CALGARY, Alberta - November 26, 1998 -

EX-2 3 mdaex2.htm 3Q INTERIM MD&A CALGARY, Alberta - November 26, 1998 -

Exhibit 2

MANAGEMENT’S DISCUSSION AND ANALYSIS

November 5, 2004

Exhibit 2

Forward-looking Statements

This Management's Discussion and Analysis contains forward-looking information as contemplated by Canadian securities regulators’ Form 51-102F1 and forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking statements”). These statements include, among others, statements regarding business plans for capital expenditures and development, anticipated royalties, or other expectations, beliefs, plans, goals, objectives, assumptions or statements about future events or performance.

Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by Talisman. These risks include, but are not limited to:

•

the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas);

•

risks and uncertainties involving geology of oil and gas deposits;

•

the uncertainty of reserve estimates;

•

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;

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);

•

uncertainties relating to the litigation process, such as possible discovery of new evidence or acceptance of novel legal theories and the difficulties of predicting the decisions of judges and juries;

•

general economic conditions;

•

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

•

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

•

the possibility that government policies 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 Talisman's operations or financial results are included in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", and "- Outlook for 2004". Additional information may also be found in Talisman'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 Talisman's management at the time the statements are made. Talisman assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change.

Note Regarding Reserves Data and Other Oil and Gas Information

Talisman’s disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities, which permits Talisman to provide disclosure in accordance with US disclosure requirements. The information provided by Talisman may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (“NI 51-101”). Information about the differences between the US requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information in Talisman’s Annual Information Form. The exemption granted to Talisman also permits it to disclose internally evaluated reserves data.

Throughout this MD&A, 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 United States, net production volumes are reported after the deduction of these amounts.

Exhibit 2

Management’s Discussion and Analysis (MD&A)

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.

Exhibit 2

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.

Exhibit 2

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.

Exhibit 2

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.

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

Talisman Energy Inc.
Product Netbacks (continued)

	Three months ended		Nine months ended
	September 30		September 30
(C$ - production before royalties)	2004	2003	2004	2003

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.