EXHIBIT 99.6

---





Management's Discussion and Analysis

March 13, 2007

Highlights

|(millions of C$ unless otherwise stated)                                 |                                         | 2006                                    |       | 20051  |       | 20041 
|------------------------------------------------------------------------ | --------------------------------------- | --------------------------------------- | ----- | ------ | ----- | ------
|                                                                        
|Net income                                                               |                                         | 2,005                                   |       | 1,561  |       | 654   
|                                                                        
|                                                                         | Net income from continuing operations   |                                         | 1,452 |        | 1,354 |       
|                                                                        
|                                                                         | Net income from discontinued operations |                                         | 553   |        | 207   |       
|                                                                        
|Dividends                                                                |                                         | 163                                     |       | 125    |       | 114   
|                                                                        
|Per share2 (C$)                                                          |                                         |                                         |       |        |       |       
|                                                                         | Net income                              |                                         | 1.84  |        | 1.41  |       
|                                                                        
|                                                                         |                                         | Net income from continuing operations   |       | 1.33   |       | 1.23  
|                                                                        
|                                                                         |                                         | Net income from discontinued operations |       | 0.51   |       | 0.18  
|                                                                        
|                                                                         | Dividends                               |                                         | 0.15  |        | 0.11  |       
|                                                                        
|Production (mboe/d)                                                      |                                         | 485                                     |       | 470    |       | 438   
|                                                                        
|Production per share2 (boe/share)                                        |                                         | 0.162                                   |       | 0.155  |       | 0.139 
|                                                                        
|Average sales price ($/boe)                                              |                                         | 57.45                                   |       | 56.67  |       | 42.75 
|                                                                        
|Gross sales3                                                             |                                         | 9,362                                   |       | 8,888  |       | 6,299 
|                                                                        
|Operating costs ($/boe)                                                  |                                         | 9.98                                    |       | 8.41   |       | 7.26  
|                                                                        
|DD&A, exploration and dry hole expense3                                  |                                         | 2,619                                   |       | 2,205  |       | 2,028 
|                                                                        
|Cash provided by operating activities                                    |                                         | 4,374                                   |       | 4,871  |       | 3,119 
|                                                                        
|Cash provided by continuing operating activities                         |                                         | 4,086                                   |       | 4,459  |       | 2,780 
|                                                                        
|Exploration and development spending3                                    |                                         | 4,540                                   |       | 3,132  |       | 2,471 
|                                                                        
|Total assets                                                             |                                         | 21,461                                  |       | 18,354 |       | 12,408
|                                                                        
|Total long-term debt                                                     |                                         | 4,560                                   |       | 4,263  |       | 2,457 
|                                                                        
|Proved reserves additions (before acquisitions and divestitures) (mmboe) |                                         | 202                                     |       | 203    |       | 265   
|                                                                        
|Proved reserves (mmboe)                                                  |                                         | 1,667                                   |       | 1,639  |       | 1,488 
|                                                                        
|Proved reserves replacement ratio4                                       |                                         | 116%                                    |       | 120%   |       | 166%  
|                                                                        

This Management's Discussion and Analysis (MD&A) dated March 13, 2007 should be read in conjunction with the Consolidated Financial Statements of the
Company. The Company's Consolidated Financial Statements and the financial data included in the MD&A have been prepared in accordance with accounting principles generally accepted in Canada (Canadian
GAAP). A summary of the differences between Canadian GAAP and those generally accepted in the United States (US GAAP) is contained in note 20 to the Consolidated Financial
Statements.

Unless
otherwise stated, references to production and reserves represent Talisman's working interest share (including Talisman's share of volumes of royalty interests and net profits interests) before
deduction of royalties. Throughout this MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas to one barrel
(bbl) of oil and is based on an energy equivalence conversion method. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an
energy equivalence conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalence at the wellhead.

Dollar
amounts included in the MD&A are expressed in Canadian dollars (C$), unless otherwise indicated. All comparative percentages are between the years ended December 31, 2006 and
December 31, 2005, unless stated otherwise.

The
United Kingdom (UK) and Scandinavia, which were classified as the North Sea in 2005, are reported separately in 2006. The reporting segment entitled Other for 2006 includes results of
operations for North Africa (Algeria and Tunisia) and Trinidad and Tobago, which were reported separately in 2005. Other exploration areas include Colombia, Peru and Qatar. During 2006, activities in
Alaska, which previously had been included in the Other reporting segment, were reclassified and included in North America. Reclassifications have been made for all corresponding reported periods.

Talisman
Energy Inc.'s subsidiaries conduct business in various parts of the world. Talisman Energy Inc.'s financial statements are prepared on a consolidated basis. For ease of
reference, throughout this MD&A, the terms Talisman and the Company are used to refer collectively to Talisman Energy Inc., its direct and indirect subsidiaries and partnership interests held
by Talisman Energy Inc. and its subsidiaries, unless the context indicates otherwise.

Information
relating to changes in the Company's reporting segments in 2005 and 2006 is included in the section entitled Segmented Results Review of this MD&A.

Additional
information relating to the Company, including the Company's Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at
www.sedar.com. The Company's annual report on Form 40-F may be found in the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database
at www.sec.gov.

2   Talisman Energy 2006 Annual Financial Report

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Talisman's Performance Highlights in 2006

In 2006, production averaged a record 485 mboe/d, 3% higher than 2005. Net income for the year was a record $2 billion ($1.84 per share), 28%
higher than 2005. The increase in net income was due to gains on asset sales, increased oil production and prices, hedging gains and decreased stock-based compensation charges, partially offset by the
impact of the stronger C$ in relation to its US counterpart, decreased prices for natural gas in North America and increases in royalties, operating expenses, DD&A and taxes.

During
2006, Talisman repurchased more than 35 million shares at an average price of $18.66 per share, long-term debt increased to $4.6 billion with increased capital
expenditures and the Company increased its semi-annual dividend rate by 32.4% to $0.075 per share.

In
North America, 2006 operational highlights included major discoveries in the Northern Alberta Foothills, Monkman and Appalachia, as well as the completion of the Palliser and Lynx Pipelines. The
Company added significant amounts of new acreage in Alaska and the Outer Foothills. In the UK and Scandinavia, the Company continued to progress 11 development projects which are expected to
increase production to approximately 240,000 boe/d in 2009. In Indonesia, the commissioning of the Phase 2 expansion of the Corridor gas plant is underway. In Malaysia, the Bunga Tulip
field came onstream in the fourth quarter and in Vietnam, a successful exploration well was drilling on Block 15-2/01 at year-end.

In
2006, production per share increased 4.4% over the previous year. Talisman spent $4.5 billion on exploration and development activities and participated in drilling 773 successful
wells in 2006 and sold non-core properties for proceeds in excess of $870 million. During 2005 and 2004, production averaged 470 mboe/d and 438 mboe/d, respectively.

In
2006, Talisman added 202 mmboe of proved reserves, before acquisitions and dispositions, replacing 116% of production. Including acquisition and disposition activity, the Company added
203 mmboe of proved reserves also replacing 116% of production.

2007 Outlook Summary

Additional discussion of management's estimates and assumptions for 2007, as highlighted below, can be found in the MD&A section entitled Outlook
for 2007:



Talisman Energy 2006 Annual Financial Report   3

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2006 Variances

Net Income

|(millions of C$)                                        |  |       |  
|------------------------------------------------------- |  | ----- | -
|                                                        | 
|2005 Net income                                         |  | 1,561 |  
|                                                        | 
|Favourable (unfavourable)                               |  |       |  
|                                                        | 
|Cash items                                              |  |       |  
|                                                        | 
|Oil and liquids volumes                                 |  | 349   |  
|                                                        | 
|Oil and liquids prices                                  |  | 1,043 |  
|                                                        | 
|Oil and liquids foreign exchange price impact           |  | (447  | )
|                                                        | 
|Natural gas volumes                                     |  | 130   |  
|                                                        | 
|Natural gas prices                                      |  | (369  | )
|                                                        | 
|Natural gas foreign exchange price impact               |  | (232  | )
|                                                        | 
|Hedging  Commodities                                   |  | 143   |  
|                                                        | 
|Royalties                                               |  | (87   | )
|                                                        | 
|Other revenue                                           |  | 9     |  
|                                                        | 
|Operating expense                                       |  | (313  | )
|                                                        | 
|Transportation expense                                  |  | (22   | )
|                                                        | 
|Interest expense                                        |  | (3    | )
|                                                        | 
|Current taxes (including petroleum revenue tax) (PRT)   |  | 116   |  
|                                                        | 
|General and administrative                              |  | (32   | )
|                                                        | 
|Stock-based compensation payments                       |  | (6    | )
|                                                        | 
|Discontinued operations                                 |  | (124  | )
|                                                        | 
|Other                                                   |  | (79   | )
|                                                        | 
|Total cash items variance                               |  | 76    |  
|                                                        | 
|Non-cash items                                          |  |       |  
|                                                        | 
|Depreciation, depletion and amortization (DD&A) expense |  | (316  | )
|                                                        | 
|Dry hole expense                                        |  | (55   | )
|                                                        | 
|Exploration expense                                     |  | (43   | )
|                                                        | 
|Future taxes (including PRT)                            |  | (421  | )
|                                                        | 
|Stock-based compensation (non-cash)                     |  | 589   |  
|                                                        | 
|Discontinued operations                                 |  | 470   |  
|                                                        | 
|Other                                                   |  | 144   |  
|                                                        | 
|Total non-cash items variance                           |  | 368   |  
|                                                        | 
|2006 Net income                                         |  | 2,005 |  
|                                                        | 

The significant variances from 2005 as summarized in the net income variance table are:



Discontinued Operations

In 2006, the Company announced a program to divest certain non-core oil and gas assets in Western Canada and the UK.

Operating
results from these assets are included in net income from discontinued operations. During 2006, several deals closed, with the resulting after tax gains on disposals of assets of
$147 million (North America assets) and $209 million (UK assets) included in net income from discontinued operations.

During
2006, the Company further advanced its plan to realize value from non-core assets by selling its oil sands interests. The sale of the Company's indirect interest in Syncrude closed
on January 2, 2007 for proceeds of $477 million, with an after tax gain of $236 million to be included in net

4   Talisman Energy 2006 Annual Financial Report

---



income
from discontinued operations in 2007. The Company held a 1.25% indirect interest in Syncrude, which produced approximately 3,400 bbls/d, net to Talisman, in 2006. Operating results from
these assets are included in net income from discontinued operations, with the related assets and liabilities reported as assets and liabilities of discontinued operations in the Consolidated
Balance Sheets.

In
December 2006, Talisman entered into an agreement to sell its non-operated interests in the Brae area in the UK North Sea for consideration of US$550 million. Operating
results from these assets are included in net income from discontinued operations, with the related assets and liabilities reported as assets and liabilities of discontinued operations in the
Consolidated Balance Sheets. The resulting gain or loss on disposition of these assets will be recorded when the transaction closes, which is expected to occur later in 2007.

During
the fourth quarter of 2006, Talisman announced plans to sell an additional 16,000 boe/d of oil and gas producing assets in Western Canada. These assets are not included in the results of
discontinued operations as at December 31, 2006, but are expected to be reclassified in 2007.

Details
on results of discontinued operations and related production are presented in the tables below. Prior years have been restated to present the effect of discontinued operations. See
note 2 to the Consolidated Financial Statements.

Results of Discontinued Operations

|                                                |  | For the 12 months ended December 31
|----------------------------------------------- |  | -----------------------------------
|                                                |  | North America                      
|(millions of C$)                                |  | 2006                               
|                                               
|Income from discontinued operations, net of tax |  | 39                                 
|                                               
|Gain on disposition of assets, net of tax       |  | 147                                
|                                               
|Income from discontinued operations             |  | 186                                
|                                               

Daily Average Production Volumes (mboe/d)

|                        |                | 2006 |    | 2005 |    | 2004
|----------------------- | -------------- | ---- | -- | ---- | -- | ----
|                       
|Discontinued operations |                |      |    |      |    |     
|                       
|                        | North America  |      | 7  |      | 11 |     
|                       
|                        | United Kingdom |      | 26 |      | 25 |     
|                       
|Discontinued operations |                | 33   |    | 36   |    | 38  
|                       

Continuing Operations Results Review

Revenue

Revenues from oil, liquids and natural gas sales in 2006 were $9.4 billion, 5% above last year, due to higher oil and liquids prices ($596 million), oil and
liquids volumes ($349 million) and natural gas volumes ($130 million), partially offset by reduced natural gas prices ($601 million). Principally due to lower natural gas prices,
hedging gains in 2006 were $66 million, compared to losses of $77 million in 2005.

Talisman Energy 2006 Annual Financial Report   5

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Daily Average Production Volumes

|                                 |                 | 2006                        |      | 2006 vs 2005 |     | 2005  |      | 2005 vs 2004 |     | 2004 
|-------------------------------- | --------------- | --------------------------- | ---- | ------------ | --- | ----- | ---- | ------------ | --- | -----
|                                
|                                 |                 |                             |      | (%)          |     |       |      | (%           | )   |      
|Oil and liquids (mbbls/d)        |                 |                             |      |              |     |       |      |              |     |      
|                                 | North America   |                             | 48.3 |              | (4  | )     | 50.5 |              | (1  | )    
|                                
|                                 | United Kingdom1 |                             | 91.9 |              | (3  | )     | 95.2 |              | (9  | )    
|                                
|                                 | Scandinavia1    |                             | 32.5 |              | 26  |       | 25.7 |              | 336 |      
|                                
|                                 | Southeast Asia1 |                             | 51.6 |              | 45  |       | 35.5 |              |    |      
|                                
|                                 | Other1          |                             | 21.5 |              | (15 | )     | 25.5 |              | 89  |      
|                                
|                                 |                 | 245.8                       |      | 6            |     | 232.4 |      | 11           |     | 210.1
|                                
|Natural gas (mmcf/d)             |                 |                             |      |              |     |       |      |              |     |      
|                                
|                                 | North America   |                             | 897  |              | 1   |       | 885  |              | 4   |      
|                                
|                                 | United Kingdom  |                             | 34   |              | 5   |       | 32   |              | 20  |      
|                                
|                                 | Scandinavia     |                             | 14   |              | 59  |       | 9    |              | 157 |      
|                                
|                                 | Southeast Asia  |                             | 292  |              | 3   |       | 284  |              | 9   |      
|                                
|                                 |                 | 1,237                       |      | 2            |     | 1,210 |      | 6            |     | 1,143
|                                
|Continuing operations (mboe/d)   |                 | 452.0                       |      | 4            |     | 434.0 |      | 8            |     | 400.6
|                                
|Discontinued operations          |                 |                             |      |              |     |       |      |              |     |      
|                                
|                                 | North America   |                             |      |              |     |       |      |              |     |      
|                                
|                                 |                 |  oil and liquids (mbbls/d) |      | 5.0          |     | (13   | )    | 5.8          |     | (10  
|                                
|                                 |                 |  natural gas (mmcf/d)      |      | 12           |     | (59   | )    | 30           |     | (8   
|                                
|                                 | United Kingdom  |                             |      |              |     |       |      |              |     |      
|                                
|                                 |                 |  oil and liquids (mbbls/d) |      | 10.9         |     | (9    | )    | 11.8         |     |     
|                                
|                                 |                 |  natural gas (mmcf/d)2     |      | 92           |     | 16    |      | 79           |     | (5   
|                                
|Discontinued operations (mboe/d) |                 | 33.2                        |      | (7           | )   | 35.8  |      | (5           | )   | 37.6 
|                                
|Total mboe/d (6 mcf = 1 boe)     |                 | 485                         |      | 3            |     | 470   |      | 7            |     | 438  
|                                
|Production per share (boe/share) |                 | 0.162                       |      | 4            |     | 0.155 |      | 11           |     | 0.139
|                                

Production

In 2006, total production from continuing and discontinued operations averaged a record 485 mboe/d, a 3% increase over last year's average of 470 mboe/d, while
production per share increased by 4%. Production in 2004 was 438 mboe/d.

Actual
2006 production was less than the 515 to 545 mboe/d range per the 2006 Outlook in the 2005 MD&A as a result of the following unanticipated events:



Volumes
reported in discontinued operations represent production from both assets currently held for sale as at December 31, 2006, as well as production up until the date of closing from assets
disposed of during 2006.

Continuing Operations

Natural gas production in North America averaged 897 mmcf/d, with increases in several core areas, reflecting Talisman's successful 2006 drilling program, as
701 wells were drilled with a 98% success rate. New wells on production contributed to increases in Bigstone/Wild River (up 20 mmcf/d to 129 mmcf/d), Monkman
(up 10 mmcf/d to 114 mmcf/d) and Alberta Foothills (up 8 mmcf/d to 155 mmcf/d). Partially offsetting these increases were the impact of a turnaround at Edson
and natural declines. The Talisman-operated Lynx and Palliser Pipelines commenced operations in 2006, transporting a combined 31 mmcf/d and 27 mmcf/d, respectively, of Talisman and third
party gas production at year-end. North America oil and liquids average production was 48,275 bbls/d during the year, down 4% from 2005 due to asset sales, natural decline
rates and the Company's continued focus on natural gas.

6   Talisman Energy 2006 Annual Financial Report

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Oil
and liquids production in the UK averaged 91,897 bbls/d, a 3% decrease from 2005 as production increases from 2006 development drilling and asset acquisitions over the past year were more
than offset by the impact of extended turnarounds and natural declines. Production decreased due to planned facility shutdowns at Piper (for Tweedsmuir tie-ins, down
2,400 bbls/d to 10,110 bbls/d), Beatrice (down 1,407 bbls/d to 2,317 bbls/d), unplanned shutdowns for a Scapa riser failure at Claymore (down 2,407 bbls/d to
18,100 bbls/d), repairs to a compressor at Tartan (down 2,102 bbls/d to 4,503 bbls/d) and repairs to Galley flowlines (down 1,870 bbls/d to 3,529 bbls/d).
Turnarounds and a compressor failure at Ross/Blake decreased production by 1,220 bbls/d to 14,948 bbls/d. Natural gas production in the UK increased 5% over 2005 to 34 mmcf/d.

Oil
and liquids production in Scandinavia averaged 32,474 bbls/d, a 26% increase from 2005 as production increases from asset acquisitions in 2005 and development drilling more than offset the
impact of turnarounds and natural declines. Production at Gyda averaged 7,441 bbls/d (down 1,008 bbls/d due to natural declines and water injection repairs). Production from the Varg
field was down 3,696 bbls/d to 9,642 bbls/d due to early water breakthrough on two wells, which reduced production from February to September. The Brage assets produced an average of
6,950 bbls/d during the year. The Veslefrikk and Siri fields (acquired through the Paladin Resources plc (Paladin) acquisition) produced an average of 5,362 bbls/d and
3,056 bbls/d, respectively, during 2006. Natural gas production for the year averaged 14 mmcf/d (up from 9 mmcf/d in 2005) primarily due to the Paladin assets acquired at
the end of 2005.

Southeast
Asia produced 51,582 bbls/d of oil and liquids, a 45% increase over 2005. A full year of production from the South Angsi PM-305 field (onstream in
mid-August of 2005) and the startup of the Naga Kecil well in PM-314 in July 2006 increased production by 8,743 bbls/d to 15,214 bbls/d in 2006. The
PM-3 CAA block in Malaysia/Vietnam decreased 3,364 bbls/d to 18,164 bbls/d in 2006, with an extended shut down period due to bad weather conditions and natural
declines. Production from SE Sumatra and Offshore NW Java in Indonesia and from the Australia properties, which were all part of the Paladin acquisition, averaged 4,195 bbls/d,
665 bbls/d and 7,367 bbls/d, respectively, in 2006. Production at Corridor and the OK Block remained relatively unchanged from 2005 at 5,976 bbls/d.

Natural
gas production in Southeast Asia increased 8 mmcf/d to 292 mmcf/d in 2006. In Malaysia/Vietnam, natural gas production from PM-3 CAA was 87 mmcf/d in
2006, down 18% from the previous year due to reduced demand from the buyer during the first half of the year, an extended shutdown in August as a result of bad weather conditions and a delay in the
commissioning of the BRE gas processing facility during the second half of the year. Natural gas sales in Indonesia averaged 205 mmcf/d (versus 177 mmcf/d in 2005), with incremental
production from 2006 development drilling and higher demand for Corridor gas from Caltex and Singapore Power. Gas production from the acquired SE Sumatra and the Offshore NW Java assets averaged
8 mmcf/d.

Oil
and liquids production from Other areas averaged 21,559 bbls/d, down 3,930 bbls/d from last year. In Algeria, production averaged 12,389 bbls/d, down from
15,261 bbls/d, due to the failure of the gas reinjection compressor motor at the MLN facilities which shut down production from May 1 through August 12, 2006. Production from
Tunisia, which was acquired from Paladin in late 2005, averaged 804 bbls/d during the year. Trinidad and Tobago production averaged 8,366 bbls/d in 2006, down from 10,111 bbls/d
in 2005 due to natural declines and a glycol gas dehydrator failure in late November 2006 (which shut down production for four weeks and reduced production into February 2007).

In
the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted and sold to third parties. Volumes transferred into and out of
inventory for the year ended December 31, 2006 have been separately identified in footnote 1 to the Daily Average Production Volumes table above.

Talisman Energy 2006 Annual Financial Report   7

---



Commodity Prices1

|                                                   |                           | 2006  |       | 2006 vs 2005 |      | 2005  |       | 2005 vs 2004 |      | 2004 
|-------------------------------------------------- | ------------------------- | ----- | ----- | ------------ | ---- | ----- | ----- | ------------ | ---- | -----
|                                                  
|                                                   |                           |       |       | (%           | )    |       |       | (%           | )    |      
|Oil and liquids ($/bbl)                            |                           |       |       |              |      |       |       |              |      |      
|                                                   | North America             |       | 56.73 |              | 8    |       | 52.62 |              | 25   |      
|                                                  
|                                                   | United Kingdom            |       | 72.11 |              | 13   |       | 64.07 |              | 33   |      
|                                                  
|                                                   | Scandinavia               |       | 73.79 |              | 9    |       | 67.72 |              | 36   |      
|                                                  
|                                                   | Southeast Asia            |       | 74.62 |              | 8    |       | 68.79 |              | 34   |      
|                                                  
|                                                   | Other                     |       | 71.65 |              | 10   |       | 65.40 |              | 28   |      
|                                                  
|                                                   |                           | 69.82 |       | 11           |      | 62.78 |       | 32           |      | 47.45
|                                                  
|Natural gas ($/mcf)                                |                           |       |       |              |      |       |       |              |      |      
|                                                  
|                                                   | North America             |       | 7.12  |              | (21  | )     | 9.05  |              | 33   |      
|                                                  
|                                                   | United Kingdom            |       | 8.50  |              | 16   |       | 7.30  |              | 29   |      
|                                                  
|                                                   | Scandinavia               |       | 4.92  |              | 14   |       | 4.30  |              | (13  | )    
|                                                  
|                                                   | Southeast Asia            |       | 6.95  |              | 9    |       | 6.40  |              | 35   |      
|                                                  
|                                                   |                           | 7.20  |       | (13          | )    | 8.30  |       | 32           |      | 6.28 
|                                                  
|Company $/boe (6 mcf:1 boe)                        |                           | 57.45 |       | 1            |      | 56.67 |       | 33           |      | 42.75
|                                                  
|Hedging loss (gain) excluded from the above prices |                           |       |       |              |      |       |       |              |      |      
|                                                  
|                                                   | Oil and liquids ($/bbl)   |       | 0.21  |              | (75  | )     | 0.85  |              | (84  | )    
|                                                  
|                                                   | Natural gas ($/mcf)       |       | (0.17 | )            |     |       |      |              | (100 | )    
|                                                  
|                                                   | Total $/boe (6 mcf:1 boe) |       | (0.37 | )            | (180 | )     | 0.46  |              | (85  | )    
|                                                  
|Benchmark prices                                   |                           |       |       |              |      |       |       |              |      |      
|                                                  
|                                                   | WTI (US$/bbl)             |       | 66.25 |              | 17   |       | 56.70 |              | 37   |      
|                                                  
|                                                   | Dated Brent (US$/bbl)     |       | 65.15 |              | 19   |       | 54.52 |              | 43   |      
|                                                  
|                                                   | NYMEX (US$/mmbtu)         |       | 7.26  |              | (15  | )     | 8.55  |              | 40   |      
|                                                  
|                                                   | AECO (C$/Gj)              |       | 6.62  |              | (18  | )     | 8.04  |              | 25   |      
|                                                  
|US$/C$ exchange rate                               |                           | 0.88  |       | 6            |      | 0.83  |       | 8            |      | 0.77 
|                                                  
|C$/£ exchange rate                                 |                           | 2.09  |       | (5           | )    | 2.21  |       | (7           | )    | 2.38 
|                                                  

World oil prices were volatile during 2006, reaching new record levels at mid-year before dropping off in the latter part of the year, with WTI
averaging US$66.25/bbl, up 17% over the 2005 average of US$56.70/bbl. North American natural gas prices decreased from 2005 with the NYMEX and AECO benchmark prices down 15% and 18%, respectively.

More
than 90% of the Company's revenues are either received in US$ or are closely referenced to US$. The Company converts these revenues to C$ for reporting purposes. The 6% strengthening of the C$
against the US$ reduced Talisman's reported oil and liquids price by $4.78/bbl to $69.82/bbl, an 11% increase over 2005.

Talisman's
average natural gas price in North America decreased 21% to $7.12/mcf. The strengthening of the C$ during 2006 reduced Talisman's reported North America natural gas price by $0.49/mcf.
Sales from Malaysia/Vietnam, where prices are referenced to the Singapore fuel oil spot market, averaged $4.72/mcf in 2006. Gas production from Malaysia/Vietnam was down 18% from 2005 and accounted
for 30% of Southeast Asia gas production during the year. A large portion of Corridor gas production, which represented approximately 64% of the Company's 2006 gas sales in Southeast Asia, is
exchanged for Duri crude oil on an energy equivalence basis and is sold with payment in US$ and averaged $8.36/mcf.

The
Company's average sales prices are before a net hedging loss on oil of $20 million, or $0.21/bbl, and net hedging gains on natural gas of $86 million, or $0.17/mcf (combined gain of
$66 million or $0.37/boe). The physical and financial commodity price contracts outstanding at year-end are disclosed in notes 11 and 12 to the Consolidated Financial
Statements with additional discussion in the MD&A section entitled Derivative Financial Instruments and Commodity Sales Contracts. Additional discussion of the expected impact of commodity price
contracts on the Company's 2007 results can be found in the Outlook for 2007 section of this MD&A. The Company's accounting policy with respect to derivative financial instruments and commodity
contracts is disclosed in note 1(k) to the Consolidated Financial Statements.

8   Talisman Energy 2006 Annual Financial Report

---



Royalties

|                |                | 2006      |    | 2005       |     | 2004     
|--------------- | -------------- | --------- | -- | ---------- | --- | ---------
|                |                | Rates (%) |    | $ millions |     | Rates (%)
|               
|Oil and liquids |                |           |    |            |     |          
|                | North America  |           | 21 |            | 210 |          
|               
|                | United Kingdom |           | 1  |            | 1   |          
|               
|                | Scandinavia    |           |   |            | 4   |          
|               
|                | Southeast Asia |           | 43 |            | 598 |          
|               
|                | Other          |           | 31 |            | 165 |          
|               
|                |                | 16        |    | 978        |     | 14       
|               
|Natural gas     |                |           |    |            |     |          
|               
|                | North America  |           | 18 |            | 422 |          
|               
|                | United Kingdom |           | 5  |            | 4   |          
|               
|                | Southeast Asia |           | 27 |            | 199 |          
|               
|                |                | 18        |    | 625        |     | 21       
|               
|Total           |                | 17        |    | 1,603      |     | 17       
|               

The consolidated royalty expense in 2006 was $1,603 million, an increase of $87 million (6%) from $1,516 million in 2005, as a result of
higher world prices, increased oil volumes and rate increases for oil in Southeast Asia, partially offset by reduced North America natural gas prices. The Company's oil and liquids royalty rate
increased to 16%, while the amount of royalties paid increased by 34% to $978 million. This increase is due primarily to a combination of higher prices and production increases in Southeast
Asia. Natural gas royalties for 2006 decreased 21% to $625 million due principally to lower prices and rates in North America.

In
North America, natural gas royalties fell 28% to $422 million, averaging 18%, down from 20% in 2005. This decrease in expense reflects a 21% drop in realized unit prices, partially offset by
a 1% increase in production.

Oil
and liquids royalties in Southeast Asia increased 70% to $598 million due to increases in both prices and production volumes. Malaysia/Vietnam oil royalties are tied to production, price
and cost levels and averaged 49% in 2006, up from 37% last year, as both PM-3 CAA and PM-305 fully recovered past oil cost pools. This royalty rate will continue
to fluctuate as costs are incurred and recovered. Based on current forecasts of production, prices and spending, the rate is expected to decrease to approximately 41% in 2007. In Southeast Asia, the
natural gas royalty rates fell as a result of additional spending at Corridor, which increased gas cost recovery pools. Corridor's natural gas royalty rate averaged 27% during 2006, compared to 32% in
the prior year due to an increase in the cost recovery shield. The Southeast Asia gas royalty rate was also impacted by lower Malaysia/Vietnam natural gas volumes, which have a royalty rate of 24%.
This royalty rate is expected to continue until the Malaysia/Vietnam gas cost pools are recovered in 2011, based on current forecasts of production, prices and spending.

In
Other, the oil royalty expense decreased from $170 million to $165 million as production decreased 15% from last year while the rate increased from 30% last year to 31%
in 2006.

Effective
August 1, 2006, the Government of Algeria implemented a new tax on exceptional profits. The calculation of such tax is applicable when the monthly average Brent crude oil price
exceeds US$30/bbl and is dependent on the terms of the contract for the exploration and production of hydrocarbons. Implementation of the new tax is in process and the 2006 estimated impact to the
Company is $3 million, which has been classified as additional royalty expense. The future impact of such tax is not expected to be material.

Talisman Energy 2006 Annual Financial Report   9

---



Unit Operating Expenses

|                        |                 | 2006  |       | 2006 vs 2005 |     | 2005  |       | 2005 vs 2004 |     | 2004 
|----------------------- | --------------- | ----- | ----- | ------------ | --- | ----- | ----- | ------------ | --- | -----
|                       
|                        |                 |       |       | (%)          |     |       |       | (%           | )   |      
|Oil and liquids ($/bbl) |                 |       |       |              |     |       |       |              |     |      
|                        | North America   |       | 8.57  |              | 18  |       | 7.24  |              | 7   |      
|                       
|                        | United Kingdom1 |       | 19.83 |              | 19  |       | 16.67 |              | 32  |      
|                       
|                        | Scandinavia     |       | 22.42 |              | 18  |       | 18.98 |              | (26 | )    
|                       
|                        | Southeast Asia  |       | 6.63  |              | 48  |       | 4.48  |              | (20 | )    
|                       
|                        | Other           |       | 4.99  |              | 28  |       | 3.89  |              | 11  |      
|                       
|                        |                 | 14.11 |       | 19           |     | 11.81 |       | 14           |     | 10.32
|                       
|Natural gas ($/mcf)     |                 |       |       |              |     |       |       |              |     |      
|                       
|                        | North America   |       | 1.07  |              | 19  |       | 0.90  |              | 14  |      
|                       
|                        | United Kingdom  |       | 0.71  |              | (22 | )     | 0.91  |              | 2   |      
|                       
|                        | Southeast Asia  |       | 0.36  |              | 20  |       | 0.30  |              | 11  |      
|                       
|                        |                 | 0.87  |       | 14           |     | 0.76  |       | 15           |     | 0.66 
|                       
|Company ($/boe)         |                 | 9.98  |       | 19           |     | 8.41  |       | 16           |     | 7.26 
|                       

Total Operating Expenses

|(millions of C$) |                 | 2006  |     | 2005  |     | 2004 
|---------------- | --------------- | ----- | --- | ----- | --- | -----
|                
|Oil and liquids  |                 |       |     |       |     |      
|                 | North America   |       | 150 |       | 132 |      
|                
|                 | United Kingdom1 |       | 616 |       | 589 |      
|                
|                 | Scandinavia     |       | 259 |       | 180 |      
|                
|                 | Southeast Asia  |       | 122 |       | 56  |      
|                
|                 | Other           |       | 36  |       | 35  |      
|                
|                 |                 | 1,183 |     | 992   |     | 802  
|                
|Natural gas      |                 |       |     |       |     |      
|                
|                 | North America   |       | 347 |       | 284 |      
|                
|                 | United Kingdom  |       | 7   |       | 10  |      
|                
|                 | Southeast Asia  |       | 39  |       | 31  |      
|                
|                 |                 | 393   |     | 325   |     | 271  
|                
|                 |                 | 1,576 |     | 1,317 |     | 1,073
|                
|Pipeline1        |                 | 75    |     | 21    |     | 18   
|                
|Total            |                 | 1,651 |     | 1,338 |     | 1,091
|                

Total operating expenses for the Company during 2006 were $1.7 billion, 23% higher than last year. On a per unit basis, oil and liquids costs increased
19% to $14.11/bbl and natural gas costs averaged $0.87/mcf, a 14% increase from 2005.

North
America oil and liquids operating costs were higher during 2006 with increases in power, maintenance and well workover costs. Unit operating costs for natural gas increased as a result of higher
third party processing fees, maintenance, power and well workover costs, partially offset by lower unit operating costs ($0.34/mcf) in Appalachia.

In
2006, UK operating expenses were up $24 million, or 4% over last year, due in part to acquisitions, partially offset by a 5% strengthening in the C$ against the UK£. Increased
costs for oil reflected higher charges for fuel, power, maintenance and turnarounds.

Operating
costs in Scandinavia increased $79 million to $259 million, reflecting increased production as a result of the prior year's acquisitions and increased well workovers at Gyda.
Production declines at Varg, which has relatively fixed costs, increased per unit costs.

In
Southeast Asia, unit operating costs increased 52% to $4.47/boe. Assets acquired in 2005 in Australia, SE Sumatra and Offshore NW Java accounted for 64% of the total increase in operating costs of
$74 million over 2005, to $161 million. A full year of production from the South Angsi PM-305 field (onstream in mid-August of 2005) and the startup of the
Naga Kecil well in PM-314 in July 2006 increased oil operating costs by $10 million. At PM-3 CAA, higher expenditures associated with maintenance,
health, safety and environment (HSE) and well intervention work increased costs by $10 million over 2005. Indonesia unit costs increased, reflecting increased production from SE Sumatra, where
costs averaged

10   Talisman Energy 2006 Annual Financial Report

---



$14.81/bbl.
Indonesia gas sales represented 70% of the total for Southeast Asia versus 62% in 2005, and unit costs increased from $0.32/mcf to $0.38/mcf in 2006. Malaysia/Vietnam gas unit costs
averaged $0.31/mcf as production for 2006 was 87 mmcf/d, down from 107 mmcf/d in 2005.

Other
operating expenses increased 3% to $36 million. On a per unit basis, operating costs also increased, reflecting the impact of increased costs and reduced production from unplanned shut
downs in the Greater MLN fields in Algeria and in Trinidad and Tobago.

Transportation Expenses

|                |                | 2006  |      | 2005       |    | 2004 
|--------------- | -------------- | ----- | ---- | ---------- | -- | -----
|                |                | $/bbl |      | $ millions |    | $/bbl
|               
|Oil and liquids |                |       |      |            |    |      
|                | North America  |       | 0.57 |            | 11 |      
|               
|                | United Kingdom |       | 1.52 |            | 46 |      
|               
|                | Scandinavia    |       | 1.80 |            | 21 |      
|               
|                | Southeast Asia |       | 0.27 |            | 5  |      
|               
|                | Other          |       | 0.94 |            | 7  |      
|               

|            |                | $/mcf |      |     |    | $/mcf |      |     |    | $/mcf |      |    
|----------- | -------------- | ----- | ---- | --- | -- | ----- | ---- | --- | -- | ----- | ---- | ---
|           
|Natural gas |                |       |      |     |    |       |      |     |    |       |      |    
|            | North America  |       | 0.19 |     | 62 |       | 0.19 |     | 64 |       | 0.20 |    
|           
|            | United Kingdom |       | 0.33 |     | 8  |       | 0.42 |     | 7  |       | 0.28 |    
|           
|            | Scandinavia    |       | 1.10 |     | 6  |       | 1.48 |     | 5  |       | 2.39 |    
|           
|            | Southeast Asia |       | 0.38 |     | 41 |       | 0.41 |     | 42 |       | 0.41 |    
|           
|            |                |       |      | 207 |    |       |      | 185 |    |       |      | 174
|           

During 2006, transportation expenses increased $22 million or 12% over 2005, primarily due to increased volumes acquired at Brage and Veslefrikk in
Scandinavia, where transportation expenses averaged $2.36/boe, and due to increased volumes acquired at Montrose/Arbroath in the UK.

Unit Depreciation, Depletion and Amortization Expense (Includes accretion of Asset Retirement Obligations (ARO))

|($/boe)        |  | 2006  |  | 2006 vs 2005 |   | 2005  |  | 2005 vs 2004 |   | 2004 
|-------------- |  | ----- |  | ------------ | - | ----- |  | ------------ | - | -----
|              
|               |  |       |  | (%)          |   |       |  | (%           | ) |      
|North America  |  | 14.18 |  | 13           |   | 12.57 |  | 20           |   | 10.49
|              
|United Kingdom |  | 12.60 |  | 14           |   | 11.07 |  | (10          | ) | 12.30
|              
|Scandinavia    |  | 19.78 |  | 19           |   | 16.65 |  | (12          | ) | 18.96
|              
|Southeast Asia |  | 6.17  |  | 28           |   | 4.83  |  | (20          | ) | 6.02 
|              
|Other          |  | 9.17  |  | (2           | ) | 9.37  |  | 54           |   | 6.07 
|              
|               |  | 12.26 |  | 13           |   | 10.81 |  | 7            |   | 10.09
|              

Total Depreciation, Depletion and Amortization Expense (Includes accretion of ARO)

|(millions of C$) |  | 2006  |  | 2005  |  | 2004 
|---------------- |  | ----- |  | ----- |  | -----
|                
|North America    |  | 1,024 |  | 908   |  | 741  
|                
|United Kingdom   |  | 440   |  | 397   |  | 489  
|                
|Scandinavia      |  | 248   |  | 157   |  | 45   
|                
|Southeast Asia   |  | 224   |  | 144   |  | 174  
|                
|Other            |  | 69    |  | 83    |  | 30   
|                
|                 |  | 2,005 |  | 1,689 |  | 1,479
|                

The Company's 2006 DD&A expense increased $316 million, or 19%, to $2 billion, with a per unit rate of $12.26/boe ($10.81/boe in 2005) due to
recently acquired assets and high levels of capital spending. DD&A rates in North America increased to $14.18/boe, primarily due to higher drilling costs, increased capital expenditures on
infrastructure projects as well as increased land amortization costs. In North America, total DD&A expense increased 13% to $1,024 million. In the UK, total DD&A expense increased by 11% to
$440 million, as DD&A rates increased 14% to $12.60/boe, but were partially offset by a 3% reduction in boe production.

In
Scandinavia, total expense increased by $91 million to $248 million, as DD&A rates increased 19% to $19.78/boe, combined with a 28% increase in boe production. Total DD&A expense for
Southeast Asia increased by $80 million, or 56%, to $224 million due to the impact of a 28% increase in the rate to $6.17/boe and a 21% increase in boe production. Total Other DD&A
expense decreased by 17% to $69 million, primarily as a result of a decrease in production.

Talisman Energy 2006 Annual Financial Report   11

---



For additional information relating to DD&A, refer to the MD&A section entitled Application of Critical Accounting Policies and the Use of Estimates and to notes 5 and 6 to the
Consolidated Financial Statements.

Dry Hole Expense

|(millions of C$) |  | 2006 |  | 2005 |  | 2004
|---------------- |  | ---- |  | ---- |  | ----
|                
|North America    |  | 135  |  | 122  |  | 147 
|                
|United Kingdom   |  | 26   |  | 38   |  | 109 
|                
|Scandinavia      |  | 11   |  | 15   |  |    
|                
|Southeast Asia   |  | 15   |  | 11   |  | 25  
|                
|Other1           |  | 109  |  | 55   |  | 30  
|                
|                 |  | 296  |  | 241  |  | 311 
|                

During 2006, the Company incurred dry hole expense of $296 million, $55 million higher than in the previous year. In North America, dry hole
expense was $135 million. In the UK, a total of three wells were expensed for a total of $26 million. The Company also wrote off one well in Scandinavia, two wells in Southeast Asia and
seven wells in the rest of the world.

Under
the successful efforts method of accounting for oil and gas activities, the costs of unsuccessful and non-commercial exploration wells are written off to dry hole expense in the year
such determination is made. Until such determination is made, the costs are included in non-depleted capital. At year-end, $769 million of costs relating to exploration
wells were included in non-depleted capital and not subject to DD&A, pending final determination (2005  $450 million;
2004  $284 million). The majority of the related wells were drilled in 2006.

Exploration Expense

|(millions of C$) |  | 2006 |  | 2005 |  | 2004
|---------------- |  | ---- |  | ---- |  | ----
|                
|North America1   |  | 168  |  | 143  |  | 132 
|                
|United Kingdom   |  | 25   |  | 29   |  | 24  
|                
|Scandinavia      |  | 30   |  | 24   |  | 4   
|                
|Southeast Asia   |  | 22   |  | 40   |  | 20  
|                
|Other1           |  | 73   |  | 39   |  | 58  
|                
|                 |  | 318  |  | 275  |  | 238 
|                

Exploration expense consists of geological and geophysical costs, seismic, non-producing land lease rentals and indirect exploration expenses. These
costs are expensed as incurred under the successful efforts method of accounting. The majority of the $43 million increase to $318 million in 2006 relates to increased exploration
activity in North America and other potential growth areas.

Corporate and Other

|(millions of C$)                         |  | 2006 |   | 2005 |  | 2004
|---------------------------------------- |  | ---- | - | ---- |  | ----
|                                        
|General and administrative (G&A) expense |  | 233  |   | 201  |  | 183 
|                                        
|Interest expense                         |  | 166  |   | 163  |  | 173 
|                                        
|Capitalized interest                     |  | 72   |   | 19   |  | 13  
|                                        
|Stock-based compensation                 |  | 51   |   | 633  |  | 171 
|                                        
|Other revenue                            |  | 119  |   | 112  |  | 80  
|                                        
|Other expense                            |  | (29  | ) | 39   |  | 89  
|                                        

G&A expense increased due to additional personnel, salary increases and higher administrative costs. On a unit basis, G&A was $1.31/boe
(2005  $1.17/boe; 2004  $1.14/boe).

The
sum of interest on long-term debt and capitalized interest was $238 million during 2006, up from $182 million in 2005 on higher debt levels in the current year. Interest
capitalized in 2006 is primarily associated with the Tweedsmuir development project in the UK, which is scheduled to come on production early in the second quarter of 2007. In addition, interest costs
of $18 million in 2006, $3 million in 2005 and nil in 2004, have been allocated to discontinued operations (see note 2 to the Consolidated Financial Statements).

Other
revenue includes pipeline and custom treating revenues of $103 million for 2006, compared to $88 million for 2005. Other expense during 2006 included the gain on sale of a royalty
interest in an undeveloped lease of $108 million, partially offset by foreign exchange losses of $24 million and costs related to the Beatrice Windfarm of $22 million.

12   Talisman Energy 2006 Annual Financial Report

---



Stock-Based Compensation

Stock-based compensation expense relates to the appreciated value of the Company's outstanding stock options and cash units at December 31, 2006. The Company's
stock-based compensation expense is based on the difference between the Company's share price and its stock options, or cash units exercise price. $51 million was expensed in 2006. The Company
paid cash of $159 million ($153 million in 2005) to employees in settlement of fully accrued option liabilities for options exercised. Comparatively, during 2005 the 90% increase in the
Company's share price resulted in an expense of $633 million. Over the course of the year, the average exercise price of all outstanding options increased from $8.71 per share to $10.79 per
share, with a total of 63.9 million options outstanding at December 31, 2006 (see note 8 to the Consolidated Financial Statements).

The
Company's stock option plans provide employees and directors who hold stock options with the choice upon exercise to purchase a share of the Company at the stated exercise price or to receive a
cash payment in exchange for surrendering the option. The cash payment is equal to the appreciated value of the stock option as determined based on the difference between the option's exercise price
and the approximate share price at the time of surrender. The cash payment alternative is expected to result in reduced shareholder dilution in the future as it is anticipated that most holders of the
stock options (now and in the future) will elect to take a cash payment. Such cash payments made by the Company to stock option holders are deductible by the Company for income tax purposes,
making these plans more cost-effective.

Since
the introduction of the cash feature, approximately 97% of options that have been exercised have been exercised for cash, resulting in reduced dilution of shares.

Additional
stock-based compensation expense or recovery in future periods is dependent on the movement of the Company's share price and the number of outstanding options and cash units.

Income Taxes

The Company's effective income tax rate for 2006, after deducting PRT, was 47%, compared to 45% in 2005 and 35% in 2004. A number of events in the past three years have affected
the Company's effective tax rates, including tax rate increases in the UK, tax rate reductions in Canada and acquisitions of producing assets in Norway last year.

Effective Income Tax Rate

|(millions of C$)                             |         | 2006  |     | 2005  |     | 2004 |     
|-------------------------------------------- | ------- | ----- | --- | ----- | --- | ---- | ----
|                                             |        
|Income from continuing operations before tax |         | 3,046 |     | 2,643 |     | 931  |     
|                                             |        
|Less PRT                                     |         |       |     |       |     |      |     
|                                             |        
|                                             | Current |       | 256 |       | 147 |      | 124 
|                                             |        
|                                             | Future  |       | 34  |       | 37  |      | 4   
|                                             |        
|                                             |         | 290   |     | 184   |     | 128  |     
|                                             |        
|                                             |         | 2,756 |     | 2,459 |     | 803  |     
|                                             |        
|Income tax expense/(recovery)                |         |       |     |       |     |      |     
|                                             |        
|                                             | Current |       | 752 |       | 978 |      | 427 
|                                             |        
|                                             | Future  |       | 552 |       | 127 |      | (143
|                                             |        
|                                             |         | 1,304 |     | 1,105 |     | 284  |     
|                                             |        
|Effective income tax rate (%)                |         | 47    |     | 45    |     | 35   |     
|                                             |        

In 2006, future tax expense increased $425 million, to $552 million, as the Company recorded a $325 million charge related to the income tax
rate increase on petroleum profits from 40% to 50% in the UK, partially offset by a recovery of future taxes of $178 million related to Canadian federal and provincial tax rate reductions and
$34 million in the UK related to the deferral of 2005 capital expenditure claims to 2006 and 2007 for tax purposes.

A
normalized effective tax rate after removing the impact of the UK and Canadian tax rate changes and the tax on unrealized foreign exchange gains on foreign denominated debt would have been 44% in
2006, 43% in 2005 and 36% in 2004. The increase in the 2006 effective tax rate results, in part, from a higher tax rate in the UK. Foreign exchange rate fluctuations over the past several years have
resulted in taxes on gains related to inter-company loans and non-C$ denominated debt, for which there is no corresponding component of the unrealized gain reflected in income before
taxes. See note 15 to the Consolidated Financial Statements for additional information on the Company's income taxes.

Current
income tax expense decreased to $752 million in 2006, due primarily to higher capital allowances in the UK and lower US charges due to reduced natural gas prices.

The
UK government levies PRT on North Sea fields that received development approval before April 1993, based on gross profit after allowable deductions, including capital and operating
expenditures. PRT, which is deductible for purposes of calculating corporate income tax, increased as a result of both higher prices and volumes on fields in the UK subject to PRT. In addition to the
UK, PRT is levied in Australia and other countries, where $66 million (nil in 2005) and $16 million ($14 million in 2005), respectively, were recorded during 2006.

Talisman Energy 2006 Annual Financial Report   13

---



Capital Spending1,2

|(millions of C$)                 |  | 2006  |   | 2006 vs 2005 |   | 2005  |   | 2005 vs 2004 |   | 2004  |  
|-------------------------------- |  | ----- | - | ------------ | - | ----- | - | ------------ | - | ----- | -
|                                 | 
|                                 |  |       |   | (%)          |   |       |   | (%)          |   |       |  
|North America                    |  | 2,420 |   | 49           |   | 1,623 |   | 16           |   | 1,457 |  
|                                 | 
|United Kingdom                   |  | 1,208 |   | 38           |   | 875   |   | 96           |   | 387   |  
|                                 | 
|Scandinavia                      |  | 332   |   | 129          |   | 145   |   | 202          |   | 108   |  
|                                 | 
|Southeast Asia                   |  | 331   |   | 9            |   | 305   |   | 20           |   | 255   |  
|                                 | 
|Other3                           |  | 249   |   | 35           |   | 184   |   | (43          | ) | 264   |  
|                                 | 
|Corporate, IS and Administrative |  | 36    |   | 29           |   | 28    |   | 8            |   | 26    |  
|                                 | 
|                                 |  | 4,576 |   | 45           |   | 3,160 |   | 27           |   | 2,497 |  
|                                 | 
|Acquisitions4                    |  | 204   |   | (62          | ) | 536   |   | 62           |   | 330   |  
|                                 | 
|Dispositions                     |  | (119  | ) | 441          |   | (22   | ) | (75          | ) | (88   | )
|                                 | 
|Discontinued operations5         |  | (715  | ) | (1,621       | ) | 47    |   | (30          | ) | 67    |  
|                                 | 
|Total                            |  | 3,946 |   | 6            |   | 3,721 |   | 33           |   | 2,806 |  
|                                 | 

The Company spent $3 billion on development and $1.5 billion on exploration primarily to pursue additional deep gas prospects in North America and
progress development opportunities in the UK and Scandinavia sectors of the North Sea and in Southeast Asia. Actual capital expenditures during 2006 differed from the amount of capital expenditures in
the 2006 Outlook of the 2005 MD&A, primarily as a result of the following:



During
2006, natural gas continued to be the focus of the Company's capital investment activities in North America, supplemented by low risk oil projects. Of the $2.4 billion of capital
spending in North America, $1.1 billion related to exploration activities and development accounted for $1.3 billion. The Company's North America drilling program had a 98% success rate,
resulting in 496 gas wells and 194 oil wells. Exploration and development spending was concentrated in the predominantly gas producing core areas in the Alberta Foothills, Greater Arch,
Deep Basin, Monkman/BC Foothills, Edson and Appalachia regions.

Total
capital spending in the UK was $1.2 billion, including $138 million for exploration and $1.1 billion for development. Major areas of activity included the ongoing
development of the Tweedsmuir, Blane, Wood, Enoch and Affleck projects and the drilling and completion activity within the Orion, Tartan and Claymore fields. A total of 24 successful
development wells were drilled in 2006, as well as six exploration wells.

In
Scandinavia, total expenditures were $332 million and included $102 million on exploration and $230 million on development. In addition to project development costs at Rev of
$27 million, five successful development wells were drilled during 2006, as well as two exploration wells.

Malaysia/Vietnam
accounted for $241 million of the $331 million of total capital spending in Southeast Asia, with the completion and start up of the Bunga Tulip development and the
ongoing development of the Northern Fields in PM-3 CAA. Talisman participated in nine successful development wells and one successful exploration well in Malaysia/Vietnam during
2006. A total of $76 million was spent in Indonesia, primarily on the Suban Phase 2 development to supply natural gas to West Java in 2007. A total of 19 successful development
wells and two successful exploration wells were drilled in Indonesia.

Capital
spending in Other included $74 million in North Africa, with Talisman participating in 13 successful exploration and development wells in Algeria and two wells in Tunisia. In
Trinidad and Tobago, a total of $84 million was spent, primarily on Block 2c development drilling and Eastern Block
onshore exploration activity. A total of four development wells and four exploration wells were drilled in Trinidad and Tobago. During 2006, the Company spent $91 million in the rest of the
world, including $22 million in Qatar on exploration drilling.

Information
related to details and funding of the 2007 capital expenditures program is included in the Outlook for 2007 section of this MD&A.

Reserves Replacement

Talisman drilled 773 successful wells in 2006 and increased its total proved reserves by 2% to 1,667 mmboe at the end of 2006. The Company replaced 116% of
conventional production from all sources and 116% before acquisitions and divestitures. Drilling related reserve additions and revisions to previous estimates totaled 202 mmboe. Talisman also
acquired a net 1 mmboe of proved reserves. Talisman's net proved reserves increased by 4% to 1,367 mmboe.

Proved
oil and liquids reserves increased 4% to 767 mmbbls. Talisman added a total of 125 mmbbls from all sources, including 62 mmbbls in the UK, 29 mmbbls in Scandinavia,
7 mmbbls in Southeast Asia, 15 mmbbls in Other and 12 mmbbls in North America. The majority (91%) of these

14   Talisman Energy 2006 Annual Financial Report

---



reserves
additions were through discoveries, additions, extensions and revisions. The UK (50%) and North America (22%) account for the majority of Talisman's year-end oil and liquids
reserves. These are predominantly high quality crude oil and natural gas liquids. Talisman has virtually no conventional heavy oil reserves.

Talisman's
proved natural gas reserves decreased by 0.3% in 2006, totaling 5.4 tcf at year-end. Talisman's North American natural gas reserves were 2.8 tcf at
year-end, up 4% from the previous year. In North America, the Company added 458 bcf through the drill bit (138% of production) and upward revisions to existing reserves
(13 bcf) offset by natural gas production (332 bcf) and minor net dispositions (41 bcf). These numbers include Fortuna's natural gas reserves in the northeastern US, which
totaled 144 bcf at year-end, with the addition of 43 bcf through drilling activities.

Talisman's
proved international natural gas reserves at year-end were 2.6 tcf and accounted for 48% of the Company's total proved natural gas reserves, with Southeast Asia
constituting 39% of total worldwide proved natural gas reserves.

Over
the past three years, Talisman has added 670 mmboe of proved reserves through discoveries, additions and extensions (including revisions) and acquired 139 mmboe of proved reserves,
net of dispositions. Approximately 86% of Talisman's proved reserves have been independently audited over the past four years.

The
reserves replacement ratio of 116% (before acquisitions and dispositions) was calculated by dividing the sum of changes (revisions of estimates, improved recovery and discoveries) to estimated
proved oil and gas reserves during 2006 by the Company's 2006 conventional production. The reserves replacement ratio of 116% (after acquisitions and dispositions) was calculated by dividing the sum
of changes (revisions of estimates, improved recovery, discoveries, acquisitions and dispositions) to estimated proved oil and gas reserves during 2006 by the Company's 2006 conventional production.

|                                      |  | Oil & Natural Gas Liquids |   | Natural Gas |   | BOE     |  
|------------------------------------- |  | ------------------------- | - | ----------- | - | ------- | -
|                                      | 
|                                      |  | (mmbbls)                  |   | (bcf)       |   | (mm)    |  
|December 31, 2005                     |  | 736.1                     |   | 5,416.6     |   | 1,638.8 |  
|                                      | 
|Discoveries, extensions and additions |  | 80.0                      |   | 564.1       |   | 174.1   |  
|                                      | 
|Net acquisitions                      |  | 10.6                      |   | (61.0       | ) | 0.4     |  
|                                      | 
|Revisions                             |  | 34.0                      |   | (33.8       | ) | 28.4    |  
|                                      | 
|Production                            |  | (94.2                     | ) | (483.0      | ) | (174.7  | )
|                                      | 
|Total Proved, December 31, 2006       |  | 766.5                     |   | 5,402.9     |   | 1,667.0 |  
|                                      | 
|Total Probable, December 31, 2006     |  | 544.0                     |   | 2,650.0     |   | 985.8   |  
|                                      | 

The Company's management uses reserves replacement ratios, as described above, as an indicator of the Company's ability to replenish annual production volumes
and grow its reserves. It should be noted that a reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies
widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since
the ratio does not take into account the cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.

Liquidity and Capital Resources

Talisman's long-term debt at year-end was $4.6 billion ($4.5 billion, net of cash), up from $4.3 billion at the end of last year.
During 2006, the Company generated $4.4 billion of cash provided by operating activities and spent $4.5 billion on exploration and development and received divestiture proceeds net of
acquisitions of $664 million. In addition, the Company repurchased approximately 35 million common shares for $659 million and paid dividends of $163 million. At
year-end, the Company had $494 million drawn against its available $2,018 million bank lines of credit. In December 2005, the Company filed as part of a registration
statement, a debt shelf prospectus in the US under the Multi-Jurisdictional Disclosure System under which it is permitted to issue up to US$2 billion of debt securities in the US public debt
market, and simultaneously filed a medium term note shelf prospectus in Canada under which it is permitted to issue up to $1 billion of medium term note securities in the Canadian public debt
market. At December 31, 2006, US$900 million remained unissued under the US shelf prospectus due to expire in January 2008 and $650 million remained unissued under the
Canadian medium term note shelf prospectus due to expire in January 2008.

In
March 2006, the Company renewed its Normal Course Issuer Bid (NCIB) to permit the purchase of up to 54,940,200 common shares, representing 5% of the total common shares outstanding at
the time of the renewal. The NCIB expires in March 2007 and the Company has received Board of Directors' approval to renew the NCIB for another year. In December 2006, Talisman amended
the current NCIB. The amendment increases the maximum number of common shares that Talisman may purchase over the 12-month period of the NCIB ending March 27, 2007 to the maximum
permitted by the TSX, being 10% of the public float on March 22, 2006. The amended maximum is 109,767,000 common shares. The Company repurchased 35,294,400 common shares under its
NCIB during 2006 for a total of $659 million ($18.67/share). Subsequent to year-end, Talisman repurchased 15,513,400 shares for a total of $299 million, leaving a
maximum of 58,959,200 shares available for repurchase prior to the expiry of the NCIB.

In
the first quarter of 2006, Talisman completed a US$500 million offering of 5.85% notes due February 1, 2037 and a $350 million offering of 4.44% notes due January 27,
2011. Interest on both notes is paid semi-annually. The $350 million offering was immediately swapped into

Talisman Energy 2006 Annual Financial Report   15

---



US$304 million
5.054% debt. The proceeds from these note offerings were used to repay a portion of the bridge financing entered into to finance the acquisition of Paladin in 2005. In the fourth
quarter of 2006, Talisman completed a US$600 million offering of 6.25% notes due February 1, 2038. Interest on the notes is paid semi-annually. Each of these offerings was
completed pursuant to the shelf prospectuses described above.

At
December 31, 2006, the Company had current assets of $2.1 billion and current liabilities of $3.2 billion, including assets and liabilities of discontinued operations. Working
capital movements are difficult to predict, but management does not anticipate a substantial change during 2007.

In
connection with the funding of the acquisition of Paladin in 2005, the Company arranged a $2,605 million (£1,300 million), unsecured non-revolving credit
facility (bridge financing facility). During 2006, the amounts outstanding thereunder were repaid in full and the credit facility was cancelled.

Two
common share dividends were paid in 2006 for a total of $163 million (an aggregate of $0.15/share). The Company's dividend is determined semi-annually by the Board of
Directors. At year-end, there were 1,064 million common shares outstanding, down from 1,099 million at December 31, 2005. As at March 1, 2007, there were
1,049 million common shares outstanding, as well as 61.1 million stock options outstanding.

At
the end of 2006, Talisman's ratio of debt-to-cash provided by operating activities was 1.04:1 and its ratio of debt-to-debt plus equity
was 38%.

For
additional information regarding the Company's liquidity and capital resources, refer to note 7 to the Consolidated Financial Statements. In addition, refer to the Sensitivities table
included in the Outlook for 2007 Section of this MD&A for possible 2007 impacts of various factors on the Company's estimated 2007 net income and cash provided by operating activities.

Talisman's
investment grade senior unsecured long-term debt credit ratings from Dominion Bond Rating Service (DBRS), Moody's Investors Services, Inc. (Moody's) and Standard &
Poor's (S&P) are BBB (high), Baa2 (stable) and BBB+, respectively. S&P has assigned a rating of BBB+ (with a negative outlook) to Talisman.

Commitments and Off-Balance Sheet Arrangements

As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company's future operations and liquidity, some of which
are reflected as liabilities in the Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments; abandonment obligations;
lease commitments relating to corporate offices and ocean-going vessels; firm commitments for gathering, processing and transmission services; minimum work commitments under various international
agreements; other service contracts and fixed price commodity sales contracts.

Additional
disclosure of the Company's debt repayment obligations and significant commitments can be found in notes 7 and 12 to the Consolidated Financial Statements. A discussion of the
Company's derivative financial instruments and commodity sales contracts can be found in the next section of this MD&A.

The
following table includes the Company's expected future payment commitments as at December 31, 2006 and estimated timing of such payments.

|                                          |  |                                      |  |        |  | Payments due by period1,2 (millions of C$)
|----------------------------------------- |  | ------------------------------------ |  | ------ |  | ------------------------------------------
|Commitments                               |  | Recognized in
financial statements   |  | Total  |  | Less than 1 year                          
|                                         
|Long-term debt                            |  | Yes  Liability                      |  | 4,560  |  | 601                                       
|                                         
|Abandonment obligations3                  |  | Yes  Partially accrued as liability |  | 4,600  |  | 52                                        
|                                         
|Office leases                             |  | No                                   |  | 214    |  | 34                                        
|                                         
|Ocean-going vessel leases                 |  | Yes  Partially accrued as liability |  | 486    |  | 190                                       
|                                         
|Transportation and processing commitments |  | No                                   |  | 1,114  |  | 168                                       
|                                         
|Minimum work commitments4                 |  | No                                   |  | 502    |  | 280                                       
|                                         
|Other service contracts                   |  | No                                   |  | 2,390  |  | 897                                       
|                                         
|Stock options and cash units5             |  | Yes  Partially accrued as liability |  | 606    |  | 514                                       
|                                         
|Total                                     |  |                                      |  | 14,472 |  | 2,736                                     
|                                         

16   Talisman Energy 2006 Annual Financial Report

---



Talisman is in negotiations for the construction and long term lease of an offshore production and storage facility for the Talisman operated (70% WI)
Yme field in Norway. Upon completion and delivery of the facility in 2009, the joint venture would lease the facility for an initial five year period, however this term can be extended
by up to an additional 17 years. Talisman's share of the minimum lease payments over the initial five year period is expected to be approximately $64 million per year, which has
not been included in the Estimated Future Minimum Commitments table above. This agreement is currently expected to be signed in late March 2007.

Derivative Financial Instruments and Commodity Sales Contracts

The Company manages its exposure to fluctuations in foreign exchange rates, interest rates and commodity prices in part through the use of derivative financial instruments and
commodity sales contracts. The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 1(k) to the Consolidated Financial Statements.
Derivative financial instruments and commodity sales contracts outstanding at December 31, 2006, including their respective fair values, are detailed in notes 11 and 12 to the
Consolidated Financial Statements.

During
2006, the Company had commodity price derivative financial instruments covering approximately 7,000 bbls/d or 3% of the Company's 2006 worldwide oil and liquids production. This resulted
in a net decrease to recorded sales of $20 million (2005  $77 million decrease; 2004  $480 million
decrease). The company also had natural gas price derivatives and long term fixed price physical sales contracts covering 66 mmcf/d of North American natural gas production, representing 5% of
the Company's worldwide gas production, which resulted in an increase in recorded sales of $86 million (nil in both 2005 and 2004). At December 31, 2006, the Company had
outstanding commodity price derivative contracts that covered approximately 16,000 bbls/d (13%) of the Company's anticipated 2007 UK oil and liquids production and approximately
10,000 bbls/d (24%) of the anticipated North American oil and liquids production. An additional 119 mmcf/d (14%) of anticipated 2007 North American natural gas production has been
committed under commodity price derivative contracts with an additional 13 mmcf/d (1%) committed under long-term fixed price commodity sales contracts. The Company's outstanding
commodity price derivative contracts outstanding at December 31, 2006 have been designated as hedges of the Company's anticipated future commodity sales. See notes 11 and 12 to
the Consolidated Financial Statements for additional details regarding the contracts outstanding at year-end.

Subsequent
to year-end, the Company entered into natural gas derivative contracts priced at AECO in the form of two-way collars covering the period April 1, 2007 to
October 31, 2007 for notional volume of 27,523 mcf/d of natural gas with a ceiling of $7.97/mcf and a floor of $7.00/mcf. The Company also entered into AECO fixed-price swaps covering
the period April 1, 2007 to October 31, 2007 for a notional volume of 36,697 mcf/d with a fixed price of $7.58/mcf. In addition, the Company entered into fixed-price swaps of UK
natural gas prices covering the period from October 1, 2008 to June 30, 2011, for initial notional volumes of 260,000 therms/d declining over the period to a final notional volume
of 180,000 therms/d in the second quarter of 2011 with an average fixed price of $0.83/therm. These contracts have not been designated as hedges of the Company's anticipated future commodity
sales, and as such are expected to increase the volatility of net income as changes in the fair value of these derivative instruments will be charged to net income.

Also
subsequent to year-end, the Company settled a portion of its 2007, ($90.84/$70.00) WTI costless collar covering a notional volume of 10,000 bbls/d for a gain of
$40 million, which will be deferred and amortized over the period ending December 31, 2007, the term of the original hedge.

In
order to support the Company's investments in natural gas projects outside North America and the North Sea, Talisman has entered into a number of long-term sales contracts. In
conjunction with the PM-3 CAA development project, the Company entered into a long-term firm supply contract for approximately 100 mmcf/d, at prices referenced to
the Singapore fuel oil spot market. The majority of Talisman's Corridor natural gas production in Indonesia is currently sold to Caltex under long-term sales agreements, with the majority
of the natural gas sales exchanged for crude oil on an energy equivalent basis. Sales to Singapore from Corridor are also under long-term sales agreements referenced to the spot price of
fuel oil in Singapore. During 2004, the Company signed a long-term contract to sell 2.3 tcf of Corridor natural gas to West Java over a 17-year period, with gas sales
commencing in 2007 at a price of US$1.91/mcf, with no associated transportation costs. The Company's share of sales will be approximately 810 bcf based on its 36% interest. The Company
anticipates having sufficient production to meet all future delivery commitments.

Effective
January 1, 2004, the Company's US$ cross currency and interest rate swap contracts were no longer designated as hedges of the £250 million Eurobond, which resulted
in a revaluation of this debt and a deferred gain of $17 million, which is being amortized over the period to 2009. The swap contracts were terminated in 2004 for net cash proceeds of
$138 million and resulted in an additional gain of $15 million, which was recognized immediately in income.

In
order to hedge a portion of the fair value risk associated with the US$375 million 5.125% notes due 2015, the Company entered into fixed to floating interest rate swap contracts with a total
notional amount of US$300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three-month US$ LIBOR plus 0.433% while receiving
payments of 5.125% semi-annually. These contracts have been designated as a hedge of the fair value of a portion (US$300 million) of the total US$375 million notes issued in
May 2005.

In
conjunction with the C$350 million notes issued during the first quarter of 2006, the Company entered into a cross currency interest rate swap in order to hedge the foreign exchange exposure
on this Canadian dollar denominated liability. As a result, the Company is effectively paying interest semi-annually in US dollars at a rate of 5.05% on a notional amount of
US$304 million.

The
Company has established a system of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties. The Board of Directors
has authorized the Company to enter into commodity derivative agreements, which in aggregate do not exceed 40% of total estimated production. From time to time, on certain development projects or
asset acquisitions, the Company may mitigate its exposure to financial risks related to commodity price fluctuations, through the use of various financial instruments and physical contracts.

Talisman Energy 2006 Annual Financial Report   17

---



Segmented Results Review of Continuing Operations

Talisman is an independent international upstream oil and gas company whose main business activities include exploration, development, production, transporting
and marketing of crude oil, natural gas and natural gas liquids. Note 19 to the Consolidated Financial Statements provides segmented financial information that forms the basis for much of the
following discussion and analysis. The Company's operations in 2006 were conducted principally in five geographic segments: North America, United Kingdom, Scandinavia, Southeast Asia, and
Other. The North America segment includes operations in Canada and the US. The UK segment includes operations in the United Kingdom and the Netherlands. The Scandinavia segment includes
operations in Norway and Denmark. The Southeast Asia segment includes operations in Indonesia, Malaysia, Vietnam and Australia. The Other segment includes operations in Algeria, Tunisia, Trinidad and
Tobago as well as other international exploration areas. All activities relate to the exploration, development, production and transportation of oil, liquids and natural gas.

In
2006, Talisman redefined its reporting segments to those described above. In 2005, the UK and Scandinavia were reported in aggregate as the North Sea, Alaska was included in the Other reporting
segment and excluded from the North American segment, and operations in North Africa (Algeria, Tunisia) and Trinidad and Tobago were reported as separate segments. The segment entitled Southeast Asia
includes Indonesia, Malaysia, Vietnam and Australia for the years ended December 31, 2006 and 2005, but only Indonesia, Malaysia and Vietnam in 2004. Similarly, the segment entitled Other
includes both Algeria and Tunisia for the years ended December 31, 2006 and 2005, but only Algeria in 2004 as well as Trinidad and Tobago for 2006 and 2005. Exploration is being advanced in
other areas outside the principal geographic segments, including Colombia, Qatar and Peru. All prior periods have been restated to conform to the current presentation. The following is a brief summary
of the financial results of each geographic segment. The Company's pre-tax segmented income from continuing operations as discussed below is before corporate general and administration,
interest, stock-based compensation, taxes and non-segmented foreign exchange gains and losses. Effective January 1, 2004, with the adoption of the new hedge accounting rules
(see notes 1(k) and 11 to the Consolidated Financial Statements), the Company
allocates hedging gains and losses on the basis of the percentage of relative hedged production. More detailed analysis of the Company's results can be found after this Segmented
Results Review.

North America (Includes Alaska)

During 2006, the North America operations contributed $1.1 billion, or 30%, of the Company's pre-tax segmented income from continuing operations of
$3.5 billion, down 27% from $1.5 billion (40% of $3.6 billion) in 2005. Gross sales in North America decreased 15% to $3.3 billion due principally to lower natural gas
prices and oil production. North American production from continuing operations averaged 197,800 boe/d, unchanged from 2005, and represented 44% of the Company's total production in 2006.
Royalty expense decreased 19% to $632 million due to lower gas prices. North American operating expense increased 20% to $505 million due to higher processing fees, increased well
workovers, maintenance and power costs. DD&A increased to $1,024 million, up from $908 million due to higher drilling costs and increased capital expenditures on infrastructure projects.
Total exploration and development spending for North America in 2006 was $2.4 billion, up 49% over 2005.

United Kingdom

The UK pre-tax segmented income increased to $1.2 billion and accounted for 34% of the Company's pre-tax segmented income from continuing
operations during 2006, up 9% from $1.1 billion in 2005. UK gross sales increased 10% to $2.5 billion due primarily to higher prices. Production from continuing operations averaged
97,500 boe/d, down 3% from 2005, and represented 22% of the Company's total production. Operating expenses increased 12% to $690 million and DD&A expense increased $43 million to
$440 million. Royalty expense decreased 50% to $5 million. Dry hole expense decreased from $38 million to $26 million in 2006. Exploration and development spending for the
UK was $1.2 billion, up 38% from 2005.

Scandinavia

In Scandinavia, pre-tax segmented income increased 44% to $322 million and accounted for 9% of the Company's pre-tax segmented income from
continuing operations during 2006, up from $223 million in 2005. Scandinavia gross sales increased 45% to $890 million due primarily to higher prices and increased production, resulting
from acquisitions and development drilling. Production averaged 34,900 boe/d and represented 8% of the Company's total production. This 28% increase in production also contributed to increases
in operating expenses of $79 million and DD&A expense of $91 million. Exploration and development spending for Scandinavia was $332 million, up 129% from 2005.

Southeast Asia

Southeast Asia contributed 24% ($853 million) to the Company's pre-tax segmented income from continuing operations in 2006. Gross sales increased 39% to
$2.1 billion with increased commodity prices and production. Southeast Asia production averaged 100,200 boe/d, an increase of 21% over 2005 and represented 21% of the Company's total
production. Total operating expenses increased 85% from 2005 to $161 million as a result of the increase in production. DD&A expense increased 56% to $224 million. Capital spending for
Southeast Asia was $331 million, up 9% from 2005.

Other

The Other reporting segment contributed 2% ($68 million, down 63% from 2005) to the Company's pre-tax segmented income from continuing operations in 2006.
Gross sales decreased 7% from 2005 to $539 million as decreased production more than offset higher commodity prices. Production for 2006 averaged 21,600 bbls/d, down 15% from 2005, and
represented 5% of the Company's total production in 2006. Operating costs in 2006 remained flat at $36 million. Dry hole costs were $109 million, up from $55 million in 2005.
Capital spending was $249 million, up $65 million from 2005.

18   Talisman Energy 2006 Annual Financial Report

---



Summary of Quarterly Results

The following is a summary of quarterly results of the Company for the eight most recently completed quarters:

|                                            |                                                | Three months ended
|------------------------------------------- | ---------------------------------------------- | ------------------
|(millions of C$, unless otherwise stated)   |                                                | Total Year        
|                                           
|2006                                        |                                                |                   
|                                           
|Gross sales                                 |                                                | 9,362             
|                                           
|Total revenue                               |                                                | 7,944             
|                                           
|Net income from continuing operations       |                                                | 1,452             
|                                           
|Net income                                  |                                                | 2,005             
|                                           
|Net income available to common shareholders |                                                | 2,005             
|                                           
|Capital expenditures                        |                                                |                   
|                                            | Exploration                                    |                   
|                                           
|                                            | Development                                    |                   
|                                           
|Per common share ($)5                       |                                                |                   
|                                            | Net income from continuing operations          |                   
|                                           
|                                            | Diluted net income from continuing operations2 |                   
|                                           
|                                            | Net income                                     |                   
|                                           
|                                            | Diluted net income2                            |                   
|                                           
|Daily average production                    |                                                |                   
|                                            | Oil and liquids (bbls/d)3                      |                   
|                                           
|                                            | Natural gas (mmcf/d)                           |                   
|                                           
|                                            | Continuing operations (mboe/d)                 |                   
|                                           
|                                            | Discontinued operations (mboe/d)4              |                   
|                                           
|                                            | Total (mboe/d)                                 |                   
|                                           

|20051                                       |                                                |       |         |       |         |       |         |       |         |      
|------------------------------------------- | ---------------------------------------------- | ----- | ------- | ----- | ------- | ----- | ------- | ----- | ------- | -----
|                                           
|Gross sales                                 |                                                | 8,888 |         | 2,682 |         | 2,459 |         | 1,932 |         | 1,815
|                                           
|Total revenue                               |                                                | 7,407 |         | 2,227 |         | 2,044 |         | 1,612 |         | 1,524
|                                           
|Net income from continuing operations       |                                                | 1,354 |         | 463   |         | 376   |         | 302   |         | 213  
|                                           
|Net income                                  |                                                | 1,561 |         | 533   |         | 430   |         | 340   |         | 258  
|                                           
|Net income available to common shareholders |                                                | 1,561 |         | 533   |         | 430   |         | 340   |         | 258  
|                                           
|Capital expenditures                        |                                                |       |         |       |         |       |         |       |         |      
|                                            | Exploration                                    |       | 1,084   |       | 358     |       | 273     |       | 216     |      
|                                           
|                                            | Development                                    |       | 2,048   |       | 608     |       | 501     |       | 439     |      
|                                           
|Per common share ($)5                       |                                                |       |         |       |         |       |         |       |         |      
|                                            | Net income from continuing operations          |       | 1.23    |       | 0.42    |       | 0.34    |       | 0.27    |      
|                                           
|                                            | Diluted net income from continuing operations2 |       | 1.20    |       | 0.41    |       | 0.33    |       | 0.27    |      
|                                           
|                                            | Net income                                     |       | 1.41    |       | 0.48    |       | 0.39    |       | 0.31    |      
|                                           
|                                            | Diluted net income2                            |       | 1.38    |       | 0.47    |       | 0.38    |       | 0.30    |      
|                                           
|Daily average production                    |                                                |       |         |       |         |       |         |       |         |      
|                                            | Oil and liquids (bbls/d)3                      |       | 232,346 |       | 273,409 |       | 226,982 |       | 211,435 |      
|                                           
|                                            | Natural gas (mmcf/d)                           |       | 1,210   |       | 1,218   |       | 1,214   |       | 1,198   |      
|                                           
|                                            | Continuing operations (mboe/d)                 |       | 434     |       | 476     |       | 430     |       | 411     |      
|                                           
|                                            | Discontinued operations (mboe/d)4              |       | 36      |       | 40      |       | 31      |       | 33      |      
|                                           
|                                            | Total (mboe/d)                                 |       | 470     |       | 516     |       | 461     |       | 444     |      
|                                           

Talisman Energy 2006 Annual Financial Report   19

---



The following discussion highlights some of the more significant factors that impacted net income in the eight most recently completed quarters.

During
the fourth quarter of 2006 gross sales increased by $2 million over the previous quarter as the impact of reduced oil prices almost offset the 6% increase in total production. Net income
from continuing operations decreased $59 million from the third quarter as increases in charges for dry holes, exploration, stock-based compensation, DD&A and operating costs more than offset
the impact of reduced taxes and the gain on sale of a royalty interest in an undeveloped lease.

During
the fourth quarter, the Company:



During
the third quarter of 2006, gross sales decreased by $115 million over the previous quarter due to decreased natural gas prices and reduced production. Net income from continuing
operations for the quarter decreased by $144 million, primarily due to the $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions recorded
in the second quarter.

During
the second quarter of 2006, gross sales decreased by $358 million over the previous quarter due to decreased production. Net income from continuing operations for the quarter increased
by $409 million, primarily due to the impact of a $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions and the $325 million future
tax charge in the first quarter.

In
the first quarter of 2006, gross sales decreased by $16 million over the previous quarter. Net income from continuing operations for the quarter decreased by $320 million, primarily
due to the impact of a one-time non-cash adjustment of $325 million related to a UK income tax rate increase.

During
the fourth quarter of 2005, gross sales rose by $223 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea. Net
income from continuing operations for the quarter increased by $87 million, as the increased revenue combined with reduced stock-based compensation charges more than offset the impact of
increases in operating, DD&A, royalty and tax expenses.

During
the third quarter of 2005, higher commodity prices and production increased gross sales by $527 million. Net income from continuing operations for the quarter increased by
$74 million, as the increased revenue more than offset the impact of increases in stock-based compensation, royalty and tax expenses.

In
the second quarter of 2005, gross sales rose due to increased commodity prices, which were partially offset by reduced production. Net income from continuing operations increased in the quarter as
higher revenue combined with reductions in stock-based compensation charges, transportation and other expenses more than offset the impact of increases in operating costs, royalties, taxes, dry hole
costs and exploration expenses.

During
the first quarter of 2005, gross sales rose over the last quarter of 2004, as a result of higher commodity prices, increased production and reduced hedging losses. Net income from continuing
operations increased in the quarter as increased revenue combined with reductions in dry hole costs, exploration expenses, impairments, DD&A and G&A more than offset the impact of increases in
stock-based compensation charges, royalties, operating costs and taxes.

Application of Critical Accounting Policies and the Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of
contingencies and revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates. Actual results could differ materially from those
estimates. A summary of significant accounting policies adopted by Talisman can be found in note 1 to the Consolidated Financial Statements. In assisting the Company's Audit Committee to
fulfill its financial statement oversight role, management regularly meets with the Committee to review the Company's significant accounting policies, estimates and any significant changes thereto,
including those discussed below.

Management
believes the most critical accounting policies, including judgments in their application, which may have an impact on the Company's financial results, relate to the accounting for property,
plant and equipment, asset retirement obligations and goodwill. The rate at which the Company's assets are depreciated or otherwise written off and the asset retirement liability provided for, with
the associated accretion expensed to the income statement, are subject to a number of judgments about future events, many of which are beyond management's control. Reserves recognition is central to
much of the accounting for an oil and gas company as described below.

Reserves Recognition

Underpinning Talisman's oil and gas assets and goodwill are its oil and gas reserves. Detailed rules and industry practice, to which Talisman adheres, have been developed to
provide uniform reserves recognition criteria. However, the process of estimating oil and gas reserves is inherently

20   Talisman Energy 2006 Annual Financial Report

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judgmental.
There are two principal sources of uncertainty: technical and commercial. Technical reserves estimates are made using available geological and reservoir data as well as production
performance data. As new data become available, including actual reservoir performance, reserves estimates may change. Reserves can also be classified as proved or probable with decreasing levels of
certainty as to the likelihood that the reserves will be ultimately produced.

Reserves
recognition is also impacted by economic considerations. In order for reserves to be recognized, they must be reasonably certain of being produced under existing economic and operating
conditions, which is viewed as being at year-end commodity prices with a cost profile based on current operations. In particular, in international operations, consideration includes the
status of field development planning and gas sales contracts. As economic conditions change, primarily as a result of changes in commodity prices and, to a lesser extent, operating and capital costs,
marginally profitable production, typically experienced in the later years of a field's life cycle, may be added to reserves or, conversely, may no longer qualify for reserves recognition.

The
Company's reserves and revisions to those reserves, although not separately reported on the Company's balance sheet or income statement, impact the Company's reported net income through the
depletion, depreciation and amortization of the Company's property, plant and equipment (PP&E), asset and goodwill impairments and the provision for future asset retirement obligations.

The
Reserves Committee of Talisman's Board of Directors reviews the Company's reserves booking process and related public disclosures and the report of the internal qualified reserves evaluator
(IQRE). The primary responsibilities of the Reserves Committee of the Board of Directors include, among other things, reviewing the Company's reserves booking process and recommending to the Board of
Directors, the Company's annual statement of reserves data and other oil and gas information. The IQRE reports the Company's annual reserves data to the Reserves Committee and delivers a regulatory
certificate regarding proved reserves and their related future net cash flows.

Depreciation, Depletion and Amortization Expense (DD&A)

A significant portion of the Company's PP&E is amortized based on the unit of production method with the remaining assets being amortized equally over their expected useful
lives. The unit of production method attempts to amortize the asset's cost over its proved oil and gas reserves base. Accordingly, revisions to reserves or changes to management's view as to the
operational life span of an asset will impact the Company's future DD&A expense.

As
outlined in the Company's DD&A accounting policy and PP&E notes (notes 1(d) and 5 to the Consolidated Financial Statements), $4.9 billion
(2005  $3.2 billion) of the Company's PP&E is not currently subject to DD&A. Approximately 21% of these costs relate to the Tweedsmuir development project
($1 billion) in the UK, due to come on production early in the second quarter of 2007, at which time amortization will commence. The remainder of the $3.9 billion of
non-depleted capital relates to the costs of other development projects ($1.6 billion), which will be amortized when production commences, the costs of acquired unproved reserves
($1.5 billion) and incomplete drilling activities, including those wells under evaluation or awaiting commencement of production ($769 million). Uncertainty exists with the treatment of
these costs. For example, if the evaluation of the acquired probable reserves or recently drilled exploration wells was determined to be unsuccessful, the associated capitalized costs would be
expensed in the year such determination is made, except that, in the case of acquired probable reserves associated with producing fields, these costs would be amortized over the reserve base of the
associated producing field. Accordingly, the rate at which these costs are written off depends on management's view of the likelihood of the existence of economically producible reserves.

Successful Efforts Accounting

Talisman uses the successful efforts method to account for its oil and gas exploration and development costs. Acquisition costs and development costs are capitalized and
depleted using the unit of production method. Costs of drilling unsuccessful exploration wells (dry hole costs) and all other exploration costs, including geological and geophysical costs,
are expensed.

The
alternative method of accounting for oil and gas exploration and development costs is the full cost method. Under this method, costs of unsuccessful exploration wells as well as all other
exploration costs are capitalized and added to the PP&E balance to be depleted on a unit of production basis in the future. In addition, future development costs are depleted over the total proved
reserves.

The
differences between the full cost and successful efforts methods of accounting make it difficult to compare net income between companies that use different methods of accounting.

Asset Impairments

The Company's oil and gas assets and goodwill are subject to impairment tests. An impairment charge is recorded in the year an asset is determined to be impaired under the
successful efforts method. Any impairment charge is the difference between the carrying value of the asset and its fair value. Goodwill represents the excess purchase price over the fair value of
identifiable assets and liabilities acquired in business combinations. There have been no changes to the number of reporting units or the manner in which goodwill is allocated to the reporting units
during the year. Goodwill is considered to be impaired if its fair value, principally determined based on discounted cash flows, falls below its carrying value. Both tests and potential asset
impairment calculations require management to make assumptions regarding cash flows well into the distant future that are subject to revisions due to changes in commodity prices, costs, recoverable
reserves, production profiles and discount rates. During the past three years, isolated asset impairments have occurred (2006  nil;
2005  $31 million; 2004  $31 million); however, it is possible that future impairments may
be material.

Talisman Energy 2006 Annual Financial Report   21

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Purchase Price Allocations

The costs of corporate and asset acquisitions are allocated to the acquired assets and liabilities based on their fair value at the time of acquisition. In many cases, the
determination of fair value requires management to make certain assumptions and estimates regarding future events. Typically in determining fair value, management develops a number of possible future
cash flow scenarios to which probabilities are judgmentally assigned. The allocation process is inherently subjective and impacts the amounts assigned to the various individually identifiable assets
and liabilities as well as goodwill. The acquired assets and liabilities may span multiple geographical segments and may be amortized at different rates, or not at all as in the case of goodwill or,
initially, for acquired probable reserves. Accordingly, the allocation process impacts the Company's reported assets and liabilities and future net income due to the impact on future depreciation,
depletion and amortization expense and impairment tests.

Goodwill,
as determined by the purchase price allocation method, represents the excess purchase price over the fair value of identifiable assets and liabilities acquired in business combinations.
Goodwill is not amortized but is subject to ongoing annual impairment reviews, or more frequently as economic events dictate, based on the fair value of reporting units. Goodwill is allocated to the
reporting units on the basis of the excess of the fair value of the reporting unit over the identifiable assets and liabilities of the reporting unit. The Company's reporting units for goodwill are
aggregated within the geographic segments included in note 19 to the Consolidated Financial Statements.

During
2005, Talisman acquired Paladin for $2.6 billion in cash and assumed long-term debt. The acquisition has been accounted for using the purchase method and the Paladin results
have been included in the Consolidated Financial Statements of the Company from the date of acquisition. Also during 2005, the Company completed a number of oil and gas property and corporate
acquisitions for a total cost of $536 million, comprised of $532 million in cash and assumed working capital and $4 million of properties exchanged. See note 3 to the
Consolidated Financial Statements for details.

Asset Retirement Obligations (ARO)

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with abandonment and reclamation activities. Estimates of the
associated costs are subject to uncertainty associated with the method, timing and extent of future retirement activities. Accordingly, the annual expense associated with future abandonment and
reclamation activities is impacted by changes in the estimates of the expected costs and reserves. Changes to these estimates in the past two years have resulted in the following: as at
December 31, 2006, an increase of $144 million in the discounted ARO liability related changes in cost estimates in the UK, as well as $14 million and $13 million for North
America and rest of the world, respectively, related to changes in cost estimates; and at December 31, 2005, a reduction of $177 million in the discounted ARO liability related to an
increase in life of reserves in the UK was offset by increases in the liability of $59 million and $21 million for North America and
rest of the world, respectively, related to changes in cost estimates. The total undiscounted abandonment liability is currently estimated at $4.6 billion, which is based on management's
probability weighted estimate of costs and in accordance with existing legislation and industry practice.

Under
Canadian GAAP, the fair value of the Company's ARO has been recorded as a liability on the Company's balance sheet. In determining the fair value of the Company's ARO liability, management
developed a number of possible abandonment scenarios to which probabilities were assigned based on management's reasonable judgment. At December 31, 2006, the discounted fair value of the
Company's ARO liability is $1.9 billion, (2005  $1.3 billion). As an indication of possible future changes in the estimated liability, if all of
the Company's abandonment obligations could be deferred by one additional year, the fair value of the liability would have decreased by approximately $72 million.

Foreign Exchange Accounting

Talisman's worldwide operations expose the Company to transactions denominated in a number of different currencies, which are required to be translated into one currency for
financial statement reporting purposes. Talisman's foreign currency translation policy, as detailed in note 1(i) to the Consolidated Financial Statements, is designed to reflect the economic
exposure of the Company's operations to the various currencies. The adoption of the US$, effective for 2002, as the Company's functional currency is a reflection of Talisman's overall exposure to US$
denominated transactions, assets and liabilities; oil prices are largely denominated in US$ as is much of the Company's corporate debt and international capital spending and operating costs. However,
the Company's operations in the UK, Canada and Norway are largely self-sufficient (self-sustaining) and their economic exposure is more closely tied to their respective
domestic currencies. Accordingly, these operations are measured in UK£, C$ and Norwegian kroner (NOK), respectively. Currently, the Company's foreign exchange translation exposure
principally relates to US$ denominated UK and Canadian oil sales.

As
part of the adoption by the Company as at January 1, 2004 of the new accounting guideline on Hedging Relationships, AcG 13, and, effective January 2004, the Eurobond debt, denominated
in UK£, and the Company's C$ debt were designated as hedges of the Company's net investments in the UK and Canadian self-sustaining operations, respectively. As such, the
unrealized foreign exchange gains and losses resulting from the translation of this debt are deferred and included in a separate component of shareholders' equity described as cumulative foreign
currency translation.

Production Sharing Contractual Arrangements

A significant portion of the Company's operations outside North America, the UK and Scandinavia are governed by Production Sharing Contracts (PSCs). Under PSCs, Talisman, along
with other working interest holders, typically bears all risk and costs for exploration, development and production. In return, if exploration is successful, Talisman recovers the sum of its
investment and operating costs (cost oil) from a percentage of the production and sale of the associated hydrocarbons. Talisman is also entitled to receive a share of the production in excess of cost
oil (profit oil). The sharing of profit oil varies between the working interest holders and the government from contract to contract. The cost oil, together with the Company's share of profit oil,
represents Talisman's hydrocarbon entitlement (working interest less royalties). Talisman records gross production, sales and reserves based on its working interest ownership. The difference between
the Company's working interest ownership and its entitlement is

22   Talisman Energy 2006 Annual Financial Report

---



accounted
for as a royalty expense. In addition, certain of the Company's contractual arrangements in foreign jurisdictions stipulate that income taxes are paid out of the respective national oil
company's entitlement share of production. The Company includes such amounts in income tax expense at the statutory tax rate in effect at the time of production.

The
amount of cost oil required to recover Talisman's investment and costs in a PSC is dependent on commodity prices and, consequently, Talisman's share of profit oil is also impacted. Accordingly,
the amount of royalty paid by Talisman over the term of a PSC and the corresponding net after royalty oil and gas reserves booked by the Company are dependent on the amount of initial investment and
past costs yet to be recovered and
anticipated future costs, commodity prices and production. As a result, when year-end prices increase, the amount of net after royalty reserves the Company books may decrease and
vice versa.

New Canadian Accounting Pronouncements

The CICA has issued a number of accounting pronouncements, some of which may impact the Company's reported results and financial position in
future periods.

Other Comprehensive Income, Financial Instruments and Hedging

Effective January 1, 2007, Talisman adopted the new CICA accounting standards related to Comprehensive Income (section 1530), Financial Instrument Recognition and
Measurement (section 3855), Financial Instruments Disclosure and Presentation (section 3861), and Hedges (section 3865).

Under
these standards, the Company must classify all financial instruments into one of the following categories: loans and receivables, assets held-to-maturity, assets
available-for-sale, other financial liabilities, and held-for-trading (assets and liabilities). Financial instruments reclassified to
held-for-trading or available-for-sale items are re-measured at fair value on adoption of this standard. Gains or losses on
re-measurement of held-for-trading items are recognized as an adjustment to opening retained earnings, while gains or losses on re-measurement of
available-for-sale items are recognized as an adjustment to opening accumulated other comprehensive income.

Financial
instruments that are classified as held-for-trading or available-for-sale are re-measured each reporting period at fair value with
the resulting gain or loss recognized immediately in net income and other comprehensive income, respectively. All other financial instruments are accounted for at amortized cost with foreign exchange
gains and losses recognized immediately in net income. The recognition, de-recognition and measurement policies followed in financial statements for periods prior to the effective date of
this standard are not reversed and, therefore, those financial statements are not restated.

Gains
and losses on financial instruments that continue to be part of a cash flow or net investment hedge are recognized in other comprehensive income until realized, at which time they are recovered
from other comprehensive income and realized in net income. Any ineffective portion of cash flow hedges is recognized in net income immediately. Net gains/losses on fair value hedges are recognized
immediately in net income. Accounting for hedging relationships in financial statements for prior fiscal years is not retroactively changed.

Section 3855
requires that an asset or liability be recognized for embedded derivatives by separating them from their host contracts and measuring them at fair value. Talisman has elected the
beginning of its fiscal year-end December 31, 2003 as the effective date for embedded derivatives. Consequently, only embedded derivatives entered into on or after January 1,
2003 are subject to the measurement provisions of these standards.

The
adjustment required to the January 1, 2007 balance sheet to implement these changes in accounting standards would be as follows:

|Consolidated Balance Sheets              |  | December 31, 2006 |  | Adjustments |   | January 1, 2007 |  
|---------------------------------------- |  | ----------------- |  | ----------- | - | --------------- | -
|                                         | 
|Assets                                   |  |                   |  |             |   |                 |  
|                                         | 
|Accounts receivable                      |  | 1,136             |  | 122         |   | 1,258           |  
|                                         | 
|Liabilities                              |  |                   |  |             |   |                 |  
|                                         | 
|Accounts payable and accrued liabilities |  | 2,477             |  | 11          |   | 2,488           |  
|                                         | 
|Other long-term obligations              |  | 157               |  | 21          |   | 178             |  
|                                         | 
|Long-term debt                           |  | 4,560             |  | (3          | ) | 4,557           |  
|                                         | 
|Future income taxes                      |  | 4,350             |  | 27          |   | 4,377           |  
|                                         | 
|Shareholders' equity                     |  |                   |  |             |   |                 |  
|                                         | 
|Accumulated other comprehensive income   |  |                  |  | 1,377       |   | 1,377           |  
|                                         | 
|Cumulative foreign currency translation  |  | 122               |  | (1,311      | ) | (1,189          | )
|                                         | 

Capital Disclosures, Financial Instruments Disclosure and Presentation

In its continued effort to align with international accounting standards, the CICA issued three new accounting standards in the fourth quarter of 2006. The new standard,
Financial Instruments Presentation (section 3863), carries forward the guidance under section 3861 with little change. The standard Financial Instruments Disclosure (section 3862)
requires disclosure on the face of the balance sheet of each of the financial instrument categories described above, as well as additional disclosure regarding credit, market and liquidity risk faced
by the Company. With regards to each of these types of risk, the Company must disclose its Company-specific exposure and how it arises, the Company's objectives, policy and process for managing the
risk, the methods used to measure the risk and quantitative data about the exposure to the risk at the balance sheet date, including

Talisman Energy 2006 Annual Financial Report   23

---



concentration
of risk that is not otherwise apparent. The new standard Capital Disclosures (section 1535) requires qualitative disclosure of the Company's objectives, policies and processes for
managing its capital and quantitative disclosures are required to summarize what the entity considers to be its capital. These standards will become effective for Talisman's first quarter 2008
reporting and are not expected to have a material impact on our results of operations or financial position.

Stock-Based Compensation

In July 2006, the Emerging Issues Committee (EIC) of the CICA issued EIC-162, Stock-based compensation for employees eligible to retire before the vesting
date. EIC-162 clarifies the accounting for stock-based compensation plans that allow for vesting of stock-based awards after an employee's retirement. If the employee is eligible to
retire on the grant date of an award, related compensation cost is to be recognized in full at that date as there is no ongoing service requirement to earn the award. If the employee becomes eligible
to retire during the vesting period, the compensation cost is to be recognized over the period from the grant date to the retirement eligibility date. EIC-162 became effective in
the fourth quarter of 2006. This EIC did not represent a change from the Company's accounting for stock-based compensation and, accordingly the adoption of EIC-162 did not have a
material impact on our results of operations or financial position.

Discontinued Operations

In April 2006, the EIC of the CICA issued EIC-161, Discontinued Operations in order to address whether corporate interest and general and administrative costs
should be allocated to discontinued operations and whether to report discontinued operations if the remaining operations are insignificant. The EIC concluded that interest should be allocated if the
debt must either be assumed or repaid upon disposition of the assets, and a company may elect to allocate a portion of its total interest expense to discontinued operations. The EIC also concluded
that a company should not report discontinued operations if the remaining operations are insignificant, but must disclose separately the assets and liabilities from discontinued operations. As part of
its discontinued operations reporting, Talisman has allocated interest from debt that was required to be repaid from the proceeds of dispositions. See note 2 to the Consolidated Financial
Statements.

Business Combinations

Concurrently with the joint Financial Accounting Standards Board/International Accounting Standards Board (FASB/IASB) project, the CICA has coordinated a project addressing the
business combinations accounting standard. The proposals under this standard will require the fair value of the acquired business to be measured on the date control is obtained. The full value of the
assets and liabilities acquired will be recorded at fair value on the acquirer's balance sheet, including the fair value of any contingent consideration, with the non-controlling interest
in these assets and liabilities included in shareholders' equity. Subsequent acquisitions of the non-controlling interest in the acquired company will be subject to gains and losses. All
acquisition and integration costs must be expensed as incurred and cannot be recognized as a liability on acquisition. The standard was expected to be finalized in 2006 but has been delayed and it is
uncertain when it will become effective.

Financial Accounting Standards Board (FASB) US Pronouncements

In September 2006, FASB issued Statement 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R). Statement 158 requires an employer to recognize the over-funded or under-funded status of a defined benefit post-retirement plan on
the balance sheet as an asset or liability and to recognize changes in the funded status through comprehensive income. This statement also requires measurement of the funded status of a plan as of the
balance sheet date. The recognition and disclosures under Statement 158 are required for fiscal years ending after December 15, 2006 while the new measurement date is effective for
fiscal years ending after December 15, 2008. As a result of the adoption of this statement, the recognized net pension liability is higher by $53 million for US GAAP purposes with no
GAAP differences to net income. Additional detail is available in our US GAAP reconciliation in note 20 to the Consolidated Financial Statements.

In
July 2006, the FASB issued Financial Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109" ("FIN 48"), which is a change in accounting for income taxes. FIN 48 specifies how tax benefits for uncertain tax positions are to be recognized, measured, and
derecognized in financial statements; requires certain disclosures of uncertain tax matters; specifies how reserves for uncertain tax positions should be classified on the balance sheet; and provides
transition and interim-period guidance, among other provisions. FIN 48 is effective for fiscal years beginning after December 15, 2006, and will be effective for Talisman's
2007 year end reporting. Talisman is currently evaluating the impact of FIN 48 on our Consolidated Financial Statements.

In
September 2006, the FASB issued Statement 157, "Fair Value Measurements". This statement is intended to increase the consistency and comparability of fair value measurements and eliminate
different definitions of fair value under various US standards. This standard clarifies that fair value is a market measure and not an entity specific measure. Among other attributes, fair value
assumes the highest and best use for the asset or liability being measured and is based on the exit price for the holder of the asset or liability. This standard also establishes a fair value
hierarchy as follows: Level 1 is fair value based on observable market inputs that reflect quoted prices in a market accessible to the entity. Level 2 is fair value based on observable
market inputs that do not reflect quoted prices in a market accessible to the entity, for example quoted prices for similar assets or identical assets in inactive markets, or inputs derived through
interpolation of other observable market data. Level 3 fair value is based on unobservable market inputs, for example inputs derived through interpolation that cannot be corroborated by
observable market data. The total fair value of assets and liabilities that are re-measured each reporting date must be grouped by hierarchy level for disclosure purposes, and in addition
a continuity of the changes in the Level 3 measurements must be disclosed. This statement is effective for fiscal years beginning on or after

24   Talisman Energy 2006 Annual Financial Report

---



November 15,
2007 and will be effective for Talisman in fiscal 2008. Talisman is currently evaluating the impact that Statement 157 on our Consolidated Financial Statements.

Outlook for 20071

|                                              |  | Estimated for 2007 |  |                    |  | Actual 20062
|--------------------------------------------- |  | ------------------ |  | ------------------ |  | ------------
|                                             
|Cash provided by operating activities ($)     |  |                    |  | 5.0 billion        |  |             
|                                             
|                                              |  |                    |  |                    |  |             
|Exploration and development spending          |  | Estimated for 2007 |  |                    |  | Actual 2006 
|                                             
|(millions of dollars)                         |  | Exploration        |  | Development        |  | Total E&D   
|                                             
|North America                                 |  | 875                |  | 1,455              |  | 2,330       
|                                             
|United Kingdom                                |  | 150                |  | 1,025              |  | 1,175       
|                                             
|Scandinavia                                   |  | 140                |  | 300                |  | 440         
|                                             
|Southeast Asia                                |  | 155                |  | 515                |  | 670         
|                                             
|Other3                                        |  | 155                |  | 85                 |  | 240         
|                                             
|                                              |  | 1,475              |  | 3,380              |  | 4,855       
|                                             
|                                              |  |                    |  |                    |  |             
|Production (daily average)                    |  |                    |  | Estimated for 2007 |  | Actual 20062
|                                             
|Oil and liquids (bbls/d)                      |  |                    |  |                    |  |             
|                                             
|North America                                 |  |                    |  |                    |  | 42,500      
|                                             
|United Kingdom                                |  |                    |  |                    |  | 122,000     
|                                             
|Scandinavia                                   |  |                    |  |                    |  | 33,000      
|                                             
|Southeast Asia                                |  |                    |  |                    |  | 45,200      
|                                             
|Other3                                        |  |                    |  |                    |  | 21,300      
|                                             
|                                              |  |                    |  |                    |  | 264,000     
|                                             
|Natural gas (mmcf/d)                          |  |                    |  |                    |  |             
|                                             
|North America                                 |  |                    |  |                    |  | 900         
|                                             
|United Kingdom4                               |  |                    |  |                    |  | 110         
|                                             
|Scandinavia                                   |  |                    |  |                    |  | 13          
|                                             
|Southeast Asia                                |  |                    |  |                    |  | 303         
|                                             
|                                              |  |                    |  |                    |  | 1,326       
|                                             
|Barrels of oil equivalent (mboe/d)            |  |                    |  |                    |  | 485         
|                                             
|                                              |  |                    |  |                    |  |             
|                                             
|Commodity price and exchange rate assumptions |  |                    |  |                    |  |             
|                                             
|US$/bbl WTI oil price                         |  |                    |  |                    |  | 65.00       
|                                             
|US$/mmbtu NYMEX natural gas price             |  |                    |  |                    |  | 7.50        
|                                             
|US$/C$ exchange rate                          |  |                    |  |                    |  | 0.90        
|                                             
|C$/£ exchange rate                            |  |                    |  |                    |  | 2.05        
|                                             

2007 Geographic Outlook

Talisman expects production to remain relatively flat in 2007 at approximately 485,000 boe/d.

Unit
operating costs are expected to be marginally higher than in 2006; however, unit production costs, in addition to being impacted by currency exchange rates, are dependent on achieving expected
production levels. Capital spending is expected to be approximately $4.8 billion and excludes significant corporate and asset acquisitions. The Company anticipates participating in the drilling
of 448 wells in North America and 158 wells internationally during 2007 (gross).

North America (Includes Alaska)

In 2007, natural gas will continue to be the focus of the Company's exploration activities in North America, including deep gas exploration in Western Canada and the ongoing
drilling program in Appalachia, supplemented by low risk oil projects. The Company has budgeted $100 million in Alaska during 2007, primarily to drill up to three exploration wells and conduct
further exploration activities. North American natural gas production in 2007

Talisman Energy 2006 Annual Financial Report   25

---



is
expected to average 900 mmcf/d, while oil and liquids is expected to average 42,500 bbls/d, as the Company will spend approximately 93% of the North America budget on natural gas exploration
and development. The Company expects to spend approximately $2.3 billion on capital projects and
drilling in 2007, 4% less than 2006. The Company plans to participate in approximately 448 wells in 2007, including 11 high impact exploration wells. Unit operating costs are expected to
increase slightly to approximately $7.33/boe due to increased processing and power costs.

United Kingdom

Production in the UK is expected to average 122,000 bbls/d and 110 mmcf/d in 2007. Capital spending is planned to decrease by 3% from 2006, to approximately
$1.2 billion, with 87% related to development projects. The Company plans to drill 32 gross development wells including one shared well with Scandinavia and up to five gross exploration
wells. The ongoing program to develop the Tweedsmuir field anticipates first production in April of 2007. Capital expenditures are also directed at development programs in eight fields, which are
expected to significantly increase production by 2009. UK 2007 unit operating expenses are expected to drop slightly from the 2006 amount. At planned exchange rates (approximately
£1:C$2.05), unit operating costs are expected to average $16.70/boe.

Scandinavia

Scandinavia production is expected to average 33,000 bbls/d and 13 mmcf/d in 2007. Capital spending is planned at $440 million, with 68% related to
development projects. The Company plans to drill 10 gross development wells including one shared with the UK and up to seven gross exploration wells. Unit operating costs are expected to
average $22/boe.

Southeast Asia

While pursing additional hydrocarbon assets in the SE Asia, monetization of the existing large gas reserves and the development of shallow water oil and gas plays will
be continued.

In
Indonesia, Talisman will continue the development of the major natural gas discoveries at Corridor and the exploration of its extensive acreage. Natural gas sales in Indonesia are expected to
average 230 mmcf/d in 2007. Total planned capital spending of $100 million in Indonesia during 2007 includes the completion of the Phase 2 expansion of the gas processing
facilities at Suban in the Corridor PSC, drilling of 32 gross development wells (excluding four injectors) and up to four gross exploration wells. Oil and liquids production in Indonesia is
expected to average 11,000 bbls/d.

Malaysia/Vietnam
production for 2007 is targeted at 39,400 boe/d, which includes an average of 27,200 bbls/d of liquids and an average of 73 mmcf/d of natural gas. Total
development capital spending during 2007 in Malaysia/Vietnam is expected to be approximately $422 million of which 21 gross development wells are planned for a total of
$105 million. The development of the Northern Fields will continue in 2007 with spending of $216 million. First gas production is expected in early second quarter of 2008 with
first oil in the third quarter of 2008. The Song Doc project in Block 46/02 will incur $28 million in 2007 with first oil production commencing in the second quarter of 2008. A
total of $119 million on exploration activities is planned with two PM-3 CAA wells, one well in PM-305 and four PM-314 wells. In addition,
Talisman plans to drill up to three exploration wells in Block 15-2/01 in Vietnam in 2007.

In
Australia in 2007, oil and liquids production is expected to average 7,000 bbls/d, with capital spending of $30 million to participate in one development well.

Operating
costs in Southeast Asia are expected to be approximately $4.46/boe in 2007 similar to 2006.

Other

Production from the Ourhoud and MLN fields in Algeria, together with production in Tunisia, is expected to average 15,000 bbls/d in 2007. Unit operating costs are
expected to fall due to higher production. A capital budget of $60 million is estimated and, in Algeria, includes drilling
17 development wells, the commissioning of the Phase 2 expansion of the Greater MLN facility and the El Merk project sanctioning, with first oil in 2010. Two development wells and up to
five exploration wells are planned in Tunisia.

In
Trinidad and Tobago, capital spending is budgeted at $65 million, split approximately equally between development and exploration with the drilling of up to seven exploration wells and four
development wells. Production in Trinidad and Tobago is expected to average 6,300 bbls/d.

The
Company is exploring in South America, where it expects to spend $26 million in 2007 on exploration activities in Peru and Colombia. The Company also plans to spend an estimated
$24 million in Qatar, which will include the drilling of up to two exploration wells in Block 10.

At
year-end, Talisman has committed approximately 15% of its anticipated 2007 North American natural gas production under commodity sales contracts at an average price of $7.89/mcf. In
addition, approximately 13% of the Company's anticipated 2007 UK oil and liquids production is hedged at an average price of US$65.90/bbl.

A
summary of the contracts outstanding at year-end can be found in notes 11 and 12 to the Consolidated Financial Statements. Additional discussion of the Company's commodity
price hedging program can be found in the MD&A section entitled Derivative Financial Instruments and Commodity Sales Contracts.

Liquidity

The Company expects to fund most of its exploration and development expenditures from cash flow from operating activities. Proceeds from the disposal of non-core
asset sales are expected to be used to fund share repurchases under its NCIB program and any excess capital expenditures over cash flow from operating activities. The maturities of certain debentures
and notes in 2007 are expected to be funded by drawings under the Company's unsecured revolving credit facilities. Subsequent acquisitions or dispositions, a change from expected commodity prices,
working capital movements or changes in the amount of share repurchases would impact the Company's net debt position.

Sensitivities

Talisman's financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated impact of these factors on the
Company's 2007 financial performance is summarized in the following table and is based on a WTI oil price of US$65/bbl, a NYMEX natural gas price of US$7.50/mmbtu, a US$/C$ exchange rate of $0.90 and
a C$/UK£ exchange rate of $2.05.

26   Talisman Energy 2006 Annual Financial Report

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Approximate Impact in 2007

|(millions of C$)      |                               | Net Income |    | Cash Provided by Operating Activities
|--------------------- | ----------------------------- | ---------- | -- | -------------------------------------
|                     
|Volume changes        |                               |            |    |                                      
|                     
|                      | Oil  1,000 bbls/d            |            | 7  |                                      
|                     
|                      | Natural gas  10 mmcf/d       |            | 8  |                                      
|                     
|Price changes1        |                               |            |    |                                      
|                     
|                      | Oil  US$1/bbl                |            | 44 |                                      
|                     
|                      | Natural gas                   |            |    |                                      
|                      | (North America)2  C$0.10/mcf |            | 16 |                                      
|                     
|Exchange rate changes |                               |            |    |                                      
|                     
|                      | US$ increased by US$0.01      |            | 40 |                                      
|                     
|                      | £ increase by C$0.023         |            | (7 | )                                    
|                     

Risk Factors

Talisman is exposed to a number of risks inherent in exploring for, developing and producing crude oil and natural gas. This section describes the risks and
other matters that would be most likely to influence an investor's decision to purchase securities of Talisman.

Ability to Find, Develop or Acquire Additional Reserves

The Company's future success depends largely on its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Exploration and
development drilling may not result in commercially productive reserves. Successful acquisitions require an assessment of a number of factors, many of which are uncertain. These factors include
recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently
uncertain.

Operational Hazards and Responsibilities

Oil and gas drilling and producing operations are subject to many risks, including the possibility of fire, explosions, mechanical failure, pipe failure, chemical spills,
accidental flows of oil, natural gas or well fluids, sour gas releases, storms or other adverse weather conditions and other occurrences or accidents, which could result in personal injury or loss of
life, damage or destruction of properties, environmental damage, interruption of business, regulatory investigations and penalties and liability to third parties. The Company has developed a
comprehensive HSE management framework to mitigate physical risks. The Company also mitigates insurable risks to protect against significant losses by maintaining a comprehensive insurance program,
while maintaining levels and amounts of risk within the Company that management believes to be acceptable. Talisman believes its liability, property and business interruption insurance is appropriate
to its business and consistent with common industry practice, although such insurance will not provide coverage in all circumstances.

Project Completion Risks

Talisman manages a variety of projects, including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay
expected revenues and project cost overruns could make projects uneconomic. Talisman's ability to complete projects depends upon numerous factors beyond the Company's control. These factors include
the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of drilling and other equipment; the ability to access lands; weather; unexpected cost
increases; accidents; the availability of skilled labour, including engineering and project planning personnel; and regulatory matters. The significant rate of inflation in the cost of materials and
services over the last two years has become a major factor affecting project economics and project planning.

Uncertainty of Reserves Estimates

The process of estimating oil and gas reserves is complex and involves a significant number of decisions and assumptions in evaluating available geological, geophysical,
engineering and economic data; therefore, reserves estimates are inherently uncertain. Talisman prepares all of its reserves information internally. The Company may adjust estimates of proved reserves
based on production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond the Company's control. In addition, there are
numerous uncertainties in forecasting the amounts and timing of future production, costs, expenses and the results of exploration and development projects. All estimates are, to some degree, uncertain
and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable
to any particular group of properties, the classification of such reserves based on risk of recovery and the standardized measure of discounted future net cash flows prepared by different engineers or
by the same engineers at different times, may vary substantially. Talisman's actual production, taxes and development and operating expenditures with respect to its reserves will likely vary from such
estimates and such variances could be material.

Talisman Energy 2006 Annual Financial Report   27

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Estimates
with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reservoirs, rather than upon
actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production
history will result in variations, which may be material, in the estimated reserves.

Political Risks

The Company's operations may be adversely affected by changes in governmental policies and legislation or social instability or other political or economic developments, which
are not within the control of Talisman, including, among other things, a change in crude oil or natural gas pricing
policy, the risks of war, terrorism, abduction, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, taxation policies, economic sanctions, the
imposition of specific drilling obligations, the development and abandonment of fields, fluctuating exchange rates and currency controls. With recent record commodity prices, there is a corresponding
re-emergence of nationalization or expropriation in increased taxation risk in many countries. In addition, both Indonesia and Algeria are members of the Organization of Petroleum
Exporting Countries (OPEC). Talisman's operations in these countries may, therefore, be impacted by the application of OPEC quotas. Various countries in which the Company is active, including
Indonesia, Algeria, Colombia and Peru, have been subject to recent economic or political instability and social unrest, military or rebel hostilities. In addition, Talisman regularly evaluates
opportunities worldwide and may, in the future, engage in projects or acquire properties in other nations that are experiencing economic or political instability and social unrest, or military
hostilities or are subject to United Nations or US sanctions. Some of the foregoing government actions may lead to political or reputational pressures on the Company from non-governmental
organizations, home governments and investors.

Volatility of Oil and Natural Gas Prices

Talisman's financial performance is highly sensitive to prevailing prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have a material
adverse effect on the Company's operations and financial condition, the value of its oil and natural gas reserves and its level of spending for oil and gas exploration and development. Prices for
crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are largely beyond the
Company's control. Oil prices are determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, world economic conditions, government regulation,
political stability in the Middle East and elsewhere, the availability of alternative fuel sources and weather conditions. Most natural gas prices realized by Talisman are affected primarily by North
American supply and demand, weather conditions and by prices of alternative sources of energy. The development of oil and natural gas discoveries in offshore areas is particularly dependent on the
outlook for oil and natural gas prices because of the large amount of capital expenditure required for development prior to commencing production.

A
substantial and extended decline in the prices of crude oil or natural gas could result in delay or cancellation of drilling, development or construction programs, or curtailment in production or
result in unutilized long-term transportation commitments, all of which could have a material adverse impact on the Company. The amount of cost oil required to recover Talisman's
investment and costs in various PSCs is dependent on commodity prices, with higher commodity prices resulting in a lower amount of net after royalty oil and gas reserves booked by the Company.

Litigation

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation, including the litigation discussed
below, may be material or may be indeterminate and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While Talisman assesses the merits
of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not
currently expected to have a material impact on the Company's financial position.

On
September 12, 2006, the United States District Court for the Southern District of New York (the Court) granted Talisman's Motion for Summary Judgment, dismissing the
lawsuit brought against Talisman by the Presbyterian Church of Sudan and others under the Alien Tort Claims Act. The lawsuit alleged that the Company conspired with, or aided and abetted, the
Government of Sudan to commit violations of international law in connection with the Company's now disposed of interest in oil operations in Sudan. The plaintiffs have twice attempted to certify the
lawsuit as a class action. In March 2005 and in September 2005, the Court rejected the plaintiffs' effort to certify two different classes (or groups) of plaintiffs. On
July 19, 2006, the Second Circuit Court of Appeals denied the plaintiffs' request to appeal the Court's refusal to certify the lawsuit as a class action. The plaintiffs have appealed the
Court's decision granting Talisman's Motion for Summary Judgment and all prior rulings to the Second Circuit Court of Appeals. Talisman believes the lawsuit is entirely without merit and will continue
to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Environmental Risks

All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of laws and regulations in the countries in which Talisman does
business. These regulatory regimes are laws of general application that apply to the Company's business in the same manner as they apply to other companies or enterprises in the energy industry.
Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of
hazardous substances and waste, and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that pipelines, wells, facility
sites and other properties associated with Talisman's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Certain types of operations,
including exploration and development projects, may require the submission and approval of environmental impact assessments or permit applications. In some cases, exploration and development
activities may be precluded or

28   Talisman Energy 2006 Annual Financial Report

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restricted
due to designation of areas as environmentally sensitive areas. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental
legislation may result in the imposition of fines and penalties and liability for cleanup costs and damages. Additionally, the Company's business is subject to the trend toward increased civil
liability for environmental matters. Although Talisman currently believes that the costs of complying with environmental legislation and dealing with environmental civil liabilities will not have a
material adverse effect on the Company's financial condition or results of operations, there can be no assurance that such costs in the future will not have such an effect. Talisman expects to incur
site restoration costs over a prolonged period as existing fields are depleted. The Company provides for future abandonment and reclamation costs in its annual Consolidated Financial Statements in
accordance with Canadian GAAP. Additional information regarding future abandonment and reclamation costs is set forth in the notes to the annual Consolidated Financial Statements.

In
1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol (the Protocol). The Protocol came into force on
February 16, 2005 and requires certain nations to reduce their emissions of carbon dioxide and other greenhouse gases. Under the terms of the Protocol, Canada will be required to reduce its
greenhouse gas (GHG) emissions to 6% below 1990 levels over the period beginning in 2008 and ending in 2012. Currently, Canadian oil and gas producers are in discussions with the provincial and
federal levels of government regarding implementation mechanisms for the industry. It is premature to predict what impact the Protocol could have on Canadian oil and gas producers
(and specifically, if and in what manner it will be implemented) but it is likely that any mandated reduction in GHG emissions will result in increased costs.

The
UK has also ratified the Protocol, with a reduction commitment of 12.5% below 1990 levels by 2008 to 2012. Talisman's UK installations are currently participating in the first phase of the
European Union Emission Trading Scheme (EU ETS), which runs from 2005 to 2007, inclusive. Direct costs associated with this participation have been negligible. Phase 2 of the EU ETS runs
from 2008 to 2012, inclusive. The UK government submitted its National Allocation Plan (NAP) for Phase 2 of the EU ETS to the European Commission in August 2006. The NAP specifies a cap
on carbon dioxide emissions for the covered sectors, the methods for allocating emission allowances to covered installations, and the number of emission allowances to be allocated to each covered
installation. Talisman expects that Phase 2 compliance costs will not be material; however, this will depend in part on future pricing in the EU and global carbon markets.

Dependence on Other Operators

Other companies operate some of the assets in which Talisman has interests. As a result, Talisman may have limited ability to exercise influence over operations of these assets
or their associated costs, which could adversely affect the Company's financial performance. The success and timing of Talisman's activities on assets operated by others will, therefore, depend on a
number of factors that may be outside of the Company's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other
participants, the selection of technology and the risk of management practices. For information on the percentages of assets which are operated/non-operated by Talisman, see Description of
the Business in the Company's Annual Information Form.

Differences in Ownership Interests in Foreign Operations

In Canada and the US, the state or private landowners own oil and gas rights and lease those rights to corporations who are responsible for the development of such rights within
the time frames described in the leases. This practice differs distinctly in some foreign countries in which Talisman does or may do business in the future. In those countries, the state often grants
interests in large tracts of lands or offshore fields and maintains control over the development of the oil and gas rights, in some cases through equity participation in the exploration and
development of the rights. This usually includes the imposition of obligations on Talisman to complete minimum work within specified time frames. Transfers of interests typically require state
approval, which may delay or otherwise impede transfers. In addition, if a dispute arises in Talisman's foreign operations, the Company may be subject to the exclusive jurisdiction of foreign
arbitration tribunals or foreign courts.

Competition

The petroleum industry is highly competitive. Specific disclosure regarding competition is disclosed under the heading Competitive Conditions in this MD&A.

Exchange Rate Fluctuations

Talisman's consolidated financial statements are presented in C$. Results of operations are affected primarily by the exchange rates between the C$, the US$, UK£ and
Norwegian kroner. These exchange rates have varied substantially in the last five years. Most of the Company's revenue is received in or is referenced to US$ denominated prices, while the majority of
Talisman's expenditures are denominated in C$, US$, UK£ and Norwegian kroner. A change in the relative value of the C$ against the US$ or the UK£ would also result in an
increase or decrease in Talisman's US$ or UK£ denominated debt, as expressed in C$ and the related interest expense. Talisman is also exposed to fluctuations in other foreign currencies.

Hedging Programs

Talisman monitors the Company's exposure to variations in commodity prices, interest rates and foreign exchange rates, and in response to these, puts in place hedging contracts
from time to time. The Company may in the future find it appropriate to enter into additional derivative financial instruments and physical delivery contracts to reduce such exposure. The terms of
these instruments or contracts may limit the benefit of commodity price increases and changes in interest rates and currency value, which are otherwise favourable to Talisman and may result in
financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with the contracts.

Talisman Energy 2006 Annual Financial Report   29

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Dependence on Management and Other Personnel

The success of Talisman is dependent upon its management and the quality of its personnel. Failure to retain current employees or to attract and retain new employees with the
necessary skills could have a materially adverse effect on Talisman's growth and profitability. Numerous competing large-scale oil and gas development projects have significantly increased the demand
for industry-specific personnel. In addition, a significant percentage of the workforce will be eligible for retirement in the next few years.

Disclosure Controls and Procedures

At the end of the period covered by this MD&A, an evaluation was carried out under the supervision of, and with the participation of, the Company's management, including the
Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operations of the Company's disclosure controls and procedures. Based on that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed
by the Company in reports that it files with or submits to the Canadian securities administrators is recorded, processed, summarized and reported within the time periods required.

It
should be noted that, while the Company's Chief Executive Officer and Chief Financial Officer believe the Company's disclosure controls and procedures provide a reasonable level of assurance that
they are effective, they do not expect that the Company's disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter
how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Advisories

Forward-Looking Statements

This MD&A contains statements that constitute forward-looking statements or forward-looking information (collectively, forward-looking statements) within the meaning of
applicable securities legislation. Forward-looking statements are included throughout this MD&A, including, among other places, under the headings 2007 Outlook Summary, Outlook for 2007, 2007
Geographic Outlook, Approximate Impact in 2007 and Risk Factors. These statements include, among others, statements regarding:



Statements
concerning oil and gas reserves contained in this MD&A may be deemed to be forward-looking statements as they involve the implied assessment that the resources described can be profitably
produced in the future, based on certain estimates and assumptions. Often, but not always, forward-looking statements use words or phrases such as 'expects', 'does not expect' or 'is expected',
'anticipates' or 'does not anticipate', 'plans' or 'planned', 'estimates' or 'estimated', 'projects' or 'projected', 'forecasts' or 'forecasted', 'believes', 'intends', 'likely', 'possible',
'probable', 'scheduled', 'positioned', 'goal', 'objective' or state that certain actions, events or results 'may', 'could', 'would', 'might' or 'will' be taken, occur or be achieved.

Various
assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking statements throughout this MD&A. Statements that discuss business
plans for drilling, exploration and development in 2007 assume that the extraction of crude oil, natural gas and natural gas liquids remains economic. For the purposes of preparing this MD&A, Talisman
assumed a US$65/bbl WTI oil price, a US$7.50/mmbtu NYMEX natural gas price, a US$/C$ exchange rate of $0.90 and a C$/UK£ exchange rate of $2.05 in 2007.

This
MD&A also discusses cash provided by operating activities for 2007. The material assumptions used in determining estimates of cash provided by operating activities are the anticipated production
volumes described in the 2007 Outlook Summary, Outlook for 2007, 2007 Geographic Outlook and Risk Factors sections of this MD&A; estimates of realized sales prices, which are, in turn, driven by
benchmark prices, quality differentials and the impact of exchange rates; estimated royalty rates; estimated operating expenses; estimated transportation expenses; estimated general and administrative
expenses; estimated interest expense, including the level of capitalized interest; anticipated cash payments made by the Company upon surrender of outstanding stock options using the cash payment
feature, which, in turn, are dependent on the trading level of the Company's common shares and the number of stock options surrendered or exercised; and the anticipated amount of cash income tax
and PRT.

30   Talisman Energy 2006 Annual Financial Report

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Forecast
production volumes are based on the midpoint of the estimated production range. Statements regarding estimated future production and production growth, as well as estimated financial results
that are derived from or depend upon future production estimates (such as cash provided by operating activities), incorporate the estimated impact of the sale of the Company's indirect Syncrude
interest which was completed on January 2, 2007, the anticipated completion of the UK Brae asset sale and the non-core asset disposition program in Canada. The completion of any contemplated
asset dispositions is contingent on various factors, including favourable market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approvals for
such dispositions. The amount of taxes and cash payments made upon surrender of existing stock options is inherently difficult to predict.

Forward-looking
statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from
those anticipated by Talisman and described in the forward-looking statements. These risk factors include:



We
caution that the foregoing list of risks and uncertainties is not exhaustive. Additional information on these and other factors that could affect the Company's operations or financial results are
included: (1) under the heading Risk Factors in the Company's Annual Information Form; and (2) under the heading Risks Factors and elsewhere in this MD&A. Additional information
may also be found in the Company's other reports on file with Canadian securities regulatory authorities and the US Securities and Exchange Commission (SEC). Forward-looking statements are based on
the estimates and opinions of the Company's management at the time the statements are made. The Company assumes no obligation to update forward-looking statements should circumstances or management's
estimates or opinions change, except as required by law.

Reserves Data and Other Oil and Gas Information

Talisman's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities,
which permits Talisman to provide disclosure in accordance with US disclosure requirements. The information provided by Talisman may differ from the corresponding information prepared in accordance
with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). Talisman's proved reserves have been calculated using the standards contained in
Regulation S-X of the SEC. US practice is to disclose net proved reserves after deduction of estimated royalty burdens, including net profits interests. Talisman makes additional
voluntary disclosure of gross proved reserves. Probable reserves, which Talisman also voluntary discloses, have been calculated using the definition for probable reserves set out by the Society of
Petroleum Engineers/World Petroleum Congress. The SEC normally permits oil and gas companies to disclose in their filings with the SEC only proved reserves that have been demonstrated by actual
production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Accordingly, any probable reserves and the calculations with
respect thereto included herein do not meet the SEC's standards for inclusion in documents filed with the SEC. Talisman's estimates of proved reserves and probable reserves are based on the same
assumptions. Further information on the differences between the US requirements and the NI 51-101 requirements is set forth under the heading Note Regarding Reserves Data and
Other Oil and Gas Information in Talisman's Annual Information Form.

The
exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data in this MD&A reflects Talisman's estimates of its reserves. While Talisman annually
obtains an independent audit of a portion of its reserves, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this MD&A.

Talisman Energy 2006 Annual Financial Report   31

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