Exhibit 4  Managements
Discussion and Analysis  Highlights  2002
  
  2001
  
  Change (%)Cash flow(1)
  
  2.6 billion
  
  2.5
  billion
  
  6Net income(2)
  
  524 million
  
  733
  million
  
  (29
  )Per shareCash flow(1)
  
  19.73
  
  18.48
  
  7Net income(2)
  
  3.73
  
  5.25
  
  (29
  )Diluted per shareCash flow(1)
  
  19.43
  
  18.15
  
  7Net income(2)
  
  3.67
  
  5.16
  
  (29
  )Production
  
  445 mboe/d
  
  419
  mboe/d
  
  6Average sales price
  
  32.10/boe
  
  32.91/boe
  
  (2
  )Operating costs
  
  6.48/boe
  
  5.79/boe
  
  12Exploration and development spending
  
  1.8 billion
  
  1.9
  billion
  
  (2
  )Proved reserve additions (including acquisitions)
  
  159 mmboe
  
  462
  mmboe
  
  (66
  )Finding,development and acquisition costs
  
  12.15/boe
  
  7.08/boe
  
  72Production per share
  
  1.21 boe/share
  
  1.13
  boe/share
  
  7 
 (1)
  
  Cash flow and cash flow per share are non-GAAP measures that represent
  net income before exploration costs, DD&A, future taxes and other
  non-cash expenses. The components of cash flow are set out in note 14 to the Consolidated
  Financial Statements.(2)
  
  Prior years comparative has been restated for a new CICA accounting
  standard (see note 2 to the Consolidated Financial Statements).       Cash Flow
  
  Cash Flow Per Share(millions of dollars)
  
  (dollars)98
  
  631
  
  98
  
  5.6499
  
  1,111
  
  99
  
  8.9100
  
  2,413
  
  00
  
  17.5101
  
  2,494
  
  01
  
  18.4802
  
  2,645
  
  02
  
  19.73    This discussion and analysis should be read in
conjunction with the audited Consolidated Financial Statements of the Company.
In particular, note 16 provides segmented financial information that forms the
basis for much of the following discussion and analysis. The calculation of
barrels of oil equivalent (boe) is based on a conversion rate of six thousand
cubic feet (mcf) of natural gas for one barrel of oil. All comparative
percentages are between the years ended December 31, 2002 and December 31,
2001, unless stated otherwise. Reported production represents Talismans
working interest share before royalties unless otherwise noted. Selected
quarterly unaudited financial data, including product netbacks, may be found on
pages 69 and 70 of this Annual Report. Included in
the Managements Discussion and Analysis (MD&A) are references to terms
commonly used in the oil and gas industry such as cash flow, cash flow per
share and EBITDAX. These terms are not defined by Generally Accepted Accounting
Principles in either Canada or the US. Consequently these are referred to as
non-GAAP measures. Cash flow, as commonly used, appears as a separate caption
on the Companys cash flow statement and is reconciled to both net income and
cash flow from operations. EBITDAX is defined on page 27 of this Annual Report.   18 
     Net Income (Loss)
  
  Net Income (Loss) Per Share(millions of dollars)
  
  (dollars)98
  
  (314
  )
  98
  
  (2.80
  )99
  
  255
  
  99
  
  1.9300
  
  857
  
  00
  
  6.0501
  
  733
  
  01
  
  5.2502
  
  524
  
  02
  
  3.73  2003 OUTLOOK  Talisman anticipates at least 5% production per share growth in 2003 and
10% in 2004 (after adjusting for Sudan).  Production is expected to
average 395,000-415,000 boe/d, including Sudan volumes in the first quarter. Startup of the
Malaysia/Vietnam PM-3 CAA Phase 2 and Algeria MLN developments. Production of 60-70 mmcf/d in
the US. Planned exploration and
development spending of $2.1 billion ($975 million in North America). The Sudan sale is expected to
close in the first quarter of 2003. Average unit operating costs
are expected to increase to $7/boe reflecting the absence of Sudan and a higher
operating cost environment.  2002 VARIANCES  The significant variances from 2001 are:  Increased production volumes
contributed $300 million of additional cash flow. Lower natural gas prices
($447 million) mostly offset by higher oil and liquids prices ($330 million)
and increased hedging gains ($67 million). Higher operating expense
($169 million). Reduced current taxes ($95
million) mostly on lower natural gas prices in North America. Higher DD&A with
increased production ($182 million). Dry hole and exploration
expense increased $99 million. Increased future tax due to
one time non-cash charge on new UK supplemental oil and gas tax.  Cash
flow of $2.6 billion ($19.73/share)(1)Net income of $524 million ($3.73/share)(1)  NET INCOME AND CASH FLOW VARIANCE (millions)2001 Net income
  
  733Favorable (unfavorable)Cash flow varianceOil and liquids volumes
  
  254Natural gas volumes
  
  46Natural gas prices
  
  (447
  )Oil and liquids prices
  
  330Hedging
  
  67Royalties
  
  62Other revenue
  
  (2
  )Operating expense
  
  (169
  )Interest expense
  
  (25
  )Current taxes (including PRT)
  
  95General and administration
  
  (30
  )Other
  
  (30
  )Total cash flow variance
  
  151Non-cash itemsDepreciation,depletion and amortization expense
  
  (182
  )Dry hole expense
  
  (61
  )Exploration expense
  
  (38
  )Future taxes (including PRT)
  
  (76
  )Other
  
  (3
  )Total non-cash items
  
  (360
  )2002 Net income(1)
  
  524 
 (1)
  
  Net income, cash flow and cash flow per share are before preferred
  security charges of $24 million, net of tax ($42 million, before tax). The
  components of cash flow are set out in note 14 to the Consolidated Financial
  Statements.  TALISMANS PERFORMANCE HIGHLIGHTS IN 2002  In 2002, Talisman posted record cash flow of $2.6 billion
($19.73/share). Production also grew to a record 445,000 boe/d.  Progress was made on the Companys key development projects. The
Malaysia/Vietnam PM-3 CAA project is expected to come on stream in 2003.
Production commenced in Algeria at year end and is expected to increase through
2003. An expansion at the Corridor gas plant facility in Indonesia was
completed in 2002to support additional future sales under gas
sales agreements and memoranda of understanding. Project sanction has been
received for the Trinidad development with first production expected in early
2005. The Company also announced a North Sea oil discovery at J-1 and is in the
process of establishing a natural gas core area in the US.  On October 30, the Company announced an agreement for the sale of its
Sudan operations for $1.2 billion. During 2002 and the early part of 2003, 5.8
million shares (4.5% of shares currently outstanding) were repurchased at an
average price of $57.05/share.   19 
   Cash flow in 2002 was $2.6 billion ($19.73/share), increasing for the
fourth straight year and up 6% from last year. Net income was $524 million
($3.73/share), down from 2001, with over half of the decrease due to a one time
non-cash expense of $128 million relating to a supplemental 10% tax on UK oil
and gas profits. The UK also eliminated government royalties effective January
2003 and accelerated capital allowance deductions. Based on current expected
capital expenditures, Talisman anticipates the short term impact of the
supplemental tax will be more than offset by the abolition of royalties and
accelerated capital allowance deductions and will have a positive impact on
cash flow through the end of 2004.  The Company grew production by 6% to average 445,000 boe/d, slightly
below the target originally set at the beginning of 2002, due in part to higher
than anticipated maintenance in the North Sea. Talisman drilled 439 successful
wells in 2002 adding 196 mmboe of reserves, excluding net reserves revisions
and acquisitions, replacing 121% of production. Net of revisions and including
acquisitions, the Company added 159 mmboe of reserves, replacing 99% of
production.  Operating costs were up 12% to $6.48/boe, above the $6/boe target set
last year, largely due to higher oil field service and maintenance costs, a
higher percentage of North Sea volumes and the strengthening UK Pound Sterling.  SEGMENTED RESULTS REVIEW  Talismans operations in 2002 were conducted principally in four
geographic segments which are North America, North Sea, Southeast Asia and
Sudan. Production had also started in Algeria at year end with the first sale
in January 2003. Exploration is being conducted in otherareas outside
the principal geographic segments. On October 30, 2002,  the Company signed an agreement for the sale
of its operations in Sudan subject to government and consortium member
approvals and other closing conditions.  The following is a brief summary of the financial results of each
geographic segment. Additional geographic financial results disclosure may be
found in note 16 of the Consolidated Financial Statements. More detailed
analysis on the Companys results can be found after this Segmented Results
Review.  NORTH
AMERICA  During 2002, the North American operations contributed $437 million or
32% of the Companys pre-tax segmented income of $1.4 billion, down from $746
million (46% of $1.6 billion) in 2001. The Companys pre-tax segmented income
is before corporate G&A, interest, taxes and non-segmented foreign exchange
gains and losses. Net revenue in North America decreased 7% to $1.7 billion due
principally to lower natural gas revenue as a result of reduced prices. Total
North American operating expenses increased by 4% to $357 million due to
industry wide cost pressures, higher processing fees and increased natural gas
volumes. DD&A increased to $614 million, up from $585 million due to a full
year of amortization of the costs associated with the Petromet acquisition. Dry
hole expense increased to $128 million due to the expanded exploration budget,
the drilling of deeper natural gas targets and a strategic property review.  NORTH
SEA  The North Sea pre-tax segmented income increased slightly to $542
million and accounted for 40% of the Companys segmented income during 2002, up
from 33% in 2001. North Sea net revenue increased 20% to $1.9 billion on higher
production volumes and higher oil and liquids prices. Operating   SEGMENTED
PRE-TAX INCOME(1)  North
  America
  
  North Sea
  
  Southeast
  Asia
  
  Sudan
  
  Other(2)
  
  Total(millions of dollars)
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001Revenue
  
  2,014
  
  2,332
  
  1,971
  
  1,638
  
  486
  
  439
  
  828
  
  638
  
  
  
  
  
  5,299
  
  5,047Royalties
  
  (373
  )
  (558
  )
  (96
  )
  (93
  )
  (130
  )
  (90
  )
  (328
  )
  (248
  )
  
  
  
  
  (927
  )
  (989
  )Other income
  
  38
  
  34
  
  40
  
  46
  
  1
  
  1
  
  1
  
  1
  
  
  
  
  
  80
  
  82Net Revenue
  
  1,679
  
  1,808
  
  1,915
  
  1,591
  
  357
  
  350
  
  501
  
  391
  
  
  
  
  
  4,452
  
  4,140ExpensesOperating
  
  (357
  )
  (343
  )
  (588
  )
  (467
  )
  (86
  )
  (70
  )
  (84
  )
  (66
  )
  
  
  
  
  (1,115
  )
  (946
  )DD&A
  
  (614
  )
  (585
  )
  (701
  )
  (558
  )
  (87
  )
  (93
  )
  (93
  )
  (77
  )
  
  
  
  
  (1,495
  )
  (1,313
  )Dry hole
  
  (128
  )
  (54
  )
  (9
  )
  (21
  )
  (4
  )
  (8
  )
  (13
  )
  (16
  )
  (20
  )
  (14
  )
  (174
  )
  (113
  )Exploration
  
  (66
  )
  (69
  )
  (20
  )
  (30
  )
  (19
  )
  (8
  )
  (6
  )
  (11
  )
  (74
  )
  (29
  )
  (185
  )
  (147
  )Other
  
  (77
  )
  (11
  )
  (55
  )
  23
  
  (11
  )
  2
  
  5
  
  (11
  )
  7
  
  (8
  )
  (131
  )
  (5
  )437
  
  746
  
  542
  
  538
  
  150
  
  173
  
  310
  
  210
  
  (87
  )
  (51
  )
  1,352
  
  1,616 
 (1)Segmented pre-tax income is
before corporate G&A,interest,taxes and non-segmented foreign exchange
gains and losses. (2)Other in 2002 and 2001
primarily relates to exploration activities in Trinidad, Algeria and Colombia.   20 
   expense increased to $588 million, up 26% from 2001 with higher volumes,
the strengthening Pound Sterling and increased maintenance and well workovers.
DD&A increased to $701 million, up from $558 million, due to increased
volumes and higher depreciation rates at certain fields. Other expense includes
property impairments of $74 million.  SOUTHEAST
ASIA  Southeast Asia contributed 11% ($150 million) to the Companys pre-tax
segmented income in both 2002 and 2001. An increase in oil revenues, primarily
from the inclusion of a full year of production from PM-3 CAA in
Malaysia/Vietnam, more than offset higher royalties in Indonesia to increase
net revenues to $357 million. Net revenue from natural gas sales were
unchanged. Operating costs increased $16 million to $86 million with the
inclusion of a full year of operating costs from PM-3 CAA and higher overhead
costs at Corridor in Indonesia. DD&A decreased $6 million to $87 million in
2002 due to 2001 including minor asset impairments. Exploration expense
increased $11 million due to the increased spending in Malaysia and Vietnam.  SUDAN  The Sudan operations in 2002 generated a pre-tax income of $310 million,
up from $210 million in 2001. Higher oil production and prices increased
Sudans corporate contribution to 23%. Operating costs and DD&A increased
primarily due to higher volumes.  CORPORATE RESULTS REVIEW  REVENUE  Revenues from oil and natural gas sales in 2002 were $5.3 billion, up
$252 million from 2001, on higher oil volumes ($254 million) and oil prices
($330 million), substantially offset by lower natural gas prices ($447
million).  DAILY PRODUCTION VOLUMES  2002
  
  2001
  
  2000Oil and liquids (mbbls/d)North America
  
  62.7
  
  66.0
  
  66.4North Sea
  
  127.5
  
  110.8
  
  111.9Southeast Asia(1)
  
  22.5
  
  20.9
  
  20.2Sudan
  
  60.0
  
  53.3
  
  45.9272.7
  
  251.0
  
  244.4Natural gas (mmcf/d)North America
  
  820
  
  809
  
  755North Sea
  
  122
  
  108
  
  122Southeast Asia(1)
  
  94
  
  93
  
  1111,036
  
  1,010
  
  988Total (mboe/d @ 6:1)
  
  445
  
  419
  
  409 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam.     Oil &
  Liquids Production
  (mbbls/d)
  
  Natural
  Gas Production
  (mmcf/d)
  
  Total
  Production
  (mboe/d)North
  America
  
  North
  Sea
  
  Southeast
  Asia
  
  Sudan
  
  Total
  
  
  
  North
  America
  
  North
  Sea
  
  Southeast
  Asia
  
  Total
  
  
  
  North
  America
  
  North
  Sea
  
  Southeast
  Asia
  
  Sudan
  
  Total98
  
  57.5
  
  57.5
  
  31.7
  
  
  
  146.7
  
  98
  
  631
  
  104
  
  13
  
  748
  
  98
  
  163
  
  75
  
  34
  
  
  
  27199
  
  58.5
  
  59.3
  
  28.8
  
  11.7
  
  158.3
  
  99
  
  681
  
  115
  
  108
  
  904
  
  99
  
  172
  
  79
  
  47
  
  12
  
  30900
  
  66.4
  
  111.9
  
  20.2
  
  45.9
  
  244.4
  
  00
  
  755
  
  122
  
  111
  
  988
  
  00
  
  192
  
  132
  
  39
  
  46
  
  40901
  
  66.0
  
  110.8
  
  20.9
  
  53.3
  
  251.0
  
  01
  
  809
  
  108
  
  93
  
  1,010
  
  01
  
  201
  
  129
  
  36
  
  53
  
  41902
  
  62.7
  
  127.5
  
  22.5
  
  60.0
  
  272.7
  
  02
  
  820
  
  122
  
  94
  
  1,036
  
  02
  
  199
  
  148
  
  38
  
  60
  
  445   21 
    In 2002, Talisman increased its daily production by 6% to 445 mboe/d
with oil and liquids production up 9% to 272,740 bbls/d and natural gas
increasing 3% to 1,036 mmcf/d.  Talismans natural gas production in North America averaged 820 mmcf/d,
up 11 mmcf/d. A successful drilling program (223 successful gas wells) and the
inclusion of a full year of production from the Petromet Resources Limited
properties acquired in mid-2001 offset natural declines. Increased lead times
to tie in new production, minor property dispositions and localized infrastructure
constraints delayed some expected production volumes in 2002. Fourth quarter
natural gas production averaged 826 mmcf/d with the tie in of new wells and an
acquisition in the Appalachia area of the US which contributed 10 mmcf/d.
Canadian oil and liquids production for 2002 averaged 62,676 bbls/d, down 5%,
due to natural declines, regulatory delays and minor property dispositions
offset by drilling at Chauvin and other core areas (146 successful oil wells).  North Sea oil and liquids production averaged 127,486 bbls/d, up 16,658
bbls/d or 15%. Growth came from the Hannay and Halley developments (on stream
in 2002), a full years production from Beatrice and Blake and development
drilling in other core areas. Production at Halley averaged 2,300 bbls/d while
Hannay averaged 2,400 bbls/d. Incremental production from Beatrice added 5,250
bbls/d and Ross/Blake increased 11,000bbls/d over 2001. Beatrice
was shut in during the first half of 2001 for pipeline repairs. Ross had been
shut in for the second quarter of 2001 to allow production vessel modifications
for Blake production. Development program delays, unsuccessful development
wells and natural decline in other fields kept volumes below last years
forecast of 144,000-155,000 bbls/d. North Sea fourth quarter production was
impacted by maintenance work at the Ross/Blake FPSO and reduced production at
Halley pending the drilling of a water injector planned for 2003. Natural gas
production in 2002 increased 13% to 122 mmcf/d, slightly above forecast, due to
a temporary increase in pipeline capacity available to Talisman and the
acquisition of Lundin Oils carried interest in the Brae Field.  Southeast Asia natural gas production averaged 94 mmcf/d. Production
from OK Block (5 mmcf/d), which commenced at the end of the first quarter,
offset lower Caltex demand for Corridor natural gas (89 mmcf/d). Caltex is
currently the sole purchaser of Corridor natural gas; however, gas sales
agreements have been signed with other parties, which will result in additional
gas sales in the future. The construction of a pipeline and an expansion of the
Corridor gas facilities are currently underway to support the additional
anticipated gas sales. As a result of sales to Caltex declining below their
committed gas quantity of approximately 100 mmcf/d, Talisman recorded $10
million of deferred revenue for the year ($18 million to date).    NORTH
  AMERICA
  
  
  
  NORTH SEAOil &
  Liquids
  ($/bbl)
  
  
  
  Oil &
  Liquids
  ($/bbl)Netbacks
  
  Operating
  Costs
  
  Royalties
  
  Hedging
  (gain)
  
  Price
  
  
  
  Netbacks
  
  Operating
  Costs
  
  Royalties
  
  Hedging
  (gain)
  
  Price00
  
  21.29
  
  4.17
  
  8.74
  
  3.44
  
  37.64
  
  00
  
  26.24
  
  9.13
  
  1.57
  
  3.44
  
  40.3801
  
  18.82
  
  5.22
  
  6.88
  
  (0.12
  )
  30.80
  
  01
  
  24.33
  
  10.06
  
  1.85
  
  (0.17
  )
  36.0702
  
  19.97
  
  5.55
  
  6.85
  
  0.06
  
  32.43
  
  02
  
  25.93
  
  11.11
  
  1.60
  
  0.12
  
  38.76Natural Gas
  ($/mcf)
  
  
  
  Natural Gas
  ($/mcf)00
  
  2.77
  
  0.56
  
  1.07
  
  0.26
  
  4.66
  
  00
  
  2.87
  
  0.57
  
  0.14
  
  
  
  3.5801
  
  3.36
  
  0.67
  
  1.34
  
  0.02
  
  5.39
  
  01
  
  3.43
  
  0.46
  
  0.46
  
  
  
  4.3502
  
  2.78
  
  0.71
  
  0.75
  
  (0.28
  )
  3.96
  
  02
  
  2.80
  
  0.61
  
  0.48
  
  
  
  3.89   22 
   Southeast Asia liquids production averaged 22,469 bbls/d with PM-3 CAA
in Malaysia/Vietnam, acquired from Lundin Oil in 2001, contributing 5,617
bbls/d.  Sudan production averaged 60,109 bbls/d, up 13% with the tie in of new
wells, increased pipeline capacity and the increased use of pipeline drag
reducing agents and electrical submersible pumps.  COMMODITY PRICES  2002
  
  2001
  
  2000Oil and liquids ($/bbl)North America
  
  32.43
  
  30.80
  
  37.64North Sea
  
  38.76
  
  36.07
  
  40.38Southeast Asia(1)
  
  39.46
  
  35.97
  
  42.50Sudan
  
  37.79
  
  32.66
  
  38.5237.20
  
  33.99
  
  39.48Natural gas ($/mcf)North America
  
  3.96
  
  5.39
  
  4.66North Sea
  
  3.89
  
  4.35
  
  3.58Southeast Asia(1)
  
  4.72
  
  4.80
  
  5.644.03
  
  5.22
  
  4.63Company ($/boe)
  
  32.10
  
  32.91
  
  34.74 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam.Prices are before hedging activities and do not include synthetic oil.  World oil prices were slightly higher in 2002 and continued to increase
throughout 2002 and into 2003, when they surpassed US$35/bbl. Political
uncertainty in the Middle East and Venezuela, modest growth in demand and lower
US oil inventories have exerted upward pressure on prices.  Talismans North American oil and liquids price averaged $32.43/bbl, up
5% from last year on improved crude oil differentials. The benchmark West Texas
Intermediate (WTI) crude oil price averaged US$26.15/bbl in 2002, up 1% from
2001. The Companys natural gas price in North America averaged $3.96/mcf, down
27% from last year. North American natural gas prices were well below 2001
levels early in the year. However, concerns over gas supplies for the winter
season led to NYMEX prices approaching US$5/mcf by year end.  The Companys North Sea oil price averaged $38.76/bbl. Both Talismans
average oil price and Brent price are up from 2001. The Companys North Sea
natural gas price decreased 11% as a result of higher spot sales during the
summer months when gas prices are typically lower.  The Companys Southeast Asia oil price averaged $39.46/bbl, up 10% over
2001. The natural gas price in Southeast Asia averaged $4.72/mcf, down slightly
from 2001. Corridor gas production, which constitutes the majority of the
Companys gas sales in Southeast Asia, is exchanged for Duri crude oil on an energy
equivalent basis and is sold offshore with payment in US dollars. However, an
adjustment to Corridors gas price in 2002, relating to 2001, decreased
Talismans average Southeast Asia     SOUTHEAST
  ASIA
  
  
  
  SUDAN
  
  
  
  COMPANYOil &
  Liquids
  
  
  
  Oil &
  Liquids
  
  
  
  Oil &
  LiquidsNetbacks
  
  Operating
  Costs
  
  Royalties
  
  Hedging
  (gain)
  
  Price
  
  
  
  Netbacks
  
  Operating
  Costs
  
  Royalties
  
  Hedging
  (gain)
  
  Price
  
  
  
  Netbacks
  
  Operating
  Costs
  
  Royalties
  
  Hedging
  (gain)
  
  Price00
  
  20.30
  
  5.40
  
  13.36
  
  3.44
  
  42.50
  
  00
  
  16.28
  
  3.80
  
  15.00
  
  3.44
  
  38.52
  
  00
  
  22.55
  
  6.50
  
  6.99
  
  3.44
  
  39.4801
  
  18.45
  
  7.13
  
  10.69
  
  (0.30
  )
  35.97
  
  01
  
  16.61
  
  3.40
  
  12.78
  
  (0.13
  )
  32.66
  
  01
  
  20.78
  
  7.15
  
  6.22
  
  (0.16
  )
  33.9902
  
  16.64
  
  7.93
  
  14.83
  
  0.06
  
  39.46
  
  02
  
  18.96
  
  3.82
  
  14.94
  
  0.07
  
  37.79
  
  02
  
  22.29
  
  7.99
  
  6.83
  
  0.09
  
  37.20Natural
  Gas
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  Natural Gas00
  
  4.87
  
  0.39
  
  0.34
  
  0.04
  
  5.64
  
  
  
  
  
  
  
  
  
  
  
  
  
  00
  
  3.01
  
  0.54
  
  0.88
  
  0.20
  
  4.6301
  
  4.07
  
  0.47
  
  0.24
  
  0.02
  
  4.80
  
  
  
  
  
  
  
  
  
  
  
  
  
  01
  
  3.43
  
  0.63
  
  1.14
  
  0.02
  
  5.2202
  
  3.88
  
  0.59
  
  0.25
  
  
  
  4.72
  
  
  
  
  
  
  
  
  
  
  
  
  
  02
  
  2.89
  
  0.69
  
  0.67
  
  (0.22
  )
  4.03  23 
   reported gas price by $0.22/mcf. OK Block gas, which came on stream in
2002, is sold under contract at approximately $1.35/mcf and reduced Talismans
average price for the region.  The Sudan oil price increased 16% to $37.79/bbl due to an increase in
the Minas benchmark price and reduced transportation costs.  The Companys average sales prices are before a net hedging gain of $75
million, comprised of a $0.22/mcf gain on gas hedges (2001 $0.02/mcf loss) and
a $0.09/bbl loss on oil hedges (2001 $0.16/bbl gain). The physical and
financial commodity price contracts for 2003 outstanding at year end are
disclosed in notes 9 and 10 of 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 2003 results can
be found in the Outlook 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) of the Consolidated Financial Statements.  ROYALTIES  Average
  royalty rates (%)
  
  2002
  
  2001
  
  2000Oil and liquidsNorth America
  
  21
  
  22
  
  23North Sea
  
  4
  
  5
  
  4Southeast Asia(1)
  
  38
  
  30
  
  31Sudan
  
  40
  
  39
  
  3918
  
  18
  
  18Natural gasNorth America
  
  19
  
  25
  
  23North Sea
  
  12
  
  11
  
  4Southeast Asia(1)
  
  5
  
  5
  
  617
  
  22
  
  19Company
  
  18
  
  20
  
  18 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam.Royalty rates do not include synthetic oil or pipeline operations.  The consolidated royalty expense decreased to $927 million in 2002, with
lower royalties paid in North America due primarily to lower natural gas prices
partially offset by higher royalties in Southeast Asia and Sudan. The overall
corporate royalty rate dropped to 18% due to the impact of lower natural gas
prices more than offsetting other factors.  North American natural gas royalties, which are largely determined on a
sliding scale based on price, averaged 19%, down from 25% in 2001. The
Corporate royalty rate for oil and liquids was the same, year-over-year, at 18%
with an increase in Southeast Asia offsetting small decreases in other operating
areas. Royalties increased in Southeast Asia due to the depletion of a cost
recovery pool at Tanjung. Oil from PM-3 CAA in Malaysia/Vietnam has a current
royalty rate of 30%. Sudan royalties increased in the fourth quarter to 47%,
which resulted in the annual rate being 40%. The fourth quarter Sudan royalties
increased due to higher production and pricesand the annual royalty
adjustment where the average production, price and operating costs for the year
are applied in recalculating the total royalty due for 2002.  The UK abolished government oil and gas royalties effective January
2003. Talismans remaining North Sea royalties are in respect of non-government
royalty payments. The Companys North Sea royalty rate is expected to average
less than 2%, down from 5% in 2002.  OPERATING EXPENSE  2002
  
  2001
  
  2000Oil and liquids ($/bbl)North America
  
  5.55
  
  5.22
  
  4.17North Sea
  
  11.11
  
  10.06
  
  9.13Southeast Asia(1)
  
  7.93
  
  7.13
  
  5.40Sudan
  
  3.82
  
  3.40
  
  3.807.99
  
  7.15
  
  6.50Natural gas ($/mcf)North America
  
  0.71
  
  0.67
  
  0.56North Sea
  
  0.61
  
  0.46
  
  0.57Southeast Asia(1)
  
  0.59
  
  0.47
  
  0.390.69
  
  0.63
  
  0.54Company ($/boe)
  
  6.48
  
  5.79
  
  5.19 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam.Unit operating costs do not include synthetic oil or pipeline
operations.  Total operating expense for the Company increased $169 million to $1.1
billion due to increased maintenance and oil field service costs, higher
production volumes and the strengthening UK Pound Sterling. On a per unit
basis, costs increased 12% to $6.48/boe.  Unit operating costs in North America averaged $4.65/boe, up 5% from
2001. Oil and liquids unit operating costs increased 6% to $5.55/bbl, largely
due to lower production and higher oil field service costs. Unit operating
costs for natural gas increased to $0.71/mcf with higher processing and
maintenance costs.  North Sea oil and liquids unit operating costs increased $1.05/bbl or
10% to average $11.11/bbl. The strengthening UK Pound Sterling accounted for
over half of the unit cost increase with the remainder due to higher
maintenance and well workover costs. North Sea natural gas costs averaged
$0.61/mcf, up from $0.46/mcf in 2001, due to higher maintenance costs at Brae.  Southeast Asia unit operating costs averaged $6.13/boe, up from
$5.29/boe in 2001. Operating costs at Corridor averaged $0.60/mcf, up from
$0.47/mcf in 2001, partly due to higher overhead allocations from the operator.
OK Block natural gas production costs averaged $0.12/mcf. Oil and liquids unit
costs were $7.93/bbl in Southeast Asia with operating costs at PM-3 CAA
averaging $8.18/bbl. In Indonesia, oil and liquids unit costs increased in 2002
due to declining production.  Sudan operating costs averaged $3.82/bbl, up 12% with the increased use
of drag reducing agents and electrical submersible pumps.   24 
   DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE  2002
  
  2001
  
  2000$/boe
  
  $millions
  
  $/boe
  
  $millions
  
  $/boe
  
  $millionsNorth America
  
  8.44
  
  614
  
  7.98
  
  585
  
  6.79
  
  478North Sea
  
  12.99
  
  701
  
  11.86
  
  558
  
  10.59
  
  512Southeast Asia(1)
  
  6.24
  
  87
  
  7.00
  
  93
  
  5.87
  
  83Sudan
  
  4.24
  
  93
  
  3.98
  
  77
  
  4.72
  
  80Company
  
  9.19
  
  1,495
  
  8.58
  
  1,313
  
  7.70
  
  1,153 
 (1)Includes operations in Indonesia and
Malaysia/Vietnam. The Companys depreciation, depletion and amortization (DD&A)
expense increased to $1.5 billion or $9.19/boe, with half the increase due to
higher production volumes in the North Sea. The DD&A rate in North America
increased with a full year of amortization of the costs associated with the
Petromet acquisition. The 2001 DD&A expense in North America included $10
million of goodwill amortization. Goodwill ceased being amortized effective
2002. In the North Sea, higher DD&A, primarily at Beatrice and Ross/Blake,
contributed to the $1.13/boe increase. The Southeast Asia rate decreased in
2002 as the 2001 expense included $8 million of minor property impairments.
Sudans DD&A rate increased slightly to $4.24/bbl.  For additional information relating to DD&A refer to the MD&A
section entitled Application of Critical Accounting Policies and to note 5 of
the Consolidated Financial Statements.  DRY HOLE EXPENSE  (millions
  of dollars)
  
  2002
  
  2001
  
  2000North America
  
  128
  
  54
  
  29North Sea
  
  9
  
  21
  
  15Southeast Asia(1)
  
  4
  
  8
  
  17Sudan
  
  13
  
  16
  
  3Other(2)
  
  20
  
  14
  
  13174
  
  113
  
  77 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam. (2)Other includes Algeria (2002
 $nil; 2001  $5 million; 2000  $13 million) and Trinidad (2002  $20
million; 2001  $9 million, 2000  $nil).  Dry hole expense in North America increased with the write-off of 40
wells, higher exploration expenditures, a strategic property review and the
focus on deeper higher value targets. In the North Sea, most of the expense
related to the Remus (Beatrice) well. Two wells were written off in each of
Malaysia, Indonesia and Trinidad. In Sudan, seven wells were dry resulting in a
$13 million expense.  Under the Successful Efforts method of accounting for oil and gas
activities, the costs of unsuccessful exploration wells are written-off to dry
hole expense in the year such determination is made. Until such determination,
the costs are included in non-depleted capital. At year end, $309 million of
costs relating to exploration wells, down from $399 million in 2001, were
included in non-depleted capital and not subject to DD&A.  EXPLORATION EXPENSE  (millions
  of dollars)
  
  2002
  
  2001
  
  2000North America
  
  66
  
  69
  
  54North Sea
  
  20
  
  30
  
  13Southeast Asia(1)
  
  19
  
  8
  
  7Sudan
  
  6
  
  11
  
  8Other
  
  74
  
  29
  
  18185
  
  147
  
  100 
 (1)Includes operations in
Indonesia and Malaysia/Vietnam.  Exploration expense consists of geological and geophysical costs,
seismic, land lease rentals and indirect exploration expenses. There has been a
steady increase in the Companys exploration spending since 1999. Exploration
expense is closely tied to the total amount of exploration capital spent in a
year. Expenses constituting Other in 2002 relate mostly to activities in
Trinidad and Colombia.  CORPORATE EXPENSE  (millions
  of dollars)
  
  2002
  
  2001
  
  2000G&A expense
  
  138
  
  108
  
  95Interest expense
  
  164
  
  139
  
  136Capitalized interest
  
  25
  
  19
  
  16Preferred securities charges, net of tax
  
  24
  
  24
  
  22Other revenue
  
  80
  
  82
  
  99Other expenses (income)(1)
  
  113
  
  78
  
  64 
 (1)Prior year comparatives have
been restated for a new CICA accounting standard (see note 2 to the
Consolidated Financial Statements)  General and administrative (G&A) expense increased due to higher
legal and pension costs, salary increases and additional personnel due to
expanding investment and operations. On a per unit basis, G&A was $0.85/boe
in 2002, compared to $0.71/boe in 2001.  As a result of higher average debt levels during the year, interest on
long-term debt, including capitalized interest, increased to $189 million.
Interest capitalized in 2002 is associated with the Malaysia/Vietnam PM-3 CAA
development.  Preferred securities charges, net of taxes, have been charged directly
to retained earnings and are deducted from net income to determine net income
per share. Preferred security charges, before tax, totaled $42 million (2001 
$42 million).  Other revenue includes pipeline and custom treating revenues and
miscellaneous income. Other expenses for 2002 include the Kildrummy and
Beechnut write-offs ($74 million), foreign exchange losses ($28 million) and
losses on property dispositions ($10 million). The 2001 other expenses included
foreign exchange losses ($51 million), a write-off associated with the early
repayment of the Corridor project loan facility ($17 million) and a gain on
property disposition ($11 million). The detailed breakdown of other revenue and
other expenses (income) can be found in notes 11 and 12 to the Consolidated
Financial Statements.   25 
   INCOME
TAXES EFFECTIVE
INCOME TAX RATE  (millions
  of dollars)
  
  2002
  
  2001
  
  2000Income before tax
  
  1,068
  
  1,296
  
  1,537Less PRT
  
  124
  
  149
  
  150944
  
  1,147
  
  1,387Income tax expenseCurrent
  
  258
  
  342
  
  334Future
  
  162
  
  72
  
  196420
  
  414
  
  530Effective income tax rate (%)
  
  44
  
  36
  
  38  The Companys effective tax rate for 2002, after deducting Production
Revenue Tax (PRT), was 44%, compared to 36% in 2001. This increase over 2001 is
due to the UK enacting a 10% supplemental tax on North Sea oil and gas profits.
See note 13 of the Consolidated Financial Statements for additional information
on the Companys income taxes.  Current income tax expense decreased to $258 million in 2002 from $342
million in 2001, with the largest drop being in North America due to lower
natural gas prices. Lower current income tax was incurred in the UK while
higher production and oil prices increased current income tax expense in Sudan.  Partially offsetting the impact of the 10% supplemental UK tax was the
acceleration of capital allowance deductions. The net effect of these changes
is expected to be cash flow positive in the near term as the acceleration of
capital allowances will more than offset the new 10% tax. On a non-cash basis,
the UK provision for future tax liability was increased $128 million due to the
supplemental tax. The 2002 future tax expense is net of a $12 million reduction
in North America, which resulted from a decrease in the Alberta corporate tax
rate.  The UK Government levies PRT on North Sea fields which received
development approval before April 1993, based on gross profit after deducting
allowable expenditures, a cost uplift, a portion of losses from certain other
fields, abandonment costs and government royalties. PRT is deductible for
purposes of calculating corporate income tax.  CAPITAL SPENDING(1)  (millions
  of dollars)
  
  2002
  
  2001
  
  2000North America
  
  939
  
  976
  
  813North Sea
  
  518
  
  664
  
  527Southeast Asia(2)
  
  269
  
  149
  
  69Sudan
  
  98
  
  117
  
  70Other
  
  228
  
  115
  
  502,052
  
  2,021
  
  1,529 
 (1)Includes exploration,
development and net asset acquisitions expenditures but excludes corporate
acquisitions. (2)Includes operations in
Indonesia and Malaysia/Vietnam.  Natural gas continues to be the focus of the Companys exploration
activities in North America, supplemented by low risk oil projects. Of the $939
million of capital spending in North America, $321 million related to
exploration activities while development accounted for $502 million. The
Company participated in 424 wells in North America. Development spending was
concentrated in the predominantly gas producing core areas in the Alberta
Foothills, Greater Arch and Edson. Other spending included $90 million to
acquire additional lands in the US with approximately 10 mmcf/d of production.
Subsequent to year end, additional acquisitions were made in the US for $390
million, adding an incremental 55 mmcf/d of gas production.  Total capital spending in the North Sea of $518 million included $134
million for exploration and $297 million for development, with the remainder
for property acquisitions. Expenditures included the Halley and Hannay
developments, development drilling at Claymore, Buchan, Piper, Saltire,
MacCulloch and the Tartan, Highlander and Petronella core area as well as
topside refurbishments at Claymore and Tartan. Exploration spending primarily
related to drilling the successful J-1 (Buchan) well, the Drum (Claymore) and
Eta 2 (Clyde) wells, as well as the Remus (Beatrice) and Kildrummy (Piper)
wells. The total North Sea capital spending in 2002 was below plan due to the
cancellation of the Kildrummy development and delays in other programs.
Interests were acquired in the producing fields Rubie, Renee and Ivanhoe/Rob
Roy as well as minor additional working interests in the Claymore and Balmoral
fields.  The PM-3 CAA development in Malaysia/Vietnam accounted for $175 million
(including $25 million of capitalized interest) or 65% of total capital
spending in Southeast Asia. A total of $73 million was spent in Indonesia with
the majority on the Corridor gas facilities expansion and development drilling
to support additional anticipated gas sales to Singapore. In addition to the
$269 million of capital spending in Southeast Asia, a $36 million investment
was made to acquire a 15% interest in Transasia Pipeline Company Pvt. Ltd.,
which owns a 40% interest in PT Transportasi Gas Indonesia, an Indonesian
pipeline company that owns and operates the Duri pipeline in Indonesia and is
currently building a pipeline from Indonesia to service gas markets in Batam
and Singapore. This investment is included in other assets and will be carried
at cost.  Capital spending in Sudan of $98 million was focused on ongoing
development drilling and the addition of new pipeline pumping stations.  Other areas accounted for $228 million of the 2002 capital spending.
Talisman spent $78 million in Trinidad, $107 million in Algeria and $22 million
in Colombia. During 2002, five exploration wells were drilled in Trinidad; one
on Block 2(ab) and four on Block 2(c). Based on the Companys review of the
drilling results and seismic information, a decision was made to proceed with
the Greater Angostura Project on Block 2(c) and to relinquish Block 2(ab). The
Algeria spending advanced the Ourhoud project to first oil production at the
end of 2002, while MLN is expected to come on stream in mid-2003. A 2D seismic
program was completed in Colombia and a 3D seismic program is ongoing.   26 
   RESERVE REPLACEMENT  Talisman drilled 439 successful wells in 2002, adding 196 mmboe of
reserves (before revisions and transfers), replacing 121% of production at a
cost of $8.87/boe. Including net revisions and acquisitions, 159 mmboe of
reserves were replaced (99% of production) at a cost of $12.15/boe.  During the year, the Company undertook an extensive review of thousands
of oil and gas wells on smaller properties in Canada. These reviews, combined
with the decision not to develop the Kildrummy field in the North Sea,
contributed to a downward revision in total proved reserves of approximately 38
mmboe, or less than 3% of the total.  Finding and development costs in any one year can be misleading due to
the long lead times associated with exploration and development. Therefore,
five year weighted averages are better indicators. Over the last five years,
the Company has replaced approximately 210% of production at a cost of
$7.29/boe. Net revisions and transfers over the past five years have resulted
in 54 mmboe of reserves being added to the Companys proved reserve base, or
approximately 7%.  FINDING,
DEVELOPMENT AND ACQUISITION COSTS  Proved
  F&D costs ($/boe)
  
  2002
  
  3-year 
  Average
  
  5-year 
  AverageF&D costs (excluding revisions and transfers)
  
  8.87
  
  6.98
  
  7.15F&D costs
  
  11.03
  
  6.86
  
  6.58Total including acquisitions (FD&A)
  
  12.15
  
  7.66
  
  7.29  LIQUIDITY AND CAPITAL RESOURCES  Talismans long-term debt at year end was $3 billion, including $265
million drawn on the Companys $1,049 million bank lines of credit. The Company
also maintains a shelf prospectus under which it may issue up to $500 million
of medium term notes in aggregate in the Canadian public debt market. The shelf
prospectus expires in March 2004.  During 2002, the Company issued $1,055 million of long-term debt
including $325 million of medium term notes under its previous shelf
prospectus, a $571 million (£250 million) Eurobond notes offering and a private
debt placement in the US for $159 million (US$100 million). Subsequent to year
end, the Company spent $390 million on acquisitions to expand the Companys
operations and land base in the US Appalachia area. During the first quarter of
2003, the Company expects to complete the Sudan sale. Refer to note 17 of the
Consolidated Financial Statements for additional information on the sale of the
Sudan operations.  In June 2003, $180 million of medium term notes mature and will be
repaid. No amount of the long-term debt has been classified as a current
liability as the Company has the ability to refinance amounts due within one
year with existing bank facilities.  The Company repurchased 3,847,500 of its common shares under its normal
course issuer bid (NCIB) during 2002 at a cost of $220 million
($57.24/share). Subsequent to year end, an additional 1,986,200 common shares
were repurchased for $113 million ($56.70/share). The total common shares
repurchased under the existing NCIB represents 87% of the 6,716,781 common
shares currently permitted to be repurchased. The NCIB expires on March 25,
2003 and it is expected to be renewed for an additional 5% of the Companys
outstanding common shares.  Two dividends of $0.30/share were paid in 2002 (total dividends were
$0.60/share). The Companys dividend is determined semi-annually by the Board
of Directors.  Talisman maintains targets for long-term debt of less than 2:1 debt to
cash flow and 40% debt to debt-plus-equity. At the end of 2002, Talisman met
the debt targets with ratios of 1.1:1 for debt to cash flow and 40% for debt to
debt-plus-equity. For purposes of these calculations, the Companys preferred
securities have been classified as equity.  The projected 2003 year end net debt position of the Company is expected
to decrease as a result of the proceeds from the Sudan sale. The 2003
anticipated cash flow is expected to be more than sufficient to fund the $2.1
billion of planned capital expenditures. Significant acquisitions, a prolonged
drop in commodity prices and the continuation of share repurchases would impact
the anticipated reduction in the Companys projected 2003 year end net debt
position.  For additional information regarding the Companys liquidity and capital
resources, refer to note 6 of the Consolidated Financial Statements.  Talismans investment grade corporate credit and senior unsecured
long-term debt credit ratings remain unchanged with Dominion Bond Rating
Service (DBRS), Moodys Investor Service, Inc. (Moodys) and Standard &
Poors (S&P) at BBB (high), Baa1 and BBB+ respectively. Due to the
subordinated nature of the preferred securities, they have a lower rating.
DBRS, Moodys and S&P have rated the preferred securities as Pfd-3 (high),
Baa3 and BBB-, respectively.  FINANCIAL
LEVERAGE AND COVERAGE RATIOS(1)  2002
  
  2001
  
  2000Long-term debt(2)to cash flow(3)(times)
  
  1.1
  
  1.2
  
  0.7Interest coverage  cash flow(3,4)(times)
  
  16
  
  19
  
  19EBITDAX(5)(millions of dollars)
  
  3,036
  
  2,859
  
  2,853Interest coverage  EBITDAX(5),(6)(times)
  
  16
  
  18
  
  18Long-term debt to debt-plus-equity(2)(%)
  
  40
  
  41
  
  32 
 (1)
  
  Preferred securities are classified as equity and the related charges
  have been excluded from interest expense.(2)
  
  Based on balances at December 31.(3)
  
  Cash flow is a non-GAAP measure the components of which are set out in
  note 14 of the Consolidated Financial Statements.(4)
  
  Cash flow plus current income taxes and interest expense, divided by
  the sum of interest expense and capitalized interest.(5)
  
  EBITDAX is a non-GAAP measure and represents earnings before interest,
  income taxes, depreciation, depletion, amortization, impairment writedowns,
  dry hole and exploration expense.(6)
  
  EBITDAX divided by the sum of interest expense and capitalized
  interest.   27 
   COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS  As part of its normal business, the Company 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; settlements of
derivative financial instruments; lease commitments relating to corporate
offices and 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 6 and 10 of 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.  DERIVATIVE FINANCIAL INSTRUMENTS AND COMMODITY SALES
CONTRACTS  The Company may manage 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 commoditysales contracts.
Commodity price derivative financial instruments resulted in a net increase to
recorded sales of $75 million (2001  $8 million increase; 2000  $377 million
decrease). The accounting policy with respect to derivative financial
instruments is set out in note 1(k) of the Consolidated Financial Statements.  At December 31, 2002, the Company had outstanding commodity price
derivative contracts that cover approximately 60,500 mcf/d (7%) of the
Companys anticipated 2003 North American natural gas production and 75,000
bbls/d (35%) of the Companys anticipated 2003 worldwide oil and liquids
production. An additional 85,750 mcf/d (10%) of anticipated 2003 North American
natural gas production had been committed under commodity sales contracts. At
year end, the Company had also committed 48,450 mcf/d of 2004 North American
gas production under commodity sales contracts. See notes 9 and 10 of the
Consolidated Financial Statements for additional details regarding the
contracts outstanding at year end.  Subsequent to year end, the Company entered into natural gas derivative
contracts for 57,500 mcf/d at US$4.86/mcf (NYMEX) for the period February 2003
to October 2004. The Company also entered into contracts for the period April
to October 2003 for an additional 14,000 mcf/d of collars with ceiling and
floor prices referenced to AECO of $7.50/mcf and $6.24/mcf and 9,500 mcf/d
referenced to Sumas with ceiling and floor prices of US$4.96/mcf and
US$3.92/mcf. In addition, the Company entered into a commodity sales contract
to sell 4,800 mcf/d for the period April to October 2003 at $4.24/mcf.  The following table includes the Companys expected future payment
commitments and estimated timing of such payments.  Payments expected(2),(3)(millions of dollars)Commitments
  
  Recognized in 
  financial statements
  
  Total
  
  Due within 
  1 year
  
  Due within 
  2-3 years
  
  Due within 
  4-5 years
  
  Due within 
  6-10 years
  
  Due within 
  11-15 years
  
  Due after 
  15 yearsLong-term debt
  
  Yes  Liability
  
  2,997
  
  180
  
  695
  
  693
  
  379
  
  576
  
  474Preferred securities
  
  Yes  Equity
  
  474
  
  
  
  
  
  
  
  
  
  
  
  474Office leases
  
  No
  
  191
  
  18
  
  30
  
  30
  
  75
  
  38
  
  Vessel leases
  
  No
  
  115
  
  52
  
  63
  
  
  
  
  
  
  
  Transportation andprocessing commitments
  
  No
  
  942
  
  145
  
  173
  
  133
  
  250
  
  203
  
  38Abandonment obligations(1)
  
  Yes  Partially accrued as
  liability
  
  1,731
  
  24
  
  49
  
  109
  
  232
  
  649
  
  668Min. work commitments(4)
  
  No
  
  461
  
  262
  
  152
  
  47
  
  
  
  
  
  Other service contracts
  
  No
  
  160
  
  16
  
  32
  
  22
  
  30
  
  30
  
  30Total
  
  
  
  7,071
  
  697
  
  1,194
  
  1,034
  
  966
  
  1,496
  
  1,684 
 (1)
  
  The abandonment obligation represents managements best estimate of
  the cost and timing of future dismantlement, site restoration and abandonment
  obligations based on engineering estimates using current costs and technology
  in accordance with existing legislation and industry practice.(2)
  
  Payments exclude ongoing operating costs related to certain leases,
  interest on long-term debt, preferred securities charges and payments made to
  settle derivative contracts.(3)
  
  Payments denominated in foreign currencies have been translated at the
  December 31, 2002 exchange rate.(4)
  
  Minimum work commitments include contracts awarded for capital
  projects and those commitments related to exploration or drilling
  obligations.  28 
   The Company also entered into agreements to sell 15,000 mcf/d of North
Sea natural gas production for the period April to September 2003 at $4.40/mcf.  Subsequent to the Eurobond notes offering, the Company entered into US
dollar cross currency swap contracts and interest rate swap contracts for an
equivalent amount of the bond which have in effect converted this indebtedness
into US dollars with a floating interest rate based on three month US LIBOR.
These swap contracts expire on December 5, 2009. In addition, the Company
entered into a forward rate swap agreement to effectively fix the rate of the
next three month US LIBOR payment due in March 2003 under the interest rate
swap contract.  The Company entered into US dollar/UK Pound Sterling forward swap
agreements to purchase £178 million over the first six months of 2003. These
swap agreements fix the exchange rate used to convert a portion of the
Companys US dollar denominated revenues received in the UK into Pounds
Sterling for purposes of paying its operating costs and capital expenditures.  The Company has systems and processes in place to minimize risks
associated with its derivatives program and credit risk associated with
derivatives counterparties. Management believes its commodity derivatives and
fixed priced sales program to be prudent in that it provides a degree of price
support during periods of falling commodity prices while providing the ability
to participate in price increases and, in the case of certain fixed price sales
contracts, guaranteed market access. The US dollar cross currency swap of the
Eurobond and the US dollar/UK Pound Sterling forward swap agreements reduce the
Companys exposure to foreign exchange movements.  APPLICATION OF CRITICAL ACCOUNTING POLICIES  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 significant estimates.
Actual results could differ from those estimates. A summary of significant
accounting policies adopted by Talisman can be found in note 1 to the December
31, 2002, Consolidated Financial Statements. Changes to these policies during
the current year are disclosed in note 2. In assisting the Audit Committees
review and approval or recommendations for approval, of the Companys financial
statements, management regularly meets and reviews with the committee, 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, that may have an impact on the Companysfinancial
results relate to the accounting for property, plant and equipment, abandonment
and goodwill. The rate at which the Companys assets are depreciated or otherwise
written-off and the abandonment liability provided for are subject to a number
of judgments about future events, many of which are beyond managements
control.  RESERVE
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 attempt to provide uniform reserve recognition criteria.
However, the process of estimating oil and gas reserves is inherently
judgmental. The reserve estimates are made using all available geological and
reservoir data as well as production performance data. As new data becomes
available, including actual reservoir performance, reserve estimates may
change. Reserves can be classified as proved, probable or possible with
decreasing levels of certainty as to the likelihood that the reserves will be
ultimately produced.  Reserve recognition is also impacted by economic considerations. In
order for reserves to be recognized, they must be producible under existing
economic and operating conditions, which is viewed as being at year end
commodity prices with an operating cost profile based on current operations. 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 no longer qualify for reserve recognition.  The Companys reserves and revisions to those reserves, though not
separately reported on the Companys balance sheet or income statement, impact
the Companys reported net income primarily through the amortization of the
Companys Property, Plant and Equipment (PP&E), asset impairments and the
provision for future abandonment and reclamation costs. As disclosed in the
Historical Proved Reserves table, net revisions during the past three years
have resulted in 12 mmbbls of oil equivalent being added to the Companys
proved reserve base, or approximately 1%.  DEPRECIATION,
DEPLETION AND AMORTIZATION EXPENSE  A significant portion of the Companys Property, Plant and Equipment 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 reserve 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 indicated above, the Companys proved estimated reserves have been
revised upward 1% over the last three years. This degree of change would have
resulted in an insignificant reduction to the DD&A expense during the past
year.   29 
   As outlined in the Companys DD&A accounting policy and PP&E
note (notes 1(d) and 5 of the Consolidated Financial Statements), $1.2 billion
of the Companys Property, Plant and Equipment is not currently subject to
DD&A. A significant portion of these costs ($730 million) relate to
development projects that will soon be on production, at which time
amortization will commence. Also included in the $1.2 billion of non-depleted
capital is $463 million related to the costs of acquired probable reserves
($154 million) and incomplete drilling activities, including those wells under
evaluation or awaiting production to commence ($309 million). Uncertainty
exists with 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 producible reserves.  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. Individual oil and gas assets are considered impaired under the
Successful Efforts method if their undiscounted future cash flows fall 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 (2002  $74 million; 2001  $8 million; 2000  $nil)
however, it is possible that future impairments may be material.  As an indication of the volatility of cash flow projections, at December
31, 2002, the estimated undiscounted future net cash flow before tax from
proved reserves at year end prices was $28.7 billion and it is estimated that a
$1/boe change in the commodity price assumption would change this amount by
approximately $1.1 billion. As indicated above, in determining whether an asset
is impaired, management uses its best estimate of future prices and costs and
risk-adjusted recoverable reserves including those classified as probable.  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 judgmentallyassigned. The
allocation process, including the determination of the appropriate discount
rate, 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
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.  FUTURE
ABANDONMENT AND SITE RESTORATION ACTIVITIES  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.
A liability for these costs is accrued based on estimated future production.
Accordingly, the annual expense associated with future abandonment and
reclamation activities is impacted by changes in the estimates of the expected
costs, timing of abandonment and future production (reserves) over which the
remaining unrecorded liability is amortized. During 2002, the abandonment
expense included in DD&A was $147 million. The total abandonment liability
is currently estimated at $1.7 billion, which is based on current costs and
technology and in accordance with existing legislation and industry practice.
If this liability had been estimated to be 10% higher, an additional $15
million may have been recorded as DD&A during 2002. Past revisions to the
abandonment estimate have not been significant.  FAIR
VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS UNDER US GAAP  As disclosed in note 1(k) of the Consolidated Financial Statements, the
Companys derivative financial instruments are treated as hedges under Canadian
GAAP. Accordingly, gains and losses on these instruments are not recorded in
the income statement until the hedged transaction is realized. These
instruments are carried at cost. For US GAAP purposes, these instruments are
recorded on the balance sheet at fair value with changes in fair value being
recorded as either income or an expense. The fair value of certain commodity
based instruments are highly volatile. The determination of fair value for
certain non-market traded instruments requires management to make significant
estimates. In addition, the meaningfulness of an instruments fair value on
December 31, 2002 and the appropriateness of recognizing income based on such
daily values should be viewed with caution. In determining the fair value of
its commodity based instruments, the Company uses an options pricing model
based on market determined price forecasts. For other fair values such as those
for its interest rate swaps, forward currency contracts and preferred
securities, the Company obtains multiple price quotes from external sources.   30 
   ACCOUNTING CHANGES DURING THE CURRENT YEAR  CHANGE
IN THE COMPANYS FUNCTIONAL CURRENCY  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) of 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.  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 exposure principally relates
to UK oil sales denominated in US dollars and Canadian dollar denominated
long-term debt that has not been allocated to the Canadian operations.  The Company adopted the US dollar as its functional currency effective
January 1, 2002, due to its increased exposure to the US dollar as a result of
the growth in international operations. Prior to January 1, 2002, the
functional currency of the Company was the Canadian dollar. The impact of this
change was to decrease net income by $15 million during 2002.  ACCOUNTING
FOR FOREIGN EXCHANGE GAINS AND LOSSES ON LONG-TERM DEBT  Effective January 1, 2002, as disclosed in note 2 of the Consolidated
Financial Statements, in accordance with a Canadian Institute of Chartered
Accountants (CICA) accounting standard, the Company no longer defers and
amortizes the gains or losses on foreign currency denominated long-term debt.
The impact of the change in accounting as a result of the new accounting
standard was to decrease net income in 2002 by $3 million. The Companys
comparative historical financial results have been restated for this required
accounting change. The previously reported net income for 2001 and 2000 was
decreased $53 million and $49 million, respectively.  At December 31, 2002, the Companys debt was denominated in US and
Canadian dollars and UK Pounds Sterling. The UK Pounds Sterling debt has been
effectively swapped into US dollars. A portion of the Companys debt (net of
cash) is allocated to the self-sustaining Canadian operations based on the
Companys net investment in Canada. Foreign exchange gains and losses may
result from the debt allocation if the total amount of net debt allocated
exceeds or is less than the Companys total Canadian dollar denominated debt.  The Companys foreign exchange accounting policy, including the
rationale and implications of adopting the US dollar as the Companys
functional currency, was discussed with the Audit Committee of Talismans Board
of Directors.  NEW 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. These new pronouncements include the following:  IMPAIRMENTS
OF LONG-LIVED ASSETS  Effective for 2004, if a long-term asset is identified as being
impaired, as determined by its undiscounted future cash flows, the amount of
impairment is to be calculated based on the assets fair value (present value
of expected future cash flows). This is consistent with the US GAAP
methodology. Currently, the impairment is calculated based on the assets
undiscounted future cash flows.  DISPOSAL
OF LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS  Effective for disposition activities initiated after May 1, 2003, this
pronouncement expands the scope of what assets or operations are to be
reclassified as Discontinued Operations and the conditions required to
reclassify them as such. This treatment eliminates a difference between US and
Canadian GAAP.  ASSET
RETIREMENT OBLIGATIONS (FUTURE SITE RESTORATION AND ABANDONMENT LIABILITIES)  Effective January 1, 2004, the CICA has adopted a new accounting
standard, which will change the method of accruing for costs associated with
the retirement of fixed assets. The standard will require entities to record
the fair value of a liability for an asset retirement obligation in the period
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Currently, these obligations are provided for using
the unit of production method or, for certain assets, using the straight-line
method over the estimated remaining lives of the assets. The US has adopted a
similar rule commencing January 1, 2003.  SALE OF SUDAN OPERATIONS  As disclosed in note 17 of the Consolidated Financial Statements, the
Company has executed an agreement for the sale of its operations in Sudan
subject to government and consortium member approvals and other closing
conditions. The impact of the sale of Sudan operations is not included in the
financial results of the Company as at December 31, 2002. Readers are referred
to note 16 in which the Sudan operations are reported as a separate geographic
segment.   31 
   RISKS AND UNCERTAINTIES  Talisman is exposed to operational risks inherent in exploring for,
developing and producing crude oil and natural gas. 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 for each reservoir; therefore, reserve estimates are
inherently imprecise. 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 projecting
future production, costs and expenses and the results, timing and costs of
exploration and development projects. Total amounts or time of production may
vary significantly from reserves and production estimates.  The Companys future success depends largely on its ability to find,
develop or acquire additional oil and gas reserves that are economically
recoverable.  Unless produced reserves
are replaced through successful development, exploration or acquisition
activities at acceptable costs, proved reserves will decline over time.
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.  Oil and gas drilling and producing operations are hazardous. They are
subject to many risks including the possibility of fire, mechanical failure,
pipe failure, chemical spills, uncontrollable flows of oil, natural gas or well
fluids, and other accidents or occurrences which could result in personal
injury or loss of life, damage or destruction of properties, pollution or other
environmental damage, interruption of business, regulatory investigations and
penalties and liability to third parties. The Company seeks to mitigate risks
and to protect against significant losses by maintaining a comprehensive
insurance program, while maintaining levels 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.  The energy industry is extremely competitive. This is especially true
with regard to exploration for, and development and production of, new sources
of oil and natural gas. As an independent producer of oil and natural gas, the
Company frequently competes against companies that are larger with greater
financial resources to acquire properties suitable for exploration, to contract
for drilling equipment and other services and to secure trained personnel.  Talisman is subject to extensive governmental regulation in the
countries in which it does business with respect to protection of the
environment and responsibility for environmental damage and site remediation. A
trend towardstricter environmental regulation and
protection controls could increase costs for Talisman and others in the
industry. Although Talisman maintains comprehensive programs to control health,
safety and environmental risks across its operations and to comply with
applicable governmental regulations and standards, accidental discharge of
pollutants or other environmental damage or violations of applicable law may
occur and may result in significant liability to Talisman. Talisman records
provisions for abandonment and restoration of its properties in accordance with
generally accepted accounting principles; however, the estimated costs
associated with abandonment and restoration are subject to uncertainties and
actual costs may exceed Talismans estimates.  The Companys operations may be adversely affected by changes in
governmental policies or social instability or other political, economic or
diplomatic 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, foreign exchange and repatriation restrictions, economic sanctions,
changing political conditions, the imposition of specific drilling obligations,
the development and abandonment of fields (including restrictions on
production), international monetary fluctuations and currency controls.
Indonesia, Algeria, Sudan and Colombia have been subject to recent economic or
political instability and social unrest, military or rebel hostilities.
Although the Company has entered into a definitive agreement for the sale of
its interest in the Greater Nile Oil Project in Sudan, as of the date of this
document, the transaction was not completed. Accordingly, Talisman continues to
have an interest in Sudan. There is civil unrest in Sudan, which apart from
short periods of calm, has continued inconclusively since 1956. There have been
isolated, politically motivated attacks on the oilfields and pipeline in Sudan.
Minor production interruptions occurred as a result of pipeline attacks.
Although security measures are in place to reduce the risk of future attacks,
the oilfields and pipeline may be targets of future attacks.  The US has imposed comprehensive economic sanctions against Sudan. These
sanctions apply to certain Sudan related transactions and activities in the US,
activities by US individuals and entities wherever located and transactions by
US and non-US persons involving US origin goods, technology or services. With
limited exceptions, the sanctions prohibit US persons from engaging in or
facilitating virtually all direct or indirect commercial, financial or trade
transactions of any nature with Sudan or the Government of Sudan, including its
entities and agents. As of the date hereof, Talisman (Greater Nile) B.V.
(TGNBV), a subsidiary of Talisman, holds a 25% interest in the Greater Nile
Petroleum Operating Company Limited (GNPOC) and the Greater Nile Oil Project.
GNPOC, which operates the Greater Nile Oil Project, and Sudapet, which is the
national oil company of Sudan and holds a 5% interest in GNPOC and the Greater
Nile Oil Project, are treated as the Government of Sudan for purposes of the
sanctions. Although neither TGNBV nor the Company is a US personand therefore
are not bound by the   32 
   sanctions, new laws or regulations could be enacted or the scope of the
sanctions could be expanded in a manner that could have an adverse effect upon
the Companys business and financial condition. Talisman has implemented
comprehensive procedures to identify and avoid potential activities or
transactions that may result in a contravention of the Sudanese sanctions by
any US person. The Canadian government has not imposed unilateral economic
sanctions on Sudan. In addition, in 2001 the United Nations removed its
sanctions on Sudan. Those sanctions were diplomatic and not economic.  On October 21, 2002, the President of the United States signed into law
the Sudan Peace Act. The legislation is designed to facilitate a comprehensive
solution to the civil war in Sudan, but does not contain any capital market
sanctions, as were included in an earlier version passed by the US House of
Representatives in June 2001.  From time to time, Talisman is the subject of litigation arising out of
its operations. Damages claimed under such litigation may be material or may be
indeterminate and the outcome of such litigation may materially impact the
Companys financial results. A suit, which seeks class action status, was filed
against the Company by the Presbyterian Church of Sudan and others on November
8, 2001 in the United States District Court for the Southern District of New
York under the Alien Tort Claims Act and has been subsequently amended. The
Republic of the Sudan is named in the suit. The suit seeks, among other things,
a declaration that Talisman Energy Inc. has violated international law in
connection with oil exploration and drilling activities in Sudan, an injunction
permanently restraining Talisman from continuing to cooperate with the
Government of Sudan, and unquantified compensatory and punitive damages.
Talisman intends to fully defend itself against this suit and has filed a
motion to dismiss the suit, which is currently under consideration by the
United States District Court.  OUTLOOK FOR 2003  Talisman expects production per share, after adjusting for the Sudan
sale, to increase 5% in 2003. Production for 2003 is expected to average
approximately 395,000-415,000 boe/d with the sale of Sudan expected to close in
the first quarter and the commencement of production from Algeria, the PM-3 CAA
development project in Southeast Asia and the recently acquired US gas
properties.  The Company expects cash flow per share of over $21 in 2003 ($2.8
billion), assuming US$28.50/bbl WTI oil and US$5.00/mcf NYMEX gas. Unit
operating costs are expected to average approximately $7/boe, which reflects small
increases in Canada and the North Sea, startup costs in Algeria and the sale of
Sudan. Net capital spending is expected to be $2.1 billion and excludes
corporate and asset acquisitions and the proceeds from the sale of Sudan.  NORTH
AMERICA  Natural gas continues to be the focus of the Companys exploration
activities in North America supplemented by low risk oil projects. Recently
announced acquisitions in northeast US have provided the Companys first US
based production in the Appalachia area. North American production in 2003 is
expected to average between 860-880 mmcf/d and 58,000-60,000 bbls/d for a total
of 200-205 mboe/d.  Estimated total capital spending of $975 million in 2003 will be over
80% directed at natural gas. The Company plans to participate in approximately
590 wells in 2003. Drilling costs are expected to increase in 2003 due to
higher rig utilization and the Companys continuing shift in focus from shallow
natural gas targets to deeper more technically challenging prospects. Several
infrastructure projects are planned to ease capacity constraints in some of the
Companys core areas including the Alberta Foothills and Greater Arch. Unit
operating costs are expected to increase 5% with higher processing costs, an
increase in the number of facilities and higher lifting costs associated with
activities designed to maintain or increase production.  NORTH
SEA  The Companys North Sea strategy is to focus on low risk development
projects and adjacent exploration opportunities around core operated properties
and infrastructure. Of the $532 million of planned capital spending, 75% will
be related to development projects. A total of eight exploration and 27
development wells are planned for 2003. The Blake Flank development is expected
to deliver first oil in the third quarter. Natural decline offsetting the
development work is expected to result in North Sea production averaging
between 115,000-120,000 bbls/d and 125-130 mmcf/d in 2003, for a total of
136-142 mboe/d. Unit operating costs are expected to increase 7% with the
reduced production.  SOUTHEAST
ASIA  Natural gas sales in Indonesia have decreased due to reduced demand
under the current gas supply contract with Caltex. Indonesian natural gas sales
are expected to average 95-100 mmcf/d in 2003. Additional sales are expected in
early 2004 when the pipeline to supply Singapore Power with natural gas from
Corridor PSC is completed. An expansion of the gas plant facilities at Corridor
PSC from 300-700 mmcf/d over the next three years is currently underway in
order to accommodate additional anticipated gas sales. Natural gas production
from the PM-3 CAA development in Malaysia/Vietnam is expected to commence in
the fourth quarter of 2003 with an annualized production rate of 10-15 mmcf/d.
The PM-3 CAA natural gas will be sold under a 10-year firm supply contract for
approximately 100,000 mcf/d at market price. This contract is extendable on
mutual agreement of the parties for an additional 10 years.   33 
   Oil and liquids production is expected to average between 20,000-22,000
bbls/d, with production from PM-3 CAA increasing to between 6,000-7,000 bbls/d
(annualized) as a result of production from the Phase 2 development scheduled
to start in the third quarter. Oil and liquids production in the Indonesian
blocks is expected to average 14,000-15,000 bbls/d due to natural decline.
Operating costs in Southeast Asia are expected to average $6/boe.  Talisman expects to spend $296 million (including capitalized interest)
in Malaysia/Vietnam during 2003, primarily on the PM-3 CAA development project.
Malaysia/Vietnam is expected to account for approximately 80% of the $366
million Southeast Asia exploration and development spending in 2003. In
addition to the construction of the related facilities, 21 development and six
exploration wells will be drilled in PM-3 CAA. Talisman also plans to drill
three to four exploration and appraisal wells, two to three on PM-305 in
Malaysia and one on Block 46/02 in Vietnam. The $70 million planned spending in
Indonesia will primarily relate to the facilities expansion at Corridor and the
drilling of additional wells at Corridor and the other Indonesian blocks.
Exploration activities will account for $25 million of the $70 million in
Indonesia.  ALGERIA  Production in the Ourhoud field commenced at year end. The pipeline has
been filled and production is currently averaging 1,800 bbls/d (net to
Talisman). Production from the second Algerian field, MLN, is expected to
commence mid-year. Total combined production is expected to average
9,000-10,000 bbls/d in 2003. Initial operating costs, which include startup
costs, are anticipated to be $8/bbl. A capital budget of $60 million will be
used to drill 13 development wells, complete and commission the Central Process
Facility and tie in wells.  SUDAN  The sale of the Sudan operations is expected to be completed during the
first quarter of 2003. The Sudan operating results will continue to be reported
as part of ongoing operations in 2003 until such time as the sales transaction
is completed. Additional information regarding the sale is included in note 17
of the Consolidated Financial Statements. Readers are also referred to note 16
where the Sudan operations are disclosed as a separate reporting segment.
Production for the first quarter is expected to average 60,000 bbls/d.  REST
OF WORLD  Trinidad is expected to account for $149 million of capital spending
with $99 million related to the Greater Angostura development project on offshore
Block 2(c). First production is expected in early 2005. Talisman expects to
spend $50 million in Trinidad to drill five offshore exploration wells and
conduct onshore seismic in the Eastern Block.  In Colombia, the exploration program of $33 million is expected to
include a seismic program and drilling two wells with the possibility of an
additional two wells in the latter part of the year.  COMMODITY PRICES  Management currently expects commodity prices in 2003 will average
US$28.50/bbl WTI oil and US$5/mcf NYMEX gas. However, continuing heightened
world tension, including the possibility of military conflict in the Middle
East and uncertainty over supply, makes price forecasting unusually difficult.  Including those contracts entered into during the early part of 2003,
Talisman has committed 25% of its anticipated 2003 North American natural gas
production under both commodity sales contracts and commodity price derivative
contracts. Approximately 161 mmcf/d has been fixed at an average price of
$5.83/mcf and 30 mmcf/d is under collars with an average floor and ceiling
price of $6.17/mcf and $7.21/mcf.An additional 26 mmcf/d is under three-way
collars that allow the Company to participate in gas prices up to an average
$3.56/mcf and will provide a $0.60/mcf premium to spot prices should natural
gas prices average below $2.73/mcf.  The Company has hedged 75,000 bbls/d of crude oil for 2003, of which
40,000 bbls/d have been fixed at US$24.45/bbl and 35,000 bbls/d are under crude
oil collars with a ceiling price of US$27.53/bbl and a floor price of
US$22.82/bbl.  A summary of the contracts outstanding at year end can be found in notes
9 and 10 of the Consolidated Financial Statements.  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 2003 financial performance is summarized in the
following table and is based on a WTI oil price of US$28.50/bbl, a NYMEX
natural gas price of US$5.00/mcf and an exchange rate of US$0.67/C$1.  APPROXIMATE
IMPACT IN 2003  (millions
  of dollars)
  
  Net Income
  
  Cash Flow(1)Volume changesOil  1,000 bbls/d
  
  4
  
  8Natural gas  10 mmcf/d
  
  5
  
  13Price changes(2)Oil  US$1.00/bblIncrease
  
  38
  
  36Decrease
  
  (49
  )
  (54
  )Natural gas (North America)(3) C$0.10/mcf
  
  11
  
  17Exchange rate changesUS increased by US$0.01
  
  27
  
  44£ increase by C$0.035
  
  (9
  )
  2 
 (1)
  
  Cash flow is a non-GAAP measure, the components of which are set out
  in note 14 of the Consolidated Financial Statements.(2)
  
  The impact of commodity contracts outstanding for 2003 has been
  included.(3)
  
  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.   34