N E W S R E L E A S E

EX-1 2 q3full.htm EXHIBIT 1 - 3Q INTERIM RESULTS N E W S R E L E A S E

TALISMAN ENERGY

CASH FLOW EXCEEDS $2.2 BILLION YEAR TO DATE

THIRD QUARTER PRODUCTION UP 13% OVER PRIOR YEAR

CALGARY, Alberta – November 2, 2004 – Talisman Energy Inc. today reported its operating and financial results for the first nine months of 2004.

Production during the quarter averaged 429,000 boe/d, an increase of 13% over the previous year but down 2% from the second quarter, with the dip due to planned plant turnarounds for maintenance in Western Canada and the North Sea. Production averaged 434,000 boe/d for the first nine months, an increase of 11% over the same period last year. Netbacks during the quarter were $24.76/boe, compared to $22.03/boe a year ago and $24.65/boe in the second quarter

Cash flow during the third quarter was $706 million ($1.84/share), compared to $767 million ($2.00/share) in the previous quarter and $640 million ($1.66/share) a year earlier. The drop in cash flow from the previous quarter reflects lower production. Increased hedging losses and current taxes also had a significant impact during the quarter. Cash flow was up 10% compared to the third quarter of last year on both higher prices and volumes. Cash flow to September 30 was $2,252 million ($5.86/share), compared to $2,085 million ($5.39/share) a year ago.

Net income during the quarter was $122 million ($0.32/share), compared to $128 million ($0.32/share) a year ago and $197 million ($0.50/share) in the second quarter. Net income to the end of September was $542 million ($1.39/share) versus $904 million ($2.29/share) in the same period last year.

In order to better illustrate Talisman’s core operating performance on a consistent basis, the Company has calculated an adjusted earnings from operations number. This metric adjusts for significant one-time events such as the sale of Talisman’s assets in Sudan and changes to tax rates in 2003. It also adjusts for other non-operational impacts on earnings such as the mark-to-market effect of changes in share prices on stock based compensation expense.

Using this approach, adjusted earnings from operations during the quarter were $196 million ($0.51/share), an increase of 31% over the previous year. Year to date the comparable number was $626 million ($1.63/share), up 19% over the first nine months of 2003. Additional details are provided on the third page of this report.

“Although the net income number was affected by a number of non-operational factors during the quarter, our underlying performance remains strong and we achieved a number of strategic milestones,” said Dr. Jim Buckee, President and Chief Executive Officer. “The Company grew its North American gas volumes for the fourth consecutive quarter, driven by a very successful drilling program and highlighted by a number of high impact wells. The most significant success was our deep Monkman well, which tested at a constrained rate of 40 mmcf/d and reinforced our belief that this play has huge potential value.

“In the North Sea, Talisman started production from the Tartan North field two months ahead of schedule and received development approval for Tweedsmuir. Tweedsmuir is expected to come on stream late in 2006 with production of 40,000 boe/d and Talisman will have a 94% working interest. In Indonesia, an agreement was reached to sell an additional 2.3 tcf of natural gas from Corridor, where Talisman has a 36% interest. The incremental sales are expected to start in 2007. In Trinidad, development of the Angostura oil and gas field is almost complete with first production expected early in 2005.

“Year over year, we are still delivering double digit production growth and expect production to be near the mid-point of our guidance range of 420,000-450,000 boe/d for the year. With the continued strength in oil and natural gas prices, we expect cash flow of approximately $3.1-3.2 billion or $8.00-8.50 per share based on fourth quarter WTI oil prices of US$50.00/bbl, NYMEX gas prices of US$7.30/mcf and a C$/US$ exchange rate of $0.80.”

Talisman Third Quarter Summary

•

Talisman increased its 2004 capital spending by $443 million with two-thirds of the increase allocated to North America.

•

Talisman’s North American gas production increased for the fourth consecutive quarter, averaging 892 mmcf/d.

•

In early November, the Company announced a significant new gas discovery in the Monkman area of northeast British Columbia. The b-60-E deep Paleozoic well tested at rates of 40 mmcf/d, constrained by surface equipment.

•

Drilling success averaged 93% in North America with 96 gas and 46 oil wells.

•

In Appalachia, two successful natural gas wells were drilled in the third quarter. Production averaged 109 mmcf/d, a 16% increase over the second quarter

•

Development of Talisman’s Tweedsmuir and Tweedsmuir South fields in the North Sea commenced in late August. Development drilling is expected to commence in 2005, with production expected in late 2006.

•

Production at the Company’s North Tartan Field in the North Sea commenced two months ahead of schedule in August at 6,000 bbls/d.

•

Talisman announced plans to construct a deepwater wind farm demonstrator project adjacent to the Beatrice field, 25 kilometres off the east coast of Scotland.

•

In Malaysia/Vietnam, production averaged 44,234 boe/d with nine development wells completed. The South Angsi development project is proceeding on schedule for first oil in mid-2005.

•

Talisman announced an agreement to sell 2.3 tcf of natural gas from the Corridor block in Indonesia.

•

In Trinidad, development of the Angostura oil and gas field is continuing on schedule for production startup in early 2005.

•

Talisman declared a semi-annual dividend of 15 cents Canadian (C$0.15) per share on its common shares.

Adjusted earnings from operations

To assist in understanding the Company’s adjusted earnings from operations, the following table adjusts the Company’s net income per the financial statements, for certain items of a non-operational nature, on an after-tax basis. This term is not defined by Generally Accepted Accounting Principles (GAAP) in either Canada or the US. Our reported results may not be comparable to similarly titled measures by other companies. The Company uses this data to evaluate performance of core operational exploration and production activities on a basis comparable between periods.

($ millions, except per share amounts)

	Three months ended		Nine months ended
September 30,	2004	2003	2004	2003
Net income	122	128	542	904
Gain on sale of Sudan operations ¹	-	-	-	(296)
Sudan operating income ¹	-	-	-	(44)
Stock-based compensation ²	47	12	114	88
Tax effects of unrealized foreign exchange gains on foreign denominated debt ³	41	10	22	35
Tax rate reductions and other	(14)	-	(52)	(161)
Adjusted earnings from operations ⁴	196	150	626	526
Amounts per share - basic	0.51	0.39	1.63	1.36
Amounts per share - diluted	0.50	0.38	1.60	1.34

Footnotes:

On March 12, 2003, Talisman completed the sale of its indirectly held interest in the Greater Nile Oil Project in Sudan for net proceeds of $1,012 million and a gain of $296 million. During the period January 1, 2003 through March 12, 2003, the Sudan operations had after tax operating income of $44 million.

Future tax effect relating to unrealized foreign exchange gains associated with the impact of a stronger Canadian dollar on foreign denominated debt.

This is a non-GAAP measure.

Management’s Discussion and Analysis (MD&A)

(November 1, 2004)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements. All comparative percentages are between the quarters ended September 30, 2004 and 2003, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Quarterly results summary

	Three months ended		Nine months ended
September 30,	2004	2003 (Restated)⁴	2004	2003 (Restated)⁴	2003 Proforma Excluding Sudan operations and gain on sale^4&6
Financial (millions of C$ unless otherwise stated)
Cash flow^1&3	706	640	2,252	2,085	2,009
Net income¹	122	128	542	904	564
Exploration and development expenditures	687	575	1,810	1,522	1,520
Per common share⁵ (dollars)
Cash flow^1&3– Basic	1.84	1.66	5.86	5.39	5.19
– Diluted	1.81	1.64	5.77	5.33	5.13
Net income²– Basic	0.32	0.32	1.39	2.29	1.46
– Diluted	0.31	0.31	1.37	2.27	1.44
Production (daily average)
Oil and liquids (bbls/d)	218,441	202,008	226,024	212,520	195,087
Natural gas (mmcf/d)	1,263	1,064	1,248	1,074	1,074
Total mboe/d (6mcf=1boe)	429	379	434	391	374

Amounts are reported prior to preferred security charges of $15 million ($9 million net of tax) for the nine months ended September 30, 2004 (2003 - $29 million; $17 million net of tax).

Per common share amounts for net income and diluted net income are reported after preferred security charges.

Cash flow is a non-GAAP measure and represents net income before exploration costs, DD&A, future taxes and other non-cash expenses as described further in the non-GAAP section of this MD&A.

Restatement of prior year to effect retroactive adoption of the new accounting policy on asset retirement obligation as at January 1, 2004. See note 1 to the Interim Consolidated Financial Statements.

All per share amounts have been retroactively restated to reflect the impact of the Company’s three for one stock split. See note 2 to the Interim Consolidated Financial Statements.

The pro forma Sudan amounts are non-GAAP measures and are described further in the non-GAAP section of this MD&A.

The Company’s quarterly cash flow was $706 million, a 10% increase over the same period last year. Net income for the quarter decreased 5% to $122 million, as the impact of this year’s improved commodity prices and higher production was more than offset by increases in hedging losses, operating expenses, DD&A, stock-based compensation and taxes. On a pro forma basis, after removing the gain on sale and the impact of the Sudan operations, cash flow on a year to date basis increased 12% to $2,252 million. For the same period, net income on a pro forma basis decreased 4% from $564 million to $542 million, largely due to the impact of tax recoveries in 2003. The year over year variance would be an increase of $100 million, excluding the impact of the stock-based compensation, as well as the non-routine tax adjustments and Sudan sale from the first nine months of 2003 and removing similar adjustments from the current year.

On March 12, 2003, Talisman completed the sale of its indirectly held interest in the Greater Nile Oil Project in Sudan for net proceeds of $1,012 million and a gain of $296 million. See note 7 to the Interim Consolidated Financial Statements.

Company Netbacks

	Three months ended		Nine months ended
September 30,	2004	2003	2004	2003
Oil and liquids ($/bbl)
Sales price	53.30	37.33	46.87	39.60
Hedging expense (income)	7.15	2.01	4.68	2.04
Royalties	7.86	4.20	6.84	5.76
Transportation	0.95	0.88	0.89	0.85
Operating costs	11.08	9.19	10.06	8.99
	26.26	21.05	24.40	21.96
Natural gas ($/mcf)
Sales price	6.15	5.87	6.25	6.67
Hedging expense (income)	0.10	0.02	0.09	0.13
Royalties	1.25	0.98	1.24	1.22
Transportation	0.25	0.30	0.26	0.29
Operating costs	0.68	0.72	0.66	0.69
	3.87	3.85	4.00	4.34
Total $/boe (6mcf=1boe)
Sales price	45.19	36.34	42.35	39.79
Hedging expense (income)	3.91	1.13	2.67	1.45
Royalties	7.68	4.99	7.12	6.48
Transportation	1.23	1.30	1.20	1.27
Operating costs	7.61	6.89	7.11	6.75
	24.76	22.03	24.25	23.84

Netbacks do not include synthetic oil and pipeline operations. Additional netback information by major product type and region is included elsewhere in this interim report.

During the current quarter, the Company’s average netback was $24.76/boe, 12% higher than 2003 as global oil prices continued to rise but were partially offset by a stronger Canadian dollar in relation to its US counterpart and increased hedging losses, royalties and operating costs. The increase in the pound sterling/Canadian dollar exchange rates during the current quarter accounted for approximately $0.23/boe of the increase in operating costs.

During the second quarter of this year, the Company commenced retroactively reclassifying transportation costs on commodity sales as a separate line in the Consolidated Statements of Income and in the Company’s netbacks. Previously, these costs had been either netted off against revenue or included as a component of operating costs, depending on the circumstances in the various geographic segments. See note 1 to the Interim Consolidated Financial Statements for more detail.

Revenue

Revenue for the quarter ended September 30, 2004 was $1.6 billion, a 33% increase over 2003, as increases in oil production from Southeast Asia and Algeria operations and worldwide gas production combined with higher commodity prices to more than offset increased hedging losses and the negative impacts of a stronger Canadian dollar.

Production (daily average)	Three months ended		Nine months ended
September 30,	2004	2003	2004	2003
Oil and liquids (bbls/d)
North America	57,049	59,612	57,418	60,267
North Sea	111,301	112,360	119,818	107,811
Southeast Asia	36,047	22,241	35,853	22,170
Algeria	14,044	7,795	12,935	4,839
Sudan	-	-	-	17,433
	218,441	202,008	226,024	212,520
Natural gas (mmcf/d)
North America	892	853	884	863
North Sea	98	91	111	106
Southeast Asia	273	120	253	105
	1,263	1,064	1,248	1,074
Total mboe/d (6mcf=1boe)	429	379	434	391

Total Company production during the quarter was 429 mboe per day, an increase of 13% over 2003 as Southeast Asia production increased 93% on a boe basis from last year, accounting for the majority of the increase.

The Company’s average oil and liquids production for the quarter was 218 mbbls/d, up 8% compared to last year. Southeast Asia oil and liquids production in the current quarter averaged 36,047 bbls/d, up 62% from 2003 with the completion of the Malaysia/Vietnam PM-3 CAA project in the fourth quarter of last year. Algeria production averaged 14,044 bbls/d, up 80% from 2003, with continuing production increases after startup last year. In North America, oil and liquids production averaged 57,049 bbls/d during the quarter, down 4% from 2003 due to natural declines and the Company’s continued focus on natural gas, partially offset by increased liquids associated with increased gas production. In the North Sea, oil and liquids production averaged 111,301 bbls/d, down 1% from 2003 with the impact of the North Tartan well coming onstream in August and asset acquisitions over the past year being offset by the impact of planned maintenance shutdowns.

During the third quarter, natural gas production averaged 1.3 bcf/d, 19% above last year, mainly due to Southeast Asia operations where gas production in the Malaysia/Vietnam project started at the end of last year and averaged 132 mmcf/d this quarter. Indonesia gas production increased 17% over last year averaging 141 mmcf/d with higher Corridor sales to Caltex and new sales to Singapore commencing late in the third quarter of 2003. In North America, natural gas production was 892 mmcf/d, an increase of 39 mmcf/d or 5% over last year. Significant production increases were achieved in Appalachia, up 45 mmcf/d, and in Alberta Foothills, up 26 mmcf/d, as new wells were brought onstream, to more than offset decreases resulting from natural declines and the effect of plant turnarounds in the quarter. North Sea natural gas production increased 8% during the quarter to 98 mmcf/d, mainly due to the tie-in of the Braemar well, partially offset by the planned maintenance shutdown at Ross/Blake during the quarter.

With the majority of shutdowns completed, total BOE production has increased and is on track to achieve production levels near the mid-point of our guidance range of 420,000 to 450,000 boe/d for the year

Prices

	Three months ended		Nine months ended
September 30,	2004	2003 ¹	2004	2003 ¹
Oil and liquids ($/bbl)
North America	45.47	33.94	41.46	36.89
North Sea	54.57	38.66	47.59	40.08
Southeast Asia	56.95	38.58	50.46	41.26
Algeria	63.98	39.37	53.03	38.44
Sudan	-	-	-	43.89
	53.30	37.33	46.87	39.60
Natural gas ($/mcf)
North America	6.63	6.14	6.77	7.01
North Sea	4.88	4.26	5.35	4.65
Southeast Asia	5.03	5.21	4.81	5.92
	6.15	5.87	6.25	6.67
Total $/boe (6mcf=1boe)	45.19	36.34	42.35	39.79
Hedging loss (income)-excluded from the above prices Oil and liquids ($/bbl)	7.15	2.01	4.68	2.04
Natural gas ($/mcf)	0.10	0.02	0.09	0.13
Total $/boe (6mcf=1boe)	3.91	1.13	2.67	1.45
Benchmark prices and foreign Exchange rates WTI (US$/bbl)	43.88	30.20	39.11	30.99
Brent (US$/bbl)	41.54	28.41	36.29	28.65
NYMEX (US$/mmbtu)	5.84	5.10	5.83	5.73
AECO (C$/gj)	6.32	5.97	6.34	6.70
US/Canadian dollar exchange rate	0.765	0.726	0.753	0.700
Canadian dollar / pound sterling exchange rate	2.379	2.222	2.419	2.302

Excludes synthetic oil

During the second quarter of 2004, the Company has reclassified transportation costs on a retroactive basis. Previously, these costs had been partially netted off against realized prices.

During the third quarter, Talisman’s commodity price averaged $45.19/boe, up $8.85/boe or 24% from last year. Ongoing concerns about potential output problems in Iraq, Russia and other key producing nations, coupled with continuing strong demand, especially in China and the United States, are among factors contributing to crude oil’s climb to record levels. The benchmark price of WTI oil averaged US$ 43.88 per barrel, a 45% increase over 2003. A stronger Canadian dollar (US$0.77 vs. US$0.73 in the third quarter of 2003), had a negative impact on the Company’s realized price of $53.30/bbl of oil and liquids, up 43% from the same period last year. During the quarter, oil and liquids prices in North America were impacted by widening quality differentials and in Algeria by the timing of liftings.

North America gas prices rose 8% to $6.63/mcf during the third quarter, but on a year to date basis, gas prices in 2004 were 3% less than prices realized last year, in line with the AECO reference price.

For the quarter ended September 30, 2004, Talisman recorded net hedging losses related to commodity based derivative financial instruments of $142 million for oil and liquids ($7.15/bbl) and $12 million for natural gas ($0.10/mcf). As of October 1, 2004, the Company has derivative and physical contracts for approximately 20% of its remaining 2004 estimated production (35% of the Company’s oil and liquids production and 5% of North American gas production). A summary of the contracts outstanding is included in notes 9 and 10 of the December 31, 2003 Consolidated Financial Statements, which have been updated in note 5 to the September 30, 2004 Interim Consolidated Financial Statements. The Company has relatively little production hedged in 2005.

Royalties

	Three months ended September 30
	2004		2003 ¹
	%	$ millions	%	$ millions
North America	20	154	20	127
North Sea	2	9	-	(2)
Southeast Asia	36	113	24	33
Algeria	31	26	52	15
	17	302	14	173
	Nine months ended September 30
	2004		2003 ¹
	%	$ millions	%	$ millions
North America	20	456	21	465
North Sea	2	27	-	(6)
Southeast Asia	35	289	25	107
Algeria	38	71	51	26
Sudan	-	-	46	97
	17	843	16	689

During the second quarter, the Company has reclassified transportation costs on a retroactive basis. Previously, these costs had been partially netted off against realized prices. This change reduced the royalty rate which is a percentage of reported prices.

The Company’s royalty expense for the third quarter was $302 million, (17%), up from $173 million, (14%) in 2003. The royalty rate increased as a result of higher commodity prices and the impact of the payout of cost recovery pools at Corridor during the first quarter of 2004. Under the terms of the Corridor PSC, after the Company has recovered its historical capital costs, the Government of Indonesia increases its share of oil, which results in a higher royalty rate. In addition, Southeast Asia royalties increased due to production increases in Malaysia/Vietnam where rates increased to 32% from 28% during the same quarter last year. The Algeria royalty rate decreased as the operations are currently in profit oil, which increases the Algeria taxes payable while reducing the Company’s effective royalty rate. The Algerian government’s total take for the quarter including royalties and taxes equalled approximately 51%, similar to 2003 when no current taxes were payable. The 51% total government take is expected to continue for the next few years.

Operating Expense

	Three months ended
September 30,	2004		2003
	$/boe	$ millions	$/boe	$ millions
North America	5.31	99	5.07	93
North Sea	14.12	166	10.09	119
Southeast Asia	3.75	28	5.19	20
Algeria	3.86	5	10.37	7
Sudan	-	-	-	-
	7.61	298	6.89	239
Synthetic oil	20.70	6	16.64	4
Pipeline		15		11
		319		254
	Nine months ended
September 30,	2004		2003
	$/boe	$ millions	$/boe	$ millions
North America	5.19	287	4.93	271
North Sea	12.33	468	10.45	358
Southeast Asia	3.44	74	5.61	61
Algeria	3.41	12	7.06	9
Sudan	-	-	3.73	18
	7.11	841	6.75	717
Synthetic oil	20.09	17	22.86	17
Pipeline		38		33
		896		767

During the third quarter, operating expense increased by $65 million to $319 million, with the North Sea comprising $47 million of the 26% total increase from last year. Unit operating costs averaged $7.61/boe, up from $6.89/boe last year. North Sea unit operating costs increased $4.03 to $14.12/boe, with $0.93/boe of this increase due to a 7% strengthening of the pound sterling against the Canadian dollar. The balance of the cost increase was due to pipeline repair costs at Beatrice, costs associated with shutdown activity, maintenance and well intervention work combined with additional costs due to the impact of acquisitions. In North America, unit operating costs increased due to higher processing fees and plant turnarounds. Unit operating costs in Southeast Asia were down 28% to $3.75/boe due to completion of the Malaysia/Vietnam PM-3 CAA project in the fourth quarter of last year. Algeria unit operating costs decreased due to continuing production increases after the startup of the MLN and related satellite fields last year. Unit operating costs in the fourth quarter are expected to decrease with reduced maintenance expenses and higher forecasted production.

Depreciation, Depletion and Amortization

	Three months ended
September 30,	2004		2003¹
	$/boe	$ millions	$/boe	$ millions
North America	10.26	195	9.27	173
North Sea	13.08	154	12.75	149
Southeast Asia	6.51	49	5.40	21
Algeria	6.04	7	6.81	5
	10.25	405	9.96	348
	Nine months ended
September 30,	2004		2003¹
	$/boe	$ millions	$/boe	$ millions
North America	9.94	558	9.14	510
North Sea	12.71	482	12.62	432
Southeast Asia	6.62	142	5.91	64
Algeria	6.06	21	7.08	9
Sudan	-	-	3.98	19
	10.11	1,203	9.67	1,034

Restatement of prior year to effect retroactive adoption of the new accounting policy for asset retirement obligation as at January 1, 2004. See note 1 to the Interim Consolidated Financial Statements.

The 2004 third quarter DD&A expense was $405 million, up 16% from the same quarter of 2003, as an increase in unit DD&A combined with the impact of higher production and an increase in the North Sea rate related to the stronger pound sterling against the Canadian dollar. The DD&A rates in North America increased due to the inclusion of costs associated with the US property acquisitions and the Vista Midstream acquisition in 2003. Total DD&A expense for Southeast Asia increased as a result of increased production, primarily from Malaysia/Vietnam.

Other ($ millions except where noted)

September 30,	Three months ended		Nine months ended
September 30,	2004	2003	2004	2003
G&A ($/boe)	1.00	0.92	1.00	0.99
Dry hole expense	99	71	222	185
Stock-based compensation	70	18	164	123
Transportation	48	44	142	134
Other expense (income)	(1)	(9)	15	25
Interest costs capitalized	4	8	9	22
Interest expense	41	30	120	102
Other revenue	22	17	65	54

Dry hole expense for the third quarter of 2004 was $99 million, $57 million of which was incurred in the North Sea for the Roisin and Cardhu wells and the partial writedown of Delta. In North America and Southeast Asia, dry hole expenses were $28 million and $13 million, respectively. Interest expense increased during the quarter due primarily to the higher average debt level as a result of the redemption of the preferred securities earlier in the year. Other revenue of $22 million included $17 million pipeline and processing revenue.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at September 30, 2004, which was first expensed during the second quarter of 2003. The Company’s stock-based compensation expense is based on the difference between the Company’s share price and its stock options or cash units exercise price. The $70 million expense for the current quarter is due to the 13% increase in the Company’s share price over the period ($164 million from the beginning of the year).

Taxes ($ millions)

September 30,	Three months ended		Nine months ended
September 30,	2004	2003 ¹	2004	2003 ¹
Current income tax	133	59	274	194
Future income tax (recovery)	(29)	9	(6)	(42)
Petroleum Revenue Tax	38	23	95	73
	142	91	363	225
Effective tax rate	46%	35%	33%	14%

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 2003 due to the effect of a $41 million ($0.11/share) future tax expense relating to unrealized foreign exchange gains associated with the impact of a stronger Canadian dollar on the foreign denominated debt, partially offset by the impact of Canadian corporate tax rate reductions. Excluding these adjustments, the effective tax rate on the Company’s income in the third quarter of 2004 would have been 34%. In the third quarter of this year, current tax increased to $133 million as a result of both higher commodity prices and increased production, which also increased PRT on North Sea operations.

Capital expenditures ($ millions)

	Three months ended		Nine months ended
September 30,	2004	2003	2004	2003
North America	357	359	1,085	1,231

North Sea

156

325

581

545

Southeast Asia	80	78	177	232
Algeria	3	5	7	30
Sudan	-	-	-	2
Other	89	79	240	137
	685	846	2,090	2,177

Capital expenditures include exploration and development expenditures and net asset acquisitions but exclude administrative capital.

North America capital expenditures for the current quarter on exploration of $155 million and development of $202 million, included the drilling of 96 gas wells and 46 oil wells. Expenditures in the North Sea during the third quarter were comprised of $52 million of exploration spending and development spending of $104 million. The majority of the Southeast Asia spending related to ongoing development drilling including the completion of 9 development wells at PM-3 CAA. In addition, the South Angsi development in Block PM-305 in Malaysia/Vietnam is proceeding on schedule for first oil in mid-2005. Other expenditures in the third quarter of 2004 included spending in Trinidad of $43 million and $29 million in Alaska. Total capital expenditures for the current quarter are down from last year due to the acquisitions in 2003 of Gyda and Vista Midstream. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2004 section of the Company’s December 31, 2003 MD&A.

Long-term debt and liquidity

At year-end, Talisman’s long-term debt plus preferred securities was $2.6 billion. At September 30, 2004 this amount had decreased to $2.3 billion primarily due to the application of excess operational cash flow.

Talisman’s long-term debt was impacted by the termination of the Company’s long-term debt hedge resulting in the GBP 250 million debt being revalued at current exchange rates. Prior to 2004, this debt was converted using historical foreign exchange rates contained in the cross currency and interest rate swap hedge contracts.

At quarter end, debt to debt plus equity was 31%. For the 12 months ended September 30, 2004, the debt to cash flow ratio was 0.78:1.

During the first half of the year, the Company redeemed its outstanding preferred securities realizing a $23 million gain (net of tax), being the difference between the carrying value and the redemption cost. The redemptions were funded from current cash flow and bank borrowings and gains were credited directly to retained earnings.

In March of this year, the Company renewed its normal course issuer bid to permit the purchase of up to 19,204,809 of its common shares, representing 5% of the total number of common shares outstanding at the time of the renewal (on a post share split basis).

In May 2004, the Company implemented a three for one share split of its issued and outstanding common shares. As at September 30, 2004, there were 384,105,983 common shares outstanding. All per share statistics included in this report have been restated to reflect this share split.

During the month of October 2004, 580,389 stock options were exercised, 8,700 in exchange for shares and 571,689 for cash.

Asset Retirement Obligations (future site restoration and abandonment liabilities)

The Company has asset retirement obligations related to the estimated costs of future dismantlement, site restoration and abandonment of oil and gas properties, including offshore production platforms, gas plants and facilities. Effective January 1, 2004, the Company adopted, on a retroactive basis, a new accounting standard that changed the method of accruing for costs associated with the retirement of fixed assets which an entity is legally obligated to incur. The Company has recorded the fair value of the liability for asset retirement obligations in the period incurred and a corresponding increase in the carrying amount of the related property, plant and equipment asset. During 2004, this liability increased by $122 million, due mainly to the acquisition of assets in the North Sea. See note 1 to the Interim Consolidated Financial Statements for details pertaining to this restatement and the impact on current period results of operations.

Hedge Accounting

The Company has adopted the new CICA accounting guideline on Hedging Relationships (AcG 13), effective January 1, 2004. This guideline, in addition to supplementing and interpreting existing hedging requirements under Canadian GAAP, established certain new conditions that must be fulfilled before hedge accounting may be applied.

Effective January 1, 2004, the Company’s US dollar cross currency and interest rate swap contracts were no longer designated as hedges of the Eurobond, which resulted in a revaluation of this Eurobond debt and a deferred gain of $17 million. This is being amortized over the period to 2009. The swap contracts were terminated in 2004 for cash proceeds of $138 million and resulted in an additional gain of $15 million. The termination of these contracts did not accelerate recognition of the deferred gain into income. The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales.

Talisman has adopted the US dollar as its functional currency for accounting purposes. The Company’s long-term debt denominated in UK pounds sterling and Canadian dollars has been designated as hedges of the Company’s net investments in the UK and Canadian self-sustaining operations. Unrealized foreign exchange gains and losses resulting from the translation of this debt are included in a separate component of shareholders’ equity described as cumulative foreign currency translation. However, as the Company is domiciled in Canada and pays taxes in Canada, in Canadian dollars, these unrealized gains and losses, although not being reported in income, will be subject to Canadian tax if they are realized in the future.

Summary of Quarterly Results (millions of Cdn. dollars unless otherwise stated)

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

			Three months ended
			2004						2003									2002
			Sept. 30		June 30		March 31		Dec. 31		Sept. 30		June 30		March 31			Dec. 31
	Total revenue ¹		1,355		1,337		1,261		1,129		1,077		1,023		1,370	1,274
	Net income ^{2, 3}		122		197		223		108		128		202		574	177
Per common share amounts ⁴ (Cdn. dollars)
Net income ^{2, 3}		0.32		0.50		0.57		0.27		0.32		0.51		1.46			0.43
Diluted net income ^{2, 3}		0.31		0.50		0.56		0.26		0.31		0.50		1.45			0.42

Revenue has been reclassified to conform to the method of presentation adopted during the second quarter of 2004, disclosing transportation costs as a separate item. Previously, these costs had been partially netted off against revenue.

Net income and net income before discontinued operations and extraordinary items are the same.

Prior years have been restated to effect retroactive adoption of the new accounting policy on asset retirement obligation as at January 1, 2004.

All per share amounts have been retroactively restated to reflect the impact of the Company’s 3 for 1 stock split as of the second quarter of 2004.

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters as at September 30, 2004.

In the third quarter, revenue rose over the second quarter as the increase in oil prices more than offset the reduction in production, resulting from maintenance shutdowns. Net income in the third quarter declined from the previous quarter, as the increase in revenue was more than offset by increases in hedging losses, dry holes, exploration expenses and current income taxes. In the first two quarters of 2004, revenue continued to rise due to increases in both commodity prices and production. These factors combined with the benefit of tax rate reductions to increase net income in the first quarter of 2004 over the last quarter of 2003. A higher charge for stock-based compensation and reduced tax rate reductions resulted in a slight drop in net income during the second quarter of 2004 from the previous quarter.

In the first quarter of 2003, the gain on the sale of the Sudan operations increased net income by $296 million. The sale of these operations contributed to the drop in revenues during the following three quarters of 2003, which was partially offset by production increases in other areas and continued high commodity prices. Net income during the second quarter of 2003 was increased by $160 million due to a reduction in the Canadian federal and provincial tax rates. The Company began recording stock-based compensation in the second quarter of 2003. The second quarter’s net income was reduced by a $105 million ($70 million after tax) catch-up expense relating to outstanding stock options. The third and fourth quarters of 2003 included an additional $80 million ($50 million after tax) of stock-based compensation expense.

Non-GAAP financial measures

Included in the MD&A are references to terms commonly used in the oil and gas industry such as cash flow and cash flow per share. These terms are not defined by Generally Accepted Accounting Principles (GAAP) in either Canada or the US. Consequently, these are referred to as non-GAAP measures. Cash flow, as commonly used in the oil and gas industry, appears as a separate caption on the Company’s cash flow statement and represents net income before exploration costs, DD&A, future taxes and other non-cash expenses. Cash flow is used by the Company to assess operating results between years and between peer companies with different accounting policies. Our reported results may not be comparable to similarly titled measures by other companies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with Canadian GAAP as an indicator of the Company’s performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. Debt to cash flow is a non-GAAP measure. The following table of Sudan pro forma data are non-GAAP measures, which the Company uses to evaluate performance on a basis of activity, comparable to current operations.

2003 Sudan pro forma data

($ millions)

Nine months ended September 30,	2003
Net income	904
Less gain on sale	(296)
	608
Sudan operating income	(69)
Sudan current taxes	17
Sudan future taxes	8
	(44)
Pro forma Sudan net income	564
Cash flow	2,085
Less: Sudan net income	(44)
Add: Future tax	(8)
Add: DD&A	(19)
Add: Exploration	(5)
	(76)
Pro forma Sudan cash flow	2,009
Exploration and development expenditures	1,522
Less: Sudan exploration and development expenditures	2
Pro forma Sudan exploration and development expenditures	1,520

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 energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

EXPLORATION AND OPERATIONS REVIEW

North America

During the third quarter, Talisman participated in 151 gross wells (85 operated), resulting in a total of 96 gas and 46 oil wells for an average success rate of 93%. Included in the 151 wells are 30 exploration wells, which resulted in 24 gas wells and five oil wells.

Total production from North America reached 205,717 boe/d during the quarter. Gas production in North America during the third quarter averaged 892 mmcf/d, increasing for the fourth consecutive quarter and 39 mmcf/d (5%) higher than the same period last year. Liquids production averaged 57,049 bbls/d, a 4% decrease from the third quarter 2003, reflecting the Company’s continued focus on natural gas exploration and development activities in North America.

Wet weather hampered drilling and completion efforts in many of Talisman’s core areas during the third quarter. With the drier weather towards the end of September, activity has increased. In particular, Talisman’s rig activity in the Edson, Wild River and Deep Basin areas has now increased by 50% over last year.

Production in the Central Alberta Foothills averaged 152 mmcf/d in the quarter, unchanged from the previous quarter and up 21% over a year ago. Talisman drilled seven natural gas wells in the Alberta Foothills during the quarter, including a number of high impact wells. Two horizontal wells tested at rates of 12-13 mmcf/d each (TLM 50%) and a vertical well will come on production at 12 mmcf/d (TLM 44%). The Company continues to increase its emphasis on exploration in the northern Alberta Foothills.

At Turner Valley (Southern Alberta Foothills) natural gas production continues to increase with third quarter gas rates averaging 23 mmcf/d, a 14 % increase over the second quarter and a 118% increase over the third quarter of 2003. In addition, liquids production rose to 2,854 boe/d, a 19% increase over third quarter 2003 production of 2,400 boe/d.

In the Edson area, production averaged 37,800 boe/d during third quarter, an increase of 5% over the same period last year, despite the negative impact of wet weather. During the third quarter, the majority of construction of Talisman’s 10 megawatt co-generation plant at its Edson natural gas plant was completed. Commissioning commenced mid-October with startup expected in early to mid-December.

On November 1, Talisman announced the results of its b-60-E Monkman deep well (TLM 80%). The well tested at a restricted rate of 40 mmcf/d and is expected to be on production by January 1, 2005. The Company has built a strategic land position in the area, holding approximately 134,000 gross hectares of deep rights with an average working interest of 57%. Talisman has identified 30 potential drilling locations.

Maintenance turnarounds on third-party infrastructure in the Monkman and Deep Basin areas during the quarter have been completed. In the Deep Basin, record high production levels have been reached, averaging 66 mmcf/d of natural gas and 2,270 bbls/d of liquids for a total of 13,270 boe/d in the quarter. This represents a 19% increase over third quarter 2003 and is 22% above last quarter.

In Appalachia, Fortuna Energy Inc., Talisman’s wholly owned subsidiary, drilled two successful natural gas wells in the third quarter. Production during the quarter averaged 109 mmcf/d, a 16% increase over the second quarter and a 71% increase over the same period last year. In addition, Fortuna participated in two wells on the recently acquired Belden and Blake acreage and will be participating in an additional two to four wells in the fourth quarter. Incremental production of 5-8 mmcf/d is expected from these wells in the latter portion of the fourth quarter.

The recently completed Soderblom HZ#1 well tested at a restricted rate of 19 mmcf/d. The well is expected to be tied in this January, reaching full production towards the end of the first quarter.

North American Frontiers

Fortuna Exploration LLC participated in the Beaufort Sea area wide 2004 Competitive Oil and Gas Lease Sale in Alaska on October 27, 2004. Fortuna bid successfully on 19 tracts encompassing 101,120 acres in the Harrison Bay area adjacent to the NE-NPRA. Fortuna now holds a total of 49 exploration blocks in Alaska.

North Sea

Production from the North Sea averaged 127,704 boe/d in the third quarter, compared to 142,000 boe/d in the second quarter and up slightly from the third quarter of 2003. Third quarter production reflected a number of planned annual maintenance shutdown programs.

During the quarter, development wells were completed at Clyde (4,000 bbls/d) and Claymore (1,900 bbls/d). Development wells are currently drilling at Gyda, Claymore, Iona and Galley.

North Tartan development project commenced production at 6,000 bbls/d in August, two months ahead of schedule and on budget.

The Tweedsmuir development project received approval in late August. Drilling is expected to start in early 2005 and first oil production is planned for late 2006.

At the Beatrice field, 25 kilometres off the east coast of Scotland, development of a deepwater wind farm demonstrator project commenced.

The Roisin, Cardhu and Skate exploration wells were not commercially successful.

Malaysia/Vietnam

Production averaged 44,234 boe/d in the third quarter, an increase of 7% over the second quarter of 2004. Drilling continued at the PM-3 development with nine wells completed during the quarter.

The South Angsi development project is proceeding on schedule for first oil in mid-2005. The jacket was loaded out in October.

The North West Besar-1 exploration in Block PM-305 was unsuccessful.

On Malaysia’s Block PM-314, a 1,002 square kilometer 3D seismic acquisition started on June 29 and finished on August 31. Talisman operates the block and has a 60% working interest.

Indonesia

Production averaged 37,296 boe/d in the third quarter, compared to 35,981 boe/d during the same period of 2003 and 37,000 boe/d in the second quarter. Natural gas sales averaged 141 mmcf/d, 17% above last year with increased sales to Caltex and Singapore.

In the Corridor Block (Talisman Corridor Ltd 36%) an agreement was reached to sell 2.3 tcf of additional gas to PT Perusahaan Gas Negara (Persero) Tbk. Gas sales are expected to commence in the first quarter of 2007 at 170 mmcf/d.

Algeria

Production averaged 14,044 bbls/d in the third quarter, an increase of 20% over the second quarter. Development drilling continued at Ourhoud throughout the quarter.

Trinidad

Development of the Angostura oil and gas field is continuing on schedule for production startup in early 2005, with initial production expected to be in the 60,000 bbls/d range (TLM 25%). Development drilling at Angostura is continuing with four gas injection wells, eight production wells and a dry hole drilled to date.

Processing of Galera 3D offshore seismic survey was completed and interpretation has begun. A number of leads that have been identified with plans to arrive at drillable locations for the 2005 budget year.

The onshore Eastern Block 3D seismic processing was completed during the quarter and initial interpretation appears encouraging. Pre-well planning is underway, with the first well expected to spud in the third quarter of next year.

Colombia

On the Tangara block, the Tangara-1 exploration well (TLM 30%) began drilling in July. Total depth will be approximately 5,600 metres and the well should be completed in the second quarter of 2005.

Peru

On Block 64, the Situche Norte 1X well (TLM 25%) was spud in early August. Total depth will be approximately 5,500 metres and drilling should be completed in the first quarter of 2005.

Qatar

Acquisition of 1,200 km² of seismic commenced in Block 10 in early September. The program is anticipated to be completed by mid-November and processing should be completed sometime in the first quarter of 2005. We expect to spud the first exploration well in late 2005.

Talisman Energy Inc. is a large, independent oil and gas producer, with operations in Canada and, through its subsidiaries, the North Sea, Indonesia, Malaysia, Vietnam, Algeria and the United States. Talisman's subsidiaries also conduct business in Trinidad, Colombia, Qatar and Peru. Talisman has adopted the International Code of Ethics for Canadian Business and is committed to maintaining high standards of excellence in corporate citizenship and social responsibility wherever its business is conducted. The Company is a participant in the United Nations Global Compact, a voluntary initiative that brings together companies, governments, civil society and other groups to advance human rights, labour and environmental principles. Talisman's shares are listed on the Toronto Stock Exchange in Canada and the New York Stock Exchange in the United States under the symbol TLM.

For further information, please contact:

David Mann, Senior Manager, Corporate and Investor Communications

Phone:

(403) 237-1196

Fax:

(403) 237-1210

E-mail:

tlm@talisman-energy.com

Website:

www.talisman-energy.com

Forward-looking Statements

This interim report contains statements about future production and cash flows, business plans for drilling, exploration and development, estimated future commodity prices and exchange rates, other expectations, beliefs, plans, goals, objectives, assumptions and statements about future events or performance that constitute "forward-looking statements" or “forward-looking information” within the meaning of applicable securities law.

Statements concerning oil and gas reserves contained in this report may be deemed to be forward-looking statements as they involve the implied assessment that the resources described can be profitably produced in the future, based on certain estimates

and assumptions.

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;

•

risks and uncertainties involving geology of oil and gas deposits;

•

the uncertainty of reserves estimates and reserves life;

•

the uncertainty of estimates and projections relating to production, costs and expenses;

•

potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

•

fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

uncertainties related to the litigation process, such as possible discovery of new evidence or acceptance of novel legal theories and the 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);

•

general economic conditions;

•

the effect of acts of, or actions against international terrorism; and

•

the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.

We caution that the foregoing list of risks and uncertainties is not exhaustive. Additional

information on these and other factors, which could affect the Company's operations or financial results, are included in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", "- Liquidity and Capital Resources", and "- Outlook for 2004", as well as 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.

Throughout this interim report, Talisman 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 U.S., net production volumes are reported after the deduction of these amounts.

Throughout this report, 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 ration of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Talisman Energy Inc.
Highlights


	Three months ended		Nine months ended
	September 30		September 30
	2004	2003	2004	2003
Financial		(restated)		(restated)
(millions of Canadian dollars unless otherwise stated)
Cash flow	706	640	2,252	2,085
Net income	122	128	542	904
Exploration and development expenditures	687	575	1,810	1,522
Per common share (dollars)
Cash flow (1)	1.84	1.66	5.86	5.39
Net income (2)	0.32	0.32	1.39	2.29
Production
(daily average)
Oil and liquids (bbls/d)
North America	53,857	56,556	54,372	57,570
North Sea	111,301	112,360	119,818	107,811
Southeast Asia	36,047	22,241	35,853	22,170
Algeria	14,044	7,795	12,935	4,839
Sudan	-	-	-	17,433
Synthetic oil	3,192	3,056	3,046	2,697
Total oil and liquids	218,441	202,008	226,024	212,520
Natural gas (mmcf/d)
North America	892	853	884	863
North Sea	98	91	111	106
Southeast Asia	273	120	253	105
Total natural gas	1,263	1,064	1,248	1,074
Total mboe/d	429	379	434	391
Prices (3)
Oil and liquids ($/bbl)
North America	45.47	33.94	41.46	36.89
North Sea	54.57	38.66	47.59	40.08
Southeast Asia	56.95	38.58	50.46	41.26
Algeria	63.98	39.37	53.03	38.44
Sudan	-	-	-	43.89
Crude oil and natural gas liquids	53.30	37.33	46.87	39.60
Synthetic oil	53.06	42.59	49.22	45.14
Total oil and liquids	53.30	37.42	46.90	39.68
Natural gas ($/mcf)
North America	6.63	6.14	6.77	7.01
North Sea	4.88	4.26	5.35	4.65
Southeast Asia	5.03	5.21	4.81	5.92
Total natural gas	6.15	5.87	6.25	6.67
Total ($/boe) (includes synthetic)	45.25	36.39	42.40	39.82

(1) Cash flow per common share is calculated before deducting preferred security charges.
(2) Net income per common share is calculated after deducting preferred security charges.
(3) Prices are before hedging.

Talisman Energy Inc.
Consolidated Statements of Income

	Three months ended		Nine months ended
(millions of Canadian dollars	September 30		September 30
except per share amounts)	2004	2003	2004	2003
		(restated)		(restated)
Revenue		(note 1)		(note 1)
Gross sales	1,635	1,233	4,731	4,105
Less royalties	302	173	843	689
Net sales	1,333	1,060	3,888	3,416
Other	22	17	65	54
Total revenue	1,355	1,077	3,953	3,470

Expenses
Operating	319	254	896	767
Transportation	48	44	142	134
General and administrative	39	32	119	106
Depreciation, depletion and amortization	405	348	1,203	1,034
Dry hole	99	71	222	185
Exploration	71	70	167	161
Interest	41	30	120	102
Stock-based compensation	70	18	164	123
Other	(1)	(9)	15	25
Total expenses	1,091	858	3,048	2,637
Gain on sale of Sudan operations (note 7)	-	-	-	296
Income before taxes	264	219	905	1,129
Taxes
Current income tax	133	59	274	194
Future income tax (recovery)	(29)	9	(6)	(42)
Petroleum revenue tax	38	23	95	73
	142	91	363	225
Net income	122	128	542	904
Preferred security charges, net of tax	-	6	9	17
Net income available to common shareholders	122	122	533	887

Per common share (dollars)
Net income	0.32	0.32	1.39	2.29
Diluted net income	0.31	0.31	1.37	2.27
Average number of common shares outstanding (millions)
Basic	384	384	384	387
Diluted	390	390	390	391

See accompanying notes.
Interim statements are not independently audited.

Consolidated Statements of Retained Earnings
	Three months ended		Nine months ended
	September 30		September 30
(millions of Canadian dollars)	2004	2003	2004	2003
		(restated)		(restated)
		(note 1)		(note 1)
Retained earnings, beginning of period	2,279	1,793	1,903	1,141
Net income	122	128	542	904
Common share dividends	-	-	(58)	(39)
Purchase of common shares	-	(48)	-	(122)
Redemption of preferred securities, net of tax (note 2)	-	-	23	-
Preferred security charges, net of tax	-	(6)	(9)	(17)
Retained earnings, end of period	2,401	1,867	2,401	1,867
See accompanying notes.
Interim statements are not independently audited.

Talisman Energy Inc.
Consolidated Balance Sheets


	September 30	December 31
(millions of Canadian dollars)	2004	2003
Assets		(restated)
Current		(note 1)
Cash and cash equivalents	28	98
Accounts receivable	821	760
Inventories	78	100
Prepaid expenses	11	17
	938	975

Accrued employee pension benefit asset	62	63
Other assets	72	76
Goodwill	469	473
Property, plant and equipment	10,866	10,193
	11,469	10,805
Total assets	12,407	11,780


Liabilities
Current
Accounts payable and accrued liabilities	1,179	1,064
Income and other taxes payable	265	154
	1,444	1,218

Deferred credits	138	57
Asset retirement obligation (note 1)	1,290	1,157
Long-term debt (note 4)	2,273	2,203
Future income taxes	2,182	2,127
	5,883	5,544
Contingencies and commitments (note 5)

Shareholders' equity
Preferred securities (note 2)	-	431
Common shares (note 2)	2,727	2,725
Contributed surplus	73	73
Cumulative foreign currency translation	(121)	(114)
Retained earnings	2,401	1,903
	5,080	5,018
Total liabilities and shareholders' equity	12,407	11,780

See accompanying notes.
Interim statements are not independently audited.

Talisman Energy Inc.
Consolidated Statements of Cash Flows


	Three months ended		Nine months ended
	September 30		September 30
(millions of Canadian dollars)	2004	2003	2004	2003
		(restated)		(restated)
Operating		(note 1)		(note 1)
Net income	122	128	542	904
Items not involving current cash flow (note 6)	513	442	1,543	1,020
Exploration	71	70	167	161
Cash flow	706	640	2,252	2,085
Deferred gain on unwound hedges	-	(3)	-	(8)
Changes in non-cash working capital	(13)	(4)	157	(2)
Cash provided by operating activities	693	633	2,409	2,075
Investing
Proceeds on sale of Sudan operations	-	-	-	1,012
Capital expenditures
Exploration, development and corporate	(692)	(584)	(1,830)	(1,550)
Acquisitions	1	(246)	(299)	(644)
Proceeds of resource property dispositions	1	48	5	62
Investments	(4)	-	(4)	(3)
Changes in non-cash working capital	74	16	(60)	1
Cash used in investing activities	(620)	(766)	(2,188)	(1,122)
Financing
Long-term debt repaid	(534)	(54)	(568)	(791)
Long-term debt issued	582	-	582	292
Short-term borrowings	(555)	-	-	-
Common shares issued (purchased)	-	(72)	2	(186)
Common share dividends	-	-	(58)	(39)
Preferred securities redeemed	-	-	(402)	-
Preferred security charges	-	(10)	(15)	(29)
Deferred credits and other	31	2	193	20
Changes in non-cash working capital	(2)	-	(8)	-
Cash provided by (used in) financing activities	(478)	(134)	(274)	(733)
Effect of translation on foreign currency cash	(8)	(1)	(17)	(27)
Net (decrease) increase in cash and cash equivalents	(413)	(268)	(70)	193
Cash and cash equivalents, beginning of period	441	488	98	27
Cash and cash equivalents, end of period	28	220	28	220

See accompanying notes.
Interim statements are not independently audited.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

(tabular amounts in millions of Canadian dollars (“$”) except as noted)

The Interim Consolidated Financial Statements of Talisman Energy Inc. (“Talisman” or the “Company”) have been prepared by management in accordance with Canadian generally accepted accounting principles. Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. The Interim Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and the notes thereto in Talisman’s Annual Report for the year ended December 31, 2003.

1. Significant Accounting Policies

The Interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the Consolidated Financial Statements for the year ended December 31, 2003 except for the following:

1a) Asset Retirement Obligation

Effective January 1, 2004 the Company retroactively adopted the Canadian Institute of Chartered Accountants (“CICA”) new standard for accounting for asset retirement obligations (ARO). This standard requires that the fair value of the statutory, contractual or legal obligation associated with the retirement and reclamation of tangible long-lived assets be recorded when the related assets are put into use, with a corresponding increase to the carrying amount of the related assets. This corresponding increase to capitalized costs is amortized to earnings on a basis consistent with depreciation, depletion, and amortization of the underlying assets. Subsequent changes in the estimated fair value of the asset retirement obligations are capitalized and amortized over the remaining useful life of the underlying asset.

The asset retirement obligation liabilities are carried on the consolidated balance sheet at their discounted present value and are accreted over time for the change in their present value, with this accretion charge included in depreciation, depletion and amortization.

The adjustment required to the December 31, 2003 consolidated balance sheet to implement this change in accounting is as follows:

	As previously reported	Adjustments	As restated
Property, plant and equipment	9,778	415	10,193
Provision for future site restoration/ARO	840	317	1,157
Future income taxes	2,088	39	2,127
Retained earnings	1,844	59	1,903

The adjustment to the consolidated income statement for the 3 months ended September 30, 2003 is as follows:

	As previously reported	Adjustments	As restated
Depletion, depreciation and amortization	350	(2)	348
Future income tax recovery	9	-	9
Net income	126	2	128

Per common share (Canadian dollars)
Net income	.31	0.01	.32
Diluted net income	.31	0.00	.31

The adjustment to the consolidated income statement for the 9 months ended September 30, 2003 is as follows:

	As previously reported	Adjustments	As restated
Depletion, depreciation and amortization	1,040	(6)	1,034
Future income tax recovery	(44)	2	(42)
Net income	900	4	904

Per common share (Canadian dollars)
Net income	2.28	0.01	2.29
Diluted net income	2.26	0.01	2.27

The change in accounting for ARO did not significantly affect earnings for the three or nine months ended September 30, 2004. Total accretion for the nine months ended September 30, 2004 of $53 million (2003 - $44 million) has been included in depreciation, depletion and amortization. At September 30, 2004 the estimated total undiscounted asset retirement obligation was $2.0 billion. These obligations will be settled based on the useful lives of the underlying assets, the majority of which are expected to be settled within the next 25 years. The asset retirement obligation has been discounted using a credit-adjusted risk free rate of 5.5 percent. No amount of market risk premium has been included in the estimate of the Company’s ARO liability as management does not believe there to be sufficient evidence in the oil and gas industry to estimate any such market premium.

During the first nine months of 2004, the Company’s asset retirement obligation changed as follows:

ARO liability at January 1, 2004¹	1,177
Liabilities incurred during period	107
Liabilities settled during period	(19)
Accretion expense	53
Foreign currency translation	(19)
ARO liability at September 30, 2004¹	1,299

1 Included in January 1, 2004 and September 30, 2004 liabilities are $20 million and $9 million respectively of short-term reclamation costs recorded in accounts payable on the balance sheet for a net ARO liability of $1,157 and $1,290 respectively.

1b) Hedging

The CICA has issued a new accounting guideline on Hedging Relationships (AcG 13), which is effective for 2004. This guideline, in addition to supplementing and interpreting existing hedging requirements under Canadian GAAP, establishes certain other conditions required before hedge accounting may be applied. Effective January 1, 2004, the Company’s US dollar cross currency swap contracts and interest rate swap contracts are no longer designated as hedges of the Eurobond. These contracts were subsequently terminated in 2004 for proceeds of $138 million. As a result of these contracts no longer hedging the Eurobond debt, on January 1, 2004, the Company recorded a deferred gain of $17 million. Subsequently, the debt has been revalued based on the September 30, 2004 exchange rate, resulting in an increase to long-term debt of $101 million. The unrealized gain of $17 million will be deferred and amortized over the period to 2009, the original term of the contracts. The termination of these contracts does not accelerate the recognition of the deferred gain into income. This accounting guideline has not impacted the Company’s accounting for its commodity price derivative contracts that have been designated as hedges of anticipated future commodity sales.

The Company’s long-term debt denominated in UK pounds sterling and Canadian dollars has been designated as hedges of the Company’s net investments in the UK and Canadian self-sustaining operations. Unrealized foreign exchange gains and losses resulting from the translation of this debt are deferred and included in a separate component of shareholders’ equity described as cumulative foreign currency translation.

1c) Transportation Expenses

During the second quarter, the Company reclassified transportation costs on a retroactive basis. Previously, these costs had been either netted off against the realized price or included as a component of operating costs, depending on the circumstances in the various geographic segments. On a year to date basis as at September 30, 2004 $142 million in transportation expenses have been reclassified representing $50 million in decreased operating expenses and $92 million of increased revenue (2003, transportation expenses of $134 million, $44 million of operating expenses and $90 million of revenue).

2. Share Capital

Talisman’s authorized share capital consists of an unlimited number of common shares without nominal or par value and first and second preferred shares. No preferred shares have been issued.

Continuity of common shares (year to date)	2004
	Shares	Amount
Balance at January 1,	383,996,183	$2,725
Issued upon exercise of stock options	109,800	2
Balance at September 30,	384,105,983	2,727

Pursuant to a normal course issuer bid renewed in March 2004, Talisman may repurchase up to 19,204,809 common shares representing 5% of the outstanding common shares of the Company at the time the normal course issuer bid was renewed (on a post share split basis). The total remaining shares that may be repurchased under the existing normal course issuer bid is 19,204,809.

During the first half of the year, the Company redeemed its outstanding preferred securities realizing a $23 million gain, (net of tax) being the difference between the carrying value and the redemption cost. The redemptions were funded from current cash flow and bank borrowings and gains were credited directly to retained earnings.

In May 2004, the Company implemented a three-for one share split of its issued and outstanding common shares. All references to net income per share, diluted net income per share, weighted average number of common shares outstanding and common shares issued and outstanding have been retroactively restated to reflect the impact of the Company’s three-for one share split.

3. Stock Options

Continuity of stock options (year to date)	2004
	Number	Average
	Of	Exercise
	Options	Price ($)
Outstanding at January 1,	23,599,596	17.55
Granted during the period	3,666,480	25.63
Exercised for common shares	109,800	10.68
Exercised for cash payment	5,142,588	15.62
Expired/forfeited	249,690	21.36
Outstanding at September 30,	21,763,998	19.35
Exercisable at September 30,	8,571,006	15.57

Effective in the second quarter of 2003 the Company began to use the intrinsic-value method to recognize compensation expense associated with our stock appreciation rights. Obligations are accrued on a graded vesting basis and represent the difference between the market value of our common shares and the exercise price of the options. This obligation is revalued each reporting period based on the changes in the graded vested amount of options outstanding and changes in the market value of our common shares.

All options issued by the Company permit the holder to purchase one common share of the Company at the stated exercise price or, effective July 1, 2003, to receive a cash payment equal to the appreciated value of the stock option.

4. Long-Term Debt

	September 30, 2004			December 31, 2003
Debentures and Notes (unsecured)
US$ denominated (US$825 million, 2003 US$850 million)			1,043		1,098
Canadian $ denominated			658		634
£ denominated (£250 million)¹			572		471
		$	2,273	$	2,203

Prior to January 1, 2004 the £250 million Eurobond was effectively swapped into US$364 million indebtedness. Effective January 2004 this debt is no longer swapped into US dollars and is now revalued based on the Canadian dollar to Pound Sterling exchange rate.

The Company has a debenture maturing in the fourth quarter in the amount of $75 million. The Company expects to settle this debt from cash on hand or by drawing upon bank lines of credit.

5. Commodity Based Sales Contracts

The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales. The following tables summarize commodity price derivative contracts and fixed price sales contracts outstanding at September 30, 2004:

Commodity price derivative contracts

Natural gas

Fixed price swaps	Remainder 2004
(NYMEX gas index)
Volumes (mcf/d)	19,351
Price (US$/mcf)	4.34

Crude oil contracts

Fixed price swaps	Remainder 2004	2005	Two-way collars	Remainder 2004
(Brent oil index)			(Brent oil index)
Volumes (bbls/d)	11,000	-	Volumes (bbls/d)	31,000
Price (US$/bbl)	25.99	-	Ceiling price (US$/bbl)	26.61
			Floor price (US$/bbl)	23.56
(WTI/NYMEX oil index)			(WTI/NYMEX oil index)
Volumes (bbls/d)	12,000	6,000	Volumes (bbls/d)	25,000
Price (US$/bbl)	29.20	26.97	Ceiling price (US$/bbl)	28.90
			Floor price (US$/bbl)	25.08

Physical contracts (North America)

Fixed price sales	Remainder 2004	2005	2006-2007
Volumes (mcf/d)	28,578	14,650	14,650
Weighted average price ($/mcf)	3.90	3.50	4.19

Three-way collars (NIT)	Remainder 2004
Volumes (mcf/d)	6,117
Ceiling ($/mcf)	3.31
Floor ($/mcf)	3.17
Sold put strike ($/mcf)	2.52

The three-way collars are similar to two-way commodity collars with the call and put strike prices being equivalent to the ceiling and floor prices, except that should the NIT (Nova Inventory Transfer) index fall below the sold put strike price, Talisman will receive NIT plus the difference between the put strike and sold put strike prices.

6. Selected Cash Flow Information
	Three months ended September 30		Nine months ended September 30
	2004	2003	2004	2003
Net income	122	128	542	904
Items not involving current cash flow
Depreciation, depletion and amortization	405	348	1,203	1,034
Property impairments	-	-	-	28
Dry hole	99	71	222	185
Net loss (gain) on asset disposals	(1)	(5)	2	(14)
Gain on sale of Sudan operations	-	-	-	(296)
Stock-based compensation	56	1	99	106
Future income taxes and deferred petroleum revenue tax	(54)	29	(16)	(22)
Other	8	(2)	33	(1)
	513	442	1,543	1,020
Exploration	71	70	167	161
Cash flow	706	640	2,252	2,085

The cash interest and taxes paid for the nine months ended September 30 were as follows:

	2004	2003
Interest paid	79	83
Income taxes paid	152	117

7. Sale of Sudan Operations

On March 12, 2003, the Company completed the sale of its 25% indirectly held interest in the Greater Nile Oil Project in Sudan. Total gross proceeds were $1.13 billion (US$771 million), including interest and cash received by Talisman during the interim period between September 1, 2002 and closing on March 12, 2003. The gain on sale is as follows:

Gross proceeds on sale of Sudan operations (US$771 million)	$ 1,135
Less interim adjustments	(123)
	1,012
Property, plant and equipment	687
Working capital and other assets	72
Future income tax liability	(59)
Net carrying value at March 12, 2003	700
Closing costs	16
Gain on disposal	$296

8. Segmented Information

	North America (1)				North Sea (2)				Southeast Asia (3)
	Three months		Nine months		Three months		Nine months		Three months		Nine months
	ended		ended		ended		ended		ended		ended
	September 30		September 30		September 30		September 30		September 30		September 30
(millions of Canadian dollars)	2004	2003	2004	2003	2004	2003	2004	2003	2004	2003	2004	2003
Revenue
Gross sales (6)	740	658	2,199	2,187	497	415	1,515	1,256	315	133	829	405
Royalties	154	127	456	465	10	(2)	27	(6)	112	33	289	107
Net sales	586	531	1,743	1,722	487	417	1,488	1,262	203	100	540	298
Other	12	12	48	32	10	5	17	22	-	-	-	-
Total revenue	598	543	1,791	1,754	497	422	1,505	1,284	203	100	540	298
Segmented expenses
Operating (6)	106	99	307	291	179	128	503	388	29	20	74	61
Transportation (6)	20	18	57	58	16	15	48	47	10	10	31	27
DD&A (6)	195	173	558	510	154	149	482	432	49	21	142	64
Dry hole	28	47	90	109	57	(1)	95	50	13	1	13	2
Exploration	40	28	87	66	8	5	22	16	9	4	17	11
Other	(2)	(11)	(16)	(31)	1	3	14	32	1	1	3	5
Total segmented expenses	387	354	1,083	1,003	415	299	1,164	965	111	57	280	170
Segmented income before taxes	211	189	708	751	82	123	341	319	92	43	260	128
Non-segmented expenses
General and administrative
Interest
Gain on sale of Sudan operations
Stock-based compensation
Currency translation
Total non-segmented expenses
Income before taxes
Capital expenditures
Exploration	155	115	409	348	52	25	139	59	23	11	38	44
Development	200	149	575	393	104	118	256	301	57	67	139	188
Midstream	4	6	7	20	-	-	-	-	-	-	-	-
Exploration and development	359	270	991	761	156	143	395	360	80	78	177	232
Property acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures (4)
Property, plant and equipment			6,124	5,767			3,170	2,995			1,066	1,084
Goodwill			291	291			73	74			105	108
Other			311	403			353	386			255	217
Segmented assets			6,726	6,461			3,596	3,455			1,426	1,409
Non-segmented assets
Total assets (5)

	Three months		Nine months						Three months		Nine months
	ended		ended						ended		ended
	September 30		September 30						September 30		September 30
(1) North America	2004	2003	2004	2003	(2) North Sea				2004	2003	2004	2003
Canada	534	503	1,631	1,615	United Kingdom				467	404	1,405	1,249
US	64	40	160	139	Netherlands				9	6	25	23
Total revenue	598	543	1,791	1,754	Norway				21	12	75	12
Canada			5,637	5,356	Total revenue				497	422	1,505	1,284
US			487	411	United Kingdom						2,955	2,777
Property, plant and equipment (5)			6,124	5,767	Netherlands						40	40
					Norway						175	178
(4) Excluding corporate acquisitions.					Property, plant and equipment (5)						3,170	2,995
(5) Current year represents balances as at September 30, prior year represents balances as at December 31.
(6) See note 1 to the Interim Consolidated Financial Statements - Revenues, operating expenses and transportation reclassified in 2004.
DD&A restated effective January 1, 2004 for retroactive adoption of CICA policy on Asset Retirement Obligations.

Algeria				Sudan				Other				Total
Three months		Nine months		Three months		Nine months		Three months		Nine months		Three months		Nine months
ended		ended		ended		ended		ended		ended		ended		ended
September 30		September 30		September 30		September 30		September 30		September 30		September 30		September 30
2004	2003	2004	2003	2004	2003	2004	2003	2004	2003	2004	2003	2004	2003	2004	2003

83	27	188	48	-	-	-	209	-	-	-	-	1,635	1,233	4,731	4,105
26	15	71	26	-	-	-	97	-	-	-	-	302	173	843	689
57	12	117	22	-	-	-	112	-	-	-	-	1,333	1,060	3,888	3,416
-	-	-	-	-	-	-	(1)	-	-	-	1	22	17	65	54
57	12	117	22	-	-	-	111	-	-	-	1	1,355	1,077	3,953	3,470

5	7	12	9	-	-	-	18	-	-	-	-	319	254	896	767
2	1	6	2	-	-	-	-	-	-	-	-	48	44	142	134
7	5	21	9	-	-	-	19	-	-	-	-	405	348	1,203	1,034
-	1	-	1	-	-	-	-	1	23	24	23	99	71	222	185
-	-	-	-	-	-	-	5	14	33	41	63	71	70	167	161
-	-	-	-	-	-	-	-	-	-	-	3	-	(7)	1	9
14	14	39	21	-	-	-	42	15	56	65	89	942	780	2,631	2,290
43	(2)	78	1	-	-	-	69	(15)	(56)	(65)	(88)	413	297	1,322	1,180

												39	32	119	106
												41	30	120	102
												-	-	-	(296)
												70	18	164	123
												(1)	(2)	14	16
												149	78	417	51
												264	219	905	1,129

-	1	-	4	-	-	-	7	50	63	116	101	280	215	702	563
3	4	7	26	-	-	-	(5)	39	16	124	36	403	354	1,101	939
-	-	-	-	-	-	-	-	-	-	-	-	4	6	7	20
3	5	7	30	-	-	-	2	89	79	240	137	687	575	1,810	1,522
												-	343	294	741
												(2)	(72)	(14)	(86)
												4	8	20	27
												689	854	2,110	2,204
		197	202			-	-			309	145			10,866	10,193
		-	-			-	-			-	-			469	473
		72	27			-	-			19	18			1,010	1,051
		269	229			-	-			328	163			12,345	11,717
														62	63
														12,407	11,780
				Three months		Nine months
				ended		ended
				September 30		September 30
(3) Southeast Asia				2004	2003	2004	2003
Indonesia				96	83	266	248
Malaysia				99	16	257	42
Vietnam				8	1	17	8
Total revenue				203	100	540	298
Indonesia						351	384
Malaysia						691	677
Vietnam						24	23
Property, plant and equipment (5)						1,066	1,084

Talisman Energy Inc.
Product Netbacks
		Three months ended		Nine months ended
		September 30		September 30
(C$ - production before royalties)		2004	2003	2004	2003
North	Oil and liquids ($/bbl)
America	Sales price	45.47	33.94	41.46	36.89
	Hedging (gain)	7.28	2.05	5.05	2.58
	Royalties	9.51	6.81	8.53	7.54
	Transportation	0.53	0.51	0.50	0.48
	Operating costs	6.64	6.21	6.40	6.13
		21.51	18.36	20.98	20.16
	Natural gas ($/mcf)
	Sales price	6.63	6.14	6.77	7.01
	Hedging (gain)	0.14	0.03	0.12	0.16
	Royalties	1.29	1.18	1.35	1.47
	Transportation	0.20	0.22	0.20	0.22
	Operating costs	0.81	0.77	0.79	0.74
		4.19	3.94	4.31	4.42
North Sea	Oil and liquids ($/bbl)
	Sales price	54.57	38.66	47.59	40.08
	Hedging (gain)	10.31	1.98	6.41	1.98
	Royalties	0.49	(0.27)	0.40	(0.35)
	Transportation	1.28	1.07	1.16	1.23
	Operating costs	15.59	11.05	13.78	11.78
		26.90	24.83	25.84	25.44
	Natural gas ($/mcf)
	Sales price	4.88	4.26	5.35	4.65
	Hedging (gain)	-	-	-	-
	Royalties	0.46	0.09	0.44	0.14
	Transportation	0.32	0.39	0.34	0.36
	Operating costs	0.69	0.50	0.49	0.39
		3.41	3.28	4.08	3.76
Southeast Asia (1)	Oil and liquids ($/bbl)
	Sales price	56.95	38.58	50.46	41.26
	Hedging (gain)	-	2.07	-	2.50
	Royalties	23.37	14.43	21.01	16.28
	Transportation	0.20	0.47	0.24	0.48
	Operating costs	6.60	6.98	5.57	7.43
		26.78	14.63	23.64	14.57
	Natural gas ($/mcf)
	Sales price	5.03	5.21	4.81	5.92
	Hedging (gain)	-	-	-	-
	Royalties	1.39	0.24	1.19	0.28
	Transportation	0.40	0.80	0.42	0.82
	Operating costs	0.25	0.53	0.27	0.55
		2.99	3.64	2.93	4.27
Algeria	Oil ($/bbl)
	Sales price	63.98	39.37	53.03	38.44
	Hedging (gain)	-	2.07	-	2.32
	Royalties	20.15	20.38	20.12	19.73
	Transportation	1.79	1.87	1.81	1.87
	Operating costs	3.86	10.37	3.41	7.06
		38.18	4.68	27.69	7.46
Sudan	Oil ($/bbl)
	Sales price	-	-	-	43.89
	Hedging (gain)	-	-	-	-
	Royalties	-	-	-	20.34
	Operating costs	-	-	-	3.73
		-	-	-	19.82
Total Company	Oil and liquids ($/bbl)
	Sales price	53.30	37.33	46.87	39.60
	Hedging (gain)	7.15	2.01	4.68	2.04
	Royalties	7.86	4.20	6.84	5.76
	Transportation	0.95	0.88	0.89	0.85
	Operating costs	11.08	9.19	10.06	8.99
		26.26	21.05	24.40	21.96
	Natural gas ($/mcf)
	Sales price	6.15	5.87	6.25	6.67
	Hedging (gain)	0.10	0.02	0.09	0.13
	Royalties	1.25	0.98	1.24	1.22
	Transportation	0.25	0.30	0.26	0.29
	Operating costs	0.68	0.72	0.66	0.69
		3.87	3.85	4.00	4.34
(1) Includes operations in Indonesia and Malaysia/Vietnam.
Netbacks do not include synthetic oil or pipeline operations.

Talisman Energy Inc.
Additional Information for US Readers
Product Netbacks

		Three months ended		Nine months ended
		September 30		September 30
(US$ - production net of royalties)		2004	2003	2004	2003
North	Oil and liquids (US$/bbl)
America	Sales price	34.78	24.68	31.22	25.90
	Hedging (gain)	7.06	1.87	4.78	2.27
	Transportation	0.51	0.46	0.48	0.43
	Operating costs	6.43	5.65	6.07	5.41
		20.78	16.70	19.89	17.79
	Natural gas (US$/mcf)
	Sales price	5.07	4.48	5.10	4.94
	Hedging (gain)	0.13	0.02	0.11	0.14
	Transportation	0.19	0.19	0.19	0.19
	Operating costs	0.77	0.70	0.74	0.66
		3.98	3.57	4.06	3.95
North Sea	Oil and liquids (US$/bbl)
	Sales price	41.76	28.01	35.83	28.04
	Hedging (gain)	7.96	1.42	4.87	1.37
	Transportation	0.99	0.77	0.88	0.85
	Operating costs	12.03	7.95	10.47	8.17
		20.78	17.87	19.61	17.65
	Natural gas (US$/mcf)
	Sales price	3.72	3.10	4.03	3.26
	Hedging (gain)	-	-	-	-
	Transportation	0.27	0.29	0.28	0.26
	Operating costs	0.59	0.37	0.41	0.28
		2.86	2.44	3.34	2.72
Southeast Asia (1)	Oil and liquids (US$/bbl)
	Sales price	43.62	28.06	38.03	28.99
	Hedging (gain)	-	2.41	-	2.90
	Transportation	0.25	0.54	0.31	0.55
	Operating costs	8.56	8.10	7.19	8.60
		34.81	17.01	30.53	16.94
	Natural gas (US$/mcf)
	Sales price	3.85	3.81	3.62	4.18
	Hedging (gain)	-	-	-	-
	Transportation	0.43	0.61	0.42	0.61
	Operating costs	0.26	0.41	0.27	0.41
		3.16	2.79	2.93	3.16
Algeria	Oil (US$/bbl)
	Sales price	49.03	28.53	40.05	26.89
	Hedging (gain)	-	3.11	-	3.34
	Transportation	1.94	2.82	2.20	2.74
	Operating costs	4.18	15.56	4.14	10.09
		42.91	7.04	33.71	10.72
Sudan	Oil (US$/bbl)
	Sales price	-	-	-	30.70
	Hedging (gain)	-	-	-	-
	Operating costs	-	-	-	4.86
		-	-	-	25.84
Total Company	Oil and liquids (US$/bbl)
	Sales price	40.80	27.18	35.31	27.67
	Hedging (gain)	6.40	1.65	4.11	1.67
	Transportation	0.85	0.72	0.78	0.70
	Operating costs	9.91	7.54	8.85	7.34
		23.64	17.27	21.57	17.96
	Natural gas (US$/mcf)
	Sales price	4.70	4.26	4.71	4.65
	Hedging (gain)	0.10	0.02	0.08	0.11
	Transportation	0.24	0.26	0.24	0.25
	Operating costs	0.65	0.62	0.62	0.58
		3.71	3.36	3.77	3.71

(1) Includes operations in Indonesia and Malaysia/Vietnam.
Netbacks do not include synthetic oil or pipeline operations.

Talisman Energy Inc.
Additional Information for US Readers
Production net of royalties


	Three months ended		Nine months ended
	September 30		September 30
	2004	2003	2004	2003

Oil and liquids (bbls/d)
North America	42,594	45,032	43,187	45,648
North Sea	110,309	113,136	118,805	108,745
Southeast Asia (1)	21,254	13,854	20,927	13,347
Algeria	9,620	3,761	8,028	2,356
Sudan	-	-	-	9,355
Synthetic oil (Canada)	3,048	2,903	2,906	2,554
Total oil and liquids	186,825	178,686	193,853	182,005

Natural gas (mmcf/d)
North America	718	684	707	676
North Sea	89	89	102	102
Southeast Asia (1)	197	113	190	99
Total natural gas	1,004	886	999	877

Total mboe/d	354	326	361	328

(1) Includes operations in Indonesia and Malaysia/Vietnam.

Talisman Energy Inc.
Consolidated Financial Ratios
September 30, 2004

The following financial ratios are provided in connection with the Company's shelf prospectus, filed with
Canadian and US securities regulatory authorities, and are based on the company's consolidated
financial statements that are prepared in accordance with accounting principles generally accepted in Canada.


The asset coverage ratios are calculated as at September 30, 2004.
The interest coverage ratios are for the 12 month period then ended.

	Preferred	Preferred
	Securities	Securities
	as equity (5)	as debt (6)
Interest coverage (times)
Income (1)	6.65	5.81
Cash flow (2)	20.27	17.73
Asset coverage (times)
Before deduction of future income taxes and deferred credits (3)	4.82	4.82
After deduction of future income taxes and deferred credits (4)	3.24	3.24

(1) Net income plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(2) Cash flow plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(3) Total assets minus current liabilities; divided by long-term debt.
(4) Total assets minus current liabilities and long-term liabilities excluding long-term debt; divided by long-term debt.
(5) The Company's preferred securities are classified as equity and the related charges have been excluded from interest expense.
(6) Reflects adjusted ratios, had the preferred securities been treated as debt and the related charges been included in interest expense.