and uncertainties. Actual
results in the future may differ materially from managements present assessment of this information because future events and circumstances may not occur as expected.

The financial information presented elsewhere in this annual report is consistent with that in the consolidated financial statements.

To meet its responsibility for reliable and accurate financial statements, management has established systems of internal control which are designed to provide reasonable assurance that financial information is
relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with managements authorization. These systems are monitored by management and by internal auditors. In addition, the internal auditors
perform appropriate tests and related audit procedures.

The consolidated financial statements have been examined by Ernst & Young LLP, independent chartered accountants. The external auditors responsibility is to express a professional opinion on the fairness of
managements consolidated financial statements. The auditors report outlines the scope of their examination and sets forth their opinion.

The Audit and Environment (A&E) Committee of the Board of Directors is comprised of independent directors. The A&E Committee meets regularly with management, the internal auditors and the external auditors to
satisfy itself that each is properly discharging its responsibilities, and to review the consolidated financial statements and MD&A. The A&E Committee reports its findings to the Board of Directors for consideration when approving the
consolidated financial statements for issuance to the shareholders. The A&E Committee also recommends, for approval of shareholders, the appointment of the external auditors. The internal and external auditors have full and free access to the
A&E Committee.

TransAltas President and Chief Executive Officer, Executive Vice-President and Chief Financial Officer have certified TransAlta Corporations annual disclosure documents in the United States as required by
the U.S. Sarbanes-Oxley Act and in Canada by the Canadian securities regulators.

STEPHEN G. SNYDERPresident & Chief Executive Officer 
 February 16, 2006
      BRIAN BURDENExecutive Vice-President & Chief Financial Officer




| | CONSOLIDATED FINANCIAL
      STATEMENTS         69
| | --------------------------------------------------

---

REPORT OF
INDEPENDENT AUDITORS

To the Shareholders of TransAlta Corporation

We have audited the consolidated balance sheets of TransAlta Corporation as at December 31, 2005 and 2004 and the consolidated statements of earnings and retained earnings and cash flows for each of the years in the
three year period ended December 31, 2005. These financial statements are the responsibility of the Corporations management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Corporations internal control over financial reporting. An audit includes
consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Corporations internal
control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2005 and 2004 and the results of its operations and its
cash flows for each of the years in the three year period ended December 31, 2005 in conformity with Canadian generally accepted accounting principles.

As discussed in Note 1to the consolidated financial statements, in 2005 the Corporation changed its method of accounting for variable
interest entities.







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CONSOLIDATED STATEMENTS OF EARNINGS & RETAINED EARNINGS

|Year ended Dec. 31                                         | 2005      |                    | 2004               |   | 2003   
|---------------------------------------------------------- | --------- | ------------------ | ------------------ | - | -------
|(in millions of Canadian dollars except per share amounts) |           | (Restated, Note 1) | (Restated, Note 1)
|Revenues                                                   | $ 2,838.5 | $                  | 2,586.2            | $ | 2,413.5
|Trading purchases                                          | (174.1)   |                    | (197.7)            |   | (97.4) 
|Fuel and purchased power                                   | (1,201.8) |                    | (1,031.7)          |   | (990.8)
|Gross margin                                               | 1,462.6   |                    | 1,356.8            |   | 1,325.3
|Operations, maintenance and administration                 | 596.0     |                    | 547.5              |   | 540.8  
|Depreciation and amortization (Note 2)                     | 367.9     |                    | 357.5              |   | 329.8  
|Taxes, other than income taxes                             | 21.3      |                    | 20.5               |   | 22.9   
|Operating expenses                                         | 985.2     |                    | 925.5              |   | 893.5  
|Gain on sale of Sheerness Generating Station (Note 4)      |          |                    |                   |   | (191.5)
|Gain on sale of Meridian Cogeneration Facility (Note 4)    |          |                    | (17.7)             |   |       
|Gain on sale of TransAlta Power partnership units (Note 4) |          |                    | (44.8)             |   | (15.2) 
|Gain on sale of land (Note 4)                              |          |                    |                   |   | (10.5) 
|Asset impairment charges (Note 6)                          | 36.2      |                    |                   |   | 90.3   
|Prior period regulatory decision (Note 15)                 |          |                    | 22.9               |   |       
|                                                           | 36.2      |                    | (39.6)             |   | (126.9)
|Operating income                                           | 441.2     |                    | 470.9              |   | 558.7  
|Other expense                                              |          |                    |                   |   | (3.2)  
|Foreign exchange gain (loss)                               | 1.0       |                    | 0.7                |   | (4.7)  
|Net interest expense(Note 10)                              | (188.6)   |                    | (207.4)            |   | (212.1)
|Equity loss (Note 1)                                       | (0.9)     |                    | (8.5)              |   | (6.0)  
|Earnings before non-controlling interests and income taxes | 252.7     |                    | 255.7              |   | 332.7  
|Non-controlling interests(Note 12)                         | 18.5      |                    | 46.0               |   | 34.2   
|Earnings before income taxes                               | 234.2     |                    | 209.7              |   | 298.5  
|Income tax expense(Note 16)                                | 47.4      |                    | 49.1               |   | 64.3   
|Earnings from continuing operations                        | 186.8     |                    | 160.6              |   | 234.2  
|Earnings from discontinued operations, net of tax(Note 3)  | 12.0      |                    | 9.6                |   |       
|Net earnings                                               | 198.8     |                    | 170.2              |   | 234.2  
|Common share dividends                                     | (196.9)   |                    | (192.7)            |   | (185.0)
|Adjustment arising from normal course issuer bid(Note 13)  |          |                    | (1.1)              |   |       
|Retained earnings                                          |           |                    |                    |   |        
|Opening balance                                            | 910.3     |                    | 933.9              |   | 884.7  
|Closing balance                                            | $ 912.2   | $                  | 910.3              | $ | 933.9  
|Weighted average common shares outstanding in the year     | 196.8     |                    | 192.7              |   | 185.3  
|Basic earnings per share(Note 13)                          |           |                    |                    |   |        
|Earnings from continuing operations                        | $ 0.95    | $                  | 0.83               | $ | 1.26   
|Earnings from discontinued operations                      | 0.06      |                    | 0.05               |   |       
|Net earnings                                               | $ 1.01    | $                  | 0.88               | $ | 1.26   
|Diluted earnings per share(Note 13)                        |           |                    |                    |   |        
|Earnings from continuing operations                        | $ 0.95    | $                  | 0.83               | $ | 1.26   
|Earnings from discontinued operations                      | 0.06      |                    | 0.05               |   |       
|Net earnings                                               | $ 1.01    | $                  | 0.88               | $ | 1.26   

See accompanying notes.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         71
| | --------------------------------------------------

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C O N S O L I D A T E D
BALANCE SHEETS

|Dec. 31                                                    | 2005      |                    | 2004*    
|---------------------------------------------------------- | --------- | ------------------ | ---------
|(in millions of Canadian dollars)                          |           | (Restated, Note 1)
|ASSETS                                                     |           |                    |          
|Current assets                                             |           |                    |          
|Cash and cash equivalents                                  | $ 79.3    | $                  | 101.2    
|Accounts receivable (Note 20)                              | 593.4     |                    | 422.5    
|Prepaid expenses                                           | 75.8      |                    | 52.3     
|Price risk management assets(Note 18)                      | 63.8      |                    | 41.9     
|Future income tax assets (Note 16)                         | 26.6      |                    | 21.5     
|Income taxes receivable                                    | 48.8      |                    | 60.1     
|Inventory                                                  | 27.7      |                    | 39.9     
|Current portion of other assets (Note 8)                   | 10.9      |                    | 301.0    
|                                                           | 926.3     |                    | 1,040.4  
|Restricted cash(Note 4)                                    | 6.3       |                    | 8.9      
|Investments(Note 5)                                        | 414.3     |                    | 421.3    
|Property, plant and equipment(Note 6)                      |           |                    |          
|Cost                                                       | 8,411.8   |                    | 8,295.4  
|Accumulated depreciation                                   | (2,866.3) |                    | (2,592.8)
|                                                           | 5,545.5   |                    | 5,702.6  
|Goodwill(Note 4)                                           | 137.6     |                    | 142.2    
|Intangible assets(Note 7)                                  | 349.8     |                    | 392.3    
|Future income tax assets(Note 16)                          | 147.1     |                    | 132.0    
|Price risk management assets(Note18)                       | 13.8      |                    | 11.3     
|Other assets(Note 8)                                       | 200.0     |                    | 199.7    
|Total assets                                               | $ 7,740.7 | $                  | 8,050.7  
|LIABILITIES AND SHAREHOLDERS EQUITY                       |           |                    |          
|Current liabilities                                        |           |                    |          
|Short-term debt(Note 9)                                    | $ 13.1    | $                  | 34.4     
|Accounts payable and accrued liabilities                   | 590.3     |                    | 442.6    
|Price risk management liabilities(Note 18)                 | 58.3      |                    | 27.7     
|Income taxes payable                                       | 13.8      |                    | 6.1      
|Future income tax liabilities(Note 16)                     | 18.2      |                    | 11.1     
|Dividends payable                                          | 50.5      |                    | 19.3     
|Deferred credits and other current liabilities (Note 11)   | 0.4       |                    | 241.5    
|Current portion of long-term debt  recourse(Note 10)      | 354.2     |                    | 538.1    
|Current portion of long-term debt  non-recourse (Note 10) | 42.2      |                    | 42.0     
|                                                           | 1,141.0   |                    | 1,362.8  
|Long-term debt  recourse(Note 10)                         | 1,887.0   |                    | 1,939.8  
|Long-term debt  non-recourse(Note 10)                     | 321.6     |                    | 381.3    
|Preferred securities(Note 10)                              | 175.0     |                    | 175.0    
|Deferred credits and other long-term liabilities(Note 11)  | 365.5     |                    | 391.5    
|Future income tax liabilities(Note 16)                     | 740.3     |                    | 703.9    
|Price risk management liabilities(Note 18)                 | 8.6       |                    | 10.0     
|Non-controlling interests(Note 12)                         | 558.6     |                    | 616.4    
|Common shareholders equity                                |           |                    |          
|Common shares (Note 13)                                    | 1,697.9   |                    | 1,611.9  
|Retained earnings                                          | 912.2     |                    | 910.3    
|Cumulative translation adjustment                          | (67.0)    |                    | (52.2)   
|                                                           | 2,543.1   |                    | 2,470.0  
|Total liabilities and shareholders equity                 | $ 7,740.7 | $                  | 8,050.7  
|                                                           |           |                    |          
|Contingencies(Notes 15 and 22)                             |           |                    |          
|Commitments(Note 21)                                       |           |                    |          

* Derived from the audited Dec. 31, 2004 consolidated financial statements.

On behalf of the Board:
      
      DONNA SOBLE KAUFMANDirector
      WILLIAM D. ANDERSONDirector


|72         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

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C O N S O L I D A T E D S T A T E M E N T S O F
CASH FLOWS

|Year ended Dec. 31                                                | 2005    |                    | 2004               |   | 2003   
|----------------------------------------------------------------- | ------- | ------------------ | ------------------ | - | -------
|(in millions of Canadian dollars)                                 |         | (Restated, Note 1) | (Restated, Note 1)
|Operating activities                                              |         |                    |                    |   |        
|Net earnings                                                      | $ 198.8 | $                  | 170.2              | $ | 234.2  
|Depreciation and amortization(Note 2)                             | 400.9   |                    | 390.1              |   | 368.9  
|Prior period regulatory decision(Note 15)                         |        |                    | 22.9               |   |       
|Gain on sale of TransAlta Power partnership units (Note 4)        |        |                    | (44.8)             |   | (15.2) 
|Non-controlling interests                                         | 18.5    |                    | 46.0               |   | 34.2   
|Write-down of investments (Note 5)                                |        |                    |                   |   | 6.2    
|Asset retirement obligation accretion(Note 11)                    | 19.3    |                    | 19.3               |   | 22.0   
|Future income taxes (Note 16)                                     | 5.6     |                    | 17.8               |   | 27.4   
|Change in unrealized loss (gain) from energy marketing activities | 4.9     |                    | (9.7)              |   | (18.6) 
|Asset retirement obligation costs settled (Note 11)               | (29.4)  |                    | (19.7)             |   | (26.5) 
|Foreign exchange (gain) loss                                      | (1.0)   |                    | (0.7)              |   | 4.7    
|Asset impairment charge                                           | 36.2    |                    |                   |   | 90.3   
|Gain on sale of assets                                            |        |                    | (24.7)             |   | (202.0)
|Equity loss                                                       | 0.9     |                    | 8.5                |   | 6.0    
|Other non-cash items                                              | (3.0)   |                    |                   |   | 3.2    
|                                                                  | 651.7   |                    | 575.2              |   | 534.8  
|Change in non-cash operating working capital balances             | (32.3)  |                    | 16.0               |   | (60.5) 
|Cash flow from operating activities                               | 619.4   |                    | 591.2              |   | 474.3  
|Investing activities                                              |         |                    |                    |   |        
|Long-term receivables                                             |        |                    | 90.8               |   |       
|Additions to property, plant and equipment                        | (325.5) |                    | (345.7)            |   | (434.4)
|Proceeds on sale of property, plant and equipment (Note 4)        | 1.6     |                    | 43.2               |   | 226.7  
|Proceeds on sale of TransAlta Power partnership units (Note 4)    |        |                    | 116.5              |   | 37.2   
|Equity Investment                                                 | (9.3)   |                    | (10.1)             |   | (95.3) 
|Restricted cash (Note 4)                                          | 2.3     |                    | 1.1                |   | 46.7   
|Acquisitions (Note 4)                                             |        |                    |                   |   | (323.4)
|Proceeds on sale of long-term investments(Note 5)                 |        |                    |                   |   | 21.6   
|Realized foreign exchange gains on net investment hedges(Note 18) | 89.8    |                    | 47.8               |   | 194.1  
|Deferred charges and other                                        | (1.0)   |                    | (1.0)              |   | 11.8   
|Cash flow used in investing activities                            | (242.1) |                    | (57.4)             |   | (315.0)
|Financing activities                                              |         |                    |                    |   |        
|Repayment of short-term debt                                      | (23.6)  |                    | (85.4)             |   | (170.2)
|Repayment of long-term debt                                       | (139.3) |                    | (284.7)            |   | (601.1)
|Dividends on common shares                                        | (99.2)  |                    | (135.4)            |   | (158.3)
|Issuance of long-term debt                                        | 200.0   |                    | 2.7                |   | 544.6  
|Redemption of common shares                                       |        |                    | (2.3)              |   |       
|Net proceeds on issuance of common shares                         | 19.6    |                    | 3.4                |   | 265.0  
|Distributions to subsidiaries non-controlling limited partner    | (77.5)  |                    | (48.4)             |   | (38.9) 
|Redemption of preferred securities                                | (300.0) |                    |                   |   |       
|Deferred financing charges and other                              |        |                    | (1.2)              |   | (6.6)  
|Reduction in advance to TransAlta Power (Note 4)                  | 23.7    |                    | 2.0                |   |       
|Cash flow used in financing activities                            | (396.3) |                    | (549.3)            |   | (165.5)
|Cash flow from operating, investing and financing activities      | (19.0)  |                    | (15.5)             |   | (6.2)  
|Effect of translation on foreign currency cash                    | (2.9)   |                    | (7.1)              |   | (7.2)  
|Increase in cash and cash equivalents                             | (21.9)  |                    | (22.6)             |   | (13.4) 
|Cash and cash equivalents, beginning of year                      | 101.2   |                    | 123.8              |   | 137.2  
|Cash and cash equivalents, end of year                            | $ 79.3  | $                  | 101.2              | $ | 123.8  
|Cash taxes paid                                                   | $ 14.7  | $                  | 4.6                | $ | 34.1   
|Cash interest paid                                                | $ 183.7 | $                  | 218.2              | $ | 215.4  

| | CONSOLIDATED FINANCIAL
      STATEMENTS         73
| | --------------------------------------------------

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NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS(Tabular dollar amounts in millions of Canadian dollars, except as otherwise noted)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Consolidation
These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects
from United States generally accepted accounting principles (U.S. GAAP). The significant differences are described in
Note 25.

The consolidated financial statements include the accounts of TransAlta Corporation (TransAlta or the corporation), all subsidiaries and the proportionate share of the accounts of joint ventures and jointly controlled
corporations.

B. Use of Estimates and Measurement Uncertainty
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, currency exchange rates,
inflation levels and commodity prices, changes in economic conditions and legislative and regulatory changes
(Notes 7, 17, 18 and 22).

C. Revenue Recognition
The majority of the corporations revenues are derived from the sale of physical power and from energy marketing and trading activities. Revenues under long-term electricity and thermal sales contracts generally
include one or more of the following components: fixed capacity payments for being available, energy payments for generation of electricity, incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power
generation above committed capacity and ancillary services. Each is recognized upon output, delivery, or satisfaction of specific targets, all as specified by contractual terms. Revenues from non-contracted capacity are comprised of energy payments
for each megawatt hour (MWh) produced at market prices, and are recognized upon delivery.

Derivatives used in trading activities include physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn trading revenues and to gain market information. These
derivatives are accounted for using the fair value method of accounting. Derivatives, other than real-time physical contracts, are presented on a net basis in the statements of earnings. Real-time physical contracts meet the definition of derivative
contracts held for delivery and therefore realized gains and losses are reported gross in the consolidated statements of earnings. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the
change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as price risk management assets and liabilities. Non-derivative trading
contracts are accounted for using the accrual method.

The majority of the corporations derivatives have quoted market prices on active exchanges or over-the-counter quotes are available from brokers. However, some derivatives are not traded on an active exchange or
the contracts extend beyond the time period for which market-based quotes are available, requiring the use of internal valuation techniques or models (mark-to-model accounting).

D. Discontinued Operations
The results of discontinued operations are presented net of tax on a one-line basis in the consolidated statements of earnings. Interest expense, direct corporate overheads and income taxes are allocated to
discontinued operations. General corporate overheads are not allocated to discontinued operations.

E. Inventory
The corporations inventory balance represents fuel which is valued at the lower of cost and market value, defined as net replacement value. Inventory cost is determined using moving average cost. The costing
method used is direct costing which is determined as the sum of all applicable expenditures and charges directly or indirectly incurred in bringing an inventory item to its existing condition and location.

F. Property, Plant and Equipment
The corporations investment in property, plant and equipment (PP&E) is stated at original cost at the time of construction, purchase or acquisition. Original cost includes items such as materials,
labour,
interest and other appropriately allocated costs. As costs are expended for new construction, the entire amount is capitalized as PP&E on the consolidated balance sheet and is subject to depreciation upon commencement of commercial operations.
The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor parts, are charged to expense as incurred. Certain expenditures relating to replacement of components incurred during major
maintenance are capitalized and amortized over the estimated benefit period of such expenditures. A component is a tangible portion of the asset that can be separately identified as an asset and depreciated over its own expected useful life, and is
expected to provide a benefit of greater than one year.

The estimate of the useful life of PP&E is based on current facts and past experience, and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand and the potential
for technological obsolescence. The useful life is used to estimate the rate at which the PP&E is depreciated or amortized. These estimates are subject to revision in future periods based on new or additional information.

|74         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

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Depreciation and amortization is calculated using straight-line, declining balance and unit-of-production methods. Coal rights are amortized on a unit of production basis, based on the estimated mine
reserves.

TransAlta capitalizes interest on capital invested in projects under construction. Upon commencement of commercial operations, capitalized interest, as a portion of the total cost of the plant, is amortized over the
estimated useful life of the plant.

On an annual basis, and when indicators of impairment exist, TransAlta determines whether the net carrying amount of PP&E is recoverable from future undiscounted cash flows. Factors that could indicate an
impairment exists include significant underperformance relative to historical or projected future operating results, significant changes in the manner or use of the assets, significant negative industry or economic trends or a change in the strategy
for the corporations overall business. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over
a period of time leading to an indication that an asset may be impaired. This can be further complicated where TransAlta is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their
occurrence.

The corporations businesses, the markets and business environment are continually monitored, and judgments and assessments are made to determine whether an event has occurred that indicates possible impairment.
If such an event has occurred, an estimate is made of future undiscounted cash flows from the PP&E. If the total of the undiscounted future cash flows, excluding financing charges with the exception of plants that have specifically dedicated
debt, is less than the carrying amount of the PP&E, an asset impairment must be recognized in the financial statements. The amount of the impairment charge to be recognized is calculated by subtracting the fair value of the asset from the
carrying value of the asset. Fair value is the amount at which an item could be bought or sold in a current transaction between willing parties, and is normally estimated by calculating the present value of expected future cash flows related to the
asset.

G. Goodwill
Goodwill is the cost of an acquisition less the fair value of the net assets of an acquired business. Goodwill and certain intangibles are not subject to amortization, but are instead tested for impairment at least
annually, or more frequently if an analysis of events and circumstances indicate that a possible impairment may arise earlier. These events could include a significant change in financial position of the reporting unit to which the goodwill relates
or significant negative industry or economic trends. To test for impairment, the fair value of the reporting units to which the goodwill relates is compared to the carrying values of the reporting units. The corporation determined that the fair
values of the reporting units, based on historical cash flows and estimates of future cash flows, exceeded their carrying values. There was no impairment of goodwill at Dec. 31, 2005 or 2004.

H. Intangible Assets
Intangible assets consist of power sale contracts, with rates higher than market rates at the date of acquisition, acquired in the purchase of CE Generation LLC (CE Gen), a jointly controlled enterprise
(Note 4). Sale contracts are valued at cost and are amortized on a straight-line basis over the remaining contract period, which ranges from seven to 30 years at the date of
acquisition.

I. Asset Retirement Obligations
The corporation recognizes asset retirement obligations in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The associated asset retirement costs are capitalized as part
of the carrying amount of the long-lived asset. The liability is accrued over the estimated time period until settlement of the obligation and the asset is depreciated over the estimated useful life of the asset. Reclamation costs for mining assets
were recognized on a unit-of-production basis. No provision for future site restoration for gas generation plants had been recorded as the costs of restoration are expected to be offset by the salvage value of the related plant.

TransAlta recorded an asset retirement obligation for all generating facilities for which it is legally required to remove the facilities at the end of their useful lives and restore the plant and mine sites to their
original condition. For the hydro facilities, the corporation is required to remove the generating equipment, but is not legally required to remove the structures. TransAlta has recognized legal obligations arising from government legislation,
written agreements between entities and case law. The asset retirement liabilities are recognized when the asset retirement obligation is incurred. Asset retirement liabilities for coal mines are incurred over time, as new areas are mined, and a
portion of the liability is settled over time as areas are reclaimed prior to final pit reclamation.

J. Investments
Effective Jan. 1, 2005, TransAlta retroactively adopted the new Canadian Institute of Chartered Accountants
(CICA) Accounting Guideline 15 Consolidation of Variable Interest Entities. The wholly-owned
subsidiaries that hold TransAltas interests in the Campeche and Chihuahua power plants are considered VIEs and are shown as equity investments. Investments in shares of companies over which the corporation exercises significant influence are
accounted for using the equity method. Other investments are carried at cost. If there is an other than temporary decline in the value of an investment, it is written down to net realizable value.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         75
| | --------------------------------------------------

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K. Other Assets
Deferred licence fees and deferred contract costs are amortized on a straight-line basis over the useful life of the related assets or long-term contracts.

Financing costs for the issuance of long-term debt and preferred securities are amortized to earnings on a straight-line basis over the term of the related issue.

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

L. Income Taxes
The corporation uses the liability method of accounting for income taxes for its operations. Under the liability method, income taxes are recognized for the differences between financial statement carrying values and
the respective income tax basis of assets and liabilities (temporary differences), and the carry forward of unused tax losses. Future income tax assets and liabilities are measured using income tax rates expected to apply in the years in which
temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in tax rates is included in earnings in the period the change is substantively enacted. Future income tax assets are
evaluated annually and if realization is not considered more likely than not, a valuation allowance is provided.

M. Employee Future Benefits
The corporation accrues its obligations under employee benefit plans and the related costs, net of plan assets. The cost of pensions and other post-employment and post-retirement benefits earned by employees is
actuarially determined using the projected benefit method pro-rated on services and managements best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. The defined
benefit pension plans are based on an employees final average earnings and years of service. Pension benefits will increase annually by two per cent. The expected return on plan assets is based on the historical returns earned by assets of
similar risk and performance. The discount rate used to calculate the interest cost on the accrued benefit obligation is determined by reference to market interest rates at the balance sheet date on high-quality debt instruments with cash flows that
match the timing and amount of expected benefit payments. Past service costs from plan amendments are amortized on a straight-line basis over the estimated average remaining service period of employees active at the date of amendment
(EARSL). If the
cumulative net unamortized gain or loss exceeds 10 per cent of the accrued benefit obligations or the market value of the plan assets, whichever is greater, the amount in excess of this 10 per cent and threshold is amortized to earnings over
EARSL.
When the restructuring of a benefit plan gives rise to both a curtailment and settlement of obligations, the curtailment is accounted for prior to the settlement. Transition obligations and assets arising from the prospective adoption of new
accounting standards are amortized over EARSL.

N. Foreign Currency Translation
The corporations self-sustaining foreign operations are translated using the current rate method. Translation gains and losses are deferred and included in the cumulative translation adjustment
(CTA) account in
shareholders equity. Foreign currency denominated monetary and non-monetary assets and liabilities are translated at exchange rates in effect on the balance sheet date.

Transactions denominated in foreign currencies are translated at the exchange rate on the transaction date. The resulting exchange gains and losses on these items are included in net earnings.

O. Derivatives and Financial Instruments
Derivatives used in trading activities are described in Note 1(C).

Physical and financial swaps, forward sales contracts, futures contracts and options are used to hedge the corporations exposure to fluctuations in electricity and natural gas prices related to output from the
plants. Under Canadian GAAP, if hedging criteria are met (described below), gains and losses on these derivatives are recognized in earnings in the same period and financial statement caption as the hedged exposure (settlement accounting). The
derivatives are not recorded on the balance sheet.

Cross-currency interest rate swaps, foreign currency forward contracts and foreign currency debts are used to hedge exposure to changes in the carrying values of the corporations net investments in foreign
operations as a result of changes in foreign exchange rates. Under Canadian GAAP, gains and losses on the principal component of the cross-currency interest rate swaps as well as gains and losses on the forward sales contracts and foreign currency
long-term debt are deferred and included in CTA. The gains and losses on the principal component of the cross-currency interest rate swaps as well as the gains and losses on forward sales contracts are deferred and recorded in other assets
(Note 8)or deferred credits and other long-term liabilities (Note 11)as
appropriate.

|76         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

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Foreign currency forward contracts are used to hedge the foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies. Under Canadian GAAP, if hedge criteria
are met, these derivatives are not recognized on the balance sheet. Upon settlement of the derivative, any gain or loss on the forward contracts is deferred and included in other assets
(Note 8)or deferred credits and other long-term liabilities (Note 11), and is included in the cost of the asset or liability when
the asset is purchased and depreciated over the assets estimated useful life (settlement accounting).

Interest rate swaps are used to manage the impact of fluctuating interest rates on existing debt. These instruments are not recognized on the balance sheet under Canadian GAAP. Interest rate swaps require the periodic
exchange of payments without the exchange of the notional principal amount on which the payments are based. If hedge criteria are met, interest expense on the debt is adjusted to include the payments made or received under the interest rate swaps
(settlement accounting).

To be accounted for as a hedge under both Canadian and U.S. GAAP, a derivative must be designated and documented as a hedge, and must be effective at inception and on an ongoing basis. The documentation defines all
relationships between hedging instruments and hedged items, as well as the corporations risk management objective and strategy for undertaking various hedge transactions. The process includes linking derivatives to specific assets and
liabilities on the balance sheet or to specific firm commitments or anticipated transactions. The corporation also formally assesses, both at the hedges inception and on an ongoing basis, whether the derivatives used are highly effective in
offsetting changes in fair values or cash flows of hedged items. Hedge effectiveness of cash flows is achieved if the derivatives cash flows substantially offset the cash flows of the hedged item and the timing of the cash flows is similar.
Hedge effectiveness of fair values is achieved if changes in the fair value of the derivative substantially offset changes in the fair value of the item hedged. If a hedge is determined to be ineffective, U.S. and Canadian GAAP require the
ineffective portion to be recognized in earnings in the current period. If the above hedge criteria are not met, the derivative is accounted for on the balance sheet at fair value, with the initial fair value and subsequent changes in fair value
recorded in earnings in the period of change.

If a derivative that has been accorded hedge accounting matures, expires, is sold, terminated or cancelled, and is not replaced as part of the corporations hedging strategy, the termination gain or loss is
deferred and recognized when the gain or loss on the item hedged is recognized. If a designated hedged item matures, expires, is sold, extinguished or terminated, or the hedged item is no longer probable of occurring, any previously deferred amounts
associated with the hedging item are recognized in current earnings along with the corresponding gains or losses recognized on the hedged item. If a hedging relationship is terminated or ceases to be effective, hedge accounting is not applied to
subsequent gains or losses. Any previously deferred amounts are carried forward and recognized in earnings in the same period as the hedged item.

P. Stock-based Compensation Plans
The corporation has three types of stock-based compensation plans comprised of two stock option-based plans, and a Performance Share Ownership Plan (PSOP), described in
Note
14. Under the fair value method, compensation expense is measured at the grant date at fair value and recognized over the service period. Effective Jan. 1, 2003, the corporation elected to prospectively use
the fair value method of accounting for stock-based compensation arrangements. In 2005, the corporation granted options to purchase 1.2 million common shares of the corporation to its employees at a weighted average exercise price of $17.80 per
common share. Note 14provides pro forma measures of net earnings and earnings per share had compensation expense been recognized for awards granted prior to 2003
based on the estimated fair value of the options on the grant date in accordance with the fair value method of accounting for stock-based compensation.

Stock grants under PSOP are accrued in corporate operations, maintenance and administration (OM&A) expense as earned to the balance sheet date, based upon the percentile ranking of the total shareholder return of
the corporations common shares in comparison to the total shareholder returns of companies comprising the S&P/TSX composite index. Compensation expense under the phantom stock option plan is recognized in OM&A expense for the amount by
which the quoted market price of TransAltas shares exceed the option price, and adjusted for changes in each period for changes in the excess over the option price. If stock options or stock are repurchased from employees, the excess of the
consideration paid over the carrying amount of the stock option or stock cancelled is charged to retained earnings.

Q. Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

R. Changes in Accounting Standards
Effective Jan. 1, 2005, TransAlta adopted the CICA Accounting Guideline 15 Consolidation of Variable Interest Entities (VIE). The guideline establishes that a VIE is to be consolidated by the primary
beneficiary based upon the determination of who will receive the majority of a VIEs expected losses, expected residual returns, or both, rather than solely based on the voting interests. Variable interests are ownership interests or
contractual relationships that enable the holder to share in the financial risks and rewards resulting from the activities of a VIE.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         77
| | --------------------------------------------------

---

The accounting guideline specifies that an entity is a VIE if either of the following criteria are met:

1. total equity invested is insufficient to finance the entity without additional subordinated financial support; or
2. the holders of the equity investment, as a group,

i) do not have the right to make decisions about
an entitys activities that have a significant effect on the success of the entity; or 
 ii) are protected either directly or indirectly from variability in cash flows from the entity; or 
 iii) do not have the right to all of the residual returns
of the entity.

The corporation has considered the provisions of the guideline for all subsidiaries and their related power purchase, power sale or tolling agreements. Factors considered in the analysis include the duration of the
agreements, how capacity and energy payments are determined, source of payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses.

As a result of this review, the corporation determined that the wholly-owned subsidiary that holds TransAltas interest in the Campeche power plant is considered a VIE as the equity invested was not sufficient to
finance the entity without additional subordinated financial support. The corporation then determined that the power sale contract with the Comisión Federal de Electricidad
(CFE) insulates the corporation from significant variability in the
fuel costs and related cash flows from the entity. Therefore, TransAlta is not the primary beneficiary of the VIE and does not consolidate the entity. Accordingly, the subsidiary owning the Campeche plant is presented as an equity investment and the
results from operations are presented as equity income on the consolidated income statement. There was no impact to net earnings as a result of adoption of this accounting guideline.

As a result of this review, the corporation determined that the wholly-owned subsidiary that holds TransAltas interest in the Chihuahua power plant is considered a VIE as the power sale contract with the CFE
indirectly protects TransAlta from the variability in the fuel costs and related cash flows from the entity. Therefore the entity is a VIE and as TransAlta is not the primary beneficiary of the VIE, it does not consolidate the entity. Accordingly,
the subsidiary owning the Chihuahua plant is presented as an equity investment and the results from operations of the plant are presented as equity income on the consolidated income statement. There was no impact to net earnings as a result of
adoption of this interpretation.

The following is summary information about the subsidiaries holding the Campeche and Chihuahua plants:

|Dec. 31                  |          |   | 2005      |   |          |   | 2004     
|------------------------ | -------- | - | --------- | - | -------- | - | ---------
|                         | Campeche |   | Chihuahua |   | Campeche |   | Chihuahua
|Total assets             | $ 276.9  | $ | 302.6     | $ | 280.1    | $ | 318.3    
|Total liabilities        | $ 184.1  | $ | 7.2       | $ | 187.7    | $ | 8.4      
|Maximum exposure to loss | $ 93.7   | $ | 307.9     | $ | 89.7     | $ | 328.6    
|Capacity (MW)            | 252      |   | 259       |   | 252      |   | 259      
|Annual production (GWh)  | 1,683    |   | 1,067     |   | 1,742    |   | 1,422    

A. Description of Reportable SegmentsThe corporation has two reportable segments: Generation and Energy Marketing. TransAltas segments are supported by a corporate group that provides finance, treasury, information technology, legal, environmental
health & safety, human resources and other administrative support. These corporate group overheads are allocated to the business segments based on budgeted gross salaries.

Each business segment assumes responsibility for its operating results measured as operating income or loss. Operating income is not defined under Canadian or U.S. GAAP. Operating income is calculated as net earnings
before discontinued operations, income taxes, non-controlling interests, equity losses, foreign exchange gains and losses, and net interest expense.

The Generation segment owns coal, gas, wind, geothermal and hydro power plants in Canada, the United States and Australia, and generates its revenue from the sale of electricity, steam, gas and ancillary services.
Generation expenses include Energy Marketings intersegment charge for energy marketing and financial risk management services in the amount of $26.0 million (2004  $26.0 million; 2003  $24.8 million).

The Energy Marketing segment derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives not supported by TransAlta-owned generation assets. Energy
Marketing also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available generating capacity and fuel and transmission needs on behalf of
Generation. These results are included in the Generation segment. Operating expenses are net of the intersegment charges for provision of these energy marketing, financial risk management, commercial, portfolio and regulatory management
services.

The accounting policies of the segments are the same as those described inNote 1. Intersegment transactions are accounted for on a
cost recovery basis that approximates market rates. Segment revenues are net of intersegment transactions.

|78         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

B. Reported Segment Earnings and Segment AssetsI. Earnings information

|Year ended Dec. 31, 2005                                | Generation |   | Marketing |   | Corporate |   | Total    
|------------------------------------------------------- | ---------- | - | --------- | - | --------- | - | ---------
|Revenues                                                | $ 2,607.5  | $ | 231.0     | $ |          | $ | 2,838.5  
|Trading purchases                                       |           |   | (174.1)   |   |          |   | (174.1)  
|Fuel and purchased power                                | (1,201.8)  |   |          |   |          |   | (1,201.8)
|Gross margin                                            | 1,405.7    |   | 56.9      |   |          |   | 1,462.6  
|Operations, maintenance and administration              | 507.1      |   | 12.5      |   | 76.4      |   | 596.0    
|Depreciation and amortization                           | 354.9      |   | 1.7       |   | 11.3      |   | 367.9    
|Taxes, other than income taxes                          | 21.3       |   |          |   |          |   | 21.3     
|Operating expenses                                      | 883.3      |   | 14.2      |   | 87.7      |   | 985.2    
|Asset impairment charges                                | (36.2)     |   |          |   |          |   | (36.2)   
|Operating income (loss) before corporate allocations    | 486.2      |   | 42.7      |   | (87.7)    |   | 441.2    
|Corporate allocations                                   | (76.4)     |   | (11.3)    |   | 87.7      |   |         
|Operating income                                        | $ 409.8    | $ | 31.4      | $ |          | $ | 441.2    
|Foreign exchange gain                                   |            |   |           |   |           |   | 1.0      
|Net interest expense                                    |            |   |           |   |           |   | (188.6)  
|Equity loss                                             |            |   |           |   |           |   | (0.9)    
|Earnings from continuing operations before income taxes |            |   |           |   |           |   |          
|and non-controlling interests                           |            |   |           |   |           | $ | 252.7    
|                                                        |            |   | Energy    |   |           |   |          
|Year ended Dec. 31, 2004(Restated, Note 1)              | Generation |   | Marketing |   | Corporate |   | Total    
|Revenues                                                | $ 2,341.7  | $ | 244.5     | $ |          | $ | 2,586.2  
|Trading purchases                                       |           |   | (197.7)   |   |          |   | (197.7)  
|Fuel and purchased power                                | (1,031.7)  |   |          |   |          |   | (1,031.7)
|Gross margin                                            | 1,310.0    |   | 46.8      |   |          |   | 1,356.8  
|Operations, maintenance and administration              | 476.0      |   | 5.3       |   | 66.2      |   | 547.5    
|Depreciation and amortization                           | 343.5      |   | 2.0       |   | 12.0      |   | 357.5    
|Taxes, other than income taxes                          | 20.5       |   |          |   |          |   | 20.5     
|Operating expenses                                      | 840.0      |   | 7.3       |   | 78.2      |   | 925.5    
|Prior period regulatory decision                        |           |   | (22.9)    |   |          |   | (22.9)   
|Gain on sale of TransAlta Power partnership units       | 44.8       |   |          |   |          |   | 44.8     
|Gain on sale of Meridian Cogeneration Facility          | 17.7       |   |          |   |          |   | 17.7     
|Operating income (loss) before corporate allocations    | 532.5      |   | 16.6      |   | (78.2)    |   | 470.9    
|Corporate allocations                                   | (69.7)     |   | (8.5)     |   | 78.2      |   |         
|Operating income                                        | $ 462.8    | $ | 8.1       | $ |          | $ | 470.9    
|Foreign exchange gain                                   |            |   |           |   |           |   | 0.7      
|Net interest expense                                    |            |   |           |   |           |   | (207.4)  
|Equity loss                                             |            |   |           |   |           |   | (8.5)    
|Earnings from continuing operations before income taxes |            |   |           |   |           |   |          
|and non-controlling interests                           |            |   |           |   |           | $ | 255.7    

| | CONSOLIDATED FINANCIAL
      STATEMENTS         79
| | --------------------------------------------------

---

|                                                        |            |   | Energy    |   |           |   |        
|------------------------------------------------------- | ---------- | - | --------- | - | --------- | - | -------
|Year ended Dec. 31, 2003(Restated, Note 1)              | Generation |   | Marketing |   | Corporate |   | Total  
|Revenues                                                | $ 2,304.8  | $ | 108.7     | $ |          | $ | 2,413.5
|Trading purchases                                       |           |   | (97.4)    |   |          |   | (97.4) 
|Fuel and purchased power                                | (990.8)    |   |          |   |          |   | (990.8)
|Gross margin                                            | 1,314.0    |   | 11.3      |   |          |   | 1,325.3
|Operations, maintenance and administration              | 461.5      |   | 14.9      |   | 64.4      |   | 540.8  
|Depreciation and amortization                           | 312.4      |   | 3.1       |   | 14.3      |   | 329.8  
|Taxes, other than income taxes                          | 22.9       |   |          |   |          |   | 22.9   
|Operating expenses                                      | 796.8      |   | 18.0      |   | 78.7      |   | 893.5  
|Asset impairment and equipment cancellation charges     | (90.3)     |   |          |   |          |   | (90.3) 
|Gain on sale of Sheerness Generating Station            | 191.5      |   |          |   |          |   | 191.5  
|Gain on sale of land                                    | 10.5       |   |          |   |          |   | 10.5   
|Gain on sale of TransAlta Power partnership units       | 15.2       |   |          |   |          |   | 15.2   
|Operating income (loss) before corporate allocations    | 644.1      |   | (6.7)     |   | (78.7)    |   | 558.7  
|Corporate allocations                                   | (69.9)     |   | (8.8)     |   | 78.7      |   |       
|Operating income (loss)                                 | $ 574.2    | $ | (15.5)    | $ |          | $ | 558.7  
|Other income                                            |            |   |           |   |           |   | (3.2)  
|Foreign exchange loss                                   |            |   |           |   |           |   | (4.7)  
|Net interest expense                                    |            |   |           |   |           |   | (212.1)
|Equity loss                                             |            |   |           |   |           |   | (6.0)  
|Earnings from continuing operations before income taxes |            |   |           |   |           |   |        
|and non-controlling interests                           |            |   |           |   |           | $ | 332.7  

II. Selected Balance Sheet Information

|                                           |            |   | Energy    |   |           |          
|------------------------------------------ | ---------- | - | --------- | - | --------- | ---------
|Dec. 31, 2005                              | Generation |   | Marketing |   | Corporate | Total    
|Goodwill                                   | $ 108.1    | $ | 29.5      | $ |          | $ 137.6  
|Total Segment assets                       | $ 6,508.2  | $ | 293.2     | $ | 939.3     | $ 7,740.7
|                                           |            |   | Energy    |   |           |          
|Dec. 31, 2004(Restated, Note 1)            | Generation |   | Marketing |   | Corporate | Total    
|Goodwill                                   | $ 112.7    | $ | 29.5      | $ |          | $ 142.2  
|Total Segment assets                       | $ 6,705.6  | $ | 221.6     | $ | 1,123.5   | $ 8,050.7
|III. Selected Cash Flow Information        |            |   |           |   |           |          
|                                           |            |   | Energy    |   |           |          
|Year ended Dec. 31, 2005                   | Generation |   | Marketing |   | Corporate | Total    
|Capital expenditures                       | $ 313.2    | $ | 1.5       | $ | 10.8      | $ 325.5  
|                                           |            |   | Energy    |   |           |          
|Year ended Dec. 31, 2004(Restated, Note 1) | Generation |   | Marketing |   | Corporate | Total    
|Capital expenditures                       | $ 332.3    | $ | 2.3       | $ | 11.1      | $ 345.7  
|                                           |            |   | Energy    |   |           |          
|Year ended Dec. 31, 2003(Restated, Note 1) | Generation |   | Marketing |   | Corporate | Total    
|Capital expenditures                       | $ 421.1    | $ | 0.8       | $ | 12.5      | $ 434.4  
|Acquisitions                               | $ 323.4    | $ |          | $ |          | $ 323.4  

|80         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

IV. Reconciliation

Year ended Dec. 31
	2005
	
	2004
	
	2003(Restated, Note 1)
	(Restated, Note 1)Depreciation and amortization expense for reportable segments
	$ 367.9
	$
	357.5
	$
	329.8Mining equipment depreciation, included in fuel and purchased power
	49.9
	
	53.3
	
	47.1Accretion expense, included in depreciation and amortization expense
	(19.3)
	
	(19.3)
	
	(22.0)Other
	2.4
	
	(1.4)
	
	14.0Depreciation and amortization expense per statements of cash flows
	$ 400.9
	$
	390.1
	$
	368.9


C. Geographic InformationI. Revenues

Year ended Dec. 31
	
	2005
	
	2004
	
	2003(Restated, Note 1)
	(Restated, Note 1)Canada
	$
	1,716.1
	$
	1,662.7
	$
	1,412.4U.S.
	
	1,026.2
	
	833.0
	
	918.8Australia
	
	96.2
	
	90.5
	
	82.3$
	2,838.5
	$
	2,586.2
	$
	2,413.5


II. Property, Plant and Equipment and Goodwill

PP&E
	
	
	
	GoodwillDec. 31
	
	2005
	
	2004
	
	2005
	
	2004(Restated, Note 1)Canada
	$
	3,789.3
	$
	3,858.7
	$
	56.5
	$
	56.5U.S.
	
	1,585.0
	
	1,657.2
	
	81.1
	
	85.7Australia
	
	171.2
	
	186.7
	
	
	
	$
	5,545.5
	$
	5,702.6
	$
	137.6
	$
	142.2


A. TransmissionIn June 2004, a settlement was reached to finalize the sale of the corporations Transmission operations. In April 2002, the Transmission operations were sold for proceeds of $820.7 million. The disposal
resulted in an after-tax gain on sale of $120.0 million that was recorded in 2002. During 2004, final working capital adjustments were made to reflect post-closing adjustments and other provisions related to closing costs, which resulted in an
additional $9.6 million after-tax gain.

B. Alberta Distribution and Retail (D&R)In August 2000, the corporation sold its Alberta D&R business for proceeds of $857.3 million. The original gain recorded on this transaction was $262.4 million. During the fourth quarter of 2005, the
corporation settled an outstanding income tax dispute related to this business. Included in earnings from discontinued operations for the year ended Dec. 31, 2005 is $12.0 million related to this matter. The settlement of this issue brings the
final gain on disposal of the Alberta D&R business to $274.4 million. In 2005, $12.0 million related to the favourable resolution of a tax dispute related to the Transmission operations was included in net earnings.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         81
| | --------------------------------------------------

---

A. AcquisitionsOn Jan. 29, 2003, the corporation acquired a 50 per cent interest in CE Gen for US$240.0 million (Cdn$366.6 million). The acquisition was accounted for using the purchase method of accounting. CE Gen is
controlled jointly by TransAlta and MidAmerican Energy Holdings Company (MidAmerican). As such, the financial results of CE Gen subsequent to the acquisition date are proportionately consolidated with those of TransAlta and are included in the
Generation segment. The purchase price was finalized in the second quarter of 2003 and is presented below:

Net assets acquired at assigned values:Working capital, including cash of $43.2 million
	$ 60.3Restricted cash
	57.9Current income tax receivable
	2.4Property, plant and equipment
	414.6Intangibles
	610.5Goodwill
	108.9Note receivable
	90.0Non-recourse long-term debt, including current portion
	(717.4)Future income tax liability
	(216.0)Non-controlling interests
	(44.6)Total
	$ 366.6Consideration:Cash
	$ 366.6


Goodwill resulted from the purchase of PP&E with no tax basis.

The restricted cash is comprised of debt service funds which are legally restricted, and require the maintenance of specific minimum balances equal to the next debt service payment, and amounts restricted for capital
and maintenance expenditures. The amount of restricted cash acquired has been reduced subsequent to the acquisition primarily as a result of TransAlta issuing a letter of credit in lieu of holding the restricted cash(Note 10).

B. DisposalsOn Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220 megawatt (MW) Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TransAlta Cogeneration, L.P. (TA Cogen), owned
50.01% by TransAlta and 49.99% by TransAlta Power, L.P. (TA Power), for its fair value of $110.0 million. TA Cogen financed the acquisition through the use of $50.0 million of cash on hand, by the issuance of $30.0 million of units to
each of TransAlta Energy Corporation (TEC) and TA Power and by an advance to TEC for $30.0 million. The advance outstanding at Dec. 31, 2005 was $5.0 million (2004  $18.0 million) and is included in accounts receivable.

On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit 756 MW coal-fired Sheerness Generating Station to TA Cogen. As part of the financing, and concurrent with the sale, TA Power
issued 17.75 million partnership units and 17.75 million warrants to the public, and 17.75 million partnership units to TransAlta. As a result of the unit issuance, TransAltas ownership interest in TA Power on July 31, 2003 was approximately
26 per cent. Each warrant, when exercised, was exchangeable for one TA Power unit at any time until Aug. 3, 2004. As the warrants were exercised, TransAlta sold TA Power units back to TA Power for $9.30 per unit, reducing its ownership interest
in TA Power and increasing cash proceeds. As a result of exercising warrants and the subsequent sale of TA Power units by the corporation, TransAltas ownership interest in TA Power was reduced to 0.01 per cent held by TransAlta Power Ltd., the
general partner of TA Power, as at Dec. 31, 2004.

As a result of the sale, TransAlta realized a gain on sale of $191.5 million recorded in 2003, which included the realization of the $119.8 million 1998 deferred gain related to the disposition of the Ottawa,
Windsor and Mississauga cogeneration facilities. Proceeds from the sale of the Sheerness Generating Station were used to repay debt. For the year ended Dec. 31, 2005, TransAlta recognized $ nil (2004  $44.8 million) of dilution gains
on the exercise of warrants and subsequent sale of units. Prior to Aug. 3, 2004, 10.4 million warrants were exercised while a further 0.3 million units were sold in the third quarter of 2004 subsequent to the expiry of the warrants. In the fourth
quarter of 2004, TransAlta sold 7.1 million units for net proceeds of $64.0 million.

On Dec. 31, 2003, TransAlta completed the sale of 539 acres of undeveloped land at Seebe, Alberta for $11.0 million, resulting in a pre-tax gain on sale of $10.5 million.

On May 9, 2003, TransAlta sold the Calgary head office building for $65.8 million, which was an agreed upon value. TransAlta is leasing the property for a term of 20 years. The lease is accounted for as an
operating lease.

|82         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

Year Ended Dec. 31
	
	2005
	
	2004(Restated, Note 1)Investment in oil and gas companies
	$
	3.0
	$
	3.0Investment in Mexico
	
	411.3
	
	418.3$
	414.3
	$
	421.3


In 2003, as the result of its annual review of its long-term investments, the corporation recorded a $6.2 million charge to recognize an other than temporary decline in fair value. The charge is included in
corporate operations, maintenance and administrative expenses.

Also in 2003, the corporation sold its 8.82 per cent interest in the Goldfields gas pipeline, for proceeds of AUD$24.1 million (Cdn$21.6 million), which approximated book value.

Year ended Dec. 31
	
	
	
	
	2005
	
	
	
	
	2004Accumulated
	
	
	AccumulatedDepreciation
	
	
	depreciation and
	Net book
	
	depreciation and
	
	Net bookrates
	
	Cost
	amortization
	value
	Cost
	amortization
	
	value(Restated, Note 1)Thermal generation
	3%  33%
	$
	3,244.8
	$ 1,180.1
	$ 2,064.7
	$ 3,129.4
	$
	1,078.3
	$
	2,051.1Thermal environmental equipment
	4%  13%
	
	608.6
	270.4
	338.2
	621.5
	
	253.1
	
	368.4Mining property & equipment
	4%  33%
	
	747.3
	349.0
	398.3
	732.6
	
	353.4
	
	379.2Gas generation
	2%  50%
	
	2,492.4
	677.1
	1,815.3
	2,153.9
	
	539.9
	
	1,614.0Geothermal generation
	3%  33%
	
	389.2
	96.9
	292.3
	394.6
	
	85.1
	
	309.5Hydro generation
	2%  5%
	
	348.9
	197.2
	151.7
	343.5
	
	189.1
	
	154.4Wind generation
	2%  3%
	
	205.5
	17.9
	187.6
	206.8
	
	10.7
	
	196.1Capital spares and other
	2%  50%
	
	204.4
	45.8
	158.6
	246.8
	
	51.4
	
	195.4Assets under construction
	
	
	10.7
	
	10.7
	322.8
	
	
	
	322.8Coal rights1
	
	
	79.1
	17.1
	62.0
	73.9
	
	18.4
	
	55.5Land
	
	
	40.0
	
	40.0
	38.3
	
	
	
	38.3Transmission systems
	2%  20%
	
	40.9
	14.8
	26.1
	31.3
	
	13.4
	
	17.9$
	8,411.8
	$ 2,866.3
	$ 5,545.5
	$ 8,295.4
	$
	2,592.8
	$
	5,702.6


The corporation capitalized $3.4 million of interest to PP&E in 2005 (2004  $20.0 million, 2003  $43.0 million) related to the construction of Genesee 3, the Summerview wind farm and the
McBride Lake wind farm.

For the year ended Dec 31, 2005, TA Cogen, a subsidiary that is owned 50.01 per cent by TransAlta and 49.99 per cent by TA Power, a publicly traded entity, recorded an impairment charge of $78.3 million in respect
of the Ottawa facility as the net book value of that facility exceeded its net recoverable amount, measured as the future cash flows from the facility. The net book value of the Ottawa facility in the accounts of the corporation is lower than that
in TA Cogen. The carrying value in TransAlta is fully recoverable from future cash flows of the facility. The difference in net book value between the accounts of the corporation and TA Cogen is due to the higher purchase price of the plant by TA
Cogen. The corporation has recognized an increase in depreciation expense of $36.2 million related to TA Powers share of the impairment charge. This amount is offset by a recovery in the earnings attributable to non-controlling interests
in the corporations income statement.

In 2003, the corporation concluded that the book value of its turbine inventory was unlikely to be recovered. As a result, TransAlta recorded an $84.7 million pre-tax impairment charge to write the turbines down to
fair value, included in gas generation. Fair value was based on quoted market prices.

In 2003, TransAlta recorded a $5.6 million pre-tax impairment charge on the Binghamton plant to reduce the plants book value to fair value, based on the present value of expected future cash flows.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         83
| | --------------------------------------------------

---

Year ended Dec. 31
	
	
	
	2005
	
	
	
	2004Accumulated
	
	Net book
	
	
	Accumulated
	Net bookCost
	amortization
	
	value
	
	Cost
	amortization
	valueSales contracts1
	$ 473.6
	$ 123.8
	$
	349.8
	$
	488.7
	$ 96.4
	$ 392.3


1 Intangible assets consist of power sale contracts, with rates higher than market rates at the date of acquisition, acquired in the purchase of CE Gen. Sales contracts are valued
at cost and are amortized on a straight-line basis over the remaining contract period, which ranges from seven to 30 years at the date of acquisition.

OTHER ASSETS

Year ended Dec. 31
	
	2005
	
	2004(Restated, Note 1)Cross-currency interest rate swaps and foreign currency forward contracts(Note 18)
	$
	102.6
	$
	375.3Interest rate swaps(Note 18)
	
	38.4
	
	44.4Deferred financing costs
	
	18.7
	
	22.5Deferred licence fees
	
	27.1
	
	27.1Deferred contract costs
	
	17.1
	
	21.1Deferred project development costs and other
	
	2.6
	
	2.3Long-term gas transportation deals
	
	4.4
	
	8.0210.9
	
	500.7Less current portion
	
	(10.9)
	
	(301.0)$
	200.0
	$
	199.7


Deferred financing costs are costs associated with the issuance of long-term debt and preferred securities and are being amortized on a straight-line basis over the term of the related issue.

Deferred licence fees consist primarily of an Australian licence which is being amortized on a straight-line basis over the useful life of the power station assets to which the licence relates.

Deferred contract costs consist of prepayments related to long-term contracts, which are being amortized on a straight-line basis over the term of the related contracts.

Year ended Dec. 31
	
	
	2005
	
	
	2004Outstanding
	Interest)1
	
	Outstanding
	Interest)1Commercial paper
	$
	12.5
	3.3%
	$
	34.4
	2.6%Bank debt
	
	0.6
	
	
	
	$
	13.1
	
	$
	34.4


|84         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

A. Amounts Outstanding

As at Dec. 31
	
	
	2005
	
	
	2004Outstanding
	Interest1
	
	Outstanding
	Interest1(Restated, Note 1)Debentures, due 2006 to 20332
	$
	1,496.1
	6.2%
	$
	1,388.5
	6.5%Senior notes, US$600.0 million3
	
	694.0
	6.3%
	
	733.6
	6.3%Non-recourse debt4
	
	363.8
	7.7%
	
	423.3
	6.9%Notes payable  Windsor plant, due 2006 to 20145
	
	51.1
	7.4%
	
	55.0
	7.4%Preferred securities, due 20506
	
	175.0
	7.8%
	
	475.0
	7.8%Other
	
	
	
	
	0.8
	8.0%$
	2,780.0
	
	$
	3,076.2Less current portion
	
	396.4
	
	
	580.1$
	2,383.6
	
	$
	2,496.1


|1 | Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2 | Debentures: The debentures bear interest at fixed rates ranging from 4.2 per cent to 7.3 per cent. A floating charge on the property and assets of TransAlta Utilities (TAU) has been provided as collateral for
$365.0 million of the debentures as at Dec. 31, 2005. The interest rate on $375.0 million of the debentures amount has been converted to floating rates based on bankers acceptance rates using interest rate swaps maturing between 2006
to 2011(Note 18). Debentures of $100.0 million maturing in 2023 and $50.0 million maturing in 2033 are redeemable at the option of the holder in 2008 and
2009, respectively. Debentures in the amount of $150.0 million matured in 2005, with the holders of $141.1 million of the debentures exercising their option to extend their maturity until 2030 at an interest rate of 6.9 per cent. Debentures
of $200 million were issued in December 2005 and mature in December 2007, they bear interest at a fixed rate 4.2 per cent.                                                                                 
|3 | Senior notes: The notes bear an interest rate of 5.75 per cent and mature in 2013. The US$300.0 million has been converted to a floating rate based on LIBOR using receive fixed, pay floating interest rate swaps
maturing in 2013. The notes bear interest at 6.75 per cent and mature on July 15, 2012. All senior notes have been designated as a hedge of the corporations net investment in U.S. and Mexican operations(Note 18).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|4 | Non-recourse debt: The debt consists of project financing debt, debt securities and senior secured bonds of CE Gen. The related assets have been pledged as security for the project financing debt. Maturity dates
range from 2004 to 2008, with a fixed interest rate of 8.56 per cent. The debt securities are non-recourse, have maturity dates ranging from 2005 to 2018 and interest rates ranging from 7.48 per cent to 8.30 per cent. The outstanding balance of the
non-recourse senior secured bonds as of Dec. 31, 2005 was $309.0 million and bears interest at 7.42 per cent, and is due in 2018.                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|5 | Notes payable  Windsor plant: The Windsor plant notes bear interest at fixed rates and are recourse to the corporation through a standby letter of credit.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|6 | Preferred securities: The preferred securities bear interest of 7.75 per cent and are due in 2050. The preferred securities are subordinated and unsecured and the corporation may redeem the preferred securities in
whole or in part in 2006 at a redemption price equal to 100 per cent of the principal amount of the preferred securities plus accrued and unpaid distributions thereon to the date of such redemption. The corporation may elect to defer coupon payments
on the preferred securities and settle deferred coupon payments in either cash or common shares of the corporation. Historically, the coupon payments have been in cash; therefore, the preferred securities have no dilutive effect on earnings per
share. Supplemental diluted earnings per share for 2005 from continuing operations and net earnings as though the coupon payments were settled with shares were $0.94 (2004  $0.82, 2003  $1.25, 2002  $0.39) and
$1.00 (2004  $0.87, 2003  $1.25, 2002  $1.16). Interest accretion at the coupon rate is included in interest expense.
|  | In February 2005, the corporation redeemed $175.0 million of preferred securities that had an interest rate of 7.5 per cent and $125.0 million of preferred securities that had an interest rate of 8.15 per
cent.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

B. Principal Repayments

2006
	$ 396.42007
	249.42008
	157.62009
	239.72010
	29.42011 and thereafter
	1,707.5Total
	$ 2,780.0


C. Interest Expense

Year ended Dec. 31
	2005
	
	2004
	
	2003(Restated, Note 1)
	(Restated, Note 1)Interest on recourse and non-recourse debt
	$ 184.2
	$
	192.8
	$
	222.8Interest on preferred securities
	16.5
	
	44.5
	
	36.8Interest income
	(8.7)
	
	(9.9)
	
	(4.5)Capitalized interest
	(3.4)
	
	(20.0)
	
	(43.0)Net interest expense
	$ 188.6
	$
	207.4
	$
	212.1


| | CONSOLIDATED FINANCIAL
      STATEMENTS         85
| | --------------------------------------------------

---

D. GuaranteesIn the normal course of operations, TransAlta and certain of its subsidiaries enter into agreements to provide financial or performance assurances to third parties. This includes guarantees and letters of credit which
are entered into to support or enhance creditworthiness in order to facilitate the extension of sufficient credit for Energy Marketing trading activities, treasury hedging, Generation construction projects, equipment purchases and mine reclamation
obligations.

At Dec. 31, 2005, the corporation had letters of credit outstanding of $216.9 million and US$415.3 million. The letters of credit were issued to coun-terparties that have credit exposure to certain
subsidiaries. If the corporation or its subsidiary does not pay amounts due under the contract, the counterparty may present its claim for payment to the financial institution, which in turn will request payment from the corporation. Any amounts
owed by the corporation or its subsidiaries are reflected in the consolidated balance sheet. All letters of credit expire in 2006 and 2007.

The corporation has arranged for the issuance of a surety bond in the amount of US$192.0 million in support of mine reclamation obligations at the Centralia mine.

TransAlta has provided guarantees of subsidiaries obligations under contracts that facilitate physical and financial transactions in various derivatives. To the extent liabilities related to these guaranteed
contracts exist for trading activities, they are included in the consolidated balance sheet. To the extent liabilities exist related to these guaranteed contracts for hedges, they are not recognized on the consolidated balance sheet. The guarantees
provided for under all contracts facilitating physical and financial transactions in various derivatives at Dec. 31, 2005 were to a maximum of $1.8 billion. In addition, the corporation has a number of unlimited guarantees. The fair value of the
trading and hedging positions under contracts where TransAlta has a net liability at Dec. 31, 2005, under the limited and unlimited guarantees, was $559.7 million (2004  $345.2 million).

TransAlta has also provided guarantees of subsidiaries obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at Dec. 31, 2005 was $645.3 million
(2004  $662.5 million). To the extent actual obligations exist under the performance guarantees at Dec. 31, 2005, they are included in accounts payable and accrued liabilities.

The corporation has approximately $1.2 billion of undrawn collateral available to secure these exposures.

|As at Dec. 31                                                                      |   | 2005  |                    | 2004   
|---------------------------------------------------------------------------------- | - | ----- | ------------------ | -------
|                                                                                   |   |       | (Restated, Note 1)
|Asset retirement obligations                                                       | $ | 249.2 | $                  | 238.1  
|Deferred revenues and other                                                        |   | 21.8  |                    | 30.0   
|Power purchase arrangement in limited partnership                                  |   | 29.2  |                    | 31.4   
|Accrued benefit liability(Note 17)                                                 |   | 49.3  |                    | 58.2   
|Cross-currency interest rate swaps and foreign currency forward contracts(Note 18) |   | 14.8  |                    | 270.4  
|Fair value of swap transaction with limited partnership                            |   | 1.6   |                    | 4.9    
|                                                                                   | $ | 365.9 | $                  | 633.0  
|Less current portion                                                               |   | (0.4) |                    | (241.5)
|                                                                                   | $ | 365.5 | $                  | 391.5  

A reconciliation between the opening and closing asset retirement obligation balances is provided below:

|                                  |        
|--------------------------------- | -------
|Balance, Dec. 31, 2003            | $ 253.3
|Liabilities incurred in period    | 21.8   
|Liabilities settled in period     | (19.7) 
|Accretion expense                 | 19.3   
|Revision in estimated cash flows  | (22.3) 
|Change in foreign exchange rates  | (14.3) 
|Balance, Dec. 31, 2004            | $ 238.1
|Liabilities incurred in period    | 12.3   
|Liabilities settled in period     | (29.4) 
|Accretion expense                 | 19.3   
|Revisions in estimated cash flows | 25.6   
|Change in foreign exchange rates  | (16.7) 
|Balance, Dec. 31, 2005            | $ 249.2

|86         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|------------------------------------------------------------

---

TransAlta estimates the undiscounted amount of cash flow required to settle the asset retirement obligations is approximately $1.4 billion, which will be incurred between 2007 and 2072. The majority of the costs
will be incurred between 2020 and 2030. A discount rate of eight per cent was used to calculate the carrying value of the asset retirement obligations. At Dec. 31, 2005, the corporation had a surety bond in the amount of US$192.0 million in
support of future retirement obligations at the Centralia mine. At Dec. 31, 2005, the corporation had letters of credit in the amount of $60.8 million in support of future retirement obligations at the Alberta mines.

The Power Purchase Arrangement (PPA) in the limited partnership represents the fair value adjustments for the Sheerness Generating Station to deliver power at less than the prevailing market price at the time of the
acquisition of the plant by TA Cogen.

A. Statements of Earnings

Year ended Dec. 31
	
	2005
	
	2004
	
	2003TA Powers limited partnership interest in TA Cogen(Note 21)
	$
	2.1
	$
	31.5
	$
	21.3Other shareholders interests
	
	16.4
	
	14.5
	
	12.9$
	18.5
	$
	46.0
	$
	34.2


B. Balance Sheets

As at Dec. 31
	
	2005
	
	2004TA Powers limited partnership interest in TA Cogen
	$
	525.0
	$
	582.4Other shareholders interests
	
	33.6
	
	34.0$
	558.6
	$
	616.4


Other shareholders interests represents the 25 per cent interest in the Saranac Partnership not owned by CE Gen.

A. Issued and OutstandingThe corporation is authorized to issue an unlimited number of voting common shares without nominal or par value.

Year ended Dec. 31
	
	2005
	
	2004
	
	2003Common
	
	Common
	
	Commonshares
	
	shares
	
	shares(millions)
	Amount
	(millions)
	Amount
	(millions)
	AmountIssued and outstanding, beginning of year
	194.1
	$ 1,611.9
	190.7
	$ 1,555.7
	169.8
	$ 1,226.2Issued as a public offering and other
	
	
	
	
	17.3
	270.4Issued under dividend reinvestmentand share purchase plan
	3.5
	68.1
	3.4
	55.3
	3.3
	54.6Issued on purchase of Vision Quest
	
	0.2
	
	0.7
	0.1
	1.7Issued for cash under stock option plans
	1.0
	16.3
	0.1
	1.1
	0.1
	1.4Issued under Performance Share Ownership Plan
	0.1
	1.2
	
	1.1
	0.1
	1.4Repurchased by the corporation
	
	
	(0.1)
	(1.2)
	
	Employee share purchase loans
	
	0.2
	
	(0.8)
	
	198.7
	$ 1,697.9
	194.1
	$ 1,611.9
	190.7
	$ 1,555.7


At Dec. 31, 2005, the corporation had 198.7 million (2004  194.1 million; 2003  190.7 million) common shares issued and outstanding, plus outstanding employee stock options to purchase an additional 2.9
million shares (2004  2.9 million; 2003  3.1 million).

In February 2004, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation. In 2005, no shares were repurchased. In 2004, 143,500 shares were repurchased and no
shares were repurchased during 2003. The $1.1 million in 2004 in excess of the repurchase price over the average net book value of the common shares was charged to retained earnings.

In March 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million, with issue costs of $8.0 million. The offering included an option for the underwriters to purchase a
further 2.25 million common shares for $36.0 million. This option was fully exercised on April 17, 2003 with issue costs of $3.0 million.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         87
| | --------------------------------------------------

---

B. Shareholder Rights PlanThe primary objective of the shareholder rights plan is to provide the corporations Board of Directors sufficient time to explore and develop alternatives for maximizing shareholder value if a takeover bid is
made for the corporation and to provide every shareholder with an equal opportunity to participate in such a bid. The plan was originally approved in 1992, and has been revised from time to time for conformity with current practices.

When an acquiring shareholder acquires 20 per cent or more of the outstanding common shares of the corporation and that shareholder does not make a bid for all of the common shares outstanding, each shareholder other
than the acquiring shareholder may receive one right for each common share owned. Each right will entitle the holder to acquire an additional $160 worth of common shares for $80.

C. Dividend Reinvestment and Share Purchase PlanUnder the terms of the dividend reinvestment and share purchase plan, participants are able to purchase additional common shares by reinvesting dividends. Common shares will be issued from treasury. In 2005, 3.5
million (2004  3.4 million, 2003  3.3 million) common shares were purchased under this program for $68.1 million (2004  $55.3 million, 2003  $54.6 million).

D. Earnings Per Share (EPS)

Year ended Dec. 31
	
	2005
	
	2004
	
	2003Numerator
	Denominator
	Numerator
	Denominator
	Numerator
	DenominatorBasic EPS from continuing operations
	186.8
	196.8
	160.6
	192.7
	234.2
	185.3Impact of PSOP
	
	0.4
	
	0.1
	
	0.1Diluted EPS from continuing operations
	186.8
	197.2
	160.6
	192.8
	234.2
	185.4


STOCK-BASED COMPENSATION PLANAt Dec. 31, 2005, the corporation had three types of stock-based compensation plans and an employee share purchase plan.

The corporation is authorized to grant employees options to purchase up to an aggregate of 13.0 million common shares at prices based on the market price of the shares as determined on the grant date. The corporation
has reserved 13.0 million common shares for issue.

A. Fixed Stock Option PlansI. Management Plan
The granting of options under this fixed stock option plan was discontinued in 1997. Options were granted under this plan to certain eligible employees. The options could not be exercised until one year after grant and
thereafter at an amount not exceeding 20 per cent of the grant per year on a cumulative basis until the sixth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

II. Canadian Employee Plan
This plan is offered to all full-time and part-time employees in Canada at or below the level of manager. Options granted under this plan may not be exercised until one year after grant and thereafter at an amount not
exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

III. Alberta Distribution and Retail (D&R) Plan
This plan is offered to all full-time and part-time employees of the Alberta D&R business segment. Options granted under this plan could not be exercised until the date of the closing of the Alberta D&R sale on
Aug. 31, 2000, after which the entire grant could be exercised for up to three years after the closing. The outstanding options under this plan at Dec. 31, 2003 expired in January 2004.

IV. U.S. Plan
This plan is offered to all full-time and part-time employees in the United States at or below the level of manager. Options granted under this plan may not be exercised until one year after grant and thereafter at an
amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

V. Australian Phantom Plan
This plan came into effect in 2001 and was offered to all full-time and part-time employees in Australia, excluding directors and officers. Options under this plan are not physically granted; rather, employees receive
the equivalent value of shares in cash when exercised. Options granted under this plan may not be exercised until one year after grant and thereafter at an amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth
year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

|88TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

VI. Mexican Phantom PlanThe Mexican phantom plan mirrors the rules of the Australian plan, with the first grant occurring in 2005.

|                     |                 |               |                  | Canadian           |              |              |          |            |          |            | Australian |          | Mexican   
|-------------------- | --------------- | ------------- | ---------------- | ------------------ | ------------ | ------------ | -------- | ---------- | -------- | ---------- | ---------- | -------- | ----------
|                     | Management plan | employee plan | Alberta D&R plan | U.S. employee plan | phantom plan | phantom plan
|                     | Number          | Weighted      | Number           | Weighted           | Number       | Weighted     | Number   | Weighted   | Number   | Weighted   | Number     | Weighted
|                     | of share        | average       | of share         | average            | of share     | average      | of share | average    | of share | average    | of share   | average 
|                     | options         | exercise      | options          | exercise           | options      | exercise     | options  | exercise   | options  | exercise   | options    | exercise
|                     | (millions)      | price         | (millions)       |                    | price        | (millions)   | price    | (millions) | price    | (millions) |            | price    | (millions)
|Outstanding,         |                 |               |                  |                    |              |              |          |            |          |            |            |          |           
|Jan.1, 2003          | 0.1             | $ 14.91       | 1.6              | $                  | 21.89        | 0.1          | $ 14.20  | 1.1        | $ 13.61  | 0.1        | $          | 22.00    |          
|Granted              |                |              | 0.1              |                    | 17.11        |             |          |           |         |           |           |          |          
|Exercised            |                |              |                 |                    |             | (0.1)        | 14.20    |           |         |           |            |         |          
|Cancelled or expired |                |              | (0.1)            |                    | 21.39        |             |          |           |         |           |           |          |          
|Outstanding,         |                 |               |                  |                    |              |              |          |            |          |            |            |          |           
|Dec. 31, 2003        | 0.1             | $ 14.91       | 1.6              | $                  | 21.18        |             | $        |           | 1.1      | $ 13.61    | 0.1        | $        | 22.00     
|Granted              |                |              |                 |                    |             |             |          |           |         |           |           |          |          
|Exercised            |                |              | (0.1)            |                    | 22.52        |             |          |           |         |           |           |          |          
|Cancelled or expired |                |              |                 |                    |             |             |          |           | (0.1)    | 13.47      |           |          |          
|Outstanding,         |                 |               |                  |                    |              |              |          |            |          |            |            |          |           
|Dec. 31, 2004        | 0.1             | $ 14.91       | 1.5              | $                  | 21.93        |             | $        |           | 1.0      | $ 13.56    | 0.1        | $        | 22.00     
|Granted              |                |              | 0.7              |                    | 17.80        |             |          |           | 0.4      | 14.48      |           |          | 17.80     
|Exercised            | (0.1)           | 14.82         | (0.2)            |                    | 18.20        |             |          |           | (0.6)    | 13.73      |           |          | 21.56     
|Cancelled or expired |                |              | (0.1)            |                    | 21.04        |             |          |           |         | 13.85      |           |          | 20.12     
|Outstanding,         |                 |               |                  |                    |              |              |          |            |          |            |            |          |           
|Dec. 31, 2005        |                | $ 15.00       | 1.9              | $ 20.85            |             | $            |         | 0.8        | $ 14.03  | 0.1        | $ 20.37    |         | $ 17.80   

|                         |                | Options outstanding | Options exercisable
|------------------------ | -------------- | ------------------- | -------------------
|                         |                | Weighted            |                    
|                         | Number         | average             | Weighted           
|                         | outstanding at | remaining           | average            
|                         | Dec. 31, 2005  | contractual         | exercise           
|                         | (millions)     | life (years)        | price              
|Range of exercise prices |                |                     |                    
|$13.12  $18.00          | 1.7            | 7.8                 | $ 16.72            
|$18.01  $23.00          | 0.5            | 6.0                 | 21.05              
|$27.70                   | 0.5            | 5.3                 | 27.70              
|$13.12  $27.70          | 2.7            | 7.0                 | $ 19.45            

B. Performance Stock Option PlanIn 1999, the corporation expanded enrolment in the share option program to include all Canadian employees of the corporation, excluding the level of director and above, by issuing stock options with an expiry date of
2009 and vesting dependent upon achieving certain earnings per share targets.

|Year ended Dec. 31             |               | 2005     |               |   | 2004     |               |   | 2003    
|------------------------------ | ------------- | -------- | ------------- | - | -------- | ------------- | - | --------
|                               |               | Weighted |               |   | Weighted |               |   | Weighted
|                               | Number of     | average  | Number of     |   | average  | Number of     |   | average 
|                               | share options | exercise | share options |   | exercise | share options |   | exercise
|                               | (millions)    | price    | (millions)    |   | price    | (millions)    |   | price   
|Outstanding, beginning of year | 0.2           | $ 22.44  | 0.2           | $ | 22.44    | 0.2           | $ | 22.44   
|Exercised                      |              | 21.33    |              |   |         |              |   |        
|Cancelled or expired           |              | 23.05    |              |   |         |              |   |        
|Outstanding, end of year       | 0.2           | $ 22.62  | 0.2           | $ | 22.44    | 0.2           | $ | 22.44   

At Dec. 31, 2005, the corporation had 9,333 options under this plan with an exercise price of $14.15 and a weighted average remaining contractual life of 4.0 years and 185,000 options with an exercise price of
$23.05 and a weighted average remaining contractual life of 3.1 years outstanding. At Dec. 31, 2005, all outstanding options had vested.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         89
| | --------------------------------------------------

---

C. Performance Share Option Plan
(PSOP)Under the terms of the PSOP, which commenced in 1997, the corporation was authorized to grant to employees and directors up to an aggregate of 2.0 million common shares. The number of common shares which could be
issued under both the PSOP and the share option plans, however, could not exceed 6.0 million common shares. Participants in the PSOP receive awards which, after three years, make them eligible to receive a set number of common shares or cash
equivalent up to the maximum of the award amount plus any accrued dividends thereon. The actual number of common shares or cash equivalent a participant may receive is determined by the percentile ranking of the total shareholder return over three
years of the corporations common shares amongst the companies comprising the S&P/TSX composite index.

On Dec. 31, 2001, the plan was modified so that after three years, once the PSOP eligibility has been determined, 50 per cent of the shares may be released to the participant, while the remaining 50 per cent will be
held in trust for one additional year. In addition, the number of common shares the corporation is authorized to grant under the terms of the PSOP was increased to 4.0 million common shares and the maximum number of common shares that may be issued
under both the PSOP and share option plans was increased to 13.0 million common shares.

Year ended Dec. 31
	2005
	2004
	2003Number of awards outstanding, beginning of year
	1.5
	1.5
	1.3Granted
	0.4
	0.4
	0.7Awarded
	(0.1)
	
	(0.1)Cancelled or expired
	(0.7)
	(0.4)
	(0.4)Number of awards outstanding, end of year
	1.1
	1.5
	1.5


In 2005, PSOP compensation expense was $10.6 million (2004  $3.4 million, 2003  $nil), which is included in operations, maintenance and administration expense in the statements of earnings. In
2005, 65,332 common shares were issued at $25.41 per share. In 2004, 16,457 common shares were issued at $17.11 per share and 44,846 common shares were issued at $18.53 per share. In 2003, 83,300 common shares were issued at $17.11
per share.

D. Employee Share Purchase PlanUnder the terms of the employee share purchase plan, the corporation will extend an interest-free loan (up to 30 per cent of an employees base salary) to employees below executive level and allow for payroll
deductions over a three-year period to repay the loan. Executives are no longer eligible for this program in accordance with the Sarbanes-Oxley legislation. The corporation will purchase these common shares on the open market on behalf of employees
at prices based on the market price of the shares as determined on the date of purchase. Employee sales of these shares are handled in the same manner. At Dec. 31, 2005, accounts receivable from employees under the plan totalled $0.6 million
(2004  $0.8 million).

E. Stock-Based CompensationAt Dec. 31, 2005, the corporation had 2.9 million outstanding employee stock options (Dec. 31, 2004  2.9 million).

The corporation uses the fair value method of accounting for awards granted under its fixed stock option plans and its performance stock option plan. In March 2005, 1.2 million options were granted. One quarter of the
options granted vest on each of the first, second, third and fourth anniversaries of the date of grant and expire after 10 years. The estimated fair value of these options granted was determined using the binomial model using the following
assumptions, resulting in a fair value of $6.84 per option.

2005Risk-free interest rate
	4.3%Life of the options (years)
	10Dividend rate
	5.6%Volatility in the price of the corporations shares
	47.0%


|90TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

As disclosed inNote 1(P), on Jan. 1, 2003 the corporation adopted the fair value method of accounting for stock-based compensation
prospectively, under which a compensation expense is measured at the grant date and recognized over the service period. In 2005, the corporation granted options to purchase 1.2 million common shares of the corporation to its employees (2004 
nil, 2003  nil) at a weighted average exercise price of $17.80. The following table provides pro forma measures of net earnings and earnings per share had compensation expense been recognized based on the estimated fair value of the
options on the grant date in accordance with the fair value method of accounting for stock-based compensation for grants made in 2002:

Year ended Dec. 31
	2005
	
	2004
	
	2003Reported net earnings
	$ 198.8
	$
	170.2
	$
	234.2Compensation expense
	1.5
	
	1.7
	
	2.6Pro forma net earnings
	$ 197.3
	$
	168.5
	$
	231.6Reported basic earnings per share
	$ 1.01
	$
	0.88
	$
	1.26Compensation expense per share
	0.01
	
	0.01
	
	0.01Pro forma basic earnings per share
	$ 1.00
	$
	0.87
	$
	1.25Reported diluted earnings per share
	$ 1.01
	$
	0.88
	$
	1.26Compensation expense per share
	0.01
	
	0.01
	
	0.01Pro forma diluted earnings per share
	$ 1.00
	$
	0.87
	$
	1.25


The estimated fair value of these stock options granted in 2002 and prior was determined using the binomial model using the following assumptions, resulting in a weighted-average fair value of $4.25 in
2002.

2002Risk-free interest rate
	5.9%Expected hold period to exercise (years)
	7.0Volatility in the price of the corporations shares
	28.3%


PRIOR PERIOD REGULATORY DECISION

At Dec. 31, 2000, the corporation had made a provision of US$28.8 million against US$58.0 million of receivables outstanding related to sales to the California market. US$5.0 million of this amount was
received during 2001. In March 2004, TransAlta recorded an additional pre-tax provision of US$17.2 million ($22.9 million).

The U.S. Federal Energy Regulatory Commission (FERC) has provided TransAlta with an opportunity to petition for relief from refund obligations. To be successful in such a petition for relief we will be required to
demonstrate that, as a result of the refund methodology, TransAlta suffered operating losses in respect of California transactions during the refund period. On Aug. 8, 2005, FERC issued an order detailing the methodology for a petition for relief
from refund obligations. TransAlta prepared a petition for relief from the refund obligation and filed it with FERC. The California Independent System Operator (CAISO) and California Power Exchange (CALPX) have reviewed and commented on our petition
and TransAlta replied to the CAISO and CALPX comments on Oct. 17, 2005. On Jan. 26, 2006, FERC conditionally accepted TransAltas petition for relief, subject to modification. This revised compliance filing is due Feb. 10, 2006.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         91
| | --------------------------------------------------

---

A. Statements of EarningsI. Rate Reconciliations

2005
	
	2004
	
	2003(Restated, Note 1)
	(Restated, Note 1)Earnings from continuing operations before income taxes
	$ 234.2
	$
	209.7
	$
	298.5Statutory Canadian federal and provincial income tax rate
	33.6%
	
	33.9%
	
	36.8%Expected taxes on income
	$ 78.7
	$
	71.0
	$
	109.8Increase (decrease) in income taxes resulting from:Lower effective foreign tax rates
	(23.3)
	
	(19.2)
	
	(22.9)Resolution of uncertain tax positions
	(13.0)
	
	(6.8)
	
	Resource allowance (net of non-deductible royalties)
	(1.4)
	
	(1.6)
	
	(2.5)Manufacturing and processing rate reduction
	(1.3)
	
	(1.7)
	
	(3.5)Large corporations tax (net of surtax)
	10.0
	
	10.3
	
	9.5Effect of tax rate changes
	(3.8)
	
	(7.8)
	
	(4.4)Unrecognized future income tax assets
	1.5
	
	6.1
	
	1.5Non-taxable portion of gain on disposition of assets
	
	
	
	
	(22.7)Other
	
	
	(1.2)
	
	(0.5)Income tax expense
	$ 47.4
	$
	49.1
	$
	64.3Effective tax rate
	20.2%
	
	23.4%
	
	21.5%


The corporations operations are complex, and the computation and provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. The corporations tax
filings are subject to audit by taxation authorities. The outcome of some audits may change the tax liability of the corporation. Management believes it has adequately provided for income taxes based on all information currently
available.

II. Components of Income Tax Expense

2005
	
	2004
	
	2003(Restated, Note 1)
	(Restated, Note 1)Current tax expense
	$ 41.8
	$
	36.1
	$
	51.0Future income tax expense related to the origination and reversal of temporary differences
	9.4
	
	20.8
	
	17.7Future income tax benefit resulting from changes in tax rates or laws
	(3.8)
	
	(7.8)
	
	(4.4)Income tax expense
	$ 47.4
	$
	49.1
	$
	64.3


2005
	
	2004Net operating and capital loss carry forwards
	$
	260.5
	$
	275.7Asset retirement obligation
	
	82.6
	
	88.9Unrealized losses on electricity trading contracts
	
	10.5
	
	29.7Property, plant and equipment
	
	(947.8)
	
	(949.4)Unrealized gains on electricity trading contracts
	
	(12.6)
	
	(36.4)Other deductible temporary differences
	
	22.0
	
	30.0$
	(584.8)
	$
	(561.5)


|92TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

Presented in the balance sheet as follows:

2005
	
	2004AssetsCurrent
	$
	26.6
	$
	21.5Long term
	
	147.1
	
	132.0LiabilitiesCurrent
	
	(18.2)
	
	(11.1)Long term
	
	(740.3)
	
	(703.9)$
	(584.8)
	$
	(561.5)


EMPLOYEE FUTURE BENEFITS

A. DescriptionThe corporation has registered pension plans in Canada and the United States covering substantially all employees of the corporation in these countries and specific named employees working internationally. These plans
have defined benefit and defined contribution options and in Canada, there is an additional supplemental defined benefit plan for Canadian-based defined contribution members whose annual earnings exceed the Canadian income tax limit. The defined
benefit option of the registered pension plans has been closed for new employees for all periods presented.

The latest actuarial valuations of the registered and supplemental pension plans were as at Dec. 31, 2005. The measurement date used to determine plan assets and accrued benefit obligation was Dec. 31, 2005. The
effective date of the next required valuation for funding purposes is Dec. 31, 2007. The supplemental pension plan is solely the obligation of the corporation. The corporation is not obligated to fund the supplemental plan but is obligated to pay
benefits under the terms of the plan as they come due. The corporation has posted a letter of credit in the amount of $41.8 million to secure the obligations under the supplemental plan.

The corporation provides other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation
of these other plans was as at Dec. 31, 2004. The measurement date used to determine the accrued benefit obligation was also Dec. 31, 2005. The effective date of the next required valuation for funding purposes is Dec. 31, 2007.

B. Costs Recognized

Year ended Dec. 31, 2005
	Registered
	Supplemental
	
	Other
	
	TotalCurrent service cost
	$ 4.2
	$ 1.1
	$
	1.3
	$
	6.6Interest cost
	20.4
	2.0
	
	1.2
	
	23.6Actual return on plan assets
	(43.9)
	
	
	
	
	(43.9)Actuarial (gains) losses in 2005
	26.3
	4.6
	
	0.9
	
	31.8Past service cost in 2005
	0.5
	(1.2)
	
	
	
	(0.7)Difference between expected return and actual return on plan assets
	19.8
	
	
	
	
	19.8Difference between actuarial (gain) loss recognized for the yearand actual actuarial (gain) loss on accrued benefit obligation for the year
	(23.9)
	(4.3)
	
	(0.6)
	
	(28.8)Difference between amortization of past service costs for the yearand actual plan amendments for the year
	(0.4)
	1.2
	
	0.3
	
	1.1Amortization of net transition obligation (asset)
	(9.2)
	0.3
	
	
	
	(8.9)Defined benefit (income) cost
	(6.2)
	3.7
	
	3.1
	
	0.6Defined contribution option expense of registered pension plan
	11.5
	
	
	
	
	11.5Net expense
	$ 5.3
	$ 3.7
	$
	3.1
	$
	12.1


| | CONSOLIDATED FINANCIAL
      STATEMENTS         93
| | --------------------------------------------------

---

Year ended Dec. 31, 2004
	Registered
	Supplemental
	
	Other
	
	TotalCurrent service cost
	$ 4.2
	$ 1.1
	$
	0.6
	$
	5.9Interest cost
	20.5
	2.1
	
	1.0
	
	23.6Actual return on plan assets
	(33.4)
	
	
	
	
	(33.4)Actuarial (gains) losses in 2004
	14.4
	(1.5)
	
	0.2
	
	13.1Plan amendments in 2004
	
	
	
	3.8
	
	3.8Difference between expected return and actual return on plan assets
	9.6
	
	
	
	
	9.6Difference between actuarial (gain) loss recognized for the yearand actual actuarial (gain) loss on accrued benefit obligation for the year
	(12.3)
	2.0
	
	0.3
	
	(10.0)Difference between amortization of past service costs for the yearand actual plan amendments for the year
	0.1
	(0.1)
	
	(3.8)
	
	(3.8)Amortization of net transition obligation (asset)
	(9.2)
	0.3
	
	
	
	(8.9)Defined benefit (income) cost
	(6.1)
	3.9
	
	2.1
	
	(0.1)Defined contribution option expense of registered pension plan
	10.4
	
	
	
	
	10.4Net expense
	$ 4.3
	$ 3.9
	$
	2.1
	$
	10.3


Year ended Dec. 31, 2003
	Registered
	Supplemental
	
	Other
	
	TotalCurrent service cost
	$ 3.8
	$ 1.4
	$
	0.6
	$
	5.8Interest cost
	21.0
	2.2
	
	1.1
	
	24.3Actual return on plan assets
	(35.9)
	
	
	
	
	(35.9)Actuarial (gains) losses in 2003
	21.5
	(0.7)
	
	0.5
	
	21.3Difference between expected return and actual return on plan assets
	12.3
	
	
	
	
	12.3Difference between actuarial (gain) loss recognized for the yearand actual actuarial (gain) loss on accrued benefit obligation for the year
	(20.2)
	1.3
	
	(0.1)
	
	(19.0)Difference between amortization of past service costs for the yearand actual plan amendments for the year
	0.1
	(0.1)
	
	
	
	Amortization of net transition obligation (asset)
	(9.1)
	0.3
	
	
	
	(8.8)Defined benefit (income) cost
	(6.5)
	4.4
	
	2.1
	
	Defined contribution option expense of registered pension plan
	9.7
	
	
	
	
	9.7Net expense
	$ 3.2
	$ 4.4
	$
	2.1
	$
	9.7


C. Status of Plans

Year ended Dec. 31, 2005
	Registered
	Supplemental
	
	OtherFair value of plan assets
	$ 369.5
	$ 1.7
	$
	Accrued benefit obligation
	402.8
	41.2
	
	23.4Funded status  plan deficit
	(33.3)
	(39.5)
	
	(23.4)Amounts not yet recognized in financial statements:Unrecognized past service costs
	1.0
	(1.6)
	
	3.5Unamortized transition (asset) obligation
	(45.8)
	2.6
	
	Unamortized net actuarial gains
	60.9
	10.7
	
	6.6Total recognized in financial statements:Accrued benefit liability
	$ (17.2)
	$ (27.8)
	$
	(13.3)Amortization period in years (EARSL)
	8
	8
	
	15


|94TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

Year ended Dec. 31, 2004
	Registered
	Supplemental
	
	OtherFair value of plan assets
	$ 352.0
	$ 1.4
	$
	Accrued benefit obligation
	379.0
	36.6
	
	21.7Funded status  plan deficit
	(27.0)
	(35.2)
	
	(21.7)Amounts not yet recognized in financial statements:Unrecognized past service costs
	0.5
	(0.5)
	
	3.8Unamortized transition (asset) obligation
	(55.0)
	3.0
	
	Unamortized net actuarial gains
	57.1
	6.6
	
	6.2Total recognized in financial statements:Accrued benefit liability
	$ (24.4)
	$ (26.1)
	$
	(11.7)Amortization period in years (EARSL)
	9
	9
	
	11


The current portion of the accrued benefit liability is included in accounts payable and accrued liabilities on the consolidated balance sheets. The long-term portion is included in deferred credits and other long-term
liabilities.

Year ended Dec. 31, 2005
	Registered
	Supplemental
	
	OtherAccrued current liabilities
	$ 7.2
	$ 0.5
	$
	1.3Other long-term liabilities
	10.0
	27.3
	
	12.0Accrued benefit liability
	$ 17.2
	$ 27.8
	$
	13.3Year ended Dec. 31, 2004
	Registered
	Supplemental
	
	OtherAccrued current liabilities
	$ 2.2
	$ 0.7
	$
	1.1Other long-term liabilities
	22.2
	25.4
	
	10.6Accrued benefit liability
	$ 24.4
	$ 26.1
	$
	11.7


D. ContributionsExpected cash flows are as follows:

Registered
	Supplemental
	
	Other
	
	TotalEmployer contributions2006 (expected)
	$ 11.1
	$ 0.5
	$
	0.3
	$
	11.9Expected benefit payments2006
	24.0
	1.7
	
	1.3
	
	27.02007
	24.4
	2.0
	
	1.5
	
	27.92008
	25.1
	2.0
	
	1.6
	
	28.72009
	26.0
	2.1
	
	1.7
	
	29.82010
	26.4
	2.3
	
	1.8
	
	30.52011  2015
	141.6
	12.9
	
	10.0
	
	164.5


| | CONSOLIDATED FINANCIAL
      STATEMENTS         95
| | --------------------------------------------------

---

E. Plan Assets

Registered
	Supplemental
	
	OtherFair value of plan assets at Dec. 31, 2003
	$ 351.9
	$ 0.9
	$
	Contributions
	2.6
	0.5
	
	0.1Transfers to defined contribution option
	(9.0)
	
	
	Benefits paid
	(25.3)
	
	
	(0.1)Effect of translation on U.S. plans
	(1.6)
	
	
	Actual return on plan assets1
	33.4
	
	
	Fair value of plan assets at Dec. 31, 2004
	$ 352.0
	$ 1.4
	$
	Contributions
	2.1
	0.5
	
	0.3Transfers
	0.1
	
	
	Benefits paid
	(27.7)
	(0.1)
	
	(0.3)Effect of translation on U.S. plans
	(1.0)
	
	
	Actual return on plan assets1
	43.9
	
	
	Fair value of plan assets at Dec. 31, 2005
	$ 369.4
	$ 1.8
	$
	


1 Net of expenses.

The corporations investment policy is to achieve a consistently high investment return over time while maintaining an acceptable level of risk to satisfy the benefit obligations of the pension plans. The goal is
to maintain a long-term rate of return on the fund that at least equals the growth of liabilities, currently 7 per cent. The pension fund may be invested in publicly traded common or preferred equity shares, rights or warrants; convertible
debentures or preferred securities; bonds, debentures, mortgages, notes or other debt instruments of government agencies or corporations; private company securities; guaranteed investment contracts; term deposits; cash or money market securities;
and mutual or pooled funds eligible for pension fund investment. The target allocation percentages are 60 per cent equity and 40 per cent fixed income. Cash and money market instruments may be held from time to time as short-term investment
decisions or as defensive reserves within the portfolios of each asset class. The fund may invest in derivatives for the purpose of hedging the portfolio or altering the desired mix of the fund. Derivative transactions that leverage the fund in any
way are not permitted without the specific approval of the Pension Committee.

The allocation of plan assets by major asset category at Dec. 31, 2005 and 2004 is as follows:

Year ended Dec. 31, 2005
	Registered
	SupplementalEquity securities
	62.8%
	Debt securities
	36.7%
	Cash equivalents
	0.5%
	100.0%Total
	100.0%
	100.0%Year ended Dec. 31, 2004
	Registered
	SupplementalEquity securities
	55.9%
	Debt securities
	42.5%
	Cash equivalents
	1.6%
	100.0%Total
	100.0%
	100.0%


Plan assets include common shares of the corporation having a fair value of $1.0 million at Dec. 31, 2005 (2004  $0.7 million). The corporation charged the registered plan $0.1 million for
administrative services provided for the year ended Dec. 31, 2005 (2004  $0.1 million).

|96TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

F. Reconciliation of Accrued Benefit Obligations

|                                               | Registered | Supplemental |   | Other
|---------------------------------------------- | ---------- | ------------ | - | -----
|Accrued benefit obligation as at Dec. 31, 2003 | $ 366.6    | $ 36.5       | $ | 18.0 
|Current service cost                           | 4.2        | 1.1          |   | 0.6  
|Interest cost                                  | 20.5       | 2.1          |   | 1.0  
|Expected benefits paid                         | (23.7)     | (1.6)        |   | (1.2)
|Past service charge                            |           |             |   | 3.8  
|Effect of translation on U.S. plans            | (3.0)      |             |   | (0.7)
|Actuarial loss (gain)                          | 14.4       | (1.5)        |   | 0.2  
|Accrued benefit obligation as at Dec. 31, 2004 | $ 379.0    | $ 36.6       | $ | 21.7 
|Current service cost                           | 4.2        | 1.1          |   | 1.3  
|Interest cost                                  | 20.4       | 2.0          |   | 1.2  
|Expected benefits paid                         | (25.7)     | (1.8)        |   | (1.2)
|Past service charge                            | 0.5        | (1.2)        |   |     
|Effect of translation on U.S. plans            | (2.0)      |             |   | (0.5)
|Actuarial loss (gain)                          | 26.3       | 4.6          |   | 0.9  
|Accrued benefit obligation as at Dec. 31, 2005 | $ 402.7    | $ 41.3       | $ | 23.4 

G. AssumptionsThe significant actuarial assumptions adopted in measuring the corporations accrued benefit obligations were as follows:

|Year ended Dec. 31, 2005                       | Registered | Supplemental | Other        
|---------------------------------------------- | ---------- | ------------ | -------------
|Accrued benefit obligation at Dec. 31          |            |              |              
|Discount rate                                  | 5.0%       | 5.0%         | 5.2%         
|Rate of compensation increase                  | 3.5%       | 3.5%         |             
|Benefit cost for year ended Dec. 31            |            |              |              
|Discount rate                                  | 5.5%       | 5.5%         | 5.6%         
|Rate of compensation increase                  | 3.5%       | 3.5%         |             
|Expected rate of return on plan assets         | 7.1%       |             |             
|Assumed health care cost trend rate at Dec. 31 |            |              |              
|Health care cost escalation                    |           |             | 9.5%11.5%)1 
|Dental care cost escalation                    |           |             | 4.0%         
|Provincial health care premium escalation      |           |             | 2.5%         
|                                               |            |              |              
|Year ended Dec. 31, 2004                       | Registered | Supplemental | Other        
|Accrued benefit obligation at Dec. 31          |            |              |              
|Discount rate                                  | 5.5%       | 5.5%         | 5.6%         
|Rate of compensation increase                  | 3.5%       | 3.5%         |             
|Benefit cost for year ended Dec. 31            |            |              |              
|Discount rate                                  | 5.8%       | 5.8%         | 5.9%         
|Rate of compensation increase                  | 3.5%       | 3.5%         |             
|Expected rate of return on plan assets         | 7.1%       |             |             
|Assumed health care cost trend rate at Dec. 31 |            |              |              
|Health care cost escalation                    |           |             | 10.0%12.5%)1
|Dental care cost escalation                    |           |             | 4.0%         
|Provincial health care premium escalation      |           |             | 2.5%         

| | CONSOLIDATED FINANCIAL
      STATEMENTS         97
| | --------------------------------------------------

---

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. The estimated rate of return is lower than the historical returns
of the appropriate indices.

Sensitivity to changes in assumed health care cost trend rates are as follows:

One percentage
	One percentagepoint increase
	point decreaseEffect on total service and interest costs
	$
	0.2
	$
	(0.2)Effect on post-retirement benefit obligation
	$
	1.3
	$
	(1.2)


A. Foreign Exchange Rate Risk ManagementI. Hedges of Foreign Operations
The corporation has exposure to changes in the carrying values of its self-sustaining foreign operations as a result of changes in foreign exchange rates. The corporation uses cross-currency interest rate swaps at
fixed and floating rate terms, forward sales contracts and direct foreign currency debt to hedge these exposures. The principal component of the cross-currency interest rate swaps and direct foreign currency debt hedge a portion of the carrying
value of foreign operations. Translation gains and losses related to these components are deferred and included in CTA in shareholders equity on a net of tax basis.

Realized gains and losses arising from the hedging of net investments and inter-company transactions are reflected as an investing activity in the statement of cash flows. Upon the settlement of certain financial
instruments designated as net investment hedges, a foreign exchange gain of $89.8 million was realized in 2005 (2004  $47.8 million, 2003  $194.1 million). This is recorded in the corporations cumulative translation
account in total equity. During 2004, the corporation reclassified prior year cash flows to be consistent with the current presentation.

Details of the notional amounts of cross-currency interest rate swaps are as follows:

|Year ended Dec. 31 |          |   |            | 2005       |          |   |            | 2004      
|------------------ | -------- | - | ---------- | ---------- | -------- | - | ---------- | ----------
|                   | Amount   |   | Fair value | Maturities | Amount   |   | Fair value | Maturities
|Australian dollars | AUD$34.0 | $ | 0.8        | 2009       | AUD$34.0 | $ | (3.4)      | 2005      
|U.S. dollars       | US$752.1 | $ | 101.9      | 20072015  | US$706.9 | $ | 128.7      | 20052012 

The corporation has also hedged a portion of its net investment in self-sustaining subsidiaries with foreign currency forward sales contracts as shown below:

|Year ended Dec. 31  |           |   |            | 2005       |           |   |            | 2004      
|------------------- | --------- | - | ---------- | ---------- | --------- | - | ---------- | ----------
|                    | Amount    |   | Fair value | Maturities | Amount    |   | Fair value | Maturities
|New Zealand dollars | NZ$      | $ |           |           | NZ$513.3  | $ | (142.5)    | 2005      
|U.S. dollars        | US$339.9  | $ | 15.8       | 20062008  | US$499.5  | $ | 82.10      | 2005      
|Australian dollars  | AUD$22.8  | $ | (0.1)      | 2006       | AUD$8.6   | $ |           | 2005      
|Mexican pesos       | MXN 871.6 | $ | (11.9)     | 2009       | MXN 871.6 | $ | 10.8       | 2009      

At Dec. 31, 2005, a $101.9 million asset (2004  $231.5 million) and a $14.7 million liability (2004  $83.9 million) related to the cross-currency interest rate swaps and forward sales
contracts was recorded in other assets (Note 8) and deferred credits and other long-term liabilities
(Note
11), respectively.

|98TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|--------------------------------------------

---

II. Hedges of Future Foreign Currency Obligations

The corporation has hedged future foreign currency obligations through forward purchase contracts as follows:

|Year ended Dec. 31 |           |           |                             |            |       | 2005                        |            |            |   |       | 2004
|------------------ | --------- | --------- | --------------------------- | ---------- | ----- | --------------------------- | ---------- | ---------- | - | ----- | ----
|Currency           | Amount    | Currency  | Amount                      | Fair value |       | Amount                      | Amount     | Fair value |  
|sold               | sold      | purchased | purchased asset (liability) | Maturities | sold  | purchased asset (liability) | Maturities
|Canadian dollars   | $7.8      | US$       | US$6.6                      | $          | (0.2) | 2006                        | $43        | US$29.5    | $ | (6.8) | 2005
|U.S. dollars       | $71.4     | Cdn$      | $83.0                       | $          | 0.4   | 2006                        | US$24.5    | $37.3      | $ | 7.1   | 2005
|Mexican pesos      | MXN 160.7 | US$       | US$15.1                     | $          | 0.1   | 2006                        | MXN 51.6   | US$4.6     | $ | 0.1   | 2005
|Canadian dollars   |          | NZ$       | NZ$                        | $          |      | N/A                         | $17.8      | NZ$20.0    | $ | (0.5) | 2005
|U.S. dollars       |          | NZ$       | NZ$                        | $          |      | N/A                         | US$207.1   | NZ$456.7   | $ | 141.1 | 2005

At Dec. 31, 2005, a $25.6 million asset (2004  $8.7 million) and a $25.2 million liability (2004  $52.2 million) related to these hedges was recorded in other assets(Note 8)and deferred credits and other long-term liabilities(Note 11), respectively.

B. Interest Rate Risk ManagementI. Existing DebtThe corporation has converted fixed interest rate debt at fixed rates, ranging from 5.75 per cent to 6.9 per cent, to floating rates through interest rate swaps(Note 10)as shown below:

|Year ended Dec. 31 |          |   |            | 2005       |          |   |            | 2004      
|------------------ | -------- | - | ---------- | ---------- | -------- | - | ---------- | ----------
|                   | Notional |   | Fair value |            | Notional |   | Fair value |           
|                   | amount   |   | of swaps   | Maturities | amount   |   | of swaps   | Maturities
|Fixed rate debt    | $ 375.0  | $ | 30.8       | 20062011  | $ 375.0  | $ | 39.9       | 20062011 
|                   | US$300.0 | $ | (4.8)      | 2013       | US$300.0 | $ | 1.60       | 2013      

|Year ended Dec. 31 |          |   |            | 2005     |          |   |            | 2004              
|------------------ | -------- | - | ---------- | -------- | -------- | - | ---------- | ------------------
|                   | Notional |   | Fair value |          | Notional |   | Fair value |                   
|                   | amount   |   | of swaps   | Maturity | amount   |   | of swaps   | Maturity          
|                   |          |   |            |          |          |   |            | (Restated, Note 1)
|Floating rate debt | US$37.1  | $ | (1.3)      | 2008     | US$50.3  | $ | (3.9)      | 2008              

The fair value of the corporations fixed interest long-term debt changes as interest rates change, with details as follows:

|Year ended Dec. 31                        |           | 2005       |           | 2004              
|----------------------------------------- | --------- | ---------- | --------- | ------------------
|                                          | Carrying  |            | Carrying  |                   
|                                          | amount    | Fair value | amount    | Fair value        
|                                          |           |            |           | (Restated, Note 1)
|Long-term debt, including current portion | $ 2,780.0 | $ 2,905.0  | $ 3,076.2 | $ 3,259.9         

At Dec. 31, 2005, a $38.4 million asset (2004  $44.4 million) related to the interest rate swaps was recorded in other assets(Note 8).



| | CONSOLIDATED FINANCIAL
      STATEMENTS         99
| | --------------------------------------------------

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C. Energy Commodities Price Risk Management

I. Trading Activities

The corporation markets energy derivatives, including physical and financial swaps, forwards and options, to optimize returns from assets, to earn trading revenues and to gain market information.

At Dec. 31, 2005 and 2004, details of the corporations fixed price trading positions were as follows:

Electricity
	Natural gasUnits (000s)
	(MWh)
	(GJ)Fixed price payor, notional amounts, Dec. 31, 2005
	19,315
	11,126Fixed price payor, notional amounts, Dec. 31, 2004
	14,029
	13,422Fixed price receiver, notional amounts, Dec. 31, 2005
	19,047
	12,158Fixed price receiver, notional amounts, Dec. 31, 2004
	13,558
	12,277Maximum term in months, Dec. 31, 2005
	24
	12Maximum term in months, Dec. 31, 2004
	24
	12


The gross physical and financial volumes of settled sales of proprietary trading transactions are as follows:

Electricity (GWh)Year ended Dec. 31
	2005
	2004
	2003Physical
	58,016
	61,165
	55,506Financial
	57,666
	23,239
	34,327115,682
	84,404
	89,833Gas (million GJ)Year ended Dec. 31
	2005
	2004
	2003Physical
	86.9
	122.4
	100.1Financial
	326.9
	308.0
	170.1413.8
	430.4
	270.2


Dec. 31
	2005
	
	2004Price risk management assetsCurrent
	$ 63.8
	$
	41.9Long term
	13.8
	
	11.3Price risk management liabilitiesCurrent
	(58.3)
	
	(27.7)Long term
	(8.6)
	
	(10.0)Net price risk management assets outstanding
	$ 10.7
	$
	15.5


The change in fair value of contracts outstanding at Dec. 31, 2005 and 2004, as well as the changes in fair value of the net price risk management assets for 2005, is attributed to the following:

Change in fair value of net assets
	Fair valueNet price risk management assets outstanding at Dec. 31, 2004
	$
	15.5Contracts realized, amortized or settled during the year
	
	(24.4)Changes in values attributable to market price and other market changes
	
	6.1New contracts entered into during the current calendar year
	
	13.5Net price risk management assets outstanding at Dec. 31, 2005
	$
	10.7


|100TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|---------------------------------------------

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II. Hedging ActivitiesThe corporation uses energy derivatives, including physical and financial swaps, forwards and options, to manage its exposure to changes in electricity and natural gas prices. At Dec. 31, 2005, details of the
corporations hedging position were as follows:

Fixed price
	Fixed pricepayor
	receivernotional
	notional
	Maximum termamount (GJ)
	amount (MWh)
	in monthsCommodity hedges (000s)
	8,093.7
	33,770.7
	60


The fair value of these hedges is a $382.6 million liability (2004  $12.6 million).

In addition, the corporation has entered into a number of long-term power sales and gas purchase contracts, as well as transportation agreements in the normal course of business. The maximum remaining term of these
contracts is 20 years.

D. Credit Risk ManagementThe corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts, and continually
monitors these exposures. For Energy Marketing, the corporation sets strict credit limits for each counterparty and halts trading activities with the counterparty if the limits are exceeded. The corporation makes detailed assessments of the credit
quality of all counterparties and, where appropriate, obtains corporate guarantees and/or letters of credit to support the ultimate collection of these receivables. TransAlta is exposed to minimal credit risk for Alberta Generation PPAs as all
receivables are guaranteed by letters of credit.

The maximum credit exposure to any one customer, excluding the California market receivables discussed above and including the fair value of open trading positions, is $34.2 million.

Joint venture
	Ownership interest
	DescriptionSheerness joint venture
	50%
	Coal-fired plant in Alberta, of which TA Cogen has a 50 per cent interest,and is operated by Canadian UtilitiesMeridian joint venture
	50%
	Cogeneration plant in Alberta, of which TA Cogen has a 50 per cent interest,and is operated by Husky EnergyFort Saskatchewan joint venture
	60%
	Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest,and is operated by TransAltaMcBride Lake joint venture
	50%
	Wind generation facilities in Alberta, operated by TransAltaGoldfields Power joint venture
	50%
	Gas-fired plant in Australia, operated by TransAltaCE Generation LLC
	50%
	Geothermal and gas plants in the United States, operated by CE Gen affiliatesGenesee 3
	50%
	Coal-fired plant in Alberta, operated by EPCOR Utilities Inc.


| | CONSOLIDATED FINANCIAL
      STATEMENTS         101
| | ---------------------------------------------------

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Summarized information on the results of operations, financial position and cash flows relating to the corporations pro-rata interests in its jointly controlled corporations was as follows:

2005
	
	2004
	
	2003Results of operationsRevenues
	$ 619.9
	$
	505.2
	$
	539.0Expenses
	(481.1)
	
	(424.3)
	
	(429.3)Non-controlling interests
	(43.7)
	
	(37.1)
	
	(25.9)Proportionate share of net earnings
	$ 95.1
	$
	43.8
	$
	83.8Cash flowsCash flow from operations
	$ 111.5
	$
	153.2
	$
	498.7Cash flow used in investing activities
	(10.3)
	
	(21.6)
	
	(1,603.4)Cash flow used in financing activities
	(76.3)
	
	(129.1)
	
	1,131.5Proportionate share of decrease in cash and cash equivalents
	$ 24.9
	$
	2.5
	$
	26.8Financial positionCurrent assets
	$ 162.5
	$
	112.7
	$
	125.9Long-term assets
	1,895.4
	
	2,033.7
	
	2,214.4Current liabilities
	(118.0)
	
	(110.9)
	
	(135.1)Long-term liabilities
	(552.7)
	
	(635.6)
	
	(806.2)Non-controlling interests
	(396.1)
	
	(416.3)
	
	(164.5)Proportionate share of net assets
	$ 991.1
	$
	983.6
	$
	1,234.5


RELATED-PARTY TRANSACTIONSOn March 8, 2005, TA Cogen entered into an agreement with TEC whereby TEC provided a financial fixed-for-floating price swap to TA Cogen during planned maintenance at Sheerness in the second quarter of 2005.

On Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220 MW Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TA Cogen for its fair value of $110.0 million. TA
Cogen (owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power) financed the acquisition through the use of $50.0 million of cash on hand and by the issuance of $30.0 million of units to each of TransAlta Power and TEC. TA
Cogen also issued an advance to TEC for $30.0 million. The advance outstanding at Dec. 31, 2005 was $5.0 million (2004  $28.0 million) and is included in accounts receivable. TransAlta recorded a gain of $11.5 million after-tax
or $0.06 per common share ($17.7 million pre-tax) in 2004.

On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit coal-fired Sheerness Generating Station to TA Cogen for $630.0 million. The exchange amount was at fair value and was
determined based on an estimate of the future net cash flows of the plant and approved by the independent directors of TA Cogen. There are no ongoing contractual commitments or arrangements resulting from this sale apart from the provision of
operational and management services under normal commercial terms for the Sheerness Generating Station.

In connection with the sale of the Sheerness Generating Station, the obligation for TransAlta to purchase all of TransAlta Powers interest in TA Cogen on Dec. 31, 2018 that arose on the sale of power generation
assets to TA Cogen in 1998 has been eliminated; therefore the deferred gain of $119.8 million related to this sale was recognized in earnings in 2003. In addition, the management agreements between TransAlta, TransAlta Power and TA Cogen were
amended to remove the mechanism for the deferral of management fees and remove the obligation for TransAlta Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the amendments, TransAlta received $1.0
million from TransAlta Power and $5.0 million from TA Cogen.

In February 2003, TransAlta entered into an agreement with CE Gen, a corporation jointly controlled by TransAlta and MidAmerican Energy Holdings Company, a subsidiary of Berkshire Hathaway, whereby TransAlta buys
available power from certain CE Gen subsidiaries under normal commercial terms. In addition, CE Gen has entered into contracts with related parties to provide administrative and maintenance services.

For the period November 2002 to November 2007, TA Cogen entered into a transportation swap transaction with a wholly-owned subsidiary of TransAlta, TEC
(Note 8). TEC operates and maintains TA Cogens three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan, Alberta. TEC also provides management services to the
Sheerness Generating Station in Alberta, which
is operated by Canadian Utilities. The business purpose of the transportation swap was to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline trans-

|102TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|---------------------------------------------

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portation for two of its plants over the period of the swap. This stabilizes cash distributions in TA Cogen and thereby preserves the value of the limited partnership as a financing vehicle of TransAlta. The notional
gas volume in the transaction was the total delivered fuel for both facilities. Exchange amounts are based on the market value of the contract. TransAlta entered into an offsetting contract with an external third party, therefore TransAlta has no
risk other than counterparty risk.

TA Cogen entered into a fixed-for-floating gas swap transaction with TEC for a 61-month period starting Dec. 1, 2000. The swap transaction provides TA Cogen with fixed price gas for both the Mississauga and Ottawa
plants over the period. The floating prices associated with the Mississauga and Ottawa cogeneration plants long-term fuel supply agreements were transferred to TECs account. The notional gas volume in the transaction was the total
delivered fuel for both facilities. As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales. At Dec. 31, 2005, the portion of
the contract related to the non-controlling interest had a fair value liability of $1.6 million (2004  $4.9 million).

COMMITMENTSA significant portion of the corporations electricity and thermal sales revenues are subject to PPAs and long-term contracts. Commencing Jan. 1, 2001, a large portion of Albertas coal generation assets
became subject to long-term PPAs for a period approximating the remaining life of each plant or unit. These PPAs set a production requirement and availability target for each plant or unit and the price at which each MWh will be supplied to the
customer. Remaining coal capacity in Alberta is sold on the open electricity market. A portion of Poplar Creeks gas-fired capacity and all of its steam is committed to the customer under a long-term contract. The remaining capacity may be
taken by the customer at specified rates or sold on the open electricity market by TransAlta. Other gas-fired facilities in Alberta supply steam and/or electricity to specified customers under long-term contracts with additional requirements for
availability, reliability and other plant-specific performance measures. For Mexico, the plants energy production is subject to 25-year contracts with the Comisión Federal de Electricidad. These contracts set availability targets and
the price at which the plant will be paid per kilowatt of available capacity, as well as plant efficiency targets for recovery of fuel costs based on market prices. At Sarnia, there are 20-year contracts with a customer group with three, five-year
options for extensions to the contracts. The contracts allow for up to 40 per cent of the plants maximum capacity. These contracts set payments for peak megawatts, total megawatt hours and steam consumed, while TransAlta assumes the
availability and heat rate risk. The remaining capacity is available for export to the merchant market, based on market conditions. Energy production at the remaining Ontario plants is subject to contracts expiring in seven to 12 years. The Ontario
plants, except Ottawa, have contracts that set availability targets and the price at which the plant will be paid per MWhs produced, as well as risk sharing of fuel costs based on market prices. The terms of the Ottawa plant for electricity are
similar to the other Ontario plants except the risk sharing of fuel costs. Thermal energy contracts for these Ontario plants expire at the same time as the energy production contracts and are with a different customer base. These contracts set
payments for volumes consumed, while TA Cogen assumes the heat rate risk. At Centralia, a significant portion of production is subject to short- to medium-term energy sales contracts. In addition, a portion of the corporations energy sales
from its gas plants are subject to medium- to long-term energy sales contracts.

The corporation has entered into a number of long-term gas purchase agreements, transportation and transmission agreements, royalty and right-of-way agreements in the normal course of operations. Approximate future
payments under the fixed price purchase contracts, operating lease and mining agreements are as follows:

Fixed pricegas purchase
	
	Operating
	
	Miningcontracts
	
	leases
	
	agreements
	
	Total2006
	$
	55.8
	$
	12.8
	$
	61.6
	$
	130.22007
	
	56.5
	
	11.3
	
	44.9
	
	112.72008
	
	58.3
	
	10.3
	
	34.1
	
	102.72009
	
	35.2
	
	9.6
	
	20.1
	
	64.92010
	
	13.4
	
	9.3
	
	19.9
	
	42.62011 and thereafter
	
	127.0
	
	86.6
	
	297.7
	
	511.3Total
	$
	346.2
	$
	139.9
	$
	478.3
	$
	964.4


| | CONSOLIDATED FINANCIAL
      STATEMENTS         103
| | ---------------------------------------------------

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OTHER CONTINGENCIESIn March 2003, FERC completed its investigation of natural gas and power markets and indicated that the total industry refunds for price overcharges will be higher than originally anticipated.

In June 2003, FERC issued two show cause orders, the Partnership Gaming Order and the Gaming Practices Order, in which TransAltas U.S. subsidiaries were named. These orders required TransAlta to justify certain
trading activities in California between Oct. 1, 2000 and June 20, 2001. In response to FERCs show cause orders, TransAlta confirmed that it did not engage in gaming behavior. Based on the information provided by TransAlta, FERC Trial Staff
filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. On Jan. 22, 2004, FERC granted the FERC Trial Staffs motion to dismiss TransAlta from both the Partnership Gaming Order and the Gaming Practices Order. FERC
found that TransAlta did not engage in prohibited gaming practices.

On May 30, 2002, the California Attorney Generals Office filed civil complaints in the state court of California against eight wholesale power companies, including TransAlta. The complaint alleges violations of
Californias unfair business practices law in connection with rates charged for wholesale electricity sales. The state court denied the Attorney Generals complaint and granted an order to dismiss the claims against TransAlta. The Attorney
General dropped its appeal of this decision on Nov. 2, 2004, as such the decision is final as of such date.

On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol, which came into effect on Feb. 16, 2005. The Kyoto Protocol is not expected to have an impact on TransAltas U.S., Mexican or Australian
operations. TransAlta is not able to estimate the full impact the Protocol will have on its Canadian operations, as the Canadian government has not yet established its regulatory requirements. However, the PPAs for TransAltas coal-fired plants
in Alberta contain Change of Law provisions that should provide an opportunity to recover compliance costs from the PPA customers.

Mercury control requirements are being drafted in Canada and the United States and will impact coal-fired generation plants. In Alberta, TransAlta anticipates its coal-fired plants will require some form of mercury
capture technology in the next five to seven years. The exact technology and performance requirements have not yet been finalized, however, TransAlta is maintaining engineering readiness. Our PPAs will also provide an opportunity to recover these
costs under Change of Law provisions. In the United States, TransAltas Centralia coal-fired plant may or may not be subject to mercury reduction requirements by 2010, depending on Washington State determinations which are expected
by the end of 2006.

The corporation is involved in various other claims and legal actions arising from the normal course of business. The corporation does not expect that the outcome of these proceedings, having regard to insurance
available to it and the amounts reserved in respect of such claims, will have a materially adverse effect on the corporation as a whole.

COMPARATIVE FIGURESCertain of the comparative figures have been reclassified to conform with the current years presentation. Such reclassification did not impact previously reported net income or retained earnings.

SUBSEQUENT EVENTSOn Feb. 15, 2006, the corporation announced the signing of a five-year agreement with the Ontario Power Authority (OPA) for its Sarnia Regional Cogeneration Power Plant. Under the terms of the agreement, TransAlta will
be available to supply an average of 400 MW of electricity to the Ontario market. The supply agreement is effective from Jan. 1, 2006 to Dec. 31, 2010.

|104TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|---------------------------------------------

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A. Earnings and Earnings Per Share (EPS)

|                                                                | Reconciling |   |         |                    |                    |   |      
|--------------------------------------------------------------- | ----------- | - | ------- | ------------------ | ------------------ | - | -----
|Year ended Dec. 31                                              | items       |   | 2005    |                    | 2004               |   | 2003 
|                                                                |             |   |         | (Restated, Note 1) | (Restated, Note 1)
|Earnings from continuing operations  Canadian GAAP             |             | $ | 186.8   | $                  | 160.6              | $ | 234.2
|Derivatives and hedging activities, net of tax                  | I           |   | 10.5    |                    | (3.8)              |   | (4.5)
|Start-up costs, net of tax                                      | III         |   | (0.1)   |                    | (0.1)              |   | (6.7)
|Recognition of debt extinguishment, net of tax                  | IV          |   |        |                    |                   |   | 11.1 
|Amortization of pension transition adjustment                   | II          |   | (4.0)   |                    | (4.5)              |   | (4.6)
|Cumulative effect of change in accounting principle, net of tax | X           |   |        |                    |                   |   | 52.5 
|Earnings from continuing operations  U.S. GAAP                 |             |   | 193.2   |                    | 152.2              |   | 282.0
|Earnings from discontinued operations  Canadian and U.S. GAAP  |             |   | 12.0    |                    | 9.6                |   |     
|Net earnings before change in accounting principle  U.S. GAAP  |             |   | 205.2   |                    | 161.8              |   | 282.0
|Net earnings  U.S. GAAP                                        |             | $ | 205.2   | $                  | 161.8              | $ | 282.0
|Foreign currency cumulative translation adjustment              | I,VII       |   | (22.6)  |                    | 3.7                |   | 8.2  
|Net gain (loss) on derivative instruments                       | I,VII       |   | (214.6) |                    | 10.4               |   | 8.8  
|Registered pension alternate minimum liability                  | II,VII      |   | (11.5)  |                    | (0.6)              |   | 0.6  
|Comprehensive income  U.S. GAAP                                |             | $ | (43.5)  | $                  | 175.3              | $ | 299.6
|Basic EPS  U.S. GAAP                                           |             |   |         |                    |                    |   |      
|Earnings from continuing operations                             |             | $ | 0.98    | $                  | 0.79               | $ | 1.24 
|Earnings from discontinued operations                           |             |   | 0.06    |                    | 0.05               |   |     
|Cumulative effect of change in accounting principle             |             |   |        |                    |                   |   | 0.28 
|Net earnings                                                    |             | $ | 1.04    | $                  | 0.84               | $ | 1.52 
|Diluted EPS  U.S. GAAP                                         |             |   |         |                    |                    |   |      
|Earnings from continuing operations                             |             | $ | 0.98    | $                  | 0.79               | $ | 1.24 
|Earnings from discontinued operations                           |             |   | 0.06    |                    | 0.05               |   |     
|Cumulative effect of change in accounting principle             |             |   |        |                    |                   |   | 0.28 
|Net earnings                                                    |             | $ | 1.04    | $                  | 0.84               | $ | 1.52 

| | CONSOLIDATED FINANCIAL
      STATEMENTS         105
| | ---------------------------------------------------

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B. Balance Sheet Information

|Dec. 31                                                               |              |          | 2005      |          | 2004       
|--------------------------------------------------------------------- | ------------ | -------- | --------- | -------- | -----------
|                                                                      | Reconciling  | Canadian |           | Canadian |            
|                                                                      | items        | GAAP     | U.S. GAAP | GAAP     | U.S. GAAP)1
|Assets                                                                |              |          |           |          |            
|Price risk management assets, current                                 | I            | 63.8     | 77.7      | 41.9     | 89.7       
|Accounts receivable                                                   | VIII         | 593.4    | 593.4     | 422.5    | 421.0      
|Income taxes receivable                                               | I            | 48.8     | 50.2      | 60.1     | 75.1       
|Property, plant and equipment, net                                    | II           | 5,545.5  | 5,542.4   | 5,702.6  | 5,680.7    
|Price risk management assets, long term                               | I            | 13.8     | 162.6     | 11.3     | 199.0      
|Other assets (including current portion)                              | I, II        | 210.9    | 46.2      | 500.7    | 298.8      
|Liabilities                                                           |              |          |           |          |            
|Accounts payable and accrued liabilities                              | V            | 590.3    | 587.5     | 442.6    | 367.7      
|Income taxes payable                                                  | II           | 13.8     | 8.4       | 6.1      | 0.7        
|Price risk management liabilities, current                            | I            | 58.3     | 229.7     | 27.7     | 59.9       
|Long-term debt                                                        | I            | 2,208.6  | 2,237.0   | 2,321.1  | 2,365.0    
|Deferred credits and other liabilities (including current portion)    | I            | 365.9    | 365.9     | 633.0    | 639.8      
|Price risk management liabilities, long term                          | I            | 8.6      | 259.3     | 10.0     | 58.6       
|Future or deferred income tax liabilities (including current portion) | I, II, IV, V | 758.5    | 609.9     | 715.0    | 705.9      
|Non-controlling interest                                              | I            | 558.6    | 557.9     | 616.4    | 615.4      
|Equity                                                                |              |          |           |          |            
|Contributed surplus                                                   | X            |         | 133.0     |         | 133.0      
|Retained earnings                                                     | I, II, V     | 912.2    | 756.8     | 910.3    | 771.0      
|Cumulative translation adjustment                                     | I            | (67.0)   |          | (52.2)   |           
|Accumulated other comprehensive income                                | I, V, VII    |         | (341.3)   |         | (92.6)     

C. Reconciling ItemsI. Derivatives and Hedging Activities
Under U.S. GAAP, trading and non-trading activities are accounted for in accordance with Statement 133, which requires that derivative instruments be recorded in the consolidated balance sheets at fair value as either
assets or liabilities, and that changes in fair value be recognized currently in earnings, unless specific hedge accounting criteria are met. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and
of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in other comprehensive income, and the gains
and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness relating to these hedges is recognized currently in earnings. The assets and
liabilities related to derivative instruments for which hedge accounting criteria are met are reflected as price risk management assets and liabilities in the consolidated balance sheets. Many of the corporations electricity sales and fuel
supply agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment. This exemption is available for the
electricity industry as electricity cannot be stored and generators may be required to maintain sufficient capacity to meet customer demands. This exemption is also available for some physically settled commodity contracts if certain criteria are
met. Non-derivatives used in trading activities are accounted for using the accrual method under U.S. GAAP.

i. Fair Value Hedging Strategy
The corporation enters into forward exchange contracts to hedge certain firm commitments denominated in foreign currencies to protect against adverse changes in exchange rates and uses interest rate swaps to manage
interest rate exposure. The swaps modify exposure to interest rate risk by converting a portion of the corporations fixed-rate debt to a floating rate.

There was no ineffectiveness related to these hedges in the periods presented.

ii. Cash Flow Hedging Strategy
At Dec. 31, 2005, the corporations cash flow hedges of the forecasted sale of power and the forecasted purchase of natural gas for the corporations plants resulted in the recognition of an after tax
unrealized loss in OCI of $241.7 million. These hedges have been accounted for on an accrual basis under Canadian GAAP but have been recorded on the balance sheet at fair value for U.S. GAAP.

In the year ended Dec. 31, 2005, the corporations cash flow hedges resulted in an after-tax loss of $nil (2004  $nil, 2003  $1.9 million) related to the ineffective portion of its hedging
instruments, and an after-tax gain of $nil for year ended Dec. 31, 2005 (2004  $nil, 2003  $2.0 million) related to the portion not designated as a hedge.

|106TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|---------------------------------------------

---

In November 2003, forward starting swaps with a notional amount of US$200.0 million and treasury and spread locks with a notional amount of $100.0 million were settled and debt was issued, resulting in an
after-tax loss of $25.3 million. The loss is being reclassified from accumulated other comprehensive income (AOCI) into income as interest expense is recognized on the debt.

Over the next 12 months, the corporation estimates that $91.4 million of after-tax losses that arose from cash flow hedges will be reclassified from AOCI to net earnings. These estimates assume constant gas and
power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors. Therefore, management is unable to predict what the actual reclassification from AOCI to
earnings (positive or negative) will be for the next 12 months.

iii. Net Investment HedgesThe company uses cross-currency interest rate swaps, forward sales contracts and direct foreign currency debt to hedge its exposure to changes in the carrying value of its investments in its foreign subsidiaries in the
United States, Australia and Mexico. Realized and unrealized gains and losses from these hedges are included in Other Comprehensive Income (OCI), with the related amounts due to or from counterparties included in long-term derivative assets and
liabilities and long-term debt.

In the year ended Dec. 31, 2005, the corporation recognized an after-tax loss of $22.6 million (2004  $3.7 million income, 2003  $8.2 million income) on its net investment hedges, included in
OCI.

In the year ended Dec. 31, 2005, the corporation recognized after-tax gains of $nil (2004  nil, 2003  $0.2 million), related to ineffectiveness of net investment hedges.

iv. Trading ActivitiesThe corporation markets energy derivatives to optimize returns from assets, to earn trading revenues and to gain market information. Derivatives, as defined under Statement 133, are recorded on the consolidated balance
sheets at fair value under both Canadian and U.S. GAAP. Non-derivative contracts entered into subsequent to the rescission of EITF 98-10 are accounted for using the accrual method.

v. Other Hedging ActivitiesIn the year ended Dec. 31, 2005, the corporation recognized pre-tax losses of $13.7 million (2004  $1.1 million, 2003  $0.7 million gains) related to hedging activities that do not qualify for
hedge accounting under Statement 133.

II. Employee Future BenefitsU.S. GAAP requires that the cost of employee pension benefits be determined using the accrual method with application from 1989. It was not feasible to apply this standard using this effective date. The transition
asset as at Jan. 1, 1998 was determined in accordance with elected practice prescribed by the Securities and Exchange Commission (SEC) and is amortized over 10 years.

As a result of the corporations plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2005, the corporation was required under U.S. GAAP to recognize an additional minimum liability. The
liability was recorded as a reduction in common equity through a charge to OCI, and did not affect net income for 2005. The charge to OCI, will be restored through common equity in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation.

III. Start-up CostsUnder U.S. GAAP, certain start-up costs, including revenues and expenses in the pre-operating period, are expensed rather than capitalized to deferred charges and property, plant and equipment as under Canadian GAAP,
which also results in decreased depreciation and amortization expense under U.S. GAAP.

IV. Debt ExtinguishmentUnder U.S. GAAP, the premium on redemption of long-term debt related to the 1998 limited partnership transaction was recorded when incurred, whereas for Canadian GAAP, the loss was being amortized to earnings over the
period of the limited partnership (20 years). As the buyback option was terminated in connection with the sale of the Sheerness plant, the deferred amount was recognized in earnings in 2003.

V. Income Taxes

Future income taxes under Canadian GAAP are referred to as deferred income taxes under U.S. GAAP.

Deferred income taxes under U.S. GAAP would be as follows:

Dec. 31
	
	2005
	
	2004Future income tax liabilities (net) under Canadian GAAP
	$
	(584.8)
	$
	(561.5)Derivatives
	
	160.0
	
	23.2Start-up costs
	
	(2.3)
	
	(2.3)Pensions
	
	(9.1)
	
	(11.8)$
	(436.2)
	$
	(552.4)


| | CONSOLIDATED FINANCIAL
      STATEMENTS         107
| | ---------------------------------------------------

---

Comprised of the following:

Dec. 31
	
	2005
	
	2004Current deferred income tax assets
	$
	26.6
	$
	21.5Long-term deferred income tax assets
	
	147.1
	
	132.0Current deferred income tax liabilities
	
	(15.5)
	
	(11.1)Long-term deferred income tax liabilities
	
	(594.4)
	
	(694.8)$
	(436.2)
	$
	(552.4)


VI. Joint Ventures
In accordance with Canadian GAAP, joint ventures are required to be proportionately consolidated regardless of the legal form of the entity. Under U.S. GAAP, incorporated joint ventures are required to be accounted for
by the equity method. However, in accordance with practices prescribed by the SEC, the corporation, as a Foreign Private Issuer, has elected for the purpose of this reconciliation to account for incorporated joint ventures by the proportionate
consolidation method.

VII. Other Comprehensive Income (Loss)
The changes in the components of OCI were as follows:

Year ended Dec. 31
	2005
	
	2004
	
	2003Net gain on derivative instruments:Unrealized loss, net of taxes of $151.1 million
	$ (204.4)
	$
	7.0
	$
	5.4Reclassification adjustment for losses included in net income, net of taxes of $8.9 million
	(10.2)
	
	3.4
	
	3.4Net loss on derivative instruments
	(214.6)
	
	10.4
	
	8.8Translation adjustments
	(22.6)
	
	3.7
	
	8.2Registered pension alternate minimum liability (net of taxes of $9.1 million)
	(11.5)
	
	(0.6)
	
	0.6Other comprehensive (loss) income
	$ (248.7)
	$
	13.5
	$
	17.6


The components of AOCI were:

Dec. 31
	2005
	
	2004
	
	2003Net loss on derivative instruments
	$ (275.4)
	$
	(60.8)
	$
	(71.2)Translation adjustments
	(52.7)
	
	(30.1)
	
	(33.8)Registered pension alternate minimum liabilities
	(13.2)
	
	(1.7)
	
	(1.1)Accumulated other comprehensive loss
	$ (341.3)
	$
	(92.6)
	$
	(106.1)


IX. Asset Retirement ObligationsFinancial Accounting Standards Board (FASB) issued Statement 143,Asset Retirement Obligations,which requires asset retirement
obligations to be measured at fair value and recognized when the obligation is incurred. A corresponding amount is capitalized as part of the assets carrying amount and depreciated over the assets useful life. TransAlta adopted the
provisions of Statement 143 effective Jan. 1, 2003.

In accordance with Canadian GAAP, the asset retirement obligations standard was adopted retroactively with restatement of prior periods. Under U.S. GAAP, the impact of adopting Statement 143 was recognized as a
cumulative effect of a change in accounting principle as of Jan. 1, 2003, the beginning of the fiscal year in which the Statement was first applied. The change resulted in an after-tax increase in net earnings of $52.5 million ($82.7 million
pre-tax).

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. FIN No. 47 clarifies the
term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, and provides further guidance as to when an entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation.

|108TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|---------------------------------------------

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Effective Dec. 31, 2005, TransAlta adopted the provisions of FIN No. 47. TransAltas conditional asset retirement obligations (ARO) relate to the possible future retirement of our Centralia coal-fired
plant and Australian gas plants and related facilities and structures. TransAlta does not have a legal obligation to reclaim the site of the Centralia coal-fired plant, nor the Australian sites. If, however, TransAltas customers in Australia
close their respective sites, TransAlta must remove the existing plant from these sites. The ability to reasonably estimate a conditional ARO is a matter of management judgment, based on managements ability to reasonably estimate a settlement
date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs.

In accordance with the provisions of FIN No. 47, the Company has not recorded an asset retirement obligation associated with retirement of these facilities, given the uncertainty concerning the timing of future
retirement, if any. The adoption of FIN No. 47 on Dec. 31, 2005 did not result in any impact to TransAltas results of operations or financial position for the year ended Dec. 31, 2005, and the company does not expect the adoption to have a
material impact on future results of operations, financial position or liquidity.

X. Limited Partnership TransactionIn 1998, the corporation transferred generation assets to its subsidiary TA Cogen. TA Power, an unrelated entity, concurrently subscribed to a minority interest in TA Cogen. The fair value paid by TA Cogen for the
assets exceeded their historical carrying values. For Canadian GAAP, the corporation recognized a portion of this difference, to the extent it was funded by TA Powers investment in TA Cogen, as a gain. As TA Power held an option to resell
their interest in TA Cogen to the corporation in 2018, this gain was originally being amortized in to income over this period. In 2003, TA Powers option to resell these units was eliminated and the unamortized balance of the gain was
recognized in income.

Under U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 51, the option initially held by TA Power to potentially resell TA Cogen units to the corporation in 2018 causes the excess of the
consideration paid by TA Power over the corporations historical carrying value in these assets to be characterized as contributed surplus in 1998. This amount of contributed surplus is reduced by the related tax effect. As a result, under U.S.
GAAP, there is no amortization of the gain into income in the period from 1998 to 2002 and no recognition of the unamortized balance of the gain in 2003.

XI. Changes in Accounting StandardsOn May 19, 2004, FASB issued FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act
of 2003(the Act) that provides guidance on the accounting for the effects of the Act for employers that sponsor post-retirement health care plans that provide drug benefits. The Act introduces a
prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. TransAltas prescription drug benefit plan in the
United States is not material to the corporations post-retirement benefit plan and therefore the impact of the FSP is not material to the consolidated financial statements.

| | CONSOLIDATED FINANCIAL
      STATEMENTS         109
| | ---------------------------------------------------

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ELEVEN-YEAR
FINANCIAL & STATISTICAL SUMMARY(millions of Canadian dollars, except where noted)

|Year ended Dec. 31                                            | 2005      | 2004      | 2003     
|------------------------------------------------------------- | --------- | --------- | ---------
|FINANCIAL SUMMARY                                             |           |           |          
|Earnings statement                                            |           |           |          
|Revenues                                                      | $ 2,838.5 | $ 2,838.3 | $ 2,508.6
|Operating income                                              | $ 441.2   | $ 478.1   | $ 553.7  
|Net earnings applicable to common shareholders                | $ 198.8   | $ 170.2   | $ 234.2  
|Balance sheet                                                 |           |           |          
|Total assets                                                  | $ 7,740.7 | $ 8,133.0 | $ 8,420.2
|Short-term debt, net of cash and interest-earning investments | $ (66.2)  | $ (102.7) | $ (35.2) 
|Long-term debt                                                | $ 2,605.0 | $ 3,057.9 | $ 3,162.1
|Preferred shares of a subsidiary                              | $        | $        | $       
|Other non-controlling interests                               | $ 558.6   | $ 616.4   | $ 477.9  
|Preferred securities                                          | $ 175.0   | $ 175.0   | $ 450.8  
|Common shareholders equity                                   | $ 2,543.1 | $ 2,472.7 | $ 2,460.6
|Total invested capital                                        | $ 5,809.2 | $ 6,519.3 | $ 6,516.2
|Cash flow                                                     |           |           |          
|Cash flow from operating activities                           | $ 619.4   | $ 613.4   | $ 756.5  
|Cash flow used in investing activities                        | $ (242.1) | $ (65.4)  | $ (535.1)
|Common share information (per share)                          |           |           |          
|Net earnings                                                  | $ 1.01    | $ 0.88    | $ 1.26   
|Dividends declared                                            | $ 1.00    | $ 1.00    | $ 1.00   
|Book value (at year-end)                                      | $ 12.80   | $ 12.74   | $ 12.90  
|Market price:                                                 |           |           |          
|High                                                          | $ 26.66   | $ 18.75   | $ 19.55  
|Low                                                           | $ 17.67   | $ 15.25   | $ 15.36  
|Close (TSX at Dec. 31)                                        | $ 25.41   | $ 18.05   | $ 18.53  
|Ratios(percentage except where noted)                         |           |           |          
|Debt/invested capital                                         | 43.6      | 47.4      | 47.9     
|Return on common shareholders equity                         | 7.5       | 6.5       | 10.3     
|Return on invested capital                                    | 7.4       | 7.5       | 9.1      
|Cash flow to total debt                                       | 23.5      | 18.5      | 17.9     
|Cash flow to interest coverage                                | 4.8       | 4.1       | 3.3      
|Dividend payout                                               | 105.4     | 120.0     | 79.0     
|Dividend yield                                                | 3.9       | 5.5       | 5.4      
|Price/earnings multiple                                       | 26.7      | 21.7      | 14.7     
|Weighted average common shares for the year (in millions)     | 196.8     | 192.7     | 185.3    
|Common shares outstanding at Dec. 31 (in millions)            | 198.7     | 194.1     | 190.7    
|STATISTICAL SUMMARY                                           |           |           |          
|Number of employees                                           | 2,657     | 2,505     | 2,563    
|Generating capacity(net MW)3:                                 |           |           |          
|Hydro                                                         | 802       | 802       | 801      
|Coal                                                          | 4,885     | 4,778     | 4,777    
|Gas                                                           | 1,933     | 2,444     | 2,499    
|Renewables                                                    | 315       | 313       | 245      
|Total generating capacity                                     | 7,935     | 8,337     | 8,322    
|Total generation production (GWh)4                            | 51,810    | 54,560    | 53,134   

1 2002 and 2001 Energy Marketing real-time trading contract revenues restated to be presented on a gross basis.
2 Includes discontinued operations.
3 Represents TransAltas ownership.
4 Includes discontinued operations.

Ratio FormulasDebt/invested capital = (short-term debt + long-term debt  cash and interest-earning investments)/(debt + preferred securities + non-controlling interests + common equity) 
 Return on common shareholders
equity = net earnings excluding gain on discontinued operations/average of opening and closing common equity

|110         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|-------------------------------------------------------------

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|2002       | 2001        | 2000      | 1999      | 1998      | 1997      | 1996      | 1995     
|---------- | ----------- | --------- | --------- | --------- | --------- | --------- | ---------
|           |             |           |           |           |           |           |          
|           |             |           |           |           |           |           |          
|$ 1,814.91 | $ 2,559.51  | $ 1,587.0 | $ 1,029.4 | $ 1,089.9 | $ 1,656.4 | $ 1,515.6 | $ 1,330.5
|$ 223.92   | $ 468.92    | $ 604.62  | $ 442.02  | $ 660.12  | $ 586.6   | $ 570.6   | $ 591.4  
|$ 189.9    | $ 214.6     | $ 279.8   | $ 170.1   | $ 211.4   | $ 182.6   | $ 181.0   | $ 181.7  
|$ 7,419.6  | $ 7,877.9   | $ 7,627.1 | $ 6,038.4 | $ 5,392.6 | $ 4,882.2 | $ 4,804.4 | $ 4,346.9
|$ 146.7    | $ 475.2     | $ 220.5   | $ (173.6) | $ (149.4) | $ (20.3)  | $ 13.3    | $ 1.3    
|$ 2,706.6  | $ 2,511.1   | $ 2,201.4 | $ 2,177.4 | $ 1,903.6 | $ 2,198.0 | $ 2,364.0 | $ 2,009.0
|$         | $          | $ 121.6   | $ 268.3   | $ 268.4   | $ 267.6   | $ 270.5   | $ 371.9  
|$ 263.0    | $ 281.0     | $ 253.4   | $ 377.4   | $ 503.3   | $ 162.9   | $ 164.4   | $ 73.3   
|$ 451.7    | $ 452.6     | $ 292.0   | $ 287.1   | $        | $        | $        | $       
|$ 2,039.6  | $ 1,989.7   | $ 1,957.4 | $ 1,835.6 | $ 1,855.0 | $ 1,594.3 | $ 1,582.3 | $ 1,542.7
|$ 5,607.6  | $ 5,709.6   | $ 5,046.3 | $ 4,772.2 | $ 4,380.9 | $ 4,202.5 | $ 4,394.5 | $ 3,998.2
|$ 437.7    | $ 715.6     | $ 188.7   | $ 422.0   | $ 470.7   | $ 666.4   | $ 563.2   | $ 430.7  
|$ (36.2)   | $ (1,076.9) | $ (205.0) | $ (988.8) | $ (137.2) | $ (319.7) | $ (459.9) | $ (361.3)
|$ 1.12     | $ 1.27      | $ 1.66    | $ 1.00    | $ 1.31    | $ 1.14    | $ 1.14    | $ 1.14   
|$ 1.00     | $ 1.00      | $ 1.00    | $ 1.00    | $ 0.99    | $ 0.98    | $ 0.98    | $ 0.98   
|$ 12.01    | $ 11.82     | $ 11.61   | $ 10.85   | $ 10.94   | $ 9.96    | $ 9.92    | $ 9.71   
|$ 23.95    | $ 30.13     | $ 22.55   | $ 25.15   | $ 25.40   | $ 22.75   | $ 18.20   | $ 14.88  
|$ 16.69    | $ 19.15     | $ 13.20   | $ 12.25   | $ 18.20   | $ 15.10   | $ 14.25   | $ 13.00  
|$ 17.11    | $ 21.60     | $ 22.00   | $ 14.15   | $ 22.60   | $ 22.55   | $ 17.25   | $ 14.63  
|50.9       | 52.3        | 48.0      | 45.6      | 40.0      | 51.8      | 54.1      | 50.3     
|3.5        | 10.9        | 11.7      | 9.2       | 12.3      | 11.5      | 11.6      | 11.9     
|4.0        | 8.7         | 12.3      | 9.7       | 15.4      | 13.7      | 13.6      | 15.5     
|16.1       | 21.8        | 25.3      | 21.7      | 22.8      | 22.0      | 22.1      | 24.0     
|3.8        |            |          |          |          |          |          |         
|241.8      | 78.5        | 75.8      | 99.7      | 75.8      | 85.7      | 86.2      | 85.7     
|5.8        | 4.6         | 4.6       | 7.1       | 4.4       | 4.4       | 5.7       | 6.7      
|41.7       | 17.3        | 16.7      | 14.2      | 17.3      | 19.8      | 15.1      | 12.8     
|169.6      | 169.0       | 168.8     | 169.5     | 161.3     | 159.7     | 159.2     | 158.9    
|169.8      | 168.3       | 168.6     | 169.2     | 169.6     | 160.0     | 159.5     | 158.9    
|2,573      | 2,656       | 2,363     | 2,679     | 2,455     | 2,667     | 3,099     | 2,128    
|801        | 800         | 800       | 800       | 800       | 800       | 800       | 800      
|4,966      | 5,090       | 5,016     | 3,676     | 3,676     | 3,676     | 3,676     | 3,676    
|1,333      | 1,108       | 1,054     | 1,464     | 1,008     | 832       | 815       | 485      
|44         |            |          |          |          |          |          |         
|7,144      | 6,998       | 6,870     | 5,940     | 5,484     | 5,308     | 5,291     | 4,961    
|46,877     | 44,136      | 40,644    | 37,771    | 39,001    | 36,401    | 34,264    | 33,373   

| | CONSOLIDATED FINANCIAL
      STATEMENTS         111
| | ---------------------------------------------------

---

SHAREHOLDER INFORMATION

ANNUAL MEETINGThe Annual Meeting will be held at 1 p.m. EST on Thursday, April 27, 2006 at Le Royal Meridien King Edward Hotel, Vanity Fair A Ballroom, 37 King Street East, Toronto, Ontario

TRANSFER AGENTCIBC Mellon Trust Company 
 P.O. Box 7010 
 Adelaide Street Station 
 Toronto, Ontario M5C 2W9

PhoneNorth America:
1.800.387.0825 toll-free 
 Toronto/outside North America: 416.643.5500

E-mailinquiries@cibcmellon.com

Fax416.643.5501

Websitewww.cibcmellon.com

EXCHANGESToronto Stock Exchange (TSX) 
 New York Stock Exchange (NYSE)

TICKER SYMBOLSTransAlta Corporation common shares: 
TSX: TA          NYSE: TAC 
 TransAlta Corporation preferred securities: 
TSX: TA.Pr.C

VOTING RIGHTSCommon shareholders receive one vote for each common share held

ADDITIONAL INFORMATIONRequests can be directed to: 
 Investor Relations 
 TransAlta Corporation 
 P.O. Box 1900, Station M 
 110 - 12th Avenue S.W. 
 Calgary, Alberta T2P 2M1

PhoneNorth America:
1.800.387.3598 toll-free 
 Calgary/outside North America: 
 403.267.2520

E-mailinvestor_relations@transalta.com

Fax403.267.2590

Websitewww.transalta.com

SPECIAL SERVICES FOR REGISTERED SHAREHOLDERS

|Service                  | Description                                         
|------------------------ | ----------------------------------------------------
|Dividend reinvestment    | Conveniently reinvest your TransAlta dividends and  
|and share purchase plan* | purchase common shares without brokerage costs      
|Direct deposit for       | Automatically have dividend payments deposited to   
|dividend payments        | your bank account                                   
|Account consolidations   | Eliminate costly duplicate mailings by consolidating
|                         | account registrations                               
|Address changes          | Receive tax slips and dividends without the delays  
|and share transfers      | resulting from address and ownership changes        

STOCK SPLITS AND SHARE CONSOLIDATIONS

|Date          | Events                                      | Ratio
|------------- | ------------------------------------------- | -----
|May 8, 1980   | Stock split                                 | 3:1  
|Feb. 1, 1988  | Stock split1                                | 2:1  
|Dec. 31, 1992 | Reorganization  TransAlta Utilities shares | 1:1  
|              | exchanged for TransAlta Corporation shares2 |      

The valuation date value of common shares owned on Dec. 31, 1971, adjusted for stock splits, is $4.54 per share.
1 The adjusted cost base for shares held on Jan. 31, 1988 was reduced by $0.75 per share following the Feb. 1, 1988 share split.
2 TransAlta Utilities Corporation became a wholly-owned subsidiary of TransAlta Corporation as a result of this reorganization.

DIVIDEND POLICY

In declaring dividends, the directors consider several factors, including the corporations earnings, cash flow, capital requirements and the expectations of shareholders.

IMPORTANT DIVIDEND DATES

|Payment Date  | Record Date   | Ex-Dividend Date
|------------- | ------------- | ----------------
|April 1, 2005 | March 1, 2005 | Feb. 25, 2005   
|July 1, 2005  | June 1, 2005  | May 30, 2005    
|Oct. 1, 2005  | Sept. 1, 2005 | Aug. 30, 2005   
|Jan. 1, 2006  | Dec. 1, 2005  | Nov. 29, 2005   
|April 1, 2006 | March 1, 2006 | Feb. 27, 2006   

Dividends are paid on the first of the month in January, April, July and October. When a dividend payment date falls on a weekend or holiday, the payment is made on the following business day. Only dividend payments
that have been approved by the Board of Directors are included in this table.

SUBMISSION OF CONCERNS REGARDING ACCOUNTING OR AUDITING MATTERS

In 2002, TransAlta adopted a procedure for employees, shareholders or others to report concerns or complaints regarding accounting or auditing matters on an anonymous, confidential basis to the Audit and Environment
Committee of the Board of Directors. Such submissions may be directed to the Audit and Environment Committee c/o the Corporate Secretary of the corporation.

|112         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|-------------------------------------------------------------

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SHAREHOLDER HIGHLIGHTS



| | CONSOLIDATED FINANCIAL
      STATEMENTS         113
| | ---------------------------------------------------

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CORPORATE INFORMATION

In an effort to be environmentally responsible, please notify your financial institution to avoid duplicate mailings of this annual report.

Design Karo
Photography Jason Stang 
Production DaSilva Graphics 
 Printing Sundog Printing 
 Project Management Joan Moss

*The TransAlta design and TransAlta wordmark are trademarks of TransAlta Corporation.

This report was printed in Canada by Sundog Printing on FSC Certified paper. The paper, paper mills and printer are all Forest Stewardship Council certified, which is an international network that promotes
environmentally appropriate and socially beneficial management of the worlds forests. The report was produced in a printing facility that results in nearly zero volatile organic compound (VOC) emissions.

TRANSALTA CORPORATION OFFICERS

Stephen G. Snyder
President &
Chief Executive Officer

Ian A. Bourne
Executive Vice-President

Brian Burden
Executive Vice-President & 
 Chief Financial Officer

Linda K. Chambers
Executive Vice-President, 
 Generation Technology & 
 Supply Chain Management

Frederick M. Gallagher
Executive Vice-President, 
 Gasification

Richard P. Langhammer
Executive Vice-President, 
 Generation Operations

Thomas M. Rainwater
Executive Vice-President, 
 Corporate Development & 
 Marketing

Ken Stickland
Executive Vice-President,
Legal

Michael Williams
Executive Vice-President, 
 Human Resources & Communications

Gregory Wilson
Senior Vice-President & 
 Chief Information Officer

Mike Bartel
Vice-President, 
 Engineering Services

William D.A. Bridge
Vice-President,
Western Canada Operations

Kelly Gunsch
Vice-President,
Commercial Portfolio Management

Mark Mackay
Vice-President, 
 Energy Technology

Robert J.D. Page
Vice-President,
Sustainable Development

Gregory P. Reinhart
Vice-President,
Generation Human Resources

Don Thomas
Vice-President,
Vision Quest Windelectric

Marvin J. Waiand
Vice-President & Treasurer

Jubran Whalan
Vice-President, Commodity Trading

Garth A. Wong
Vice-President & Comptroller

Maryse St.-Laurent
Corporate Secretary

Frank Hawkins
Assistant Treasurer

TRANSALTA SUBSIDIARIES

JoAnne C. Butler
President, TransAlta Mexico, S.A. de C.V.

Doug Jackson
President, TransAlta Centralia 
 Generation LLC & Mining LLC

Troy A. Morrison
Country Manager,
TransAlta Energy (Australia) Pty Ltd.

2005 CHANGES
Ian Bourne retired as Executive 
 Vice-President & Chief Financial Officer 
 in 2005. Ian remains part of TransAltas 
 leadership team.

Robert Soeldner, officer of TransAlta 
 Corporation, left in 2005.

|114         
      TRANSALTA CORPORATION / 2005 ANNUAL REPORT
|-------------------------------------------------------------

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