EXHIBIT 6

MANAGEMENT’S DISCUSSION AND ANALYSIS

July 29, 2004

EXHIBIT 6

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 6

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 June 30, 2004 and 2003, unless stated otherwise.   All amounts are in Canadian dollars unless otherwise indicated.      

Quarterly results summary

	Three months ended		Six months ended
June 30,	2004	2003 (Restated)4	2004	2003 (Restated)4	2003 Proforma Excluding Sudan operations and gain on sale4&6
Financial (millions of C$ unless otherwise stated)
Cash flow1&3	767	600	1,546	1,445	1,369
Net income1	197	202	420	776	436
Exploration and development expenditures	509	492	1,123	947	945
Per common share5 (dollars)
Cash flow1&3    – Basic	2.00	1.55	4.02	3.72	3.52
– Diluted	1.97	1.53	3.97	3.68	3.46
Net income2    – Basic	0.50	0.51	1.07	1.97	1.11
– Diluted	0.50	0.50	1.06	1.95	1.10
Production (daily average)
Oil and liquids (bbls/d)	229,579	188,682	229,857	217,864	191,569
Natural gas (mmcf/d)	1,244	1,061	1,240	1,078	1,078
Total mboe/d (6mcf=1boe)	437	365	437	398	371

1.

Amounts are reported prior to preferred security charges of $6 million ($4 million net of tax) for the three months ended June 30, 2004 (2003 - $9 million; $5 million net of tax).  

2.

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

3.

Cash flow is a non-GAAP measure and represents net income before exploration costs, DD&A, future taxes and other non-cash expenses.

4.

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.

5.

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.

6.

The pro forma Sudan amounts are non-GAAP measures and exclude the $296 million gain on sale of the Sudan operations and the Sudan results of operations during the period.   These pro forma results have been derived from the information contained in notes 7 and 8 of the Company’s Interim Consolidated Financial Statements.

The Company’s quarterly cash flow was $767 million, a 28% increase over the same period last year.  Net income for the quarter decreased 2% to $197 million, largely because the comparable quarter for last year contained a $133 million future tax recovery due to Canadian tax rate reductions which more than offset the impact of this year’s improved commodity prices and higher production. 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 13% to $1,546 million.  For the same period, net income on a pro forma basis decreased 4% from $436 million to $420 million, largely due to the impact of tax recovery in 2003.  Excluding the impact of the tax rate reductions and Sudan sale from the first six months of 2003 and removing similar tax adjustments from the current year, the year over year variance would an increase of $68 million.

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		Six months ended
June 30,	2004	2003	2004	2003
Oil and liquids ($/bbl)
Sales price	46.42	35.07	43.78	40.68
Hedging expense (income)	4.31	0.65	3.49	2.06
Royalties	6.71	3.83	6.35	6.49
Transportation	0.87	0.97	0.87	0.85
Operating costs	9.88	9.10	9.57	8.90
	24.65	20.52	23.50	22.38
Natural gas ($/mcf)
Sales price	6.47	6.36	6.30	7.07
Hedging expense (income)	0.12	0.10	0.08	0.18
Royalties	1.31	1.28	1.23	1.34
Transportation	0.26	0.28	0.26	0.29
Operating costs	0.68	0.64	0.65	0.67
	4.10	4.06	4.08	4.59
Total $/boe  (6mcf=1boe)
Sales price	42.78	36.56	40.94	41.45
Hedging expense (income)	2.59	0.62	2.06	1.60
Royalties	7.25	5.71	6.84	7.20
Transportation	1.19	1.33	1.19	1.25
Operating costs	7.10	6.53	6.87	6.69
	24.65	22.37	23.98	24.71

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.

The Company’s average netback for the quarter was $24.65/boe, up 10% from 2003 as higher global oil prices were partially offset by a slightly stronger Canadian dollar in relation to its US counterpart and increased hedging losses, operating costs and royalties on oil.  Approximately $0.30/boe of the increase in operating costs during the current quarter is attributable to the increase in the pound sterling/Canadian dollar exchange rates.

During the current quarter, the Company has retroactively reclassified 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

During the quarter ended June 30, 2004, revenue was $1.6 billion, a 34% increase over 2003, as increases in oil production from international operations and worldwide gas production combined with higher commodity prices more than offset the negative impacts of a stronger Canadian dollar and increased hedging losses.

Production (daily average)	Three months ended		Six months ended
June 30,	2004	2003	2004	2003
Oil and liquids (bbls/d)
North America	56,918	59,743	57,604	60,601
North Sea	125,003	102,274	124,124	105,498
Southeast Asia	35,908	22,899	35,755	22,134
Algeria	11,750	3,766	12,374	3,336
Sudan	-	-	-	26,295
	229,579	188,682	229,857	217,864
Natural gas (mmcf/d)
North America	885	865	879	866
North Sea	103	91	118	114
Southeast Asia	256	105	243	98
	1,244	1,061	1,240	1,078
Total mboe/d (6mcf=1boe)	437	365	437	398

Total Company production during the quarter increased 20%, to 437 mboe per day, highlighted by gas production in Appalachia, which reached a record high of 115 mmcf/d, and averaged 94 mmcf/d for the quarter and Southeast Asia production which increased 95% on a boe basis from last year .

The Company’s average oil and liquids production for the quarter was 230 mbbls/d, up 22% compared to last year.  In the North Sea, oil and liquids production averaged 125,003 bbls/d, up 22,729 bbls/d over 2003, reflecting operating performance, drilling results and asset acquisitions over the past year.  Southeast Asia oil and liquids production in the current quarter averaged 35,908 bbls/d, up 57% from 2003 due to the completion of the Malaysia/Vietnam PM-3 CAA project in the fourth quarter of last year.  Algeria production averaged 11,750 bbls/d, up over 200% from the 3,766 bbls/d in 2003, as a result of the MLN fields, which commenced production during the middle of 2003.  In North America, oil and liquids production of 56,918 bbls/d was down 5% from the same quarter of last year due to natural declines and the Company’s continued focus on natural gas.

Averaging 1.2 bcf/d in the second quarter, natural gas production was 17% 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 119 mmcf/d this quarter.  Indonesia gas sales increased 32 mmcf/d, a 31% increase over last year to a current quarter average of 137 mmcf/d with higher Corridor sales to Caltex and new sales to Singapore.  In North America, natural gas production increased 20 mmcf/d over last year to 885 mmcf/d, as increases in Appalachia of 27 mmcf/d, combined with a 28 mmcf/d increase in Alberta Foothills, more than offset a decrease of 30 mmcf/d due to plant turnarounds in Monkman.  North Sea natural gas production increased 13% during the quarter to 103 mmcf/d, mainly due to a temporary drop in demand last year.

Prices

	Three months ended		Six months ended
June 30,	2004	2003 1	2004	2003 1
Oil and liquids ($/bbl)
North America	41.39	33.43	39.45	38.33
North Sea	47.27	35.29	44.43	40.85
Southeast Asia	50.19	38.15	47.16	42.62
Algeria	49.09	35.05	46.74	37.33
Sudan	-	-	-	43.89
	46.42	35.07	43.78	40.68
Natural gas ($/mcf)
North America	7.08	6.63	6.85	7.44
North Sea	5.17	4.30	5.55	4.81
Southeast Asia	4.85	5.86	4.68	6.37
	6.47	6.36	6.30	7.07
Total $/boe (6mcf=1boe)	42.78	36.56	40.94	41.45
Hedging loss (income)-excluded from the above prices     Oil and liquids ($/bbl)	4.31	0.65	3.49	2.06
Natural gas  ($/mcf)	0.12	0.10	0.08	0.18
Total $/boe (6mcf=1boe)	2.59	0.62	2.06	1.60
Benchmark prices and foreign Exchange rates    WTI        (US$/bbl)	38.32	28.91	36.73	31.39
Brent       (US$/bbl)	35.36	26.03	33.66	28.77
NYMEX (US$/mmbtu)	5.97	5.48	5.83	6.05
AECO     (C$/gj)	6.45	6.63	6.36	7.07
US/Canadian dollar exchange rate	0.736	0.715	0.747	0.688
Canadian dollar / pound sterling  exchange rate	2.455	2.263	2.440	2.341

 Excludes synthetic oil

1.

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

During the second quarter, Talisman’s commodity price averaged $42.78/boe, up $6.22/boe or 17% from last year.  Despite OPEC increasing output, concerns continue over world supply due in part to Middle East unrest and uncertainties regarding terrorist activities.  Strong demand, especially in China and the United States, increased the benchmark price of WTI oil by 33% to US$38.32.  Although negatively impacted by a slightly stronger Canadian dollar (US$0.74 vs. US$0.72 in the second quarter of 2003), the Company realized a price of $46.42 /bbl of oil and liquids, up 32% from the same period last year.

North America gas prices rose 7% to $7.08/mcf during the second quarter, but on a year to date basis, gas prices in 2004 were 8% less than prices realized last year.

For the quarter ended June 30, 2004, Talisman recorded net hedging losses related to commodity based derivative financial instruments of $89 million for oil and liquids ($4.31/bbl) and $13 million for natural gas ($0.12/mcf).  These hedges represented 34% of oil and liquids production and 7% of North America gas production or 20% of total boe production for the quarter.  As of July 1, 2004, the Company has derivative and physical contracts for approximately 22% of its remaining 2004 estimated production (35% of the Company’s oil and liquids production and 11% 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 partially updated in note 5 to the June 30, 2004 Interim Consolidated Financial Statements.

Royalties

	Three months endedJune 30
	2004		2003 1
	%	$ millions	%	$ millions
North America	20	159	22	157
North Sea	1	8	(2)	(8)
Southeast Asia	37	102	26	35
Algeria	35	18	51	6
	17	287	16	190
	Six months endedJune 30
	2004		2003 1
	%	$ millions	%	$ millions
North America	20	302	21	338
North Sea	2	17	-	(4)
Southeast Asia	34	177	26	74
Algeria	43	45	51	11
Sudan	-	-	46	97
	17	541	17	516

Excludes synthetic oil

1.

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

The Company’s royalty expense for the second quarter was $287 million, an average royalty rate of 17%, up from $190 million, an average royalty rate of 16%, in 2003.  The royalty rate increased as a result of higher commodity prices and the impact of an entire quarter of Corridor production after payout of cost recovery pools.  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 expense increased due to production increases in Malaysia/Vietnam where rates increased to 34% from 30% 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
June 30,	2004		2003
	$/boe	$ millions	$/boe	$ millions
North America	5.31	99	4.69	87
North Sea	11.90	154	10.23	109
Southeast Asia	3.34	23	5.32	20
Algeria	4.75	5	-	-
Sudan	-	-	-	-
	7.10	281	6.53	216
Synthetic oil	20.55	6	31.52	7
Pipeline		12		12
		299		235
	Six months ended
June 30,	2004		2003
	$/boe	$ millions	$/boe	$ millions
North America	5.13	190	4.87	180
North Sea	11.53	299	10.61	237
Southeast Asia	3.27	45	5.84	41
Algeria	3.15	7	3.12	2
Sudan	-	-	3.73	18
	6.87	541	6.69	478
Synthetic oil	19.76	11	26.70	12
Pipeline		25		23
		577		513

During the second quarter, operating expense increased by $64 million to $299 million, with the largest increase in the North Sea.  Unit operating costs averaged $7.10/boe, up from $6.53/boe last year.  North Sea unit operating costs increased $1.67 to $11.90/boe.  Of this increase, $0.85/boe was due to a 9% strengthening of the pound sterling against the Canadian dollar.  A 21% increase in North Sea boe production, due mainly to recent acquisitions, accounted for an additional $22 million over last year.  In North America, unit operating costs increased due to higher processing fees and plant turnarounds.  Unit operating costs in Southeast Asia were down 37% to $3.34/boe due to a full quarter’s operation of the PM3 CAA project in Malaysia/Vietnam.  Algeria operating costs increased due to the startup of the MLN and related satellite fields.

Depreciation, Depletion and Amortization

	Three months ended
June 30,	2004		20031
	$/boe	$ millions	$/boe	$ millions
North America	10.06	187	9.16	170
North Sea	12.87	167	12.26	131
Southeast Asia	6.76	48	6.52	24
Algeria	6.06	7	7.01	2
	10.27	409	9.84	327
	Six months ended
June 30,	2004		20031
	$/boe	$ millions	$/boe	$ millions
North America	9.78	363	9.07	337
North Sea	12.55	328	12.56	283
Southeast Asia	6.68	93	6.19	43
Algeria	6.07	14	7.39	4
Sudan	-	-	3.98	19
	10.04	798	9.53	686

1.

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 second quarter DD&A expense was $409 million, up 25% from the same quarter of 2003, as an increase in unit DD&A combined with the impact of the higher production, as well as 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.

Other ($ millions except where noted)

June 30,	Three months ended		Six months ended
	2004	2003	2004	2003
G&A ($/boe)	1.03	1.07	1.01	1.03
Dry hole expense	44	42	123	114
Stock-based compensation	64	105	94	105
Transportation	46	44	94	90
Other expense (income)	13	41	16	34
Interest costs capitalized	2	7	5	14
Interest expense	41	32	79	72
Other revenue	21	14	43	37

Dry hole expense for the second quarter of 2004 was $44 million, $30 million of which was incurred in North America and $13 million in the North Sea.  Interest expense increased during the quarter due to the higher average debt level.  Other revenue included $12 million of pipeline and processing revenue.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at June 30, 2004, which was first expensed during the second quarter of 2003.  The $105 million expensed in 2003 was a catch-up charge for the total value of the stock options and cash units outstanding at the time the options were first expensed.  The $64 million for the current quarter is due to the impact of the appreciation of the Company’s share price on the outstanding stock options and cash units from the beginning of the second quarter ($94 million from the beginning of the year).  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.

Taxes ($ millions)

June 30,	Three months ended		Six months ended
	2004	2003 1	2004	2003 1
Current income tax	90	43	141	135
Future income tax (recovery)	8	(142)	23	(51)
Petroleum Revenue Tax	33	17	57	50
	131	(82)	221	134
Effective tax rate	33	(96%)	28	10%

1.

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 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 a non-cash future tax recovery of $133 million last year associated with Canadian corporate tax rate reductions.  Excluding these tax rate reductions, the effective tax rate on the Company’s income in the second quarter of 2003 would have been 33%.  In the second quarter of this year, current tax increased to $90 million as operations in the US and Malaysia became taxable as tax pools were depleted due to higher prices and Algerian royalties became current taxes due to the production of profit oil.  In the North Sea, as a result of both higher commodity prices and increased production, both current taxes and PRT increased.

Capital expenditures ($ millions)

	Three months ended		Six months ended
June 30,	2004	2003	2004	2003
North America	347	236	728	872
North Sea	306	142	425	220
Southeast Asia	44	74	97	154
Algeria	1	10	4	25
Sudan	-	-	-	2
Other	77	40	151	58
	775	502	1,405	1,331

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

North America capital expenditures for the current quarter include $254 million for exploration and development with the drilling of 64 gas wells and 22 oil wells and $92 million, (US$65 million) for additional asset acquisitions in Appalachia.  Expenditures in the North Sea during the second quarter were comprised of $40 million of exploration spending and development spending of $84 million, in addition to producing assets acquired for $174 million.  The majority of the Southeast Asia spending related to ongoing development drilling including the completion of 12 development wells at PM3 CAA.  In addition, the South Angsi development in Block PM-305 in Malaysia/Vietnam is proceeding.  Other expenditures in the second quarter of 2004 included spending in Trinidad of $59 million.  There have been no significant changes in the Company’s outlook of 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 (including preferred securities), was $2.6 billion ($2.5 billion, including short-term borrowings, net of cash and cash equivalents).  At June 30, 2004 this amount had decreased to $2.3 billion ($2.4 billion, including short-term borrowings, net of cash and cash equivalents), 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 June 30, 2004 the Company had drawn down on its bank lines of credit with $543 million in short term borrowings.

At quarter end, debt to debt plus equity, including short-term borrowings, was 36% (33% net of cash and cash equivalents).  For the 12 months ended June 30, 2004, the debt to cash flow ratio was 1.02:1 (0.87:1 net of cash and cash equivalents).

During the first quarter, the Company redeemed one half of its outstanding preferred securities realizing a $16 million gain (net of tax), being the difference between the carrying value and the redemption cost.  In June, the Company redeemed the remaining half of its preferred securities, realizing a $7 million gain (net of tax).  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 June 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.

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 $187 million, due mainly to charges associated with the acquisition of assets in the North Sea, as well as the impact of the stronger pound sterling against the Canadian dollar.  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.

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.

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
	June 30	March 31	Dec. 31	Sept. 30	June 30	March 31	Dec. 31	Sept. 30
Total revenue 1	1,337	1,261	1,128	1,078	1,023	1,370	1,274	1,141
Net income 2, 3	197	223	108	128	202	574	177	146
Per common share amounts 4 (Cdn. dollars)
Net income 2, 3	0.50	0.57	0.27	0.32	0.51	1.46	0.43	0.35
Diluted net income 2, 3	0.50	0.56	0.26	0.31	0.50	1.45	0.42	0.34

1.

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.

2.

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

3.

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

4.

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 June 30, 2004.

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 $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 quarter of 2003 included an additional $80 million ($50 million after tax) of stock-based compensation expense.

Total revenue and net income increased during the third and fourth quarters of 2002 due to higher commodity prices.

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 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.

Sudan pro forma amounts are also non-GAAP measures. More information about Sudan pro forma amounts is included in note 7 to the Interim Consolidated Financial Statements.  In addition, the following measures are non-GAAP:  long-term debt including preferred securities; debt to debt plus equity where debt includes short-term borrowings and is net of cash and cash equivalents; debt to cash flow; and debt, net of cash and cash equivalents, to cash flow.

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.

EXHIBIT 6

Talisman Energy Inc.
Product Netbacks
		Three months ended		Six months ended
		June 30		June 30
(C$ - production before royalties)		2004	2003	2004	2003
North	Oil and liquids ($/bbl)
America	Sales price	41.39	33.43	39.45	38.33
	Hedging (gain)	4.81	1.26	3.93	2.83
	Royalties	8.52	6.50	8.04	7.90
	Transportation	0.48	0.51	0.49	0.46
	Operating costs	6.67	5.89	6.28	6.08
		20.91	19.27	20.71	21.06
	Natural gas ($/mcf)
	Sales price	7.08	6.63	6.85	7.44
	Hedging (gain)	0.16	0.12	0.11	0.22
	Royalties	1.44	1.54	1.38	1.61
	Transportation	0.20	0.22	0.20	0.22
	Operating costs	0.80	0.70	0.78	0.73
		4.48	4.05	4.38	4.66
North Sea	Oil and liquids ($/bbl)
	Sales price	47.27	35.29	44.43	40.85
	Hedging (gain)	5.74	0.14	4.65	1.98
	Royalties	0.60	(0.89)	0.36	(0.39)
	Transportation	1.11	1.31	1.11	1.31
	Operating costs	13.07	11.60	12.97	12.18
		26.75	23.13	25.34	25.77
	Natural gas ($/mcf)
	Sales price	5.17	4.30	5.55	4.81
	Hedging (gain)	-	-	-	-
	Royalties	0.13	0.04	0.43	0.16
	Transportation	0.31	0.34	0.34	0.36
	Operating costs	0.58	0.18	0.41	0.34
		4.15	3.74	4.37	3.95
Southeast Asia (1)	Oil and liquids ($/bbl)
	Sales price	50.19	38.15	47.16	42.62
	Hedging (gain)	-	1.26	-	2.72
	Royalties	21.77	15.86	19.80	17.23
	Transportation	0.28	0.44	0.27	0.48
	Operating costs	5.30	7.12	5.04	7.66
		22.84	13.47	22.05	14.53
	Natural gas ($/mcf)
	Sales price	4.85	5.86	4.68	6.37
	Hedging (gain)	-	-	-	-
	Royalties	1.33	0.27	1.08	0.30
	Transportation	0.43	0.81	0.43	0.84
	Operating costs	0.28	0.49	0.28	0.56
		2.81	4.29	2.89	4.67

EXHIBIT 6

Talisman Energy Inc.
Product Netbacks (continued)
		Three months ended		Six months ended
		June 30		June 30
(C$ - production before royalties)		2004	2003	2004	2003
Algeria	Oil ($/bbl)
	Sales price	49.09	35.05	46.74	37.33
	Hedging (gain)	-	1.26	-	2.62
	Royalties	17.34	18.04	20.10	18.96
	Transportation	1.84	1.88	1.82	1.89
	Operating costs	4.75	2.19	3.15	3.12
		25.16	11.68	21.67	10.74
Sudan	Oil ($/bbl)
	Sales price	-	-	-	43.89
	Hedging (gain)	-	-	-	-
	Royalties	-	-	-	20.34
	Operating costs	-	-	-	3.73
		-	-	-	19.82
Total Company	Oil and liquids ($/bbl)
	Sales price	46.42	35.07	43.78	40.68
	Hedging (gain)	4.31	0.65	3.49	2.06
	Royalties	6.71	3.83	6.35	6.49
	Transportation	0.87	0.97	0.87	0.85
	Operating costs	9.88	9.10	9.57	8.90
		24.65	20.52	23.50	22.38
	Natural gas ($/mcf)
	Sales price	6.47	6.36	6.30	7.07
	Hedging (gain)	0.12	0.10	0.08	0.18
	Royalties	1.31	1.28	1.23	1.34
	Transportation	0.26	0.28	0.26	0.29
	Operating costs	0.68	0.64	0.65	0.67
		4.10	4.06	4.08	4.59
(1) Includes operations in Indonesia and Malaysia/Vietnam.
Netbacks do not include synthetic oil or pipeline operations.