EX-99.2 3 interimmda.htm EXHIBIT 99.2 - 2Q INTERIM MANAGEMENT'S DISCUSSION AND ANALYSIS interimmda.htm




















 
INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS
 
 

 
 

 
 

 
August 2, 2007

Forward-looking Statements

This interim MD&A contains statements that constitute forward-looking statements and forward-looking information (collectively, "forward looking statements") within the meaning of applicable securities legislation.  These forward-looking statements include, among others, statements regarding:  future cash provided by operating activities, anticipated asset dispositions, estimated timing of production, expected royalty rates and taxes, the Company's outlook for major projects, business strategy and plans; impact of new accounting pronouncements, outcome of litigation, and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance. 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.

Undue reliance should not be placed on forward-looking statements.  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 the Company 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, including unpredictable facilities outages;

-  
risks and uncertainties involving geology of oil and gas deposits;

-  
uncertainty of reserves estimates, reserves life and underlying reservoir risk;

-  
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;

-  
health, safety and environmental risks;

-  
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 of 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);

-  
competitive actions of other companies, including increased competition from other oil and gas companies or companies providing alternative sources of energy;

-  
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.

Readers are cautioned 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 - Risk Factors" and elsewhere in the Company's 2006 Annual Financial Report.  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.

Forward-looking statements are based on the estimates and opinions of the Company's management at the time the statements are made.  The Company assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change, except as required by law.

Advisory - Oil and Gas Information

Throughout this interim MD&A, the Company makes reference to production volumes.  Where not otherwise indicated, such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments.  In the US, net production volumes are reported after the deduction of these amounts.

 
Use of BOE Equivalents
 
Throughout the 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.  BOEs may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 mcf:1 bbl is based on an approximate energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

 
Management’s Discussion and Analysis (MD&A)
(August 2, 2007)

This discussion and analysis should be read in conjunction with the Unaudited Interim Consolidated Financial Statements of Talisman Energy Inc. (“Talisman” or the “Company”) as at and for the period ended June 30, 2007 and 2006, and the 2006 Audited Consolidated Financial Statements of the Company.  All comparative percentages are between the quarters ended June 30, 2007 and 2006, unless stated otherwise.  All amounts are in Canadian dollars unless otherwise indicated.

Second Quarter Results Summary

·  
Total production of 450 mboe/d, down from 473 mboe/d in the prior year due principally to Talisman’s ongoing asset rationalization program.  Production from continuing operations of 422 mboe/d, 1% above the same period in 2006.
·  
Total net income of $550 million, down from $686 million in the prior year.  Net income from continuing operations of $301 million as compared to $533 million in 2006.
·  
$914 million in capital expenditures.
·  
Produced first oil from the Tweedsmuir and Enoch fields in the UK.
·  
Sold additional non-core assets in North America for total proceeds of $516 million, resulting in an after-tax gain of $203 million.
·  
Repurchased 29 million shares under the Company’s normal course issuer bid program (“NCIB”) at a total cost of approximately $624 million.

 
Three months ended
Six months ended
June 30,
2007
2006
2007
2006
Financial (millions of C$ unless otherwise stated)
    
Net income from continuing operations
301
533
502
642
Net income from discontinued operations
249
153
568
241
Net income
550
686
1,070
883
C$ per common share
        
Net income – Basic
0.53
0.62
1.02
0.80
                    – Diluted
0.52
0.61
1.00
0.78
Net income from continuing operations
        
                    – Basic
0.29
0.48
0.48
0.58
                        – Diluted
0.28
0.47
0.47
0.57
Production (daily average)
      
Oil and liquids (bbls/d)
234,039
227,303
236,839
250,706
Natural gas (mmcf/d)
1,126
1,146
1,149
1,141
Continuing operations (mboe/d)
422
418
428
441
Discontinued operations (mboe/d)
28
55
32
57
Total mboe/d (6 mcf = 1 boe)
450
473
460
498
Total production (boe) per common share -Basic
0.04
0.04
0.08
0.08
Capital Expenditures1 (millions of C$)
914
1,062
2,211
2,170
1.
Capital expenditures are prior to acquisition and dispositions

Second quarter net income of $550 million and net income from continuing operations of $301 million decreased by 20% and 44%, respectively, from the same period of 2006, due principally to a $178 million future tax recovery in the prior year related to Canadian federal and provincial tax rate reductions.  In addition, operating, depreciation, depletion and amortization (“DD&A”), and dry hole costs increased in the current quarter.  The decline in net income was partly offset by increased gains on asset sales, totalling $203 million in the second quarter of 2007 compared to $78 million in the same period in 2006.

Asset Rationalization Program

In 2006, Talisman announced its intention to sell selected non-core assets in order to rationalize the Company’s asset base.  In accordance with Canadian generally accepted accounting principles, Talisman is required to report separately the results of continuing and discontinued operations.  Discontinued operations include the results from assets the Company expects to sell and the results, to the transaction closing date, of assets that have been sold.  Prior period results are restated to show both continuing and discontinued operations for comparative purposes.  See note 2 to the Unaudited Interim Consolidated Financial Statements.

Production from discontinued operations includes both production from sales completed in the quarter, until the date of closing and production from sales expected to close in the second half of the year.  Of the 28 mboe/d of production recorded as discontinued operations in the second quarter, 9 mboe/d represents production from asset sales closed in the quarter, while 19 mboe/d represents production from asset sales expected to close subsequent to quarter-end.

The majority of North American asset disposals announced in the fourth quarter of 2006 closed in the second quarter for proceeds of approximately $516 million, resulting in an after-tax gain of $203 million, which has been recorded in net income from discontinued operations.   The Company’s disposition of its indirect interest in Syncrude closed in the first quarter of 2007 for proceeds of $472 million, resulting in an after-tax gain of $277 million.

During the second quarter of 2007, the Company entered into agreements to sell two additional North American asset packages which are expected to close in the third quarter of 2007 for proceeds of approximately $250 million.  The Company’s previously announced disposition of its non-operated assets in the Brae area of the UK North Sea for consideration of US$550 million has an effective date of January 1, 2007 and is expected to close later in 2007.  The resulting gain on disposition of these assets will be recorded when the respective transactions close.

Daily Average Production, Before Royalties

   
Three months ended
  
Six months ended
June 30,
2007
2007 vs 2006 (%)
2006
  
2007
2007 vs 2006 (%)
2006
Continuing operations
              
Oil and liquids (bbls/d)
              
 
North America
39,328
(5)
41,195
  
40,310
(4)
41,980
 
United Kingdom1
  99,660
16
85,671
  
97,641
(1)
98,593
 
Scandinavia 1
29,931
1
29,638
  
30,916
(11)
34,556
 
Southeast Asia1
43,962
(18)
53,471
  
46,740
(11)
52,662
 
Other 1
21,158
22
17,328
  
21,232
(7)
22,915
 
 
234,039
3
227,303
  
236,839
(6)
250,706
Natural gas (mmcf/d)
              
 
North America
793
1
785
  
821
4
790
 
United Kingdom
39
15
34
  
41
8
38
 
Scandinavia
14
8
13
  
14
(7)
15
 
Southeast Asia
280
(11)
314
  
273
(8)
298
 
 
1,126
(2)
1,146
  
1,149
1
1,141
Continuing operations (mboe/d)
422
1
418
  
428
(3)
441
Discontinued operations
              
 
North America
              
 
-  oil and liquids (bbls/d)
5,309
  
12,327
  
5,690
  
12,864
 
-  natural gas (mmcf/d)
67
  
99
  
70
  
99
 
United Kingdom
              
 
-  oil and liquids (bbls/d)
6,001
  
12,807
  
6,074
  
12,507
 
-  natural gas (mmcf/d)2
38
  
76
  
50
  
90
Discontinued operations (mboe/d)
28
  
55
  
32
  
57
Total mboe/d (6 mcf = 1 boe)
450
(5)
473
  
460
(8)
498
1.
Includes oil volumes produced into inventory, excludes oil volumes sold out of inventory, for the three months ended June 30, 2007 of 5,452 bbls/d, 1,949 bbls/d, 1,131 bbls/d and (1,881) bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively, and for the three months ended June 30, 2006 of 1,024 bbls/d, 476 bbls/d, 1,602 bbls/d and 1,432 bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively.
 
Includes oil volumes produced into inventory, excludes oil volumes sold out of inventory, for the six months ended June 30, 2007 of (1,799) bbls/d, (963) bbls/d, 2,016 bbls/d and 4,199 bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively, and for the six months ended June 30, 2006 of (1,672) bbls/d, (580) bbls/d, 217 bbls/d and 1,280 bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively.
2.
Includes gas acquired for injection and subsequent resale of 17 mmcf/d and 16 mmcf/d in the second quarter and year-to-date periods of 2007, respectively, and 28 mmcf/d and 21 mmcf/d in the second quarter and year to date periods of 2006, respectively.

The Company’s average oil and liquids production for the quarter was 245,349 bbls/d, 3% below the prior year, while production from continuing operations for the quarter was 234,039 bbls/d, up 3% from last year.  During the quarter, total natural gas production was 1,231 mmcf/d, 7% below the same period last year, with production from continuing operations decreasing 20 mmcf/d to an average of 1,126 mmcf/d.

In North America, oil and liquids production from continuing operations was down slightly from 2006 due primarily to plant turnarounds at Edson and the Greater Arch combined with natural declines.  Natural gas production in North America increased by 8 mmcf/d due to successful drilling in the Alberta Foothills and Edson, which increased production by 46 mmcf/d.  Realized increases were largely offset by a planned turnaround at Monkman resulting in a decrease of 37 mmcf/d in the quarter.

In the UK, oil and liquids production from continuing operations increased by 13,989 bbls/d due principally to 4,466 bbls/d of production from the Auk/Fulmar acquisition that closed on December 1, 2006 and first production from Tweedsmuir and Enoch in May, which averaged over 6,000 bbls/d in the quarter.  In addition there were increases from Scapa following a successful infill development well, and Piper where mechanical failures reduced production in 2006.

In Scandinavia, oil and liquids production was relatively unchanged from 2006 as the increased rates from the successful infill wells drilled at Brage in the first quarter of 2007 and Varg late in 2006 were offset by planned shutdowns at Gyda, Brage and Veslefrikk.

In Southeast Asia, oil and liquids production declined 9,509 bbls/d.  Oil and liquids production in Malaysia/Vietnam was 28,387 bbls/d, down 22% from 2006 mainly due to a planned shutdown to commission the BRE gas processing plant, tie in the Ca Mau pipeline to Vietnam and other routine maintenance at PM-3 CAA and PM-305.  Talisman recognized 2,600 bbls/d of historical production during the second quarter related to the unitization of its Murai discovery in PM-305.  In Indonesia, production remained relatively flat over the same period last year, averaging 11,038 bbls/d in the quarter.  Production in Australia averaged 4,537 bbls/d, down 24% as a result of a shutdown at the Laminaria facility in April, a 16 day planned shutdown in May and post-shutdown problems in June, which have been resolved.

Natural gas production in Malaysia/Vietnam averaged 63 mmcf/d in the quarter, a decrease of 46 mmcf/d compared to 2006 due to a planned 12 day shutdown at PM-3 CAA.  Production in Malaysia/Vietnam included the first natural gas sales from PM-3 CAA to Vietnam.  This gas is sold under the same terms as the existing gas sales to Malaysia with amounts received offshore in US dollars.  Gas sales increased 6 mmcf/d in the second quarter compared to the first quarter with the partial commissioning of the Bunga Raya-E gas processing facility.  Indonesia gas production was 6% higher than last year, averaging 216 mmcf/d due to strong gas nominations at Corridor.

Production from Other areas increased to 21,158 bbls/d principally due to a 47% increase in production from Algeria to 12,890 bbls/d following the compressor outage in 2006.  Production from Trinidad and Tobago declined to 7,150 bbls/d, from 7,648 in the same period in 2006, mainly due to natural declines.

Company Netbacks 1, 2

   
Three months ended
Six months ended
June 30,
2007
2006
2007
2006
Oil and liquids ($/bbl)
          
   Sales price
  
73.32
74.39
69.36
70.85
   Hedging (gain) loss
  
(0.47)
0.37
(0.77)
0.22
   Royalties
  
10.98
13.57
10.81
11.31
   Transportation
  
1.18
1.01
1.23
1.01
   Operating costs
  
17.18
15.74
16.84
13.56
   
44.45
43.70
41.25
44.75
Natural gas ($/mcf)
          
   Sales price
  
7.53
6.94
7.43
7.72
   Hedging (gain) loss
  
(0.09)
      (0.19)
(0.14)
(0.15)
   Royalties
  
1.47
1.36
1.46
1.54
   Transportation
  
0.25
0.22
0.25
0.26
   Operating costs
  
0.99
0.90
1.01
0.87
   
4.91
4.65
4.85
5.20
Total ($/boe)  (6 mcf = 1 boe)
          
   Sales price
  
60.50
59.01
57.97
59.87
   Hedging (gain) loss
  
(0.51)
(0.35)
(0.80)
(0.28)
   Royalties
  
10.01
11.02
9.87
10.39
   Transportation
  
1.32
1.16
1.36
1.25
   Operating costs
  
12.07
10.89
11.88
9.82
   
37.61
36.29
35.66
38.69
1.
Netbacks do not include synthetic oil and pipeline operations.  Additional netback information by major product type and region is included elsewhere in this MD&A.
2.
Includes impact of discontinued operations.

During the second quarter, the Company’s average netback was $37.61/boe, 4% higher than in 2006.  Talisman’s realized price of $60.50/boe was 3% higher than 2006, principally due to higher North American gas prices.  Increased operating costs and transportation expenses were partly offset by lower oil royalties and increased hedging gains in the quarter.

Prices and Exchange Rates

   
Three months ended
  
Six months ended
June 30,
2007
2007 vs 2006 (%)
2006
  
2007
2007 vs 2006 (%)
2006
Oil and liquids ($/bbl)
              
 
North America
56.67
(11)
63.34
  
55.07
(2)
56.28
 
United Kingdom
74.89
(1)
75.97
  
69.93
(4)
73.22
 
Scandinavia
77.11
-
77.25
  
70.71
(6)
75.07
 
Southeast Asia
81.42
3
78.92
  
79.14
4
76.26
 
Other
78.45
-
78.60
  
73.94
1
73.54
 
 
73.32
(1)
74.39
  
69.36
(2)
70.85
Natural gas ($/mcf)
              
 
North America
7.65
17
6.52
  
7.65
-
7.66
 
United Kingdom
6.47
(25)
8.61
  
7.19
(24)
9.46
 
Scandinavia
4.59
(17)
5.54
  
4.51
2
4.42
 
Southeast Asia
7.58
-
7.57
  
6.95
(5)
7.34
 
 
7.53
9
6.94
  
7.43
(4)
7.72
Total $/boe (6 mcf = 1 boe)
60.50
3
59.01
  
57.97
(3)
59.87
Hedging (gain) loss, not included in the above prices
            
 
Oil and liquids ($/bbl)
(0.47)
  
0.37
  
(0.77)
  
0.22
 
Natural gas  ($/mcf)
(0.09)
  
(0.19)
  
(0.14)
  
(0.15)
 
Total $/boe (6 mcf = 1 boe)
(0.51)
  
(0.35)
  
(0.80)
  
(0.28)
Benchmark prices and foreign exchange rates
              
 
WTI                    (US$/bbl)
65.03
(8)
70.72
  
61.60
(8)
67.13
 
Dated Brent        (US$/bbl)
68.76
(1)
69.59
  
63.26
(4)
65.66
 
Tapis                  (US$/bbl)
75.02
2
73.87
  
69.13
(2)
70.72
 
NYMEX            (US$/mmbtu)
7.56
11
6.82
  
7.26
(9)
7.95
 
AECO                (C$/gj)
6.99
17
5.95
  
7.03
(5)
7.37
US/Canadian dollar exchange rate
0.91
2
0.89
  
0.88
-
0.88
Canadian dollar/pound sterling exchange rate
2.18
6
2.05
  
2.24
10
2.04

Talisman’s second quarter realized commodity price increased $1.49/boe from last year to $60.50/boe as increases in North American gas prices were partially offset by decreases in oil and liquids and international gas prices.

In the quarter, Dated Brent traded at a premium to WTI as opposed to the discount experienced historically.  WTI has been discounted compared to Dated Brent, mainly due to reduced demand for WTI and logistics constraints in the Cushing, Oklahoma region.  Other international light crude streams also experienced improved differentials relative to WTI in the quarter, with a positive impact on approximately 80% of the Company’s crude oil production.

The Company’s North American natural gas price increase of 17% was consistent with the increase in AECO gas prices.

For the quarter ended June 30, Talisman recorded net hedging gains on commodity-based derivative financial instruments of $21 million, associated with gains on oil and liquids of $0.47/bbl and on natural gas of $0.09/mcf.  This compares to gains of $15 million associated with gains on natural gas of $0.19/mcf which more than offset losses on oil and liquids of $0.37/bbl during the same period in 2006.  As of July 1, the Company had derivative and fixed price physical contracts for approximately 10% of its remaining 2007 estimated production.  A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2006 Audited Consolidated Financial Statements and in note 9 to the June 30, 2007 Unaudited Interim Consolidated Financial Statements.

Royalties

   
Three months ended
June 30,
  
2007
2006
   
%
$ millions
%
$ millions
North America
  
18
136
20
131
United Kingdom
  
-
(1)
2
2
Scandinavia
  
-
1
-
1
Southeast Asia
  
39
196
44
260
Other
  
31
53
29
32
   
17
385
19
426
   
Six months ended
June 30,
  
2007
2006
   
%
$ millions
%
$ millions
North America
  
19
285
20
293
United Kingdom
  
1
(1)
2
4
Scandinavia
  
-
2
-
2
Southeast Asia
  
39
370
40
455
Other
  
31
74
29
82
   
17
730
17
836

The Company’s royalty expense from continuing operations for the second quarter was $385 million (17%), down $41 million from $426 million (19%) in 2006.  In North America, the royalty rate decreased due to the booking of deep gas royalty holidays in the second quarter.  In Southeast Asia, the rate decrease related principally to higher cost recovery associated with the Northern Fields Development.

Unit Operating Expenses

   
Three months ended
  
Six months ended
June 30,
2007
2007 vs 2006
2006
  
2007
2007 vs 2006
2006
 
$/boe
(%)
$/boe
  
$/boe
(%)
$/boe
North America
7.62
3
7.37
  
7.56
9
6.96
United Kingdom
22.70
19
19.14
  
22.79
40
16.30
Scandinavia
23.01
(12)
26.14
  
22.60
7
21.14
Southeast Asia
5.27
13
4.67
  
4.75
13
4.20
Other
4.68
(12)
5.33
  
4.66
12
4.15
 
12.07
11
10.89
  
11.88
21
9.82


Total Operating Expenses ($ millions)

   
Three months ended
Six months ended
  
 
June 30,
2007
2006
2007
2006
  
North America
121
118
247
222
  
United Kingdom
192
162
432
326
  
Scandinavia
64
72
140
141
  
Southeast Asia
42
41
78
74
  
Other
9
7
13
15
  
 
428
400
910
778
  
Pipeline
23
20
43
36
  
 
451
420
953
814
  

During the second quarter, total operating expenses from continuing operations increased by $31 million to $451 million.

In North America, operating costs were higher than the prior year due primarily to increases in lease rentals, processing costs and property and pipeline taxes.  The impact of increased expenditures and relatively flat production from continuing operations resulted in an increase in the unit operating expense.  In the quarter, increases in oil and liquids unit costs more than offset decreases in natural gas unit costs.

In the UK, operating costs increased $30 million of which $12 million, or $1.19/boe was due to the 6% strengthening of the pound sterling against the Canadian dollar.  The Auk/Fulmar interests acquired in the fourth quarter of 2006 contributed approximately $30 million and added $2.01/boe to UK unit costs.  These increases were partially offset by a new cost sharing agreement at Ross and lower workover costs at Claymore relative to the prior year.  Unit operating costs in the UK are expected to decrease with the addition of low cost production in the fourth quarter of 2007, mainly at Tweedsmuir.

In Scandinavia, operating costs decreased $8 million due to reduced maintenance at Gyda, Varg and Brage in 2007, partially offset by the 2% strengthening of the Norwegian kroner against the Canadian dollar.  Decreased costs combined with flat production resulted in a decrease in Scandinavian unit operating costs of 12%.

In Southeast Asia, total operating costs were relatively unchanged from the prior year as decreases in Australia operating expenses of nearly $7 million were mostly offset by increases in Malaysia/Vietnam due to the planned shutdowns in PM-3 CAA and PM 305 for routine maintenance.
 
Transportation Expenses
 

 
Three months ended
June 30,
2007
2006
 
$/boe
$ millions
$/boe
$ millions
North America
0.91
14
0.94
16
United Kingdom
1.53
16
1.51
12
Scandinavia
2.82
9
1.29
4
Southeast Asia
1.43
12
1.19
11
Other
1.00
2
0.84
2
 
1.32
53
1.16
45
 
Six months ended
June 30,
 
2007
 
2006
 
 
$/boe
 
$ millions
 
$/boe
 
$ millions
North America
0.94
32
1.05
38
United Kingdom
1.65
32
1.51
27
Scandinavia
2.91
18
1.83
12
Southeast Asia
1.37
23
1.20
22
Other
1.10
4
0.89
4
 
1.36
109
1.25
103

During the current quarter, transportation expenses from continuing operations increased $8 million to $53 million.

Unit Depreciation, Depletion and Amortization (DD&A) Expense (includes accretion of ARO)

   
Three months ended
  
Six months ended
June 30, ($/boe)
2007
 
2007 vs 2006 (%)
2006
 
  
2007
 
2007 vs 2006 (%)
2006
 
North America
16.87
14
14.84
  
16.41
14
14.37
United Kingdom
16.33
19
13.68
  
15.91
30
12.25
Scandinavia
27.50
31
21.04
  
27.72
43
19.35
Southeast Asia
7.47
30
5.76
  
7.94
31
6.08
Other
7.69
(17)
9.24
  
8.61
(7)
9.25
 
14.98
19
12.55
  
15.08
25
12.11


Total Depreciation, Depletion and Amortization (DD&A) Expense (includes accretion of ARO)

   
Three months ended
Six months ended
  
 
June 30, ($ millions)
2007
2006
2007
2006
  
North America
262
232
525
452
  
United Kingdom
149
113
305
236
  
Scandinavia
76
60
172
132
  
Southeast Asia
61
54
130
112
  
Other
17
13
27
36
  
 
565
472
1,159
968
  
Second quarter DD&A expense from continuing operations was $565 million, up 20% from the same quarter in 2006.

The DD&A rate in North America increased due to higher drilling and development costs, increased capital expenditures on Midstream Operations and increased land amortization costs.

The total DD&A expense in the UK increased $36 million to $149 million, principally due to the 6% strengthening of the UK pound sterling against the Canadian dollar and an increase in the depletable base.

In Scandinavia, total DD&A charges increased $16 million to $76 million, principally due to an increase in the depletable cost base and a 2% strengthening of the Norwegian kroner against the Canadian dollar.

The unit DD&A rate for Southeast Asia increased primarily due to an increase in the depletable cost base.

Other ($ millions)

 
June 30,
  
Three months ended
Six months ended
 
2007
2006
2007
2006
General and administrative
  
53
55
113
115
Dry hole expense
  
113
19
213
83
Stock-based compensation
  
43
   (46)
85
-
Other expense
  
(7)
     48
(22)
72
Interest costs capitalized
  
23
16
51
29
Interest expense
  
50
43
97
87
Gain on held-for-trading financial instruments
  
(63)
-
(26)
-
Other revenue
  
41
27
74
55

Dry hole expense for the second quarter of 2007 was up $94 million from the prior year and includes $57 million in North America, $49 million in Scandinavia, $5 million in the UK and $2 million in the rest of the world.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units as at June 30, 2007.  The Company’s stock-based compensation expense is based on the difference between the Company’s share price and the exercise price of its stock options or cash units. During the second quarter of 2007, $43 million was expensed.  The Company paid cash of $83 million ($40 million in 2006) to employees in settlement of fully accrued option liabilities for options exercised.  Since the introduction of the cash feature, approximately 97% of options exercised have been exercised for cash, with only 3% exercised for shares, resulting in reduced common share dilution.

Capitalized interest expense is associated with the Tweedsmuir, Wood, Blane, Yme and Rev development projects in the North Sea and the Northern Fields development in Malaysia.  Upon commencement of production, interest is no longer capitalized.  Tweedsmuir commenced production May 8, with Wood and Blane scheduled to come on production in the third quarter of 2007.

The gain on held-for-trading financial instruments includes the fair value change in the quarter of commodity price derivatives that are not designated as hedges and the change in value of the Canadian Oil Sands Units, which the Company received as partial consideration on disposition of its indirect interest in Syncrude.  See notes 1 and 9 of the Unaudited Interim Consolidated Financials Statements.
Other revenue of $41 million includes $30 million of pipeline and processing revenue.

Taxes ($ millions)

Effective Income Tax Rate

 
June 30,
Three months ended
Six months ended
2007
2006
2007
2006
Income from continuing operations before taxes
 
650
 
737
 
1,077
 
1,676
Less PRT
       Current
       Deferred
 
75
(2)
 
65
(1)
 
148
(7)
 
147
2
Total PRT
73
64
141
149
 
577
673
936
1,527
Income tax expense
        
       Current income tax
113
189
286
521
       Future income tax
163
(49)
148
364
Total income tax expense
276
140
434
885
Effective income tax rate
48%
21%
46%
58%


The effective tax rate is expressed as a percentage of pre-tax income adjusted for Petroleum Revenue Tax (PRT), which is deductible in determining taxable income.  The Company’s effective tax rate for the current quarter is higher than in 2006 due primarily to the impact of last year’s $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions.  Exclusive of this one time non-cash adjustment, the 2006 second quarter’s effective rate was 47%.  In the second quarter of 2007, the Company recorded a $26 million future tax recovery related to further reductions in the Canadian federal tax rates.  The effective tax rate for the six months ended June 30, 2007 is 12% below the comparable period in 2006 due to the impact of a one time non-cash charge of $325 million in the UK in the first quarter of 2006 associated with an increase in the tax rate from 40% to 50%.

Capital Expenditures1

   
Three months ended
  
Six months ended
June 30,
2007
2007 vs 2006 (%)
2006
  
2007
2007 vs 2006 (%)
2006
(millions of C$)
              
North America
258
(59)
623
  
877
(30)
1,259
United Kingdom
352
15
306
  
721
29
557
Scandinavia
117
77
66
  
242
103
119
Southeast Asia
137
128
60
  
248
107
120
Other
47
  
(4)
  
109
  
96
Corporate, IS and Administrative
3
  
11
  
14
  
19
 
914
(14)
1,062
  
2,211
2
2,170
Acquisitions
-
  
-
  
4
  
1
Dispositions
(16)
  
-
  
(16)
  
(2)
Discontinued Operations
              
Proceeds on disposition
(516)
  
(228)
  
(746)
  
(228)
Capital expenditures
11
  
29
  
22
  
59
Total
393
(54)
863
  
1,475
(26)
2,000
1.  
Capital expenditures exclude corporate acquisitions.

North America capital expenditures for the current quarter totalled $258 million, with exploration costs of $124 million and development costs of $134 million (including plant and equipment).  These expenditures included the drilling of 26 gas wells and 26 oil wells.

Expenditures in the UK during the second quarter were comprised of $43 million on exploration and $309 million on development, which included the ongoing development of the Tweedsmuir, Enoch, Affleck, Galley, Blane, Wood and Duart fields.

In Scandinavia, the Company spent $28 million on exploration and $89 million on development, including the Rev, Blane and Yme development projects.

In Southeast Asia, capital expenditures of $137 million included $38 million on exploration, principally on the Naga Dalam well in PM 314, and development spending of $99 million, primarily on the Northern Fields project and the drilling of three development wells in PM-3 CAA in Malaysia.

In Other, the Company spent $6 million on development activities in North Africa, $21 million on exploration and $12 million on development in Trinidad and Tobago and $8 million on exploration activities in the rest of the world.

There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2007 section of the Company’s MD&A dated March 13, 2007.
 
Long-term Debt and Liquidity
 

At June 30, Talisman’s long-term debt was $4.9 billion ($4.8 billion net of cash), up from $4.6 billion ($4.5 billion net of cash) at year-end.  During the first six months of 2007, the Company generated $2.1 billion of cash provided by operating activities and spent $2.2 billion on exploration and development.  It also received proceeds of $746 million from the disposal of North American assets and repurchased shares for $923 million.

During the quarter, the Company repaid the US$175 million 7.125% notes on maturity.  At June 30, the Company had $1.8 billion drawn against its available $2.7 billion of bank lines of credit.  In the second quarter, the Company increased its bank lines by $730 million.

At June 30, the Company had current assets of $2.1 billion and current liabilities of $2.8 billion, including assets and liabilities related to discontinued operations. Current assets include 8.2 million units ($270 million market value at June 30) of Canadian Oil Sands Trust.  In July, the Company sold its units in Canadian Oil Sands Trust for approximately $262 million, crystallizing a gain of $19 million, net of tax.  Working capital movements are difficult to predict, but management anticipates that accounts receivable will rise later in the year, due primarily to increasing revenue from incremental gas sales in Indonesia and increased production at Tweedsmuir.

At quarter-end, debt-to-debt plus book equity was 41%.  For the 12 months ended June 30, 2007, the debt-to-cash provided by operating activities ratio was 1.22:1.

In the first six months of 2007, the Company has repurchased 44,494,100 shares under the NCIB at a total cost of approximately $923 million.  Shareholders may obtain a copy of the Company's notice of intention to make a normal course issuer bid, free of charge, by accessing it on www.sedar.com or by emailing the Company at tlm@talisman-energy.com.

As at June 30 there were 1,019,754,255 common shares outstanding, increasing to 1,019,915,805 at July 31.

As at June 30, there were 66,298,367 stock options and 10,287,453 cash units outstanding.  Subsequent to June 30, 414,415 stock options were exercised for cash, 161,550 stock options were exercised for shares and 84,170 were cancelled, with 65,638,232 stock options outstanding at July 31.  Subsequent to June 30, 16,850 cash units were exercised and 69,920 cash units were cancelled, with 10,200,683 cash units outstanding at July 31.

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), Baa2 (stable) and BBB+, respectively.  S&P has assigned a negative outlook to its corporate rating.

Talisman continually investigates strategic acquisitions and opportunities, some of which may be material.  In connection with any such transactions, the Company may incur debt or issue equity.

Financial Instruments

Effective January 1, 2007, Talisman adopted the new CICA accounting standards related to Comprehensive Income (section 1530), Financial Instrument Recognition and Measurement (section 3855), Financial Instruments Disclosure and Presentation (section 3861) and Hedges (section 3865). These new standards require that all financial instruments be recorded at fair value on the balance sheet. As a result of adopting this standard, the Company realized the fair value of assets of $122 million and the fair value of liabilities of $18 million related to commodity price derivative contracts. The fair value of derivative contracts on the balance sheet at June 30 is presented as a current asset of $70 million, a current liability of $43 million and a long-term liability of $13 million.

The Company may use derivative instruments to manage commodity price, foreign exchange and interest rate risk. The Company may choose to designate derivative instruments as hedges. All derivative instruments in existence at December 31, 2006 continue to be designated as hedges and, as such, the gains and losses on the changes in fair value of these contracts are included in other comprehensive income until realized.

From January 1, 2007, the Company has elected not to designate any commodity price derivative contracts entered into as hedges for accounting purposes and consequently realizes changes in the fair value of such contracts in net income immediately, thereby increasing the volatility of net income. Since January 1, 2007, the Company has entered into several costless collar and swap natural gas derivative contracts. The change in fair value of these contracts in the period was a gain of $24 million which has been included in the gain on held-for-trading financial instruments.

In addition to its commodity derivatives, the Company has a fixed-to-floating interest rate swap and a cross currency interest rate swap.  These interest rate derivative contracts are designated as fair value hedges of a portion of the Company’s long-term debt.  The hedged portion of the long-term debt and hedging items are remeasured at fair value each reporting period and the respective changes in fair value are recorded in net income. In the second quarter of 2007, the changes in fair value in the derivatives and the hedged portion of long-term debt offset each other and are expected to continue to have no net impact on net income in future periods. The effect of revaluing the hedged portion of long-term debt to fair value resulted in a decrease of $19 million in the debt balance at June 30, 2007, with a corresponding $19 million liability recorded in other long-term obligations for the fair value of the derivative contracts.

During the first quarter of 2007, the Company settled a portion of its 2007 WTI costless collar covering a notional volume of 10,000 bbls/d for a gain of $40 million. The gain on settlement, net of tax, is included in accumulated other comprehensive income and will be realized as a hedging gain in net income over the period ending December 31, 2007, the term of the original hedge.

See notes 1 and 9 of the Unaudited Interim 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 annualized impact of these factors on the Company’s financial performance for 2007 is summarized in the following table and is based on an average WTI oil price of US$67.30/bbl, a NYMEX natural gas price of US$7.20/mmbtu and exchange rates of C$1=US$0.91 and £1=C$2.19.

Approximate Impact for 2007
      
 
(millions of dollars)
 
Net Income
  
Cash Provided by
Operating Activities
Volume changes
      
 
Oil - 1,000 bbls/d
8
  
12
 
Natural gas - 10 mmcf/d
8
  
16
Price changes1
      
 
Oil - US$1.00/bbl
43
  
44
 
Natural gas (North America)2 - C$0.10/mcf
12
  
17
Exchange rate changes
      
 
US$ increased by US$0.01
38
  
63
 
£ increase by C$0.023
(7)
  
2
1  
The impact of commodity contracts outstanding as of July 1 has been included.
2  
Price sensitivity on natural gas relates to North American natural gas only.  The Company’s exposure to changes in the natural gas prices in UK, Scandinavia and Malaysia/Vietnam is not material.  Most of the natural gas price in Indonesia 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.

Summary of Quarterly Results (millions of C$ unless otherwise stated)

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

 
Three months ended
 
2007
20061
20051
 
June 30
Mar. 311
Dec. 31
Sept. 30
June 30
Mar. 31
Dec. 31
Sept. 30
Gross sales
2,290
2,186
2,132
2,127
2,230
2,561
2,563
2,364
Total revenue
1,967
1,920
1,852
1,820
1,846
2,189
2,138
1,971
Net income from continuing operations
301
201
338
391
533
109
425
350
Net income
550
520
598
525
686
197
533
430
Per common share ($)2
                
  Net income from continuing
  operations
0.29
0.19
0.31
0.36
0.48
0.10
0.39
0.32
  Diluted net income from
  continuing operations
0.28
0.19
0.31
0.35
0.47
0.10
0.39
0.31
  Net income
0.53
0.49
0.55
0.48
0.62
0.18
0.48
0.39
  Diluted net income
0.52
0.48
0.54
0.47
0.61
0.17
0.47
0.38
1.
Prior periods have been restated to reflect the impact of discontinued operations.  See note 2 to the Unaudited Interim Consolidated Financial Statements.
2.
All per share amounts have been retroactively restated to reflect the Company’s three-for-one split in May 2006.  See note 5 to the Unaudited Interim Consolidated Financial Statements.

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters ended June 30, 2007.

During the second quarter of 2007, gross sales increased by $104 million over the previous quarter primarily due to increasing commodity prices offset partly by a strengthening of the Canadian dollar against the US dollar.  Net income from continuing operations increased by $100 million from the prior quarter as decreases in operating costs and DD&A along with gains on held-for-trading instruments, more than offset increased tax expenses.

During the first quarter of 2007, gross sales increased by $54 million over the previous quarter due to the impact of increased commodity prices, which more than offset the 3% decrease in total production.  Net income from continuing operations decreased $137 million from the previous quarter as the impact of the increase in gross revenue and decrease in dry hole and stock-based compensation expense was more than offset by increases in DD&A, operating costs and taxes and the gain on sale of a royalty interest in an undeveloped lease in the previous quarter.

During the fourth quarter of 2006, gross sales increased by $5 million over the previous quarter as the impact of reduced oil prices offset the 6% increase in total production.  Net income from continuing operations decreased $53 million from the third quarter as increases in charges for dry holes, exploration, stock-based compensation, DD&A and operating costs more than offset the impact of reduced taxes and the gain on sale of a royalty interest in an undeveloped lease.

During the third quarter of 2006, gross sales decreased by $103 million over the previous quarter due to decreased natural gas prices and reduced production.  Net income from continuing operations for the quarter decreased by $142 million, primarily due to the $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions recorded in the second quarter.

During the second quarter of 2006, gross sales decreased by $331 million over the previous quarter due to decreased production.  Net income from continuing operations for the quarter increased by $424 million, primarily due to the impact of a $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions and the $325 million future tax charge in the first quarter.

In the first quarter of 2006, gross sales decreased by $2 million over the previous quarter. Net income from continuing operations for the quarter decreased by $316 million, primarily due to the impact of a one-time non-cash adjustment of $325 million related to a UK income tax rate increase.

During the fourth quarter of 2005, gross sales increased by $199 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea.  Net income from continuing operations for the quarter increased by $75 million as the increased revenue combined with reduced stock-based compensation charges more than offset the impact of increases in operating, DD&A, royalty and tax expenses.

During the third quarter of 2005, higher commodity prices and production increased gross sales by $526 million.  Net income from continuing operations 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.

New Accounting Pronouncements

In December 2006, the Canadian Accounting Standards Board (AcSB) issued two new Sections in relation to financial instruments: Section 3862, Financial Instruments – Disclosures, and Section 3863, Financial Instruments – Presentation. Both sections will become effective for Talisman’s 2007 year end disclosure and will require increased disclosure regarding financial instruments.

In December 2006, the AcSB issued Section 1535, Capital Disclosures. This standard requires disclosure regarding what the Company defines as capital and its objectives, policy and processes for managing capital. This standard will be effective for Talisman’s 2007 year end disclosure.

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48 (FIN 48), Accounting for Uncertainty in Income Taxes an interpretation of FASB 109.  This interpretation prescribes a recognition threshold and measurement attributed for the financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return.  This interpretation will become effective for Talisman’s 2007 year end disclosure.  The Company is currently evaluating the impact of FIN 48 on its Consolidated Financial Statements and currently does not expect it to have a material impact on its results of operations or financial position.

Internal Controls over Financial Reporting
 
There were no changes in Talisman’s internal controls over financial reporting during the second quarter of 2007 that materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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


Product Netbacks
(unaudited)
                         
   
Three months ended June 30
  
Six months ended June 30
(C$ - production before royalties)
2007
2006
 
2007
2006
  
2007
2006
 
2007
2006
   
Oil and liquids ($/bbl)
  
Natural gas ($/mcf)
  
Oil and liquids ($/bbl)
  
Natural gas ($/mcf)
North
   Sales price
56.67
63.34
  
7.65
6.52
  
55.07
56.28
  
7.65
7.66
America
Hedging (gain) loss
(2.10)
-
  
(0.13)
(0.29)
  
(2.50)
-
  
(0.20)
(0.22)
 
   Royalties
11.84
13.56
  
1.31
1.21
  
11.44
12.04
  
1.38
1.51
 
   Transportation
0.45
0.56
  
0.18
0.18
  
0.46
0.58
  
0.18
0.20
 
   Operating costs
9.83
8.64
  
1.15
1.16
  
9.32
8.19
  
1.17
1.09
 
 
36.65
40.58
 
5.14
4.26
 
36.35
35.47
 
5.12
5.08
United
   Sales price
74.89
75.97
  
6.47
8.61
  
69.93
73.22
  
7.19
9.46
Kingdom
   Hedging (gain) loss
(0.20)
0.95
  
-
-
  
(0.75)
0.54
  
-
-
 
   Royalties
0.47
1.05
  
0.42
0.41
  
0.62
0.85
  
0.33
0.56
 
   Transportation
1.46
1.52
  
0.35
0.24
  
1.58
1.44
  
0.36
0.31
 
   Operating costs
24.50
22.01
  
1.31
0.63
  
24.94
18.60
  
1.35
0.71
 
 
48.66
50.44
 
4.39
7.33
 
43.54
51.79
 
5.15
7.88
Scandinavia
   Sales price
77.11
77.25
  
4.59
5.54
  
70.71
75.07
  
4.51
4.42
 
   Royalties
0.34
0.31
  
-
-
  
0.33
0.31
  
-
-
 
   Transportation
2.51
1.60
  
1.14
(0.48)
  
2.55
1.57
  
1.28
0.91
 
   Operating costs
24.77
28.06
  
-
-
  
24.30
22.63
  
-
-
 
 
49.49
47.28
 
3.45
6.02
 
43.53
50.56
 
3.23
3.51
Southeast
   Sales price
81.42
78.92
  
7.58
7.57
  
79.14
76.26
  
6.95
7.34
Asia
   Royalties
36.03
40.90
  
2.33
2.17
  
34.19
35.55
  
2.17
2.15
 
   Transportation
0.43
0.20
  
0.40
0.37
  
0.40
0.21
  
0.39
0.37
 
   Operating costs
7.90
7.41
  
0.46
0.31
  
6.86
6.33
  
0.43
0.32
 
 
37.06
30.41
 
4.39
4.72
 
37.69
34.17
 
3.96
4.50
Other
   Sales price
78.45
78.60
  
-
-
  
73.94
73.54
  
-
-
 
   Royalties
24.68
23.03
  
-
-
  
22.97
21.20
  
-
-
 
   Transportation
1.00
0.84
  
-
-
  
1.11
0.90
  
-
-
 
   Operating costs
4.69
5.35
  
-
-
  
4.68
4.16
  
-
-
 
 
48.08
49.38
 
-
-
 
45.18
47.28
 
-
-
Total Company
   Sales price
73.32
74.39
  
7.53
6.94
  
69.36
70.85
  
7.43
7.72
 
   Hedging (gain) loss
(0.47)
0.37
  
(0.09)
(0.19)
  
(0.77)
0.22
  
(0.14)
(0.15)
 
   Royalties
10.98
13.57
  
1.47
1.36
  
10.81
11.31
  
1.46
1.54
 
   Transportation
1.18
1.01
  
0.25
0.22
  
1.23
1.01
  
0.25
0.26
 
   Operating costs
17.18
15.74
  
0.99
0.90
  
16.84
13.56
  
1.01
0.87
 
 
44.45
43.70
 
4.91
4.65
 
41.25
44.75
 
4.85
5.20
                         
Unit operating costs include pipeline operations for the United Kingdom.
              
Netbacks do not include synthetic oil.
                      



Product Netbacks (1)
(unaudited)
                 
   
Three months ended
  
Six months ended
   
June 30
  
June 30
(US$ - production net of royalties)
2007
 
2006 (2)
 
2007
 
2006 (2)
North
Oil and liquids (US$/bbl)
              
America
   Sales price
51.59
  
56.45
  
48.58
  
49.52
 
   Hedging (gain) loss
(2.42)
  
-
  
(2.77)
  
-
 
   Transportation
0.52
  
0.64
  
0.51
  
0.64
 
   Operating costs
11.35
  
9.78
  
10.40
  
9.15
 
 
42.14
 
46.03
 
40.44
 
39.73
 
Natural gas (US$/mcf)
              
 
   Sales price
6.96
  
5.81
  
6.74
  
6.71
 
   Hedging (gain) loss
(0.14)
  
(0.32)
  
(0.21)
  
(0.25)
 
   Transportation
0.19
  
0.20
  
0.19
  
0.22
 
   Operating costs
1.27
  
1.27
  
1.26
  
1.19
 
 
5.64
 
4.66
 
5.50
 
5.55
United Kingdom
Oil and liquids (US$/bbl)
              
 
   Sales price
68.26
  
67.61
  
61.92
  
64.21
 
   Hedging (gain) loss
(0.18)
  
0.86
  
(0.65)
  
0.48
 
   Transportation
1.34
  
1.37
  
1.40
  
1.28
 
   Operating costs
22.44
  
19.89
  
22.19
  
16.55
 
 
44.66
 
45.49
 
38.98
 
45.90
 
Natural gas (US$/mcf)
              
 
   Sales price
5.88
  
7.65
  
6.29
  
8.28
 
   Transportation
0.34
  
0.23
  
0.33
  
0.29
 
   Operating costs
1.26
  
0.59
  
1.24
  
0.66
 
 
4.28
 
6.83
 
4.72
 
7.33
Scandinavia
Oil and liquids (US$/bbl)
              
 
   Sales price
69.99
  
68.72
  
62.39
  
65.80
 
   Transportation
2.29
  
1.42
  
2.26
  
1.38
 
   Operating costs
22.69
  
25.14
  
21.55
  
20.00
 
 
45.01
 
42.16
 
38.58
 
44.42
 
Natural gas (US$/mcf)
              
 
   Sales price
4.15
  
4.93
  
3.97
  
3.89
 
   Transportation
1.04
  
(0.40)
  
1.12
  
0.80
 
 
3.11
 
5.33
 
2.85
 
3.09
Southeast Asia
Oil and liquids (US$/bbl)
              
 
   Sales price
74.23
  
70.34
  
69.80
  
67.07
 
   Transportation
0.71
  
0.38
  
0.62
  
0.35
 
   Operating costs
12.95
  
13.78
  
10.70
  
10.44
 
 
60.57
 
56.18
 
58.48
 
56.28
 
Natural gas (US$/mcf)
              
 
   Sales price
6.90
  
6.75
  
6.16
  
6.46
 
   Transportation
0.52
  
0.46
  
0.50
  
0.46
 
   Operating costs
0.61
  
0.39
  
0.55
  
0.40
 
 
5.77
 
5.90
 
5.11
 
5.60


                 
   
Three months ended
  
Six months ended
   
June 30
  
June 30
(US$ - production net of royalties)
2007
 
2006 (2)
 
2007
 
2006 (2)
Other
Oil (US$/bbl)
              
 
   Sales price
71.59
  
69.63
  
65.44
  
64.16
 
   Transportation
1.34
  
1.06
  
1.41
  
1.10
 
   Operating costs
6.23
  
6.79
  
5.98
  
5.10
 
 
64.02
 
61.78
 
58.05
 
57.96
Total Company
Oil and liquids (US$/bbl)
              
 
   Sales price
66.79
  
66.22
  
61.29
  
62.17
 
   Hedging (gain) loss
(0.50)
  
0.41
  
(0.79)
  
0.23
 
   Transportation
1.26
  
1.09
  
1.28
  
1.05
 
   Operating costs
18.37
  
17.14
  
17.50
  
14.19
 
 
47.66
 
47.58
 
43.30
 
46.70
 
Natural gas (US$/mcf)
              
 
   Sales price
6.85
  
6.18
  
6.55
  
6.77
 
   Hedging (gain) loss
(0.10)
  
(0.22)
  
(0.15)
  
(0.17)
 
   Transportation
0.28
  
0.25
  
0.28
  
0.29
 
   Operating costs
1.13
  
1.00
  
1.11
  
0.96
 
 
5.54
 
5.15
 
5.31
 
5.69
                 
(1) Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty
volumes.
(2) Unit operating costs include pipeline operations for the North Sea. Prior years have been restated
accordingly.
Netbacks do not include synthetic oil.