INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

November 1, 2007

Management’s Discussion and Analysis (MD&A)

(November 1, 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 three and nine month periods ended September 30, 2007 and 2006, and the 2006 MD&A and audited Consolidated Financial Statements of the Company.  All comparative percentages are between the quarters ended September 30, 2007 and 2006, unless stated otherwise.  All amounts are in Canadian dollars unless otherwise indicated.

Third Quarter Results Summary

·   Total production of 441 mboe/d, down from 460 mboe/d in the prior year due principally to Talisman’s ongoing asset rationalization program.  Production from continuing operations of 416 mboe/d, 1% above the same period in 2006.

·   Total net income of $352 million, down from $524 million in the prior year.  Net income from continuing operations of $224 million as compared to $391 million in 2006.

·   $1,088 million in capital expenditures.

·   Sold non-core assets in North America for total proceeds of $218 million, resulting in an after-tax gain of $93 million.

	Three months ended		Nine months ended
September 30,	2007	2006	2007	2006
Financial(millions of C$ unless otherwise stated)
Net income from continuing operations	224	391	726	1,033
Net income from discontinued operations	128	133	696	374
Net income	352	524	1,422	1,407
C$ per common share
Net income– Basic	0.35	0.48	1.37	1.28
– Diluted	0.34	0.47	1.34	1.25
Net income from continuing operations
– Basic	0.22	0.36	0.70	0.94
– Diluted	0.22	0.35	0.68	0.92
Production (daily average)
Oil and liquids (bbls/d)	220,521	216,242	231,340	239,092
Natural gas (mmcf/d)	1,172	1,161	1,155	1,147
Continuing operations (mboe/d)	416	410	424	430
Discontinued operations (mboe/d)	25	50	30	55
Total mboe/d (6 mcf = 1 boe)	441	460	454	485
Total production(boe) per common share - Basic	0.04	0.04	0.12	0.12
Capital Expenditures1 (millions of C$)	1,088	1,033	3,326	3,200

1. Capital expenditures are prior to acquisition and dispositions

In the third quarter, net income of $352 million and net income from continuing operations of $224 million decreased by 33% and 43%, respectively, from the same period in 2006, due principally to increases in depreciation, depletion and amortization (“DD&A”) and dry hole expenses and decreased Company netbacks in the current quarter.

Net income for the nine months ended September 30 was slightly higher than the same period in the previous year as increased gains on sale of discontinued operations and lower income tax expense due to tax rate increases in the UK in 2006 were mostly offset by increased DD&A and dry hole expenses and decreased Company netbacks.

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 resultsfrom 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 asset sales expected to close later in the year.  Of the 25 mboe/d of production recorded as discontinued operations in the third quarter, 9 mboe/d represents production from asset sales, which closed in the quarter, while 16 mboe/d represents production from asset sales expected to close subsequent to quarter end.

During the second quarter of 2007, the Company entered into agreements to sell two additional North American asset packages, which closed in the third quarter for proceeds of $218 million, resulting in an after-tax gain of $93 million, which has been recorded in net income from discontinued operations.

In the second quarter of 2007, the Company completed the sale of several North American assets that were announced in the fourth quarter of 2006 for proceeds of approximately $516 million, resulting in an after-tax gain of $203 million.   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.

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 the year.  The resulting gain on disposition of these assets will be recorded when the transaction closes.

Daily Average Production, Before Royalties

		Three months ended			Nine months ended
September 30,		2007	2007 vs 2006 (%)	2006	2007	2007 vs 2006 (%)	2006
Continuing operations
Oil and liquids (bbls/d)
	North America	38,214	(9)	41,837	39,603	(6)	41,931
	United Kingdom1	89,334	15	77,431	94,842	4	91,462
	Scandinavia 1	29,166	4	28,174	30,326	(6)	32,405
	Southeast Asia1	45,731	(7)	49,085	46,400	(10)	51,457
	Other 1	18,076	(8)	19,715	20,169	(8)	21,837
		220,521	2	216,242	231,340	(3)	239,092
Natural gas (mmcf/d)
	North America	836	(1)	847	826	3	809
	United Kingdom	31	63	19	37	19	31
	Scandinavia	11	(8)	12	13	(7)	14
	Southeast Asia	294	4	283	279	(5)	293
		1,172	1	1,161	1,155	1	1,147
Continuing operations (mboe/d)		416	1	410	424	(1)	430
Discontinued operations
	North America
	-  oil and liquids (bbls/d)	3,180		10,558	4,844		12,087
	-  natural gas (mmcf/d)	31		71	57		90
	United Kingdom
	-  oil and liquids (bbls/d)	6,915		9,544	6,357		11,508
	-  natural gas (mmcf/d)2	57		110	53		97
Discontinued operations (mboe/d)		25		50	30		55
Total mboe/d (6 mcf = 1 boe)		441	(4)	460	454	(6)	485

1. Includes oil volumes produced into inventory, excludes oil volumes sold (out of) inventory, for the three months ended September 30, 2007 of (3,111) bbls/d, 2,189 bbls/d, (5,701) bbls/d and (8,222) bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively, and for the three months ended September 30, 2006 of 2,638 bbls/d, 707 bbls/d, 1,889 bbls/d and 4,178 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 nine months ended September 30, 2007 of (2,241) bbls/d, 100 bbls/d, (585) bbls/d and 13 bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively, and for the nine months ended September 30, 2006 of (220) bbls/d, (147) bbls/d, 781 bbls/d and 2,257 bbls/d in the UK, Scandinavia, Southeast Asia and Other, respectively.

2. Includes gas acquired for injection and subsequent resale of 18 mmcf/d and 17 mmcf/d in the third quarter and year-to-date periods of    2007, respectively, and 3 mmcf/d and 15 mmcf/d in the third quarter and year to date periods of 2006, respectively.

The Company’s total average oil and liquids production for the quarter was 230,616 bbls/d, 2% below the prior year, while production from continuing operations for the quarter was 220,521 bbls/d, up 2% from last year.  During the quarter, total average natural gas production was 1,260 mmcf/d, 6% below the same period last year, while production from continuing operations increased 11 mmcf/d to an average of 1,172 mmcf/d.

In North America, oil and liquids production from continuing operations was down 9% from 2006 due primarily to a plant turnaround at the Greater Arch combined with natural declines.  Natural gas production in North America decreased by 11 mmcf/d mainly due to natural declines and a turn around at the Greater Arch, which were mostly offset by successful drilling in the Alberta Foothills and Bigstone, which increased production by 43 mmcf/d.

In the UK, oil and liquids production from continuing operations increased by 11,903 bbls/d due to production from new field start-ups at Tweedsmuir, Enoch and Blane, which averaged nearly 11,000 bbls/d in the quarter, and 2,443 bbls/d of production from the Auk/Fulmar acquisition (closed on December 1, 2006).  These increases were partially offset by the impact of increased planned shutdowns in 2007, including the ongoing Galley field redevelopment.

Gas production in the UK from continuing operations increased by 12 mmcf/d due principally to new production from Enoch and low nominations in the Netherlands during the third quarter of 2006.

In Scandinavia, oil and liquids production increased by 4% from 2006 due to the new field startup at Blane in September, two successful infill wells drilled at Brage in 2007 and two wells drilled at Varg late in 2006, partially offset by a planned shutdown at Varg and delays in restarting two wells after the Gyda shutdown.

In Southeast Asia, oil and liquids production declined 3,354 bbls/d.  Oil and liquids production in Malaysia/Vietnam was 27,181 bbls/d, down 6% from 2006 mainly due to natural decline in the PM-305 field.  In Indonesia, oil and liquids production increased 8% over the same period last year, averaging 11,335 bbls/d in the quarter mainly as a result of increased NGL production associated with the Suban field in Corridor.  Production in Australia averaged 7,215 bbls/d, down 25%, mainly due to natural declines and the impact of a shutdown.

Natural gas production in Malaysia/Vietnam averaged 61 mmcf/d in the quarter; a decrease of 11 mmcf/d compared to 2006 due to compressor maintenance, delayed commissioning of the Bunga Raya-E gas processing facilities and natural declines.  Indonesia gas production was 10% higher than last year, averaging 233 mmcf/d due to strong gas nominations at Corridor.

Oil and liquids production from Other areas decreased to 18,076 bbls/d principally due to a 21% decrease in production from Trinidad and Tobago to 7,065 bbls/d due mainly to natural declines.  Production from North Africa increased 2%, averaging 11,011 bbls/d compared to 10,769 bbls/d in the same period in 2006.

Company Netbacks ^{1, 2}

	Three months ended		Nine months ended
September 30,	2007	2006	2007	2006
Oil and liquids ($/bbl)
Sales price	75.91	73.27	71.46	71.58
Hedging (gain) loss	(0.11)	0.36	(0.56)	0.26
Royalties	11.51	12.17	11.03	11.57
Transportation	1.32	1.15	1.26	1.05
Operating costs	18.31	14.49	17.31	13.84
	44.88	45.10	42.42	44.86
Natural gas ($/mcf)
Sales price	6.30	6.65	7.06	7.36
Hedging (gain)	(0.28)	(0.20)	(0.18)	(0.17)
Royalties	1.25	1.13	1.39	1.40
Transportation	0.28	0.26	0.26	0.26
Operating costs	1.00	0.86	1.01	0.86
	4.05	4.60	4.58	5.01
Total ($/boe)  (6 mcf = 1 boe)
Sales price	57.76	56.90	57.90	58.93
Hedging (gain)	(0.85)	(0.42)	(0.82)	(0.32)
Royalties	9.61	9.52	9.78	10.11
Transportation	1.49	1.34	1.40	1.28
Operating costs	12.44	9.90	12.06	9.84
	35.07	36.56	35.48	38.02

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 third quarter, the Company’s average netback was $35.07/boe, 4% lower than in 2006.  Talisman’s realized price of $57.76/boe was 2% higher than 2006, principally due to higher international oil and liquids prices, partially offset by decreased natural gas prices and the strengthening Canadian dollar.  Increased royalties, operating costs and transportation expenses were partly offset by increased hedging gains in the quarter.

Prices and Exchange Rates

		Three months ended			Nine months ended
September 30,		2007	2007 vs 2006 (%)	2006	2007	2007 vs 2006 (%)	2006
Oil and liquids ($/bbl)
	North America	62.66	(1)	63.29	57.45	(2)	58.54
	United Kingdom	77.89	4	74.87	72.49	(2)	73.69
	Scandinavia	80.60	6	76.11	73.92	(2)	75.37
	Southeast Asia	78.68	-	79.01	78.99	2	77.15
	Other	81.03	12	72.46	76.08	4	73.21
		75.91	4	73.27	71.46	-	71.58
Natural gas ($/mcf)
	North America	5.80	(8)	6.30	7.04	(2)	7.19
	United Kingdom	6.22	(17)	7.53	6.87	(22)	8.80
	Scandinavia	4.93	(25)	6.53	4.63	(8)	5.04
	Southeast Asia	7.90	7	7.37	7.29	(1)	7.35
		6.30	(5)	6.65	7.06	(4)	7.36
Total $/boe (6 mcf = 1 boe)		57.76	2	56.90	57.90	(2)	58.93
Hedging (gain) loss, not included in the above prices
	Oil and liquids ($/bbl)	(0.11)		0.36	(0.56)		0.26
	Natural gas  ($/mcf)	(0.28)		(0.20)	(0.18)		(0.17)
	Total $/boe (6 mcf = 1 boe)	(0.85)		(0.42)	(0.82)		(0.32)
Benchmark prices and foreign exchange rates
	WTI                    (US$/bbl)	75.38	7	70.54	66.19	(3)	68.26
	Dated Brent        (US$/bbl)	74.87	8	69.61	67.13	-	66.99
	Tapis                  (US$/bbl)	79.34	5	75.27	71.01	(2)	72.24
	NYMEX            (US$/mmbtu)	6.13	(6)	6.53	6.88	(8)	7.47
	AECO                (C$/gj)	4.91	(14)	5.72	6.32	(7)	6.82
US/Canadian dollar exchange rate		0.96	8	0.89	0.91	3	0.88
Canadian dollar/pound sterling exchange rate		2.11	-	2.10	2.20	7	2.06

Talisman’s third quarter realized commodity price increased $0.86/boe from last year to $57.76/boe.  The Company’s realized oil and liquids prices generally increased, while natural gas prices declined.  These trends followed world oil and gas price indices.

Realized prices for oil and liquids did not increase at the same rate as US$ based index prices as a result of the 8% strengthening of the Canadian dollar in the quarter, partially offset by narrowing differentials to oil and liquids benchmark prices in the North Sea and Southeast Asia.

For the quarter ended September 30, Talisman recorded net hedging gains on commodity-based derivative financial instruments of $34 million, associated with gains on oil and liquids of $0.11/bbl and on natural gas of $0.28/mcf.  This compares to gains of $18 million associated with gains on natural gas of $0.20/mcf, which more than offset losses on oil and liquids of $0.36/bbl during the same period in 2006.  As of October 1, the Company had derivative and fixed price physical contracts for approximately 8% 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 September 30, 2007 unaudited Interim Consolidated Financial Statements.

Royalties

	Three months ended
September 30,	2007		2006
	%	$ millions	%	$ millions
North America	18	117	17	124
United Kingdom	1	5	-	1
Scandinavia	-	1	-	1
Southeast Asia	40	236	36	191
Other	31	59	27	30
	18	418	16	347
	Nine months ended
September 30,	2007		2006
	%	$ millions	%	$ millions
North America	18	402	18	418
United Kingdom	-	4	-	5
Scandinavia	-	3	-	3
Southeast Asia	39	606	39	646
Other	32	133	28	112
	17	1,148	17	1,184

The Company’s royalty expense from continuing operations for the third quarter was $418 million (18%), up $71 million from $347 million (16%) in 2006.  In Southeast Asia, the royalty rate increased by 4%, where the impact of higher prices in Malaysia was only partially offset by an increase in cost recovery associated with the Northern Fields Development.

Alberta Royalty Review

On October 25, the Alberta government released its response to proposed changes to the Alberta royalty framework.  The changes to the royalty framework are expected to increase royalties paid to the Alberta government beginning in 2009.  The Company is currently evaluating the impact of these changes.

Unit Operating Expenses

	Three months ended			Nine months ended
September 30,	2007	2007 vs 2006	2006	2007	2007 vs 2006	2006
	$/boe	(%)	$/boe	$/boe	(%)	$/boe
North America	7.98	16	6.90	7.70	11	6.94
United Kingdom	23.24	32	17.59	22.93	37	16.68
Scandinavia	24.90	15	21.63	23.34	10	21.28
Southeast Asia	5.26	5	5.00	4.92	10	4.46
Other	8.23	91	4.30	5.74	37	4.20
	12.44	26	9.90	12.06	23	9.84

Total Operating Expenses ($ millions)

			Three months ended		Nine months ended
	September 30,	2007		2006	2007	2006
North America		130		114	377	337
United Kingdom		207		137	639	463
Scandinavia		67		61	207	202
Southeast Asia		48		45	126	119
Other		19		6	32	21
		471		363	1,381	1,142
Pipeline		19		21	62	57
		490		384	1,443	1,199

During the third quarter, total operating expenses from continuing operations increased by 28% to $490 million.

In North America, operating costs were higher than the prior year due primarily to increases in planned maintenance, processing costs and property and pipeline taxes.  The impact of increased expenditures and a 3% decrease in production from continuing operations resulted in an increase in the unit operating expense.

In the UK, operating costs increased by $70 million.  The Auk/Fulmar interests acquired in the fourth quarter of 2006 contributed approximately $32 million and added $2.76/boe to UK unit costs.  Additionally, increased fuel gas costs at Tartan and increased maintenance costs in a number of operating areas caused operating expenses to increase over 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 Phase 2.

In Scandinavia, operating costs increased by $6 million due to well maintenance work at Gyda and Varg in 2007, partially offset by lower well maintenance work at Brage.  Increased costs combined with flat production resulted in an increase in Scandinavian unit operating costs of 15%.

In Southeast Asia, total operating costs were slightly higher than the prior year mainly due to increases in Malaysia/Vietnam due to well workovers in PM-3 CAA and increased gas production at Corridor.

Transportation Expenses

	Three months ended
September 30,	2007		2006
	$/boe	$ millions	$/boe	$ millions
North America	1.04	19	0.93	18
United Kingdom	2.00	11	1.72	11
Scandinavia	2.49	7	2.77	8
Southeast Asia	1.54	13	1.41	13
Other	0.92	2	0.86	1
	1.49	52	1.34	51
	Nine months ended
September 30,	2007		2006
	$/boe	$ millions	$/boe	$ millions
North America	0.97	51	1.01	56
United Kingdom	1.77	43	1.57	38
Scandinavia	2.78	25	2.10	20
Southeast Asia	1.43	36	1.27	35
Other	1.05	6	0.88	5
	1.40	161	1.28	154

During the current quarter, transportation expenses from continuing operations increased $1 million to $52 million.

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

	Three months ended			Nine months ended
September 30, ($/boe)	2007	2007 vs 2006 (%)	2006	2007	2007 vs 2006 (%)	2006
North America	15.95	13	14.09	16.35	16	14.14
United Kingdom	17.29	49	11.58	16.41	33	12.34
Scandinavia	27.08	33	20.33	27.52	40	19.60
Southeast Asia	7.52	19	6.31	7.81	27	6.16
Other	7.87	(21)	9.93	8.28	(12)	9.43
	14.59	21	12.07	14.98	24	12.12

Total DD&A Expense

			Three months ended		Nine months ended
	September 30, ($ millions)	2007		2006	2007	2006
North America		265		245	790	697
United Kingdom		157		90	462	326
Scandinavia		74		55	246	187
Southeast Asia		69		55	199	167
Other		19		14	46	50
		584		459	1,743	1,427

Third quarter DD&A expense from continuing operations was $584 million, up 27% 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.

Increases in the total DD&A expense in the UK, Scandinavia and Southeast Asia were principally due to an increase in the depletable base.

Other ($ millions)

September 30,	Three months ended		Nine months ended
	2007	2006	2007	2006
General and administrative	53	48	166	163
Dry hole expense	149	37	362	120
Stock-based compensation	(47)	(47)	38	(47)
Other expense (income)	7	(3)	(15)	68
Interest costs capitalized	12	20	52	49
Interest expense	54	37	151	123
(Gain)/Loss on held-for-trading financial      instruments	10	-	(16)	-
Other revenue	38	24	112	79

Dry hole expense for the third quarter of 2007 was up $112 million from the prior year and includes $60 million in North America, $38 million in Southeast Asia, $15 million in Scandinavia and $36 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 September 30.  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 third quarter of 2007, the Company realized a recovery of $47 million.  The Company paid cash of $20 million to employees in settlement of fully accrued option liabilities for options exercised ($32 million in 2006).  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 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.  Blane came on production in the third quarter, while Wood is scheduled to come on production in the fourth quarter of 2007.

The loss on held-for-trading financial instruments in the quarter includes the realized amounts and the fair value change of commodity price derivatives that are not designated as hedges, and the change in value to disposal of the Canadian Oil Sands Trust 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 Financial Statements.

Other revenue of $38 million includes $28 million of pipeline and processing revenue.

Taxes ($ millions)

Effective Income Tax Rate

September 30,	Three months ended		Nine months ended
	2007	2006	2007	2006
Income from continuing operations before taxes	538	766	1,615	2,442
Less PRT        Current        Deferred	35 21	71 11	183 14	217 14
Total PRT	56	82	197	231
	482	684	1,418	2,211
Income tax expense
Current income tax	238	209	524	730
Future income tax	20	84	168	448
Total income tax expense	258	293	692	1,178
Effective income tax rate	54%	43%	49%	53%

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 effective tax rate in the quarter increased by 11% from the same period in 2006 due to unrealized foreign exchange gains on long-term debt related to the strengthening of the Canadian dollar and the fact that income earned by the Company was more heavily weighted to higher tax jurisdictions.

For the nine months ended September 30, the 2006 effective rate was higher than the current year principally due to a charge to future income taxes related to an increase in the UK tax rate, partially offset by a future income tax recovery related to a decrease in the Canadian federal tax rate.

On October 30, the Canadian government announced a series of upcoming corporate income tax reductions to take effect from 2008 up to and including 2012.  The Company is currently assessing the impact of such proposed income tax reductions.  These reductions have not yet been substantially enacted and once that has occurred, the Company will recognize a future tax reduction.

Capital Expenditures¹

	Three months ended			Nine months ended
September 30,	2007	2007 vs 2006 (%)	2006	2007	2007 vs 2006 (%)	2006
(millions of  C$)
North America	396	(15)	468	1,279	(25)	1,715
United Kingdom	328	8	305	1,070	22	874
Scandinavia	198	108	95	440	106	214
Southeast Asia	114	10	104	362	62	224
Other	40	(23)	52	149	1	148
Corporate, IS and Administrative	12	33	9	26	4	25
	1,088	5	1,033	3,326	4	3,200
Acquisitions	38		5	42		6
Dispositions	(21)		-	(37)		(2)
Discontinued Operations
Proceeds on disposition	(218)		(134)	(964)		(361)
Capital expenditures	3		27	20		87
Total	890	(4)	931	2,387	(19)	2,930

1.   Capital expenditures exclude corporate acquisitions.

North America capital expenditures for the current quarter totalled $396 million, with exploration costs of $205 million and development costs of $191 million (including plant and equipment).  These expenditures included the drilling of 34 gross gas wells.

Expenditures in the UK during the third quarter were comprised of $77 million on exploration and $251 million on development, which included the development of the Affleck, Galley, Blane, Wood and Duart fields and the Tweedsmuir Phase 2 project.

In Scandinavia, the Company spent $31 million on exploration and $167 million on development, including the Rev, Yme, Tambar East and Blane field developments and infill drilling at Brage.

In Southeast Asia, capital expenditures of $114 million included $24 million on exploration, principally on the Naga Dalam well in PM-314, and development spending of $90 million, primarily on the Northern Fields project and the drilling and completion of three development wells in PM-3 CAA in Malaysia.

In Other, the Company spent $6 million on development activities in North Africa, $16 million on exploration and $5 million on development in Trinidad and Tobago and $13 million on exploration activities in the rest of the world.

Long-term Debt and Liquidity

At September 30, Talisman’s long-term debt was $4.4 billion ($4.2 billion net of cash), down from $4.6 billion ($4.5 billion net of cash) at year-end.  During the first nine months of 2007, the Company generated $3.2 billion of cash provided by operating activities and spent $3.3 billion on exploration and development.  In July, the Company sold its units in Canadian Oil Sands Trust for proceeds of $262 million, crystallizing a gain of $19 million, net of tax.  It also received proceeds of $964 million from the disposal of North American assets and repurchased shares for approximately $950 million.  The translation effect of the strengthening of the Canadian dollar has reduced long-term debt by about $530 million, as the majority of the Company’s debt is denominated in US dollars.

At September 30, the Company had current assets of $1.6 billion and current liabilities of $2.5 billion, including assets and liabilities related to discontinued operations. Working capital movements are difficult to predict, but management anticipates that accounts receivable will rise later in the year, due primarily to increased production in the North Sea.

At September 30, the Company had $1.4 billion drawn against its available $2.75 billion of bank lines of credit.  In the third quarter, the Company increased its bank lines by $30 million.

At quarter-end, debt-to-debt plus book equity was 37%.  For the 12 months ended September 30, 2007, the debt-to-cash provided by operating activities ratio was 1.05:1.

In the first nine months of 2007, the Company has repurchased 45,994,100 shares under the normal course issuer bid (NCIB) at a total cost of approximately $950 million.  Shareholders may obtain a copy of the Company's notice of intention to make a NCIB, free of charge, by accessing it on www.sedar.com or by emailing the Company at tlm@talisman-energy.com.

As at September 30, there were 1,018,558,455 common shares outstanding, increasing to 1,018,573,080 at October 31.

As at September 30, there were 65,198,125 stock options and 10,124,838 cash units outstanding.  Subsequent to September 30, 1,096,550 stock options were exercised for cash, 14,625 stock options were exercised for shares and 181,010 were cancelled, with 63,905,940 stock options outstanding at October 31.  Subsequent to September 30, 157,050 cash units were exercised, with 9,967,788 cash units outstanding at October 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 these standards, the Company recognized 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 September 30 is presented as a current asset of $23 million, a long-term asset of $42 million, a current liability of $30 million and a long-term obligation of $31 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 were 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 recognizes 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 loss of $18 million, which has been included in the gain/loss on held-for-trading financial instruments.  A portion of these contracts was settled during the period for a gain of $16 million.

In addition to its commodity derivatives, the Company has a fixed-to-floating interest rate swap and a cross currency interest rate swap.  The fixed-to-floating interest rate swap is designated as a fair value hedge of a portion of the Company’s long-term debt.  The hedged portion of the long-term debt and hedging item are re-measured at fair value each reporting period and the respective changes in fair value in the derivative and the hedged portion of the long-term debt offset each other and are expected to continue to have no net impact on net income in future periods.  The change in the fair value of the fixed-to-floating interest rate swap for the three months ended September 30 was a gain of $10 million, offset by an increase in long-term debt.  The Company has designated the cross currency interest rate swap as a cash flow hedge.  The effective portion of the changes in the fair value of the cross currency interest rate swap is recognized initially in other comprehensive income (OCI) and is reclassified to foreign exchange gains or losses as foreign exchange translation gains or losses on the hedged debt are recorded.  The balance in OCI at September 30 is $4 million. The change in the hedged item and hedging item attributable to foreign exchange are included in net income from continuing operations when incurred.  The net effect of these entries has no impact on net income.

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 is being 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$69.15/bbl, a NYMEX natural gas price of US$6.88/mmbtu and exchange rates of C$1=US$0.93 and £1=C$2.15.

Approximate Impact for 2007
(millions of dollars)		Net Income	Cash Provided by Operating Activities
Volume changes
	Oil - 1,000 bbls/d	8	11
	Natural gas - 10 mmcf/d	7	15
Price changes1
	Oil - US$1.00/bbl	41	42
	Natural gas (North America)2 - C$0.10/mcf	12	17
Exchange rate changes
	US$ increased by US$0.01	40	59
	£ increase by C$0.023	(7)	1

1.   The impact of commodity contracts outstanding as of October 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.

	2007			20061				20051
	Sept. 30	Jun. 30	Mar. 311	Dec. 31	Sept. 30	Jun. 30	Mar. 31	Dec. 31
Gross sales	2,333	2,290	2,186	2,132	2,127	2,230	2,561	2,563
Total revenue	1,987	1,967	1,920	1,852	1,822	1,846	2,188	2,138
Net income from continuing operations	224	301	201	338	391	533	109	425
Net income	352	550	520	598	524	686	197	533
Per common share ($)2
Net income from continuing   operations	0.22	0.29	0.19	0.31	0.36	0.48	0.10	0.39
Diluted net income from   continuing operations	0.22	0.28	0.19	0.31	0.35	0.47	0.10	0.39
Net income	0.35	0.53	0.49	0.55	0.48	0.62	0.18	0.48
Diluted net income	0.34	0.52	0.48	0.54	0.47	0.61	0.17	0.47

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.

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

During the third quarter of 2007, gross sales increased by $43 million over the previous quarter due to slightly higher production from continuing operations and increasing oil and liquids prices, partially offset by declining gas prices.  Net income from continuing operations decreased by $77 million from the prior quarter due principally to increased operating, dry hole and DD&A expenses.

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 in the second quarter of 2006 and the $325 million future tax charge related to a UK income tax rate increase 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.

New Accounting Pronouncements

New Canadian 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 are effective for Talisman’s first quarter disclosure in 2008 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 is effective for Talisman’s first quarter 2008 disclosure.

In June 2007, the AcSB issued Section 3031, Inventories.  This standard prescribes the accounting treatment for inventories, and will be effective for Talisman’s first quarter 2008 disclosure.  The Company does not expect the standard to have a material impact on its results of operations or financial position.

New US Accounting Pronouncements

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 reporting.  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.

In September 2006, the FASB issued Statement 157, Fair Value Measurements (“FAS 157”). This statement is intended to increase the consistency and comparability of fair value measurements and eliminate different definitions of fair value under various US standards. This standard clarifies that fair value is a market measure and not an entity specific measure. Among other attributes, fair value assumes the highest and best use for the asset or liability being measured and is based on the exit price for the holder of the asset or liability. FAS 157 also establishes a fair value hierarchy as follows: Level 1 is fair value based on observable market inputs that reflect quoted prices in a market accessible to the entity. Level 2 is fair value based on observable market inputs that do not reflect quoted prices in a market accessible to the entity, for example quoted prices for similar assets or identical assets in inactive markets, or inputs derived through interpolation of other observable market data. Level 3 fair value is based on unobservable market inputs, for example inputs derived through interpolation that cannot be corroborated by observable market data. The total fair value of assets and liabilities that are re-measured each reporting date must be grouped by hierarchy level for disclosure purposes and a continuity of the changes in the Level 3 measurements must be disclosed. This statement is effective for fiscal years beginning on or after November 15, 2007 and will be effective for Talisman in fiscal 2008. Talisman is currently evaluating the impact that Statement 157 on its Consolidated Financial Statements.

In February 2007, FASB issued Statement 159, The Fair Value Option for Financial Assets and Financial Liabilities (“FAS 159”).  This statement permits entities to choose to measure certain financial instruments and other eligible items at fair value when the items are not otherwise currently required to

be measured at fair value. Under FAS 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish, on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. The provisions of FAS 159 are effective for fiscal years beginning on or after November 15, 2007 and will be effective for Talisman in fiscal 2008. Talisman is currently evaluating the impact that the adoption of FAS159 will have on its Consolidated Financial Statements.

Internal Controls over Financial Reporting

There were no changes in Talisman’s internal controls over financial reporting during the third 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.  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.

Talisman Energy Inc.
Product Netbacks
(unaudited)
		Three months ended September 30				Nine months ended September 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	62.66	63.29	5.80	6.30	57.45	58.54	7.04	7.19
America	Hedging (gain)	(1.63)	-	(0.40)	(0.30)	(2.23)	-	(0.26)	(0.25)
	Royalties	12.71	13.29	0.98	0.99	11.84	12.44	1.25	1.33
	Transportation	0.46	0.56	0.20	0.18	0.46	0.57	0.19	0.19
	Operating costs	10.81	8.64	1.19	1.06	9.79	8.34	1.18	1.08
		40.31	40.80	3.83	4.37	37.59	37.19	4.68	4.84
United	Sales price	77.89	74.87	6.22	7.53	72.49	73.69	6.87	8.80
Kingdom	Hedging (gain)	0.43	0.95	-	-	(0.37)	0.66	-	-
	Royalties	0.92	0.76	0.36	0.63	0.71	0.83	0.34	0.58
	Transportation	1.95	1.65	0.38	0.34	1.70	1.50	0.37	0.32
	Operating costs	25.74	21.08	1.14	0.59	25.19	19.30	1.28	0.67
		48.85	50.43	4.34	5.97	45.26	51.40	4.88	7.23
Scandinavia	Sales price	80.60	76.11	4.93	6.53	73.92	75.37	4.63	5.04
	Royalties	0.35	0.48	-	-	0.33	0.36	-	-
	Transportation	2.11	2.32	1.44	1.52	2.41	1.79	1.33	1.09
	Operating costs	26.45	23.17	-	-	25.00	22.79	-	-
		51.69	50.14	3.49	5.01	46.18	50.43	3.30	3.95
Southeast	Sales price	78.68	79.01	7.90	7.37	78.99	77.15	7.29	7.35
Asia	Royalties	34.30	33.41	2.38	1.84	34.22	34.86	2.24	2.05
	Transportation	0.41	0.31	0.43	0.43	0.40	0.24	0.41	0.39
	Operating costs	8.21	7.71	0.42	0.36	7.31	6.78	0.43	0.34
		35.76	37.58	4.67	4.74	37.06	35.27	4.21	4.57
Other	Sales price	81.03	72.46	-	-	76.08	73.21	-	-
	Royalties	25.52	23.58	-	-	23.74	21.92	-	-
	Transportation	0.92	0.86	-	-	1.05	0.89	-	-
	Operating costs	8.27	4.32	-	-	5.76	4.21	-	-
		46.32	43.70	-	-	45.53	46.19	-	-
Total Company	Sales price	75.91	73.27	6.30	6.65	71.46	71.58	7.06	7.36
	Hedging (gain)	(0.11)	0.36	(0.28)	(0.20)	(0.56)	0.26	(0.18)	(0.17)
	Royalties	11.51	12.17	1.25	1.13	11.03	11.57	1.39	1.40
	Transportation	1.32	1.15	0.28	0.26	1.26	1.05	0.26	0.26
	Operating costs	18.31	14.49	1.00	0.86	17.31	13.84	1.01	0.86
		44.88	45.10	4.05	4.60	42.42	44.86	4.58	5.01
Unit operating costs include pipeline operations for the United Kingdom.
Netbacks do not include synthetic oil.

Talisman Energy Inc.
Product Netbacks (1)
(unaudited)
		Three months ended		Nine months ended
		September 30		September 30
(US$ - production net of royalties)		2007	2006 (2)	2007	2006 (2)
North	Oil and liquids (US$/bbl)
America	Sales price	59.96	56.42	52.16	51.75
	Hedging (gain)	(1.96)	-	(2.51)	-
	Transportation	0.55	0.63	0.52	0.64
	Operating costs	12.98	9.76	11.21	9.35
		48.39	46.03	42.94	41.76
	Natural gas (US$/mcf)
	Sales price	5.55	5.62	6.35	6.34
	Hedging (gain)	(0.46)	(0.32)	(0.29)	(0.27)
	Transportation	0.23	0.19	0.21	0.21
	Operating costs	1.38	1.13	1.30	1.17
		4.40	4.62	5.13	5.23
United Kingdom	Oil and liquids (US$/bbl)
	Sales price	74.53	66.76	65.96	64.94
	Hedging (gain)	0.42	0.86	(0.31)	0.59
	Transportation	1.88	1.48	1.56	1.34
	Operating costs	24.93	18.97	23.07	17.24
		47.30	45.45	41.64	45.77
	Natural gas (US$/mcf)
	Sales price	5.95	6.71	6.18	7.74
	Transportation	0.39	0.33	0.35	0.30
	Operating costs	1.16	0.57	1.21	0.63
		4.40	5.81	4.62	6.81
Scandinavia	Oil and liquids (US$/bbl)
	Sales price	77.18	67.85	67.19	66.40
	Transportation	2.02	2.08	2.18	1.58
	Operating costs	25.45	20.78	22.81	20.23
		49.71	44.99	42.20	44.59
	Natural gas (US$/mcf)
	Sales price	4.74	5.82	4.19	4.46
	Transportation	1.41	1.33	1.20	0.96
		3.33	4.49	2.99	3.50
Southeast Asia	Oil and liquids (US$/bbl)
	Sales price	75.36	70.48	71.64	68.16
	Transportation	0.69	0.48	0.65	0.39
	Operating costs	13.93	11.88	11.77	10.93
		60.74	58.12	59.22	56.84
	Natural gas (US$/mcf)
	Sales price	7.56	6.57	6.65	6.49
	Transportation	0.59	0.51	0.54	0.48
	Operating costs	0.57	0.43	0.56	0.41
		6.40	5.63	5.55	5.60
Other	Oil (US$/bbl)
	Sales price	77.64	64.66	69.13	64.28
	Transportation	1.29	1.14	1.38	1.11
	Operating costs	11.57	5.70	7.66	5.26
		64.78	57.82	60.09	57.91
Total Company	Oil and liquids (US$/bbl)
	Sales price	72.66	65.33	64.94	63.13
	Hedging (gain)	(0.13)	0.38	(0.58)	0.27
	Transportation	1.48	1.23	1.34	1.11
	Operating costs	20.69	15.46	18.52	14.57
		50.62	48.26	45.66	47.18
	Natural gas (US$/mcf)
	Sales price	6.03	5.93	6.38	6.49
	Hedging (gain)	(0.33)	(0.22)	(0.21)	(0.18)
	Transportation	0.33	0.28	0.29	0.28
	Operating costs	1.18	0.92	1.13	0.94
		4.85	4.95	5.17	5.45
(1) Per US reporting practice, netbacks calculated using US$ 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.

Talisman Energy Inc.
Consolidated Financial Ratios
September 30, 2007
(unaudited)
The following financial ratio is provided in connection with the Company's shelf prospectus, filed with
Canadian and US securities regulatory authorities, and is based on the Company's Consolidated
Financial Statements that are prepared in accordance with accounting principles generally accepted in Canada.
The interest coverage ratio is for the 12 month period ended September 30, 2007.
Interest coverage (times)
Income (1)	11.25
Income from continuing operations (2)	7.53
1  Net income plus income taxes and interest expense; divided by the sum of interest expense
and capitalized interest.
2  Net income from continuing operations plus income taxes and interest expense from continuing operations;
divided by the sum of interest expense and capitalized interest from continuing operations.

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 production, 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 this interim 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.

Additional information related to the Company, including its Annual Information Form, can be found on SEDAR at www.sedar.com.