Exhibit 99.6     MANAGEMENTS DISCUSSION AND
ANALYSIS   March 13, 2006


Managements Discussion and Analysis March 13, 2006  HIGHLIGHTS  (millions of Canadian dollars unless otherwise stated)
  
  2005
  
  2004
  
  2003Net income (1)
  
  1,561
  
  654
  
  976Dividends
  
  125
  
  114
  
  90Per share (Canadian dollars)Net income (1)
  
  4.24
  
  1.71
  
  2.53Dividends
  
  0.34
  
  0.30
  
  0.23Production (mboe/d)
  
  470
  
  438
  
  398Production per share (boe/share)
  
  0.47
  
  0.42
  
  0.38Average sales price ($/boe)
  
  56.67
  
  42.75
  
  38.51Gross sales
  
  9,554
  
  6,874
  
  5,610Operating costs ($/boe)
  
  8.41
  
  7.26
  
  6.98DD&A, exploration and dry hole expense
  
  2,359
  
  2,199
  
  1,899Cash provided by operating activities (1)
  
  4,871
  
  3,119
  
  2.554Exploration and development spending
  
  3,179
  
  2,538
  
  2,180Total assets
  
  18,339
  
  12,408
  
  11,780Total long-term debt (1)
  
  4,263
  
  2,457
  
  2,595Proved reserves additions (before
  acquisitions and divestitures) (mmboe)
  
  203
  
  265
  
  143Proved reserves (mmboe)
  
  1,639
  
  1,488
  
  1,362Reserves replacement ratio (2)
  
  120
  %
  166
  %
  99
  %  
 (1)Effective January 1, 2005 the Company retroactively adopted certain
changes to the Canadian Institute of Chartered Accountants (CICA) accounting
standard for financial instruments. These changes to this standard require that
the Companys preferred securities, all of which were redeemed in 2004, be
treated as debt rather than equity. Prior years amounts have been restated
accordingly. See note 2 to the Consolidated Financial Statements. (2)See the MD&A section entitled Reserves Replacement for method of
calculation.  This Managements Discussion
and Analysis (MD&A) dated March 13, 2006, 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. A summary of
the differences between accounting principles generally accepted in Canada
(Canadian GAAP) and those generally accepted in the United States (US GAAP) is
contained in note 21 to the Consolidated Financial Statements.  Talisman follows the
successful efforts method to account for oil and gas exploration and
development costs, as described in the Application of Critical Accounting
Policies and the Use of Estimates section of this MD&A. The alternative
method of accounting for oil and gas exploration and development costs is the
full cost method. 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.  Unless otherwise stated,
references to production and reserves represent Talismans working interest
share (including 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 for one barrel 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 unless otherwise indicated. All comparative percentages are between the
years ended December 31, 2005 and December 31, 2004, unless stated otherwise.  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, 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 EDGAR database at www.sec.gov.  2


Talismans Performance Highlights in 2005  In 2005, production averaged a record 470 mboe/d (7% higher than 2004),
with the Company exiting the year producing 543 mboe/d in December. Net income
for the year was a record $1.6 billion ($4.24/share), 139% higher than 2004. In
2005, the increase in net income was due to higher oil and natural gas prices,
increased production and decreases in both hedging losses and dry hole
expenses, partially offset by the impact of the stronger Canadian dollar in
relation to its US counterpart and increases in royalties, operating expenses,
DD&A, stock-based compensation and taxes.  During 2005, nine million shares were repurchased at an average price
of $39.01/share, long term debt increased to $4.26 billion with the acquisition
of Paladin Resources plc (now Paladin Resources Limited and referred to as Paladin)
and the Company increased its semi-annual dividend rate by 13.3% to
$0.17/share.  The consolidation of the Paladin assets occurred on November 18, 2005,
producing approximately 45 mboe/d from that date forward. The acquisition was
completed in January 2006.  Operational highlights for the year included the completion of the
offshore South Angsi oilfield development in Block PM 305 in Malaysia, the
exploration discoveries near the Ross and Balmoral fields in the North Sea,
ongoing development of the Tweedsmuir fields and drilling successes in the northern
Alberta Foothills.  In 2005, production per share increased 11% over the previous year.
Talisman spent $3.2 billion on exploration and development activities and
participated in drilling 722 successful wells in 2005. During 2004 and 2003,
production averaged 438 mboe/d and 398 mboe/d, respectively. Excluding Sudan
operations, production averaged 385 mboe/d in 2003.  In 2005, Talisman added 203 mmboe of proved reserves, before
acquisitions and dispositions, replacing 120% of production. Including
acquisition and disposition activity, the Company added 320 mmboe of proved
reserves, replacing 189% of production.  2006 OUTLOOK SUMMARY  Talisman anticipates 2006 production growth of approximately 10  16%.
Additional discussion of managements estimates and assumptions for 2006 can be
found in the MD&A section entitled Outlook for 2006.  Production
is expected to average 515,000  545,000 boe/d, prior to planned acquisitions
or dispositions.  Production
increases are expected in most of the Companys geographic segments with the
majority coming from international projects.  Exploration
and development spending is expected to be $4.4 billion (including $2 billion
in North America and $1.6 billion in the North Sea).  The
Tweedsmuir and Tweedsmuir South fields in the UK sector of the North Sea are
expected to start production towards the end of the first quarter of 2007
(adding approximately 45,000 boe/d from that point forward).  Long-term
debt is expected to decrease to approximately $3.6  $4 billion through the
application of excess cash from operating activities.  2005 VARIANCES  Net Income  (millions of dollars)2004 Net income (1)
  
  654Favourable (unfavourable)Cash items varianceOil and liquids volumes
  
  243Oil and liquids prices
  
  1,800Oil and liquids foreign exchange price
  impact
  
  (426
  )Natural gas volumes
  
  134Natural gas prices
  
  1,223Natural gas foreign exchange price impact
  
  (294
  )Hedging  Commodities
  
  403Royalties
  
  (471
  )Other revenue
  
  80Operating expense
  
  (261
  )Transportation expense
  
  (14
  )Interest expense
  
  7Current taxes (including Petroleum Revenue
  Tax)
  
  (605
  )General and administrative
  
  (18
  )Stock-based compensation payments
  
  (71
  )Other
  
  26Total cash items variance
  
  1,756Non-cash itemsDepreciation, depletion and amortization
  expense
  
  (193
  )Dry hole expense
  
  70Exploration expense
  
  (37
  )Future taxes (including Petroleum Revenue
  Tax)
  
  (322
  )Stock-based compensation (non-cash)
  
  (391
  )Other
  
  24Total non-cash items variance
  
  (849
  )2005 Net income
  
  1,561  
 (1)Effective January 1, 2005, the Company retroactively adopted certain
changes to the CICA accounting standard for financial instruments. These
changes to this standard require that the Companys preferred securities, all
of which were redeemed in 2004, be treated as debt rather than equity. Prior
years amounts have been restated accordingly. See note 2 to the Consolidated
Financial Statements.  The significant variances from 2004 as summarized in the net income
variance table are:  Higher
commodity prices and increased production more than offset the impact of the
strengthening Canadian dollar and higher royalties.  Reduced
hedging losses, as a result of reduced hedging activity, in spite of increased
commodity prices.  Operating
expense increased with a change in the production mix, additional volumes,
maintenance and well workovers.  3


Current
taxes rose as a result of increased commodity prices and higher production and
a greater proportion of taxable income in higher tax jurisdictions.  Cash
stock-based compensation payments increased by $71 million.  Depreciation,
depletion and amortization (DD&A) expense increased $193 million largely
due to higher worldwide production and increased costs in North America.  The
non-cash portion of the stock-based compensation expense increased by $391
million (before tax) due to a 90% increase in Talismans share price.  CORPORATE RESULTS REVIEW  Revenue  Revenues from oil, liquids and natural gas sales in 2005 were $9.6
billion, up 39% over last year, due to higher oil and liquids prices ($1,374
million), natural gas prices ($929 million), oil and liquids volumes ($243
million) and natural gas volumes ($134 million). As a result of decreased
hedging activity, hedging losses in 2005 were $403 million less than in 2004.  Daily Production Volumes  2005
  
  2004
  
  2003Oil and liquids (mbbls/d)North America
  
  56.3
  
  57.4
  
  59.6North Sea (1)
  
  132.7
  
  121.9
  
  113.1Southeast Asia and Australia (1)
  
  35.5
  
  35.6
  
  24.4North Africa (1)
  
  15.4
  
  13.5
  
  6.6Trinidad and Tobago (1)
  
  10.1
  
  
  
  Sudan
  
  
  
  
  
  13.0250.0
  
  228.4
  
  216.7Natural gas (mmcf/d)North America
  
  915
  
  885
  
  864North Sea (2)
  
  120
  
  114
  
  109Southeast Asia and Australia
  
  284
  
  260
  
  1171,319
  
  1,259
  
  1,090Total (mboe/d at 6:1)
  
  470
  
  438
  
  398Production per share (boe/share)
  
  0.47
  
  0.42
  
  0.38  
 (1)Includes unlifted oil volumes as at December 31, 2005 of 3,670 bbls/d,
1,004 bbls/d, 650 bbls/d and 175 bbls/d in the North Sea, Southeast Asia and
Australia, North Africa and Trinidad and Tobago, respectively. (2)Includes gas acquired for injection and subsequent resale of 15 mmcf/d,
5 mmcf/d and 7 mmcf/d in 2005, 2004 and 2003, respectively.  Production  In 2005, production averaged a record 470 mboe/d, a 7% increase over
last years average of 438 mboe/d. Production per share increased by 11%.
Production in 2003, excluding Sudan, was 385 mboe/d.  Natural gas production in North America averaged 915 mmcf/d, an
increase of 30 mmcf/d over 2004. This 3% production growth reflects Talismans
drilling success. In 2005, 685 wells were drilled with a 97% success rate.  Significant production increases were recorded in Monkman, up 33 mmcf/d
to 104 mmcf/d, Bigstone/Wild River, up 15 mmcf/d to 109 mmcf/d and Appalachia,
which averaged 105 mmcf/d, up 16 mmcf/d. North America oil and liquids average
production was 56,304 bbls/d during the year, down 2% from 2004 due to decline
rates and the Companys continued focus on natural gas.  Oil and liquids production in the North Sea in 2005 averaged 132,716
bbls/d, a 9% increase over 2004. During the fourth quarter of 2005, the Company
acquired the Paladin assets, which added 4,082 boe/d for the full year 2005 and
exploration assets including those in the UK Central North Sea and Norway. The
Company also acquired a 70% interest in the Varg field producing assets in
Norway, as well as additional exploration acreage.Talisman drilled 28
successful oil and gas wells, including successful programs at Clyde, Claymore,
Tartan, Gyda and Varg. During the fourth quarter, production averaged 159,918
bbls/d, up 29% over the third quarter. North Sea natural gas production
increased 6% to 120 mmcf/d. Production averaged 198mboe/d during December.  Southeast Asia and Australia produced 35,476 bbls/d of oil and liquids
in 2005, relatively unchanged from 2004. During December, the average was
54,954 bbls/d. The Paladin acquisition added the SE Sumatra and the Offshore NW
Java Blocks in Indonesia, which together averaged 5,326 bbls/d in December, and
Australia properties, which averaged 5,846 bbls/d in the same month. Total
production for the year in Malaysia/Vietnam increased to 28,000 bbls/d from
22,388 bbls/d the previous year. The South Angsi PM-305 field came onstream in
mid-August of 2005, averaging 6,472 bbls/d for the year and 17,244 bbls/d in
December. Indonesia oil and liquids production averaged 6,790 bbls/d, down 49%
from 2004, due to the expiry of the Tanjung and Jambi production sharing contracts
(PSCs). Australia averaged 686 bbls/d for the year.  Natural gas production in Southeast Asia and Australia increased 9% to
284 mmcf/d in 2005. In Malaysia/Vietnam, natural gas production from PM-3 CAA
was 107 mmcf/d in 2005, down 11% from the previous year due to commercial
constraints. Natural gas sales in Indonesia averaged 177 mmcf/d with higher
demand for Corridor gas from Caltex and Singapore Power.  North Africa oil production averaged 15,377 bbls/d in 2005, up 14% from
13,537 bbls/d in 2004, when operational issues reduced production at the
Greater MLN facilities in Algeria. The Paladin acquisition during the fourth
quarter added producing properties in Tunisia, which averaged 116 bbls/d for
the year. During the month of December, production averaged 17,207 bbls/d,
including 991 bbls/d from Tunisia.  Trinidad and Tobago averaged 10,111 bbls/d in 2005, with first oil in
January.  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. The continued growth of Talismans international operations, combined
with the rise in oil prices, has increased the value of unlifted oil volumes as
at December 31, 2005. Accordingly, the Company has changed its practice for
recording revenue. Unlifted oil volumes are now recorded as inventory, at cost.
Had this change not been initiated, net income in 2005 would have been $43
million higher, $21 million of which relates to prior years. These volumes have
been separately identified in footnote 1 to the Daily Production Volumes table
above.  4


Commodity
Prices (1)  2005
  
  2004
  
  2003Oil and liquids ($/bbl)North America
  
  52.62
  
  42.11
  
  35.78North Sea
  
  64.78
  
  48.29
  
  39.72Southeast Asia and Australia
  
  68.79
  
  51.29
  
  41.35North Africa
  
  66.71
  
  51.17
  
  39.01Trinidad and Tobago
  
  63.40
  
  
  
  Sudan
  
  
  
  
  
  43.8962.78
  
  47.45
  
  39.09Natural gas ($/mcf)North America
  
  9.05
  
  6.83
  
  6.58North Sea
  
  7.08
  
  5.55
  
  4.77Southeast Asia and Australia
  
  6.40
  
  4.74
  
  5.728.30
  
  6.28
  
  6.30Company $/boe (6 mcf:1 boe)
  
  56.67
  
  42.75
  
  38.51Hedging loss excluded from the above pricesOil and liquids ($/bbl)
  
  0.85
  
  5.42
  
  2.05Natural gas ($/mcf)
  
  
  
  0.07
  
  0.08Total $/boe (6mcf:1boe)
  
  0.46
  
  3.02
  
  1.34Benchmark pricesWTI (US$/bbl)
  
  56.70
  
  41.40
  
  30.99Dated Brent (US$/bbl)
  
  54.52
  
  38.22
  
  28.83NYMEX (US$/mmbtu)
  
  8.55
  
  6.09
  
  5.44AECO (C$/gj)
  
  8.04
  
  6.44
  
  6.35US$/C$ exchange rate
  
  0.83
  
  0.77
  
  0.71C$/Pound sterling exchange rate
  
  2.21
  
  2.38
  
  2.29  
 (1)Prices exclude gains or losses related to hedging activities and do not
include synthetic oil.  World oil prices continued to reach new record levels during 2005, with
WTI averaging US$56.70/bbl, up 37% over the 2004 WTI average of US$41.40/bbl.
North American natural gas prices increased 40% over 2004 with NYMEX gas prices
averaging US$8.55/mmbtu.  More than 90% of the Companys revenues are either received in US
dollars or are closely referenced to US dollars. The Company converts these
revenues to Canadian dollars for reporting purposes. The 7% strengthening of
the Canadian dollar against the US dollar reduced Talismans reported oil and
liquids price by $4.65/bbl to $62.78/bbl, a 32% increase over 2004, compared to
the 37% increase in WTI (from US$41.40 in 2004 to US$56.70 during 2005).
Talismans North America oil and liquids price averaged $52.62/bbl, up 25% from
last year. The Companys North Sea oil and liquids price averaged $64.78/bbl,
up 34% over 2004. The Companys Southeast Asia and Australia oil and liquids
price averaged $68.79/bbl, up 34% over 2004. The Companys North Africa oil
price averaged $66.71/bbl, up 30% over 2004, as the price was impacted by the
timing of production liftings.  Talismans average natural gas price in North America increased 33% to
$9.05/mcf. The strengthening of the Canadian dollar during 2005 reduced
Talismans reported North America natural gas price by $0.66/mcf. The Companys
North Sea natural gas price increased 28% to $7.08/mcf.  The Companys natural gas price in Southeast Asia and Australia
averaged $6.40/mcf, up 35% from 2004. Sales from Malaysia/Vietnam, where prices
are referenced to the Singapore fuel oil spot market, averaged $4.13/mcf in
2005. Gas production from Malaysia/Vietnam accounted for 38% of Southeast Asia
and Australia gas production during the year, down from 46% in 2004. A large
portion of Corridor gas production, representing approximately 59% of the
Companys 2005 gas sales in Southeast Asia and Australia, is exchanged for Duri
crude oil on an energy equivalence basis and is sold offshore with payment in
US dollars and averaged $8.11/mcf.  The Companys average sales prices are before a net oil hedging loss of
$77 million or $0.85/bbl ($0.46/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 2006 results can be found in the Outlook for 2006
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.  Royalties(1)  2005
  
  2004
  
  2003Rates (%)
  
  $millions
  
  Rates (%)
  
  $millions
  
  Rates (%)
  
  $millionsOil and
  liquidsNorth America
  
  21
  
  214
  
  20
  
  174
  
  21
  
  155North Sea
  
  1
  
  35
  
  1
  
  19
  
  
  
  (3
  )Southeast Asia and Australia
  
  40
  
  351
  
  41
  
  277
  
  39
  
  143North Africa
  
  39
  
  135
  
  38
  
  97
  
  49
  
  46Trinidad and Tobago
  
  15
  
  35
  
  
  
  
  
  
  
  Sudan
  
  
  
  
  
  
  
  
  
  46
  
  9714
  
  770
  
  14
  
  567
  
  14
  
  438Natural
  gasNorth America
  
  20
  
  602
  
  19
  
  425
  
  21
  
  432North Sea
  
  7
  
  21
  
  8
  
  18
  
  6
  
  11Southeast Asia and Australia
  
  30
  
  202
  
  25
  
  114
  
  5
  
  1321
  
  825
  
  19
  
  557
  
  18
  
  45617
  
  1,595
  
  16
  
  1,124
  
  16
  
  894  
 (1) Royalty
rates do not include synthetic oil.  5


The consolidated royalty expense in 2005 was $1,595 million (17%), an
increase of $471 million or 42% from $1,124 million (16%) in 2004, as a result
of higher commodity prices, increased volumes and rate increases in Southeast
Asia and Australia. The Companys oil and liquids royalty rate remained
constant at 14%, while the amount of royalties paid increased by 36% to $770
million. This increase is due primarily to a combination of higher prices,
production increases in Southeast Asia and Australia and North Africa, and
first oil production in Trinidad and Tobago. Natural gas royalties for 2005
increased 48% to $825 million due to increases in both volumes and rates in
North America and Southeast Asia and Australia.  In North America, natural gas royalties increased 42% to $602 million,
averaging 20%, up from 19% in 2004. This increase in expense reflects a 33%
increase in realized unit prices coupled with a 3% increase in production.  In Southeast Asia and Australia, the natural gas royalty rate was 30%,
up from 25% in 2004, as a result of the impact of the payout of cost recovery
pools at Corridor in 2004. Under the terms of the Corridor PSC, after the
Company has recovered its historical capital costs, the Government of Indonesia
increases its share of production, which results in a higher royalty rate.
Corridors natural gas royalty rate averaged 32% during 2005, compared to 29%
in the prior year. The Southeast Asia and Australia royalty rate was also impacted
by Malaysia/Vietnam volumes at a royalty rate of 24%. Under the terms of the
PSC in Malaysia, 60% of gas production is available for cost recovery. The
government receives 10% of production as royalty and the remaining 30% profit
gas is split 50% to the government and 50% to the working interest owners. This
results in a total royalty of 25%, which is combined with a 13% royalty rate in
Vietnam for a blended rate of 24%. This royalty rate is expected to continue
until the Malaysia gas cost pools are recovered in 2009, based on current
forecasts of production and prices.  Oil and liquids royalties in Southeast Asia and Australia averaged 40%
in 2005, compared to 41% in 2004. Total royalty expense increased 27% to $351
million as price increases, coupled with production increases in
Malaysia/Vietnam, more than offset the impact of production decreases in
Indonesia related to the expiry of the Jambi and Tanjung concessions.
Malaysia/Vietnam royalties are tied to production, price and cost levels and
reached 37% in 2005, up from 35% last year. Under the terms of the PSC in
Malaysia, 50% of oil production is available for cost recovery. The government
receives 10% of production as royalty and the remaining 40% profit oil is split
with 70% going to the government and 30% to the working interest owners. This
results in a royalty of 38%, which combined with an 18% royalty rate in Vietnam
results in a blended rate of 37%. This royalty rate will continue to increase
as the Malaysia oil cost pools are recovered. Based on current forecasts of
production and prices, the rate is expected to increase to approximately 41% in
2006 and to 48% in 2007.  In North Africa, the royalty expense increased by 39% to $135 million
as production increased 14% from last year, while the rate increased from 38%
last year to 39% in 2005.  Under the terms of the Algeria PSC, Talisman is subject to a total
government take of 51%, part of which is income tax, during the first five
years of production. During the first four years of production, Talisman
receives accelerated production entitlement. During the fifth year of the
agreement, any accelerated production entitlement received by Talisman during
the first four years in excess of 49% on a cumulative basis reverts to the
government. Accordingly, during the first four years of production, Talisman
records a deferred royalty expense and liability for any production entitlement
received in excess of 49%. During 2005, Talisman recorded a drawdown of
deferred Algerian royalties of $14 million, for a total of $18 million to date.
In both 2005 and 2004, total taxes and royalties combined to average a rate of
51%.  In the North Sea, royalties increased for both oil and gas due to
production and price increases as the rates remained relatively flat.  Operating Expenses and Unit Operating Costs  2005
  
  2004
  
  2003$/bbl
  
  $millions
  
  $/bbl
  
  $millions
  
  $/bbl
  
  $millionsOil and liquidsNorth America
  
  7.24
  
  142
  
  6.75
  
  135
  
  6.28
  
  131North Sea (1)
  
  17.14
  
  808
  
  14.06
  
  627
  
  12.05
  
  498Southeast Asia and Australia
  
  4.48
  
  56
  
  5.57
  
  73
  
  7.22
  
  64North Africa
  
  4.52
  
  24
  
  3.51
  
  17
  
  5.07
  
  12Trinidad and Tobago
  
  2.94
  
  11
  
  
  
  
  
  
  
  Sudan
  
  
  
  
  
  
  
  
  
  3.73
  
  1811.81
  
  1,041
  
  10.32
  
  852
  
  9.25
  
  723  $/mcf
  
  $millions
  
  $/mcf
  
  $millions
  
  $/mcf
  
  $millionsNatural gasNorth America
  
  0.90
  
  300
  
  0.79
  
  257
  
  0.75
  
  237North Sea
  
  0.82
  
  36
  
  0.55
  
  23
  
  0.37
  
  14Southeast Asia and Australia
  
  0.30
  
  31
  
  0.27
  
  25
  
  0.50
  
  220.76
  
  367
  
  0.66
  
  305
  
  0.69
  
  273Company ($/boe)
  
  8.41
  
  1,408
  
  7.26
  
  1,157
  
  6.98
  
  973Synthetic oil
  
  30.36
  
  30
  
  20.67
  
  23
  
  22.63
  
  22Pipeline
  
  
  
  21
  
  
  
  18
  
  
  
  21
  
  1,459
  
  
  
  1,198
  
  
  
  1,039  
 (1) During
2005, North Sea pipeline costs were reclassified to operating expenses. Prior
years have been restated accordingly.  6


Total operating expenses for the Company during 2005 were $1.5 billion,
22% higher than last year, with the North Sea accounting for almost 75% of the
$261 million year-over-year increase. On a per unit basis, oil and liquids
costs increased 14% to $11.81/bbl and natural gas costs averaged $0.76/mcf, a
15% increase from 2004.  North America oil and liquids operating costs increased 5% during 2005
with increases in maintenance and well workovers. On a per unit basis, costs
increased 7% to $7.24/bbl. Unit operating costs for natural gas increased 14%
to $0.90/mcf with higher third party processing fees, maintenance and well
workover costs partially offset by the lower unit operating costs ($0.23/mcf)
in Appalachia.  In 2005, North Sea operating expenses were up $194 million or 30% over
last year, due in part to acquisitions, partially offset by a 7% strengthening
in the Canadian dollar against the pound sterling. These acquisitions resulted
in increased operating expenses of $130 million. Unit operating costs averaged
$15.54/boe which reflects increased repairs and maintenance costs related to
unscheduled shutdowns at Ross/Blake, increased well workover costs, vessel
lease costs, fuel, chemical and insurance costs. Costs in Norway reflect higher
workover costs and the impact of acquired new production at Varg and Brage.  Southeast Asia and Australia unit operating costs decreased 13% to
$2.94/boe, as increased production of lower unit cost volumes from Corridor and
PM-305 in Malaysia replaced the higher unit cost volumes from the expired
concessions in Tanjung and Jambi. Oil and liquids unit costs averaged
$4.48/bbl, down 20% from the prior year. In Malaysia/Vietnam, unit costs
averaged $2.81/bbl, a 34% increase from 2004, due to new production volumes
from PM-305. Indonesia unit costs decreased 3%, to $11.12/bbl. Southeast Asia
and Australia natural gas unit costs averaged $0.30/mcf, 11% more than 2004. In
Indonesia, where gas sales represented 62% of the total for Southeast Asia and
Australia versus 54% in 2004, unit costs decreased from $0.38/mcf to $0.32/mcf
in 2005. Malaysia/Vietnam gas unit costs averaged $0.26/mcf as production for
2005 was 107 mmcf/d, down from 119 mmcf/d in 2004.  North Africa total operating costs in 2005 were $24 million, an
increase of $7 million over the previous year. Unit operating costs averaged
$4.52/bbl, up 29% from 2004 due to increased power and maintenance costs.  Trinidad and Tobago operating costs were $11 million or $2.94/bbl
during 2005, the first year of production.  Transportation Expenses  2005
  
  2004
  
  2003$/bbl
  
  $millions
  
  $/bbl
  
  $millions
  
  $/bbl
  
  $millionsOil and liquidsNorth America
  
  0.50
  
  10
  
  0.49
  
  10
  
  0.48
  
  10North Sea
  
  1.19
  
  57
  
  1.14
  
  51
  
  1.16
  
  48Southeast Asia and Australia
  
  0.09
  
  1
  
  0.23
  
  3
  
  0.41
  
  4North Africa
  
  1.65
  
  9
  
  1.76
  
  9
  
  1.77
  
  4$/mcf
  
  
  
  $/mcf
  
  
  
  $/mcfNatural gasNorth America
  
  0.19
  
  65
  
  0.20
  
  66
  
  0.21
  
  67North Sea
  
  0.50
  
  22
  
  0.35
  
  14
  
  0.37
  
  15Southeast Asia and Australia
  
  0.41
  
  42
  
  0.41
  
  39
  
  0.77
  
  33206
  
  
  
  192
  
  
  
  181  During 2005, transportation expenses
increased $14 million or 7% over 2004, primarily due to increased volumes and
new volumes acquired at Gyda and Brage in the North Sea, where transportation
expense averaged $1.49/mcf.  Depreciation,
Depletion and Amortization Expense (includes accretion of ARO)  2005
  
  2004
  
  2003$/boe
  
  $millions
  
  $/boe
  
  $millions
  
  $/boe
  
  $millionsNorth America
  
  12.42
  
  946
  
  10.47
  
  785
  
  9.26
  
  688North Sea
  
  12.23
  
  670
  
  12.83
  
  661
  
  12.85
  
  616Southeast Asia and Australia
  
  4.98
  
  144
  
  6.02
  
  174
  
  5.92
  
  95North Africa
  
  6.80
  
  36
  
  5.99
  
  30
  
  6.99
  
  17Trinidad and Tobago
  
  13.11
  
  47
  
  
  
  
  
  
  
  Sudan
  
  
  
  
  
  
  
  
  
  3.98
  
  1910.88
  
  1,843
  
  10.29
  
  1,650
  
  9.87
  
  1,435  7


The Companys 2005 DD&A expense increased $193 million or 12% to
$1.8billion, with a per unit rate of $10.88/boe. DD&A rates in North
America increased to $12.42/boe primarily due to higher drilling costs,
increased capital expenditures on infrastructure projects as well as increased
land amortization costs. The increase in rates combined with a 2% increase in
boe production resulted in a 21% increase in the total DD&A expense to $946
million. In the North Sea, total expense increased 1% to $670 million, as the
impact of an 8% increase in total boe production was partially offset by a
decrease in the DD&A rates due to 2004 reserve additions and a weaker pound
sterling relative to the Canadian dollar. Total DD&A expense for Southeast
Asia and Australia decreased by $30 million or 17% as increased reserves in
Malaysia/Vietnam and the expiry of the Tanjung concession lowered the per unit
rate to $4.98/boe. This 17% rate reduction more than offset the impact of the
5% increase in boe production. Total DD&A expense for North Africa
increased 20% to $36 million as a result of a 14% increase in production, which
included an increased proportion of production from the higher rate MLN fields.  For additional information relating to DD&A, refer to the MD&A
section entitled Application of Critical Accounting Policies and Use of
Estimates and to notes 5 and 6 to the Consolidated Financial Statements.  Dry Hole Expense  (millions of dollars)
  
  2005
  
  2004
  
  2003North America
  
  122
  
  128
  
  135North Sea
  
  53
  
  109
  
  69Southeast Asia and Australia
  
  11
  
  25
  
  9North Africa
  
  
  
  4
  
  1Trinidad and Tobago
  
  21
  
  12
  
  Other (1)
  
  34
  
  33
  
  37241
  
  311
  
  251  
 (1) In 2005, Other includes Colombia, Qatar and Peru.  During 2005, the Company incurred dry hole expenses of $241 million,
$70 million lower than last year. In North America, dry hole expense was $122
million. In the North Sea, a total of seven wells were expensed for a total of
$53 million. The Company also wrote off four wells in Malaysia/Vietnam, three
in Trinidad and Tobago and five 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, $450 million of costs relating to exploration wells were included in
non-depleted capital and not subject to DD&A pending final determination.
The majority of the related wells were drilled in 2005, (2004  $284 million;
2003  $283 million).  Exploration Expense  (millions of dollars)
  
  2005
  
  2004
  
  2003North America
  
  128
  
  123
  
  87North Sea
  
  53
  
  28
  
  21Southeast Asia and Australia
  
  40
  
  20
  
  17Trinidad and Tobago
  
  5
  
  21
  
  35Other (1)
  
  49
  
  46
  
  53275
  
  238
  
  213  
 (1) In 2005, Other includes Colombia, Peru, Qatar and Alaska.  Exploration expense consists of geological and geophysical costs,
seismic, land lease rentals and indirect exploration expenses. These costs are
expensed as incurred under the successful efforts method of accounting. The
majority of the $37 million increase to $275 million relates to increased
exploration activity in the North Sea, particularly in Norway, and in Southeast
Asia and Australia.  Corporate and Other  (millions of dollars)
  
  2005
  
  2004(1)
  
  2003(1)G & A expense
  
  201
  
  183
  
  152Interest expense
  
  166
  
  173
  
  178Capitalized interest
  
  19
  
  13
  
  24Stock-based compensation
  
  633
  
  171
  
  185Other revenue
  
  165
  
  85
  
  76Other expense
  
  39
  
  89
  
  16  
 (1)Effective January 1, 2005, the Company retroactively adopted certain
changes to the CICA accounting standard for financial instruments. These
changes to this standard require that the Companys preferred securities, all
of which were redeemed in 2004, be treated as debt rather than equity. See note
2 to the Consolidated Financial Statements.  General and administrative (G&A) expense increased due to
additional personnel, salary increases and administrative costs. On a unit
basis, G&A was $1.17/boe (2004  $1.14/boe; 2003  $1.05/boe).  The sum of interest on long-term debt and capitalized interest remained
relatively flat at $185 million during 2005. Interest capitalized in 2005 is
associated with the Tweedsmuir development project in the North Sea, which is
scheduled to come on production towards the end of the first quarter of 2007.  Other revenue includes pipeline and custom treating revenues of $141
million for 2005, compared to $73 million in 2004. Pipeline revenues in the
North Sea increased $61 million due to higher sales of volumes acquired for
injection and subsequent resale. Other expense during 2005 included property
impairments in the North Sea of $31 million, the majority of which was
associated with the North Saltire Property.  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, 2005.
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. As a result of record high share prices throughout the year, $633
million was expensed in 2005, of which $480 million was non-cash and $153
million cash. Over the course of the year, the average exercise price of all
outstanding options increased from $19.58 per share to $26.14 per share, with a
total of 21.5 million options outstanding at December 31, 2005. See note 8 to
the Consolidated Financial Statements.  The Companys stock option plans were amended during 2003 to 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 Companys share price
approximately 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.  8


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 recoveries 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 tax rate for 2005, after deducting Petroleum
Revenue Tax (PRT), was 44% compared to 36% in 2004 and 15% in 2003. A number of
events in the past three years have affected the Companys effective tax rates,
including the recent acquisitions of producing assets in Norway, tax rate
reductions in Canada and the sale of the Companys indirectly held interest in
the Greater Nile Oil Project in Sudan in 2003.  Effective Income Tax Rate  (millions of dollars)
  
  2005
  
  2004(1)
  
  2003(1)Income before tax
  
  2,984
  
  1,150
  
  1,244Less PRTCurrent
  
  150
  
  124
  
  72Future
  
  39
  
  5
  
  20189
  
  129
  
  922,795
  
  1,021
  
  1,152Income tax expense/(recovery)Current
  
  1,058
  
  478
  
  229Future
  
  176
  
  (111
  )
  (53
  )1,234
  
  367
  
  176Effective income tax rate (%)
  
  44
  
  36
  
  15  
 (1)Effective January 1, 2005, the Company retroactively adopted certain
changes to the CICA accounting standard for financial instruments. These
changes to this standard require that the Companys preferred securities, all
of which were redeemed in 2004, be treated as debt rather than equity. See note
2 to the Consolidated Financial Statements.  In 2005, future tax expense increased $287 million, to $176 million. In
2004, the Company recorded a future tax recovery of $50 million due to a
reduction in Canadian federal and provincial tax rates, compared to a $160
million recovery of future taxes in 2003 for both Canadian rates.  A normalized effective tax rate after removing the impact of the
Canadian tax rate changes, the tax on unrealized foreign exchange gains on
foreign denominated debt and the impact of the gain on disposal of the Sudan
operations would have been 42% in 2005, 38% in 2004 and 36% in 2003. The
increase in the 2005 effective tax rate results in part from a higher
proportion of income from jurisdictions with higher tax rates, e.g. Norway.
Foreign exchange rate fluctuations over the past two years have resulted in
taxes on gains related to inter-company loans and non-Canadian dollar
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 increased to $1,058 million in 2005, due
primarily to higher commodity prices and volumes, which resulted in increases
in current taxes of $222 million in Norway, $157 million in Southeast Asia and
Australia, $67 million in the UK, $53 million in North America and $14 million
in North Africa. In Trinidad and Tobago, production first came onstream during
2005 and current income tax expense was $64 million.  In December 2005, the UK government announced an income tax rate
increase on petroleum profits from 40% to 50%, which the Company expects to be
enacted during the second quarter of 2006 resulting in a one time non-cash catch-up
expense estimated to be approximately $300 million.  The UK government levies PRT on North Sea fields, which 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 other countries, where $14 million was
recorded during 2005.  Capital Spending(1), (3)  (millions of dollars)
  
  2005
  
  2004
  
  2003North America
  
  1,763
  
  1,500
  
  1,580North Sea
  
  1,392
  
  721
  
  693Southeast Asia and Australia
  
  305
  
  235
  
  316North Africa
  
  27
  
  8
  
  34Trinidad and Tobago
  
  72
  
  191
  
  130Other (2)
  
  134
  
  125
  
  95Corporate, IS and Administrative
  
  28
  
  26
  
  383,721
  
  2,806
  
  2,886  
 (1)Includes expenditures for exploration, development and asset
acquisitions net of dispositions, but excludes corporate acquisitions and the
Sudan disposition in 2003. (2)In 2005, Other includes Colombia, Peru, Qatar and Alaska. (3)Includes interest costs, which are capitalized on major development
projects until facilities are completed and ready for use.  Natural gas continues to be the focus of the Companys capital
investment activities in North America, supplemented by low risk oil projects.
Of the $1.8 billion of capital spending in North America, $658 million related
to exploration activities and development accounted for $951 million. The
Company participated in 495 gas wells and 171 oil wells in North America and
had a success rate of 97%. 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. In addition, the Company spent $154 million on property acquisitions,
net of dispositions.  Total capital spending in the North Sea was $1.4 billion including $165
million for exploration, $867 million for development and $360 million for net
property acquisitions. Development activity included the ongoing development of
the Tweedsmuir project and drilling and recompletion activity within the Clyde,
Tartan, Piper and Claymore fields. In addition, development expenditures were
incurred in Norway on the Gyda and Varg fields. A total of 25 successful
development wells were drilled during 2005 in the North Sea. Also, a total of
three exploration wells were drilled including the 13/23b-5 well, adjacent to
the Ross and Blake fields. During 2005, the Company completed a number of
acquisitions, the most significant of which were Varg, Andrew and Brage. The
corporate acquisition of Paladin during the fourth quarter of 2005 added
producing assets in the UK, Norway and Denmark, as well as exploration acreage.  Malaysia/Vietnam accounted for $250 million of the $305 million of
total capital spending in Southeast Asia and Australia, with the South Angsi
field development in PM-305 and on-going PM-3 CAA development. Talisman
participated in 10 successful development wells in Malaysia/Vietnam during
2005. In addition, six successful exploration wells were drilled in
Malaysia/Vietnam. A total of $55 million was spent in Indonesia, primarily on
the Suban phase 2 development to supply natural gas to West Java in 2007.  9


Capital spending in North Africa totaled $27 million in 2005, with
Talisman participating in nine successful wells in Algeria and one in Tunisia.  In Trinidad and Tobago, a total of $72 million was spent primarily on
Angostura development and the Eastern Block onshore exploration activity.  During 2005, the Company spent $49 million in Alaska on seismic and
preparations for the 2006 drilling program. Talisman spent $24 million in
Colombia on exploration drilling during 2005, as well as $20 million on
exploration drilling in Peru and $14 million on seismic and exploration
drilling in Qatar.  Information related to details and funding of the 2006 capital
expenditures program is included in the Outlook for 2006 section of this
MD&A.  Reserves Replacement  Talisman drilled 722 successful wells in 2005 and increased its total
proved reserves by 10% to 1,639 mmboe at the end of 2005. The Company replaced
189% of conventional production from all sources and 120% before acquisitions
and divestitures. Drilling related reserve additions totalled 203 mmboe.
Talisman also acquired 117 mmboe of proved reserves. Talismans net proved
reserves increased by 9% to 1,312 mmboe.  Proved oil and liquids reserves increased 19% to 736 mmbbls. Talisman
added a total of 208 mmbbls from all sources, including 152 mmbbls in the North
Sea, 34mmbbls in Southeast Asia and Australia, 12 mmbbls in North Africa and 10
mmbbls in North America. The majority (53%) of these reserves additions were
through discoveries, additions, extensions and revisions. The North Sea (54%)
and North America (24%) 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 heavy oil or bitumen reserves.  Talismans proved natural gas reserves increased by 4% in 2005,
totaling 5.4 tcf at year end. Talismans North American natural gas reserves
were 2.7 tcf at year end, up 3% from the previous year. In North America, the
Company added 361 bcf through the drill bit (108% of production), minor net
asset acquisitions (16 bcf) and upward revisions to existing reserves (29 bcf)
offset by record natural gas production (334 bcf). These numbers include
Fortunas natural gas reserves in the northeastern US, which totalled 142 bcf
at year end, with the addition of 21 bcf through drilling activities.  Talismans proved international natural gas reserves at year end were
2.7 tcf and accounted for 50% of the Companys total proved natural gas
reserves, with Southeast Asia and Australia constituting 41% of total worldwide
natural gas reserves.  Over the past three years, Talisman has added 611 mmboe of proved
reserves through discoveries, additions and extensions (including revisions)
and acquired 173 mmboe of proved reserves, net of dispositions (not including
the impact of the sale of Talismans indirect interest in the Greater Nile Oil
Project in Sudan). Approximately 80% of Talismans proved reserves have been
independently evaluated over the past three years.  The reserves replacement ratio of 120% (before acquisitions) was
calculated by dividing the sum of changes (revisions of estimates, improved
recovery and discoveries) to estimated proved oil and gas reserves during 2005
by the Companys 2005 conventional production. The reserves replacement ratio
of 189% 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 2005 by the Companys 2005 conventional
production.  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 include 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 $4.26 billion ($4.1 billion,
net of cash), up from $2.5 billion at the end of last year. During 2005, the
Company generated $4.9 billion of cash provided by operating activities and
spent $3.2 billion on exploration and development and a net $3.1 billion on
acquisitions. In addition, the Company repurchased nine million common shares
and paid dividends of $125 million. At year end, the Company had not drawn
against its available $1,345 million bank lines of credit. In addition,
drawings to a total of $548 million are available in the form of letters 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 may 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 may issue up to $1 billion of medium term note
securities in the Canadian public debt market.  The Company repurchased 9,089,100 common shares under its normal course
issuer bid (NCIB) during 2005 for a total of $355 million ($39.01/share). In
March 2005, the Company renewed its NCIB to permit the purchase of up to
18,437,285 common shares, representing 5% of the total common shares
outstanding at the time of the renewal. Of the total, 2,021,900 common shares
were repurchased under the renewed NCIB. The NCIB expires in March 2006 and the
Company has received Board of Directors approval to renew the NCIB for another
year. This will allow the Company to repurchase up to 5% of the Companys
common shares outstanding at the time of renewal.  In May 2005, the Company completed a US$375 million offering of 5.125%
notes due May 15, 2015 and a US$125 million offering of 5.75% notes due May 15,
2035. Interest on both notes is payable semi-annually in arrears on May 15 and
November 15 of each year. Proceeds from the notes were used to repay amounts
drawn on bank credit facilities. In order to hedge a portion of the fair value
risk associated with the US$375 million 5.125% note 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.  Subsequent to year end, Talisman issued long term debt under both the
US and Canadian debt shelf prospectuses, completing 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 payable semi annually. The $350
million offering was immediately swapped into US$304 million 5.054% debt. The
proceeds from these note offerings were used to repay a portion of the amounts
outstanding under the acquisition credit facility discussed below.  At December 31, 2005, the Company had current assets of $1.6 billion
and current liabilities of $3 billion. Working capital movements are difficult
to predict, but management does not anticipate a substantial change during
2006.  10


In connection with the funding of the acquisition of Paladin, the
Company arranged a $2,605 million (£1,300 million), unsecured non-revolving
credit facility (bridge financing facility). At December 31, 2005, $1,848
million was drawn on this facility. Subsequent to year end, and following the
repayment of a portion of the credit facility with the proceeds of the note offerings
completed in January 2006, the total borrowings under the bridge financing
facility (which requires refinancing by October2006) were reduced to $990
million. This amount, along with any reductions in the 2005 year end working
capital deficiency, is expected to be funded from excess cash provided by
operating activities, draws on existing credit facilities or proceeds from net
asset dispositions. Borrowings may be made in US dollars or pounds sterling in
the form of bankers acceptances or LIBOR-based loans.  Two common share dividends were paid in 2005 for a total of $125
million (an aggregate of $0.34/share). The Companys dividend is determined
semi-annually by the Board of Directors. At year end, there were 366 million
common shares outstanding, down from 375 million at December 31, 2004. As at
February 28, 2006, there were 366 million common shares outstanding, as well as
20,845,591 stock options outstanding.  At the end of 2005, Talismans ratio of debt to cash provided by
operating activities was 0.9:1 and its ratio of debt to debt plus equity was
43%.  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 Section of
this MD&A for possible 2006 impacts of various factors on the Companys
estimated 2006 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 Investor Service,
Inc. (Moodys) and Standard & Poors (S&P) are BBB (high), Baa1 (under
review for downgrade) and BBB+ (with a negative outlook), respectively.  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, 2005 and estimated timing of such payments.  Payments
  due by period (1), (2) (millions of dollars)Commitments
  
  Recognized
  in
  financial statements
  
  Total
  
  Less
  than
  1 year
  
  1-3
  years
  
  4-5
  years
  
  6-10
  years
  
  11-15
  years
  
  After 15
  yearsLong-term debt
  
  Yes  Liability
  
  4,263
  
  12
  
  1,172
  
  707
  
  792
  
  501
  
  1,079Abandonment obligations (3)
  
  Yes 
  Partially accrued as liability
  
  3,114
  
  40
  
  56
  
  34
  
  141
  
  656
  
  2,187Office leases
  
  Yes 
  Partially accrued as liability
  
  207
  
  28
  
  48
  
  44
  
  86
  
  1
  
  Ocean-going vessel leases
  
  No
  
  124
  
  59
  
  20
  
  12
  
  30
  
  3
  
  Transportation and processing commitments
  
  No
  
  1,044
  
  155
  
  193
  
  139
  
  289
  
  184
  
  84Minimum work commitments (4)
  
  No
  
  391
  
  319
  
  53
  
  19
  
  
  
  
  
  Other service contracts
  
  No
  
  1,043
  
  311
  
  590
  
  116
  
  21
  
  5
  
  Stock options and cash units (5)
  
  Yes 
  Partially accrued as liability
  
  840
  
  627
  
  213
  
  
  
  
  
  
  
  Total
  
  
  
  11,026
  
  1,551
  
  2,345
  
  1,071
  
  1,359
  
  1,350
  
  3,350  
 (1)Payments exclude ongoing operating costs related to certain leases,
interest on long-term debt and payments made to settle derivative contracts. (2)Payments denominated in foreign currencies have been translated at the
December 31, 2005 exchange rate. (3)The abandonment obligation represents managements probability
weighted, undiscounted best estimate of the cost and timing of future
dismantlement, site restoration and abandonment obligations based on
engineering estimates and in accordance with existing legislation and industry
practice. (4)Minimum work commitments include contracts awarded for capital projects
and those commitments related to exploration or drilling obligations. (5)The liability for stock options and cash units recognized on the
balance sheet is based on the Companys year end stock price and the number of
options and cash units outstanding, adjusted for vesting terms. The amount
included in this table includes the full value of unvested options and cash
units. Timing of payments is based on vesting and expiry. Actual payments are
dependent on the Companys stock price at the time of exercise.  11


Derivative Financial Instruments and Commodity Sales
Contracts  The Company manages its exposure to fluctuations in foreign exchange
rates, interest rates, electricity costs 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, 2005, including their respective fair values, are
detailed in notes 11 and 12 to the Consolidated Financial Statements.  During 2005, the Company had commodity price derivative financial
instruments covering 6,000 bbls/d or 2% of the Companys 2005 worldwide oil and
liquids production. This resulted in a net decrease to recorded sales of $77
million (2004  $480 million decrease; 2003  $194 million decrease). During
the fourth quarter of 2005, the Company entered into natural gas price
derivative contracts and assumed various crude oil and natural gas derivative
contracts as a result of the acquisition of Paladin. The fair value of
derivative contracts acquired was a liability of $147 million. Virtually all of
the acquired derivative contracts qualify for hedge accounting and, as such,
subsequent unrealized changes in the fair value of these contracts are deferred
and realized in income over the remaining term of the contracts. At December
31, 2005, the Company had outstanding commodity price derivative contracts that
cover approximately 8,000 bbls/d (5%) of the Companys anticipated 2006 North
Sea oil and liquids production. An additional 68 mmcf/d (7%) of anticipated
2006 North American natural gas and 3 mmcf/d (2%) of North Sea gas production
have been committed under fixed price commodity sales contracts. The Companys
outstanding commodity price derivative contracts 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.  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 has 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.
The crude oil received from Caltex is then sold offshore. 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 dollar 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. The termination of these
contracts did not accelerate recognition of the deferred gain into 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$375
million notes issued in May 2005.  In order to facilitate the exchange of the acquisition credit facility
from pounds sterling into the Companys functional currency (US$) the Company
entered into forward contracts to buy UK pounds sterling (GBP) and sell US
dollars. At December 31, 2005 foreign currency contracts were in place for £725
million at an average rate of 1.7543US/£. Subsequent to year end, additional
contracts were executed and the amount outstanding under the acquisition
facility (£938 million) was exchanged for US$1,646 million resulting in an
average exchange rate of 1.7552.  As a result of the acquisition of Paladin, Talisman acquired a foreign
exchange derivative contract to swap US$15.1 million to Norwegian Kroner (NOK)
at a rate of 6.4475 NOK/US on March 31, 2006. The fair value of the contract
acquired was less than $1 million and is not designated as a hedge and,
therefore, is recorded at fair value.  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. With the current high commodity prices and
the Companys strong balance sheet, management does not believe the capital
expenditure program is under significant risk and has not actively renewed the
derivatives program.  SEGMENTED RESULTS REVIEW  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 20 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 2005 were conducted principally in five
geographic segments: North America, the North Sea, Southeast Asia and
Australia, North Africa and Trinidad and Tobago, where the Angostura field
began production in January 2005. Beginning in the first quarter of 2006,
changes will be made to the reporting segments as outlined in the Outlook for
2006 section of the MD&A. The segment entitled Southeast Asia and Australia
includes Indonesia, Malaysia/Vietnam and Australia for the year ended December
31, 2005, but only Indonesia and Malaysia/Vietnam in both 2004 and 2003.
Similarly, the segment entitled North Africa includes both Algeria and Tunisia
for the year ended December 31, 2005, but only Algeria in both 2004 and 2003.
Exploration is being advanced in other areas outside the principal geographic
segments, including Alaska, Colombia, Qatar and Peru. The Companys indirectly
held interest in the Greater Nile Oil Project in Sudan was sold on March 12,
2003. The following is a brief summary of the financial results of each
geographic segment. The Companys pre-tax segmented income 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  12


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 (excludes Alaska)  During 2005, the North America operations contributed $1.6 billion or
40% of the Companys pre-tax segmented income of $4 billion, up 79% from $877
million (51% of $1.7 billion) in 2004. Gross sales in North America increased
33% to $4.1 billion due principally to higher commodity prices and natural gas
production. North American production averaged 208,800 boe/d, up 2% over 2004,
and represented 44% of the Companys total production in 2005. Royalty expense
increased 36% to $816 million due to higher commodity prices. North American
operating expense increased 14% to $478 million due to increased natural gas
volumes, higher processing fees, well workovers and maintenance costs. DD&A
increased to $946 million, up from $785 million due to increased production,
higher drilling costs, increased capital expenditures on infrastructure
projects as well as increased land amortization costs. Total exploration and
development spending for North America in 2005 was $1.6 billion, up 11% over
2004.  North Sea  The North Sea pre-tax segmented income increased to $1.6 billion and
accounted for 40% of the Companys pre-tax segmented income during 2005, up
226% from $486 million in 2004. North Sea gross sales increased 39% to $3.3 billion
due primarily to higher prices and increased liquids production, resulting from
acquisitions and development drilling. Production averaged 152,700 boe/d and
represented 33% of the Companys total production. This 8% increase in
production also contributed to increases in operating expenses of $197 million
and DD&A expense of $9 million. Royalty expense increased 51% to $56
million due to higher production and increased commodity prices. Dry hole
expense decreased from $109 million to $53 million in 2005. Exploration and
development spending for the North Sea was $1 billion, up 104% from 2004.  Southeast Asia and Australia  Southeast Asia and Australia contributed 16% ($649 million) to the Companys
pre-tax segmented income in 2005. Gross sales increased 36% to $1.5 billion
with increased commodity prices and the startup of the PM 305 South Angsi field
in Malaysia. Southeast Asia and Australia production averaged 82,800 boe/d, an
increase of 5% over 2004 and represented 18% of the Companys total production.
Total operating expenses decreased 11% from 2004 to $87 million as a result of
the increase in production mainly related to the low unit cost PM-3 CAA volumes,
which offset the higher cost volumes from the Jambi and Tanjung concessions that
expired in 2004 and early 2005. DD&A expense decreased 17% to $144 million
as increased reserves in Malaysia/Vietnam and the expiry of the Tanjung
concession lowered the per unit rate 17% to $4.98/boe. Capital spending for
Southeast Asia and Australia was $305 million, up 20% from 2004.  North Africa  North Africa contributed 4% ($145 million, up 49% from 2004) to the
Companys pre-tax segmented income in 2005. Gross sales increased over 2004 by
37% to $349 million as the higher commodity prices combined with increased
production. Production for 2005 averaged 15,400 bbls/d, up 14% over 2004, and
represented 3% of the Companys total production in 2005. Operating costs in
2005 increased 41% to $24 million as a result of higher power and maintenance
costs. Capital spending for North Africa was $27 million, up $19 million from
2004 primarily related to the phase 2 expansion of the Greater MLN facilities.  Trinidad and Tobago  Trinidad and Tobago contributed 3% ($110 million) to the Companys
pre-tax segmented income in 2005, its first year of production. In 2005, gross
sales were $229 million, production averaged 10,100 bbls/d, with operating and
DD&A expenses at $11 million and $47 million, respectively. Capital
spending for Trinidad and Tobago in 2005 was $72 million, down from $191
million the previous year when installation of producing field facilities was
completed.  Other Exploration and Development  During 2005, the Company spent $134 million, the majority of which was
in Alaska, Colombia, Peru and Qatar.  13


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 Canadian dollars, unless otherwise stated)
  
  Total Year
  
  Dec. 31
  
  Sept. 30
  
  June 30
  
  March 312005Gross sales
  
  9,554
  
  2,891
  
  2,606
  
  2,080
  
  1,977Total revenue
  
  8,047
  
  2,433
  
  2,189
  
  1,748
  
  1,677Net income (1)
  
  1,561
  
  533
  
  430
  
  340
  
  258Net income available to common shareholders
  
  1,561
  
  533
  
  430
  
  340
  
  258Total assets
  
  18,339
  
  18,339
  
  14,126
  
  13,422
  
  13,233Total long-term liabilities
  
  9,512
  
  9,512
  
  6,435
  
  6,520
  
  6,563Capital expendituresExploration
  
  1,084
  
  358
  
  273
  
  216
  
  237Development
  
  2,095
  
  622
  
  511
  
  450
  
  512Per common share (dollars)Net income (1)
  
  4.24
  
  1.45
  
  1.17
  
  0.93
  
  0.70Diluted net income(5)
  
  4.14
  
  1.42
  
  1.14
  
  0.91
  
  0.68Daily average productionOil and liquids (bbls/d) (3)
  
  249,984
  
  292,039
  
  242,884
  
  228,977
  
  235,492Natural gas (mmcf/d) (4)
  
  1,319
  
  1,344
  
  1,307
  
  1,292
  
  1,332Total (mboe/d)
  
  470
  
  516
  
  461
  
  444
  
  4572004 (Restated (2))Gross sales
  
  6,874
  
  1,828
  
  1,788
  
  1,705
  
  1,553Total revenue
  
  5,355
  
  1,402
  
  1,355
  
  1,337
  
  1,261Net income (1), (2)
  
  654
  
  121
  
  122
  
  193
  
  218Net income available to common shareholders
  (2)
  
  654
  
  121
  
  122
  
  193
  
  218Total assets
  
  12,408
  
  12,408
  
  12,407
  
  13,007
  
  12,290Total long-term liabilities
  
  5,934
  
  5,934
  
  5,883
  
  6,100
  
  6,061Capital expendituresExploration
  
  952
  
  250
  
  280
  
  200
  
  222Development
  
  1,586
  
  478
  
  407
  
  309
  
  392Per common share (dollars)Net income (1), (2)
  
  1.71
  
  0.32
  
  0.32
  
  0.50
  
  0.57Diluted net income (2), (5)
  
  1.68
  
  0.31
  
  0.31
  
  0.50
  
  0.56Daily average productionOil and liquids (bbls/d)
  
  228,434
  
  235,612
  
  218,441
  
  229,579
  
  230,136Natural gas (mmcf/d) (4)
  
  1,259
  
  1,292
  
  1,263
  
  1,244
  
  1,236Total (mboe/d)
  
  438
  
  451
  
  429
  
  437
  
  436  
 (1)Net income and net income before discontinued operations and
extraordinary items are the same. (2)For 2004, net income available to common shareholders, net income per
share and diluted net income per share have been restated to treat preferred
securities as debt rather than equity. See note 2 to the Consolidated Financial
Statements. (3)Includes unlifted oil volumes as at December 31, 2005 of 5,499 bbls/d. (4)Includes gas acquired for injection and subsequent resale of 15 mmcf/d
in 2005, with 8 mmcf/d, 9 mmcf/d, 18 mmcf/d and 23 mmcf/d during each of the
quarters ended March, June, September and December, respectively and 5 mmcf/d
in 2004, with 8 mmcf/d, 8 mmcf/d, 3 mmcf/d and 3 mmcf/d during each of the
quarters ended March, June, September and December, respectively. (5)Diluted net income per common share is calculated using the treasury
stock method, which gives effect to the potential dilution that could occur if
stock options were exercised in exchange for common shares. However, since
inception of the Companys Stock Appreciation Rights Plan, only approximately
3% of stock options have been exercised for common shares, therefore, the
dilution was insignificant.  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
2005, gross sales rose by $285 million over the previous quarter due to
increased natural gas prices in North America and increased production in the
North Sea. Net income for the quarter increased by $103 million, as the
increased revenue combined with reduced stock-based compensation charges to
more than offset the impact of increases in operating, depreciation, depletion
and amortization, royalty and tax expenses.  During the third quarter of
2005, higher commodity prices and production increased gross sales by $526
million. Net income for the quarter increased by $90 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 increased in the quarter as increased 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.  14


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 increased in the quarter as increased
gross sales, combined with reductions in dry hole costs, exploration expenses,
impairments, DD&A and General and Administrative Expense (G&A) to
more than offset the impact of increases in stock-based compensation charges,
royalties, operating costs and taxes.  During the fourth quarter of 2004, gross sales increased due to higher
volumes and gas prices, which more than offset the impact of a stronger Canadian
dollar and increased hedging losses. Net income remained relatively constant as
reductions in stock-based compensation, operating expenses and dry hole costs
were offset by increases in DD&A, impairments and G&A expenses as well
as a loss on disposal of fixed assets.  In the third quarter of 2004, gross sales rose as the increase in oil
prices more than offset the reduction in production, resulting from maintenance
shutdowns. Net income in the third quarter declined from the previous quarter,
as the increase in gross sales was more than offset by increases in hedging
losses, dry hole costs, exploration expenses and current income taxes. In the
first two quarters of 2004, gross sales continued to rise due to increases in
both commodity prices and production, partially offset by increased hedging
losses. These factors combined with the benefit of tax rate reductions to
increase net income in the first quarter of 2004 over the last quarter of 2003.
A higher charge for stock-based compensation and reduced tax rate reductions
resulted in a drop in net income during the second quarter of 2004 from the
previous quarter.  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 obligation 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 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 becomes 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,
amongst 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), $3.2 billion
(2004  $1.2 billion) of the Companys PP&E is not currently subject to
DD&A. Approximately 16% of these costs relate to the Tweedsmuir development
project ($500 million) in the North Sea, due to come on production in early
2007, at which time amortization will commence. The remainder of the $3.2
billion of non-depleted capital relates to the costs of other development
projects ($725 million), which will be amortized when production commences, the
costs of acquired unproved reserves ($1.6 billion) and incomplete drilling
activities, including those wells under evaluation or awaiting commencement of
production ($450 million). Uncertainty exists with the treatment of these
costs. For example, if the evaluation of the acquired probable reserves or recently
drilled exploration wells were 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.  15


During the fourth quarter of 2004, the expected useful lives of certain
productive assets changed, resulting in a reduction in the DD&A expense of
$12 million.  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. Individual oil and gas assets
are considered impaired under the successful efforts method if their fair value
falls below their carrying value. Goodwill is considered to be impaired if its
fair value, principally determined based on discounted cash flows, falls below
its carrying value. Both tests 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, in the case of goodwill, discount rates. During the past three years,
isolated asset impairments have occurred (2005  $31 million; 2004  $31
million; 2003  $30 million), however, it is possible that future impairments
may be material.  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. The
Companys reporting units for goodwill are consistent with the geographic
segments included in note 20 to the Consolidated Financial Statements.  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. 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  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, 2005, a reduction of $191 million
in the discounted ARO liability related to an increase in life of reserves in
the North Sea was offset by increases in the liability of $59 million and $21
million for North America and rest of world, respectively, related to changes
in cost estimates; and at December 31, 2004, a reduction of $66 million in the
discounted ARO liability related to an increase in life of reserves in the
North Sea was offset by increases in the liability of $22 million for North
America, related to change in cost estimates. The total undiscounted
abandonment liability is currently estimated at $3.1 billion, which is based on
managements probability weighted estimate of costs and in accordance with
existing legislation and industry practice.  As indicated in the MD&A section entitled New Canadian Accounting
Pronouncements, the accounting for Asset Retirement Obligations was adopted on
a retroactive basis effective January 1, 2004. Under these accounting
requirements, the fair value of the Companys Asset Retirement Obligations
(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, 2005, the discounted
fair value of the Companys ARO liability is $1.3 billion, (2004  $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 $30 million.  16


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
dollar, effective for 2002, as the Companys functional currency is a
reflection of Talismans overall exposure to US dollar denominated
transactions, assets and liabilities; oil prices are largely denominated in US
dollars as is much of the Companys corporate debt and international capital
spending and operating costs. However, the Companys operations in the UK and
Canada 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 pounds sterling and Canadian
dollars, respectively. Currently, the Companys foreign exchange translation
exposure principally relates to US dollar 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 pounds sterling, and the Companys
Canadian dollar 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
and the North Sea 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 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.  Exchange of Non-monetary Assets  The CICA has issued a new standard, effective January 1, 2006 on a
prospective basis, requiring all non-monetary transactions to be measured at
fair value rather than book value if the transaction has commercial substance.
Under current rules, a transaction is a non-monetary transaction if the cash
component is less than 10% of the value exchanged. Under the new standard, a
transaction will have commercial substance if it causes an identifiable and
measurable change in the economic circumstances of the entity. For example, if
a property that is currently producing is swapped for undeveloped land, there
would be an identifiable and measurable change in the economic circumstances of
the assets swapped and this transaction would be measured at fair value under
the new rules.  Other Comprehensive Income/Financial Instruments  The CICA has issued a new standard on accounting for financial
instruments. The standard harmonizes Canadian rules with current International
and US rules, while permitting alternatives not available under US GAAP. The
standard introduces the concept of Other Comprehensive Income to Canadian
GAAP. Derivative contracts will be carried on the balance sheet at their
mark-to-market value, with the change in value flowing to either net income or
other comprehensive income. Gains and losses on instruments that are identified
as hedges will flow initially to other comprehensive income and be brought into
net income at the time the underlying hedged item is settled. Any
ineffectiveness in the hedging relationship will be brought into net income
during the period. This standard will be effective for Talismans 2007
reporting. Any instruments that do not qualify for hedge accounting will be
marked to market with the adjustment (tax affected) flowing through the income
statement.  Talisman has hedges in place related to the Paladin acquisition that
carry into 2007. See note 11 to the Consolidated Financial Statements for
details.  Variable Interest Entities  Having harmonized GAAP between Canada and the US, Variable Interest
Entities rules are designed to catch off-balance sheet financing structures and
force companies to consolidate the Variable Interest Entities (VIE) and report
the debt on their balance sheet. The rules are quite complicated and have been
written with broad applicability. An entity is a Variable Interest Entity if
there is insufficient equity at risk in the entity and the equity holders are
not exposed to residual expected losses or returns. These entities are to be
consolidated by the Primary Beneficiary who is the company that will absorb the
majority of any expected losses or residual income.  An example of a VIE would be a lease arrangement whereby the leasing
company establishes a new subsidiary capitalized primarily with debt and the
lessee guarantees a return back to the leasing company. The lessee would be
required to consolidate the subsidiary, resulting in the debt being reported on
the lessees balance sheet.  17


Talisman will continue to review its arrangements to determine if there
are any VIEs that might require consolidation. Arrangements such as Floating
Production and Storage Offloading (FPSO) leases are the most likely candidates
for potential VIEs. Management has not identified any VIE arrangements to date
that would require a change in accounting treatment.  Leasing Arrangements  The Emerging Issues Committee (EIC) of the CICA has issued EIC 150
regarding the identification of leasing arrangements. The Committee reached a
consensus that widens the scope of what is considered a lease. Arrangements
entered into prior to the December 9, 2004 date are unaffected. The Company has
reviewed arrangements, such as take or pay contracts or ship or pay contracts
and has concluded that the impact of EIC 150 has not been significant to date.  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 is expected to
be finalized in 2006, with an effective date as of January 1, 2007.  Outlook for 2006(1)  Estimated
  for 2006
  
  Actual
  2005Cash provided by operating activities
  
  
  
  
  
  $ 5.2 
  5.6 billion
  
  $ 4.9
  billion  Exploration and development spending
  
  Estimated
  for 2006
  
  
  
  Actual
  2005(millions of dollars)
  
  Exploration
  
  Development
  
  Total
  E&D
  
  Total
  E&DNorth America
  
  748
  
  1,237
  
  1,985
  
  1,609United Kingdom
  
  148
  
  1,062
  
  1,210
  
  864Norway
  
  129
  
  276
  
  405
  
  168Southeast Asia and Australia
  
  95
  
  345
  
  440
  
  305North Africa
  
  
  
  65
  
  65
  
  27Trinidad and Tobago
  
  45
  
  20
  
  65
  
  72Other (2)
  
  230
  
  
  
  230
  
  1341,395
  
  3,005
  
  4,400
  
  3,179Production (daily average)
  
  Lower 2006
  estimate
  
  Upper 2006
  estimate
  
  Actual 2005Oil and liquids (bbls/d)North America
  
  54,000
  
  56,000
  
  56,304United Kingdom
  
  109,000
  
  113,000
  
  107,020Norway
  
  45,000
  
  49,000
  
  25,696Southeast Asia and Australia
  
  53,000
  
  59,000
  
  35,476North Africa
  
  16,000
  
  18,000
  
  15,377Trinidad and Tobago
  
  7,000
  
  9,000
  
  10,111284,000
  
  304,000
  
  249,984Natural gas (mmcf/d)North America
  
  935
  
  955
  
  915United Kingdom (3)
  
  135
  
  140
  
  111Norway
  
  10
  
  15
  
  9Southeast Asia and Australia
  
  305
  
  355
  
  2841,385
  
  1,445
  
  1,319Barrels of oil equivalent (mboe/d)
  
  515
  
  545
  
  470Commodity price and exchange rate assumptions
  
  Estimate for 2006
  
  Actual 2005US$/bbl WTI oil price
  
  57.00
  
  56.70US$/mmbtu NYMEX natural gas price
  
  9.00
  
  8.55US$/C$ exchange rate
  
  0.84
  
  0.83C$/£ exchange rate
  
  2.10
  
  2.21  
 (1)A 2006 estimate of net income and net income per share has not been
provided due to the inherent difficulties of estimating certain non-cash
expenses, such as dry hole, property impairments and non-cash stock-based
compensation. The Outlook for 2006 excludes acquisitions and dispositions,
notably the planned disposition of 10,000  15,000 boe/d of non-core assets in
Western Canada and the North Sea. (2)Other includes Alaska, Colombia, Peru and Qatar. (3)Includes gas acquired for injection and subsequent resale (of 23, 23,
and 5 mmcf/d in lower 2006 estimate, upper 2006 estimate and actual 2005,
respectively).  18


Talisman expects to increase production 10  16% in 2006. Production
for 2006 is expected to average approximately 515,000  545,000 boe/d before
planned asset sales, with most of the increase coming from Norway,
Malaysia/Vietnam and the UK.  Unit operating costs are expected to be marginally higher than in 2005.
However, unit production costs, in addition to being impacted by currency
exchange rates, are dependent on achieving expected production levels. Net
capital spending is expected to be $4.4 billion and excludes significant
corporate and asset acquisitions. The Company anticipates participating in the
drilling of 685 North America and 183 international wells during 2006 (gross).  North America (excludes Alaska)  In 2006, 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. North American natural gas production in 2006 is
expected to increase between 2  4% to average between 935  955 mmcf/d, while
oil and liquids is expected to average 54,000  56,000 bbls/d, as the Company
will spend approximately 92% of the North America budget on natural gas
exploration and development. The Company expects to spend approximately $2.0
billion on capital projects and drilling in 2006, up from the $1.6 billion
spent in 2005. The Company plans to participate in approximately 685 wells in
2006, including eight high impact exploration wells. Unit operating costs are
expected to increase slightly to approximately $6.15/boe due to higher ad
valorem taxes in Appalachia and increased processing and power costs.  The North Sea  Talismans North Sea assets include producing fields and exploration
acreage in several areas of the North Sea, the principal ones being the UK and
Norway. (For the purposes of this Outlook discussion, the United Kingdom
includes interests in Germany and the Netherlands and Norway includes
interests in Denmark). The Companys North Sea strategy is to focus on
development projects and exploration opportunities adjacent to core operated
properties and infrastructure.  The United Kingdom  Production in the UK North Sea is expected to average 109,000  113,000
bbls/d and 135  140 mmcf/d in 2006. Capital spending is planned to increase by
40% over 2005, to approximately $1.2 billion, with 88% related to development
projects. The Company plans to drill 34 gross development wells and up to 11
gross exploration wells. This increase in spending is driven by new properties
from the Paladin acquisition and the ongoing program to develop the Tweedsmuir
field, with first production expected towards the end of the first quarter of
2007. UK North Sea 2006 unit operating expenses are expected to approximate the
2005 amount. At planned exchange rates (approximately £1=C$2.10) unit operating
costs are expected to be in the $15.65  17.60/boe range.  Norway  Norway production is expected to average 45,000  49,000 bbls/d and 10 
15 mmcf/d in 2006. Capital spending is planned at $405 million, with 68%
related to development projects. The Company plans to drill 11 gross
development wells and up to eight gross exploration wells. Unit operating costs
are expected to be in the $14.80  16.70/boe range.  Southeast Asia and Australia  Natural gas sales in Indonesia are expected to average 190  210 mmcf/d
in 2006. Total planned capital spending of $85 million in Indonesia during 2006
includes the completion of the Phase 2 expansion of the gas processing
facilities at Suban in the Corridor PSC, two gas wells to be drilled at Suban
and the drilling of up to six gross exploration wells. Oil and liquids
production in Indonesia is expected to average 11,000  13,000 bbls/d with the
addition of the Paladin assets in SE Sumatra and offshore NW Java.  During 2006, Talismans oil and liquids production in Malaysia/Vietnam
is expected to average between 36,000  38,000 bbls/d. Natural gas production
is expected to average 115  125 mmcf/d during 2006.  Total development capital spending during 2006 in Malaysia/Vietnam is
expected to be approximately $266 million. The commencement of the PM-3 CAA
Northern Fields development is planned in 2006, with spending of $127 million.
First production is planned for the second quarter of 2008. A total of 16 gross
development wells are planned for 2006 (five in the Bunga Tulip Field
development, four in PM-3 CAA, six in East Bunga Kekwa-Cai Nuoc Unit Area and
one in PM - 314) for a total of $67 million. A total of $84 million on
exploration activities is planned with three PM-3 CAA wells, an appraisal well
in Bunga Tulip and two PM-314 wells. In addition, Talisman plans to drill one
exploration well in Block 15-2/01 in Vietnam in 2006.  In Australia in 2006, oil and liquids production is expected to average
6,000 - 8,000 bbls/d, with capital spending of $5 million to participate in two
exploration wells and one development well.  Operating costs in Southeast Asia and Australia are expected to
increase to approximately $3.30/boe in 2006.  North Africa  Production from the Ourhoud and MLN fields in Algeria, together with
production in Tunisia is expected to average 16,000  18,000 bbls/d in 2006.
Unit operating costs are expected to fall due to higher production. A capital
budget of $65 million is estimated and in Algeria includes drilling 24
development wells, the Phase II expansion of the Greater MLN facility and the
El Merk project sanctioning, with first oil in mid-2009. Three development
wells and three exploration wells are planned in Tunisia.  Trinidad and Tobago  Capital spending is budgeted at $65 million, with approximately
two-thirds directed towards exploration, with the drilling of four exploration
wells, including three onshore wells and five development wells. Production in
Trinidad and Tobago is expected to average 7,000  9,000 bbls/d.  19


Other  The Company is exploring in South America where it expects to spend $17
million in 2006 on exploration activities in Peru and Colombia. The Company has
budgeted $105 million in Alaska during 2006 primarily to drill up to two
exploration wells and conduct further exploration activities. The Company also
plans to spend an estimated $34 million in Qatar, which will include the
drilling of up to two exploration wells in Block 10.  At year end, Talisman has committed approximately 7% of its anticipated
2006 North American natural gas production under commodity sales contracts at
an average price of $9.77/mcf, and 2% of its anticipated 2006 North Sea natural
gas production under commodity sales contracts at an average price of
£5.27/mcf. In addition, approximately 5% of the Companys anticipated 2006
North Sea oil and liquids production is hedged at an average price of
US$32.69/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s 2006 year end debt position is anticipated to decrease to
approximately $3.6  4 billion, with cash from operating activities in excess
of capital spending and dividend payments. Significant 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
projected 2006 year end 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 2006 financial performance is
summarized in the following table and is based on a WTI oil price of US$57/bbl,
a NYMEX natural gas price of US$9/mmbtu and exchange rates of C$1=US$0.84 and
£1=C$2.10.  Approximate Impact in 2006  (millions of dollars)
  
  Net
  Income
  
  Cash
  Provided
  by Operating
  ActivitiesVolume changesOil  1,000 bbls/d
  
  6
  
  9Natural gas  10 mmcf/d
  
  10
  
  17Price changes (1)Oil  US$1/bbl
  
  50
  
  54Natural gas(North America) (2)
  C$0.10/mcf
  
  15
  
  20Exchange rate changesUS$ increased by US$0.01
  
  44
  
  73£ increase by C$0.025
  
  (4
  )
  4  
 (1)The impact of commodity contracts outstanding for 2006 has been included. (2)Price sensitivity on natural gas relates to North American natural gas
only. The Companys exposure to changes in North Sea and Malaysia/Vietnam
natural gas prices is not material. Most of the Indonesia natural gas price is
based on the price of crude oil and, accordingly, has been included in the
price sensitivity for oil except for a small portion, which is sold at a fixed
price.  RISKS AND UNCERTAINTIES  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.  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.  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.  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.  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. 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 United States sanctions.  20


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, 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 health, safety and environment (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 which
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.  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 production sharing contracts 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.  Talisman conducts an annual assessment of the carrying value of its
assets in accordance with Canadian GAAP. If oil and natural gas prices decline,
the carrying value of the Companys assets could be subject to downward
revisions, which could adversely affect Talismans reported income for the
periods in which the revisions are made. However, Talisman believes that
estimates of forward-looking prices it uses in its planning process are
realistic.  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.  Talisman continues to be subject to a lawsuit brought by the
Presbyterian Church of Sudan and others commenced in November 2001 under the
Alien Tort Claims Act in the United States District Court for the Southern
District of New York (the Court). The lawsuit, which is seeking class action
status, alleges 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. On
August 30, 2005, the Court denied Talismans motion for Court approval to
appeal the Courts prior denial of Talismans motion for judgment on the
pleadings, which sought dismissal of the lawsuit. Also on August 30, 2005, the
Court declined to dismiss the lawsuit in response to the filing of a Statement
of Interest by the US Department of Justice, expressing the US governments
view that the lawsuit interferes with US-Canada relations. On September 20,
2005, the Court denied, for the second time, the plaintiffs motion to certify
the lawsuit as a class action. On October 5, 2005, the plaintiffs filed papers
to appeal the decision denying class action status. The Company has filed
papers opposing the plaintiffs appeal. Talisman believes the lawsuit is
entirely without merit and is continuing to vigorously defend itself. Talisman
does not expect the lawsuit to have a material adverse effect on it.  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 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.  21


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 more 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 Kyoto Protocol, with a reduction
commitment of 12.5% below 1990 levels by 2008  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  2007, inclusive.
The UK Governments National Allocation Plan (NAP) for the first phase of the
EU ETS was approved by the European Commission in 2005. 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. Cost of compliance is
expected to be negligible during the period 2005  2007. Details regarding the
UK governments NAP for phase two of the EU ETS (2008  2012) are as yet
uncertain.  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.  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 of proximity of pipeline capacity;
the availability of drilling and other equipment; the ability to access lands;
weather; unexpected costs increases; accidents; the availability of skilled
labour; and regulatory matters.  In Canada and the United States, the state or private land owners 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 a 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.  The oil and gas industry, both within Canada and internationally, is
highly competitive in all aspects of the business. The Company actively
competes for the acquisition of properties, the exploration for and development
of new sources of supply, the contractual service for oil and gas drilling and
production equipment and services, the transportation and marketing of current
production and industry personnel. With respect to the exploration, development
and marketing of oil and natural gas, the Companys competitors include major
integrated oil and gas companies, numerous other independent oil and gas
companies, individual producers and operators and national oil companies. A
number of the Companys competitors have financial and other resources
substantially in excess of those available to the Company. In addition, oil and
gas producers in general compete indirectly against others engaged in supplying
alternative forms of energy, fuel and related products to consumers.  While Talisman currently has minimal commodity hedging contracts in
place, it continues to monitor the Companys exposure to variations in
commodity prices, interest rates and foreign exchange rates. 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s Consolidated Financial Statements are presented in Canadian
dollars. Results of operations are affected primarily by the exchange rates
between the Canadian dollar, the United States dollar or United Kingdom pound
sterling. These exchange rates have varied substantially in the last five
years. Most of the Companys revenue is received in or is referenced to United
States dollar denominated prices, while the majority of Talismans expenditures
are denominated in Canadian dollars, United States dollars and United Kingdom
pounds sterling. A change in the relative value of the Canadian dollar against
the United States dollar or the United Kingdom pound sterling would also result
in an increase or decrease in Talismans United States dollar or United Kingdom
pound sterling denominated debt, as expressed in Canadian dollars and the
related interest expense. Talisman is also exposed to fluctuations in other
foreign currencies.  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.  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.  22


It should be noted that, while the Companys Chief Executive Officer
and Chief Financial Officer believe that 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.  ADVISORY  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 2006 Outlook Summary, Outlook for
2006 and Risks and Uncertainties. These statements include, among others,
statements regarding:  estimates of production and operations or
financial performance;  estimates and prices of future sales;  business plans for drilling, exploration and
development;  the estimated amounts and timing of capital
expenditures;  estimates of unit operating costs;  business strategy and plans or budgets;  royalty rates and exchange rates;  the merits or anticipated outcome of pending
litigation; and  other expectations, beliefs, plans, goals,
objectives, assumptions, information and statements about possible future
events, conditions, results of operations or performance.  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 which discuss business plans for drilling,
exploration and development in 2006 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$57/bbl West Texas Intermediate
oil price, a US$9/mmbtu New York Mercantile Exchange natural gas price, a
US$/Canadian$ exchange rate of $0.84 and a Canadian$/British £ rate of 2.10.  This MD&A also discusses cash provided by operating activities and
anticipated debt for 2006. The material assumptions used in determining
estimates of cash provided by operating activities are: the anticipated
production volumes described in the 2006 Outlook section 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 is 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 petroleum revenue tax. The material
assumptions used in determining estimates of year end debt are: the anticipated
amount of cash provided by operating activities; anticipated capital
expenditures; the amount of anticipated dividend payments; movements in working
capital; and estimated year end exchange rates.  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 which are derived
from or depend upon future production estimates (such as cash provided by
operating activities), do not reflect the impact of any potential asset
dispositions. 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 risks and uncertainties
include:  the risks of the oil and gas industry, such
as operational risks in exploring for, developing and producing crude oil and
natural gas, and market demand;  risks and uncertainties involving geology of
oil and gas deposits;  the uncertainty of reserves estimates and
reserves life;  the uncertainty of estimates and projections
relating to production, costs and expenses;  potential delays or changes in plans with
respect to exploration or development projects or capital expenditures;  fluctuations in oil and gas prices, foreign
currency exchange rates and interest rates;  the outcome and effects of completed
acquisitions, as well as any future acquisitions and dispositions;  the ability of the Company to integrate any assets
it has acquired or may acquire or the performance of those assets;  health, safety and environmental risks;  23


uncertainties as to the availability and cost
of financing and changes in capital markets;  uncertainties related to the litigation
process, such as possible discovery of new evidence or acceptance of novel
legal theories and difficulties in predicting the decisions of judges and
juries;  risks in conducting foreign operations (for
example, political and fiscal instability or the possibility of civil unrest or
military action);  changes in general economic and business
conditions;  the effect of acts of, or actions against,
international terrorism;  the possibility that government policies or
laws may change or governmental approvals may be delayed or withheld;  results of the Companys risk mitigation
strategies, including insurance and any hedging programs; and  the Companys ability to implement its
business strategy.  We caution that the foregoing list of risks and uncertainties is not
exhaustive. Additional information on these and other factors which 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 Managements Discussion and Analysis  Risks and
Uncertainties and elsewhere in the Companys 2005 Annual Report Financial
Review. Additional information may also be found in the Companys other reports
on file with Canadian securities regulatory authorities and the United States
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.  ADVISORY  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. 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.  24