CALGARY, Alberta – July XX, 2005

EX-5 6 f2qmda.htm 2Q INTERIM MD&A CALGARY, Alberta – July XX, 2005 – Talisman Energy Inc

MANAGEMENT’S DISCUSSION AND ANALYSIS

JULY 27, 2005

Forward-looking Statements

This interim MD & A contains statements about future production growth and production per share, expected royalty rates and taxes, the Company’s outlook for major projects, impact of new accounting pronouncements, outcome of litigation, or 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 legislation.

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:

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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;

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risks and uncertainties involving geology of oil and gas deposits;

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the uncertainty of reserves estimates and reserves life;

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

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

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

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health, safety and environmental risks;

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uncertainties as to the availability and cost of financing;

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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;

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

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general economic conditions;

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

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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 2005", under the heading “Risk Factors” in the Company’s 2004 annual information form 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.

Advisory – Oil and Gas Information

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 U.S., net production volumes are reported after the deduction of these amounts.

Throughout this 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 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.

You may read any document Talisman furnishes to the SEC at the SEC's public reference rooms at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549 and 500 West Meridian Street, Suite 1400, Chicago, Illinois 60661. You may also obtain copies of the same documents from the public reference room of the SEC at 450 Fifth Street, N.W., Washington D.C. 20549 by paying a fee. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms.

Management’s Discussion and Analysis (MD&A)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements as at June 30, 2005 and 2004 and the 2004 Audited Consolidated Financial Statements. All comparative percentages are between the quarters ended June 30, 2005 and 2004, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Quarterly results summary (unaudited)

	Three months ended		Six months ended
June 30,	2005	2004	2005	2004
Financial (millions of C$ unless otherwise stated)
Net income¹	340	193	598	411
Exploration and development expenditures	666	509	1,415	1,123
C$ per common share
Net income¹– Basic	0.93	0.50	1.62	1.07
– Diluted	0.91	0.50	1.58	1.05
Production, before royalties (daily average)
Oil and liquids (bbls/d)	228,977	229,579	232,217	229,857
Natural gas (mmcf/d)	1,292	1,244	1,312	1,240
Total mboe/d (6mcf=1boe)	444	437	451	437
Production(boe) per common share– Basic	0.110	0.104	0.221	0.207

Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants (“CICA”) accounting standard for financial instruments. The change to this standard requires that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. See note 1 to the Interim Consolidated Financial Statements.

Net income for the second quarter increased 76% to $340 million, as the impact of improved commodity prices, 2% higher production and decreased hedging losses was partially offset by increases in operating, depreciation, depletion and amortization, stock-based compensation and tax expenses.

For the six months ended June 30, 2005, production per common share of 0.221 was 7% higher than the corresponding period of 2004, and within the range of the Company’s guidance.

Company Netbacks¹ (unaudited)

	Three months ended		Six months ended
June 30,	2005	2004²	2005	2004²
Oil and liquids ($/bbl)
Sales price	58.58	46.42	56.98	43.78
Hedging expense	0.86	4.31	0.79	3.49
Royalties	8.32	6.71	7.86	6.35
Transportation	0.86	0.87	0.85	0.87
Operating costs	12.49	10.32	11.66	9.96
	36.05	24.21	35.82	23.11
Natural gas ($/mcf)
Sales price	7.31	6.47	7.02	6.30
Hedging expense	-	0.12	-	0.08
Royalties	1.53	1.31	1.45	1.23
Transportation	0.22	0.26	0.25	0.26
Operating costs	0.74	0.68	0.72	0.65
	4.82	4.10	4.60	4.08
Total $/boe (6mcf=1boe)
Sales price	51.41	42.78	49.72	40.94
Hedging expense	0.44	2.59	0.40	2.06
Royalties	8.73	7.25	8.27	6.84
Transportation	1.09	1.19	1.18	1.19
Operating costs	8.57	7.33	8.08	7.07
	32.58	24.42	31.79	23.78

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

Unit operating costs include pipeline operations for the North Sea. Prior year figures have been restated accordingly.

During the second quarter, the Company’s average netback was $32.58/boe, 33% higher than 2004. The rise in commodity prices, although partially offset by a 9% stronger Canadian dollar in relation to its US counterpart, resulted in a Company realized price of $51.41/boe which was $8.63/boe (20%) higher than in 2004. The impact of this increase in realized price, along with decreased hedging losses, was partially offset by increased royalties and operating costs, resulting in an increase in the netback of $8.16/boe.

Gross sales

Gross sales for the quarter ended June 30, 2005 were $2.1 billion, a 22% increase over 2004, as higher commodity prices combined with new production from Trinidad, increased oil and liquids production in Algeria and increased natural gas production in North America and Southeast Asia, to more than offset the impact of a stronger Canadian dollar.

Daily average production, before royalties (unaudited)

	Three months ended		Six months ended
June 30,	2005	2004	2005	2004
Oil and liquids (bbls/d)
North America	55,916	56,918	56,095	57,604
North Sea	118,670	125,003	123,250	124,124
Southeast Asia	27,082	35,908	28,020	35,755
Algeria	16,057	11,750	15,303	12,374
Trinidad	11,252	-	9,549	-
	228,977	229,579	232,217	229,857
Natural gas (mmcf/d)
North America	911	885	920	879
North Sea¹	101	103	115	118
Southeast Asia	280	256	277	243
	1,292	1,244	1,312	1,240
Total mboe/d (6mcf=1boe)	444	437	451	437

Includes gas acquired for injection and subsequent resale of 9 mmcf/d in both periods of 2005 and of 8 mmcf/d in both periods of 2004.

The Company’s average oil and liquids production for the second quarter was 228,977 bbls/d, relatively unchanged from the same period last year. In Trinidad, where first oil production commenced earlier this year, second quarter production averaged 11,252 bbls/d. In the North Sea, oil and liquids production averaged 118,670 bbls/d, down 5% from 2004 as production increases from development drilling and asset acquisitions over the past year were more than offset by the impact of a planned shutdown at Claymore (28 days, with no corresponding shutdown in 2004), a planned shutdown at Buchan (27 days in 2Q 2005 versus a shutdown in 3Q 2004), and unplanned maintenance work at the Ross/Blake fields. Southeast Asia oil and liquids production in the current quarter averaged 27,082 bbls/d, down 8,826 bbls/d or 25% from 2004 due to the expiry of the Tanjung and Jambi concessions in late 2004. Algeria production averaged 16,057 bbls/d, up 37% from the same period in 2004 when operational issues reduced production at the Greater MLN facilities. In North America, oil and liquids production averaged 55,916 bbls/d during the second quarter, down 2% from 2004, as expected, due to natural declines and the Company’s continued focus on natural gas.

During the second quarter, natural gas production averaged 1.3 bcf/d, 4% above last year, due to production increases in both North America and Southeast Asia. In North America, natural gas production was 911 mmcf/d, an increase of 26 mmcf/d or 3% over last year, with production increases in Monkman, up 44 mmcf/d to 101 mmcf/d, Appalachia, up 19 mmcf/d to 112 mmcf/d, and Bigstone/Wild River, up 14 mmcf/d to 112 mmcf/d more than offsetting decreases resulting from turnarounds in the quarter and natural declines in other areas. In Southeast Asia, natural gas production was 280 mmcf/d, an increase of 24 mmcf/d or 9% over last year. Indonesia natural gas production increased 30% over last year averaging 177 mmcf/d with higher Corridor sales to Caltex and Singapore Power. Production in Malaysia/Vietnam averaged 103 mmcf/d this quarter, down 14% from the same period last year due to production constraints. North Sea natural gas production decreased 2% during the second quarter to 101 mmcf/d.

Prices and Exchange Rates (unaudited)

	Three months ended		Six months ended
June 30,	2005	2004	2005	2004
Oil and liquids ($/bbl)
North America	48.16	41.39	47.33	39.45
North Sea	60.24	47.27	58.72	44.43
Southeast Asia	67.60	50.19	63.87	47.16
Algeria	65.40	49.09	63.27	46.74
Trinidad	58.90	-	58.44	-
	58.58	46.42	56.98	43.78
Natural gas ($/mcf)
North America	7.72	7.08	7.39	6.85
North Sea	6.27	5.17	6.67	5.55
Southeast Asia	6.36	4.85	5.91	4.68
	7.31	6.47	7.02	6.30
Total $/boe (6mcf=1boe)	51.41	42.78	49.72	40.94
Hedging loss not included in the above prices Oil and liquids ($/bbl)	0.86	4.31	0.79	3.49
Natural gas ($/mcf)	-	0.12	-	0.08
Total $/boe (6mcf=1boe)	0.44	2.59	0.40	2.06
Benchmark prices and foreign Exchange rates WTI (US$/bbl)	53.22	38.32	51.66	36.73
Brent (US$/bbl)	51.63	35.36	49.64	33.66
NYMEX (US$/mmbtu)	6.80	5.97	6.56	5.83
AECO (C$/gj)	6.99	6.45	6.67	6.36
US/Canadian dollar exchange rate	0.804	0.736	0.810	0.747
Canadian dollar / pound sterling exchange rate	2.309	2.455	2.314	2.440

Excludes synthetic oil

Talisman’s second quarter realized commodity price averaged $51.41/boe, up $8.63/boe or 20% from last year. Limited excess production capacity coupled with sustained strong demand, especially in China and India, contributed to crude oil’s price rise to record levels. Although the average benchmark price of WTI oil, at US$53.22/bbl, was 39% higher than 2004, the stronger Canadian dollar and wider heavy oil differentials limited the increase in the Company’s realized price to 26% over the same period last year, at $58.58/bbl of oil and liquids.

The Company’s realized North American natural gas sales price during the quarter was $7.72/mcf, an increase of 9% over 2004, reflecting the increase in the AECO reference price for natural gas which increased 8% from last year.

For the quarter ended June 30, 2005, Talisman recorded net hedging losses on commodity based derivative financial instruments of $18 million, all associated with oil and liquids ($0.86/bbl), compared to losses of $89 million for oil and liquids ($4.31/bbl) and $13 million for natural gas ($0.12/mcf) during the same period in 2004. As of July 1, 2005, the Company has derivative and physical contracts for approximately 2% of its remaining 2005 estimated production. A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2004 Consolidated Financial Statements and in note 8 to the June 30, 2005 Interim Consolidated Financial Statements.

Royalties¹ (unaudited)

	Three months ended
June 30,	2005		2004
	%	$ millions	%	$ millions
North America	20	173	20	159
North Sea	2	14	1	8
Southeast Asia	35	116	37	102
Algeria	39	38	35	18
Trinidad	17	11	-	-
	17	352	17	287
	Six months ended
June 30,	2005		2004
	%	$ millions	%	$ millions
North America	20	339	20	302
North Sea	2	24	2	17
Southeast Asia	36	225	34	177
Algeria	40	70	43	45
Trinidad	15	15	-	-
	17	673	17	541

Royalty rates do not include synthetic oil

The Company’s royalty expense for the second quarter was $352 million (17%), up from $287 million (17%) in 2004. Total royalty expense increased as a result of increases in both commodity prices and production, as the royalty rate remained constant. In Southeast Asia, the rate decreased due in part to the expiration of the higher rate Tanjung contract and increased production from the lower rate Corridor block. Algeria total expense increased due to increased commodity prices and production. The Algerian government’s total take for the second quarter including royalties and taxes equaled approximately 51%, similar to 2004, which is expected to continue for the next few years.

Operating Expense (unaudited)

	Three months ended
June 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	5.79	107	5.31	99
North Sea	17.05	201	12.61	154
Southeast Asia	2.78	19	3.34	23
Algeria	3.28	5	4.75	5
Trinidad	2.80	3	-	-
	8.57	335	7.33	281
Synthetic oil	29.05	8	20.55	6
Pipeline		14		12
		357		299
	Six months ended
June 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	5.47	204	5.13	190
North Sea	15.38	379	12.15	299
Southeast Asia	2.70	36	3.27	45
Algeria	4.39	12	3.15	7
Trinidad	3.29	6	-	-
	8.08	637	7.07	541
Synthetic oil	33.68	15	19.76	11
Pipeline		29		25
		681		577

During the second quarter, total operating expenses increased from last year by $58 million to $357 million, with the North Sea accounting for $47 million of the increase, primarily due to the acquisition of the Varg field on March 1, 2005. Unit operating costs averaged $8.57/boe, up from $7.33/boe last year. North Sea unit operating costs increased $4.44/boe to $17.05/boe, due to higher unit costs from the new production at the Varg field in Norway plus maintenance costs from the shutdowns at Ross/Blake, Buchan and Claymore together with lower production volumes as a result of the shutdowns. In North America, unit operating costs increased due to higher processing fees, maintenance and plant turnarounds. Unit operating costs in Southeast Asia were down 17% to $2.78/boe due to increased production from Corridor and the expiry of the Tanjung concession. Algeria unit operating costs decreased 31% to $3.28/boe as operational issues at the Greater MLN field in 2004 were rectified, resulting in a 55% increase in production with a 17% reduction in total costs.

Depreciation, Depletion and Amortization (DD&A) (unaudited)

	Three months ended
June 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	12.40	235	10.06	187
North Sea	12.24	151	12.87	167
Southeast Asia	4.40	29	6.76	48
Algeria	7.00	10	6.06	7
Trinidad	13.46	14	-	-
	10.85	439	10.27	409
	Six months ended
June 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	12.22	463	9.78	363
North Sea	12.20	315	12.55	328
Southeast Asia	4.48	60	6.68	93
Algeria	6.90	19	6.07	14
Trinidad	13.41	23	-	-
	10.78	880	10.04	798

The 2005 second quarter DD&A expense was $439 million, up 7% from the same quarter of 2004, due to an increase in the per unit DD&A rate and higher production. The DD&A rate in North America increased primarily due to higher drilling costs and capital expenditures on infrastructure projects. North Sea DD&A expense was down $16 million due mainly to decreased production. The DD&A rate for Southeast Asia decreased as a result of increased reserves in Malaysia/Vietnam and the expiry of the Tanjung concession, which coupled with a 6% decrease in boe production reduced the DD&A expense by 40%.

Other ($ millions) (unaudited)

June 30,	Three months ended		Six months ended
June 30,	2005	2004	2005	2004
G&A	52	41	102	80
Dry hole expense	51	44	97	123
Stock-based compensation	111	64	277	94
Transportation	44	46	96	94
Other expense (income)	(19)	13	5	16
Interest costs capitalized	4	2	6	5
Interest expense	41	47	83	94
Other revenue	38	21	74	43

General and administrative (G&A) expense increased over the same quarter of last year due to higher staff, office space and legal costs.

Dry hole expense for the second quarter of 2005 was $51 million, $13 million of which was expensed in the North Sea for the Tartan West Graben well and $8 million in Trinidad for the Block 2c - K1-OG well. In North America, dry hole expense was $22 million. In Malaysia, dry hole costs were $5 million. Other income of $19 million included a $17 million foreign exchange gain. Other revenue of $38 million included $31 million of pipeline and processing revenue.

Stock-based compensation expense relates to the increase in value of the Company’s outstanding stock options and cash units at June 30, 2005 and 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 $111 million expense for the current quarter is due in part to 1.2 million options being exercised for cash at an average share price of $45.51 and an average exercise price of $18.32 for a cash expense of $32 million. The remaining $79 million expense for the current quarter is a result of an 11% increase in the Company’s share price in the current quarter and the corresponding impact on the mark to market liability of the vested and prorated vested options and cash units outstanding.

Since the introduction of the cash feature, approximately 97% of options that have been exercised have been exercised for cash, resulting in reduced dilution of shares.

Gross interest expense before capitalization was lower during the second quarter of this year as a result of lower weighted average cost of debt in 2005.

Taxes ($ millions) (unaudited)

Effective Income Tax Rate

June 30,	Three months ended		Six months ended
June 30,	2005	2004¹	2005	2004¹
Income before taxes	615	322	1,104	626
Less PRT Current Deferred	36 (2)	25 8	69 8	42 15
Total PRT	34	33	77	57
	581	289	1,027	569
Income tax expense
Current income tax	213	90	398	141
Future income tax	28	6	31	17
Total income tax expense	241	96	429	158
Effective income tax rate	41%	33%	42%	28%

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 2004 due to the effect of increased taxable income in higher tax jurisdictions (e.g. Norway) during the current quarter. During 2005, current tax increased to $213 million as a result of both higher commodity prices and increased production, which also increased current PRT on North Sea operations.

Capital expenditures ($ millions) (unaudited)

	Three months ended		Six months ended
June 30,	2005	2004	2005	2004
North America	270	347	731	728
North Sea	330	306	737	425
Southeast Asia	74	44	150	97
Algeria	3	1	5	4
Trinidad	11	59	26	109
Other	21	18	41	42
	709	775	1,690	1,405

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

North America capital expenditures for the current quarter comprised $127 million on exploration and $145 million on development activities included the drilling of 34 net gas wells and 7 net oil wells. Expenditures in the North Sea during the second quarter were comprised of $51 million of exploration spending and development spending of $235 million, which included the ongoing development of the Tweedsmuir field in addition to $44 million for net acquisitions. In Southeast Asia, capital expenditures of $74 million included $10 million of exploration spending and development spending of $64 million on South Angsi in Block PM-305 and Block PM 3. In Trinidad, second quarter expenditures included $7 million of exploration spending and development spending of $4 million. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2005 section of the Company’s December 31, 2004 MD&A.

Long-term debt and liquidity

At June 30, 2005, Talisman’s long-term debt was $2.7 billion, up from $2.5 billion at year-end. This increase resulted primarily from the repurchase of eight million common shares and the acquisitions in Norway, partially offset by cash provided by operating activities in excess of exploration and development capital expenditures.

In May of 2005, the Company completed a US $375 million offering of 5.125% notes due May 15, 2015 and a US $125 million offering of 5.75% notes due May 15, 2035. Interest on both notes is payable semi-annually in arrears on May 15 and November 15 of each year. Proceeds from the notes were used to repay existing bank credit facilities. In order to hedge a portion of the fair value risk associated with the US $375 million 5.125% note due 2015, the Company entered into fixed to floating interest rate swap contracts with a total notional amount of US $300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three-month USD Libor plus 0.433% while receiving payments of 5.125% semi-annually.

At quarter end, debt to debt plus book equity was 35%, down from 38% at the end of March 2005.

During the first quarter of this year, the Company repurchased a total of 8,016,400 common shares under its normal course issuer bid (NCIB) at an average price of $37.35 per share. In March of this year, the Company renewed its NCIB to permit the purchase of up to 18,437,285 common shares, representing 5% of the total common shares outstanding at the time of the renewal. 949,200 of the total were repurchased under the renewed NCIB. A copy of the Notice of Intention to Make a Normal Course Issuer Bid may be obtained without charge from Talisman.

As at June 30, 2005, there were 367,240,640 common shares outstanding, increasing to 367,241,015 as at July 20, 2005.

During July 2005, stock options for 163,185 shares were exercised for cash, with 23,524,391 stock options outstanding at July 20, 2005.

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

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

The following is a summary of quarterly results of the Company for the eight most recently completed quarters ended June 30, 2005.

	Three months ended (unaudited)
	2005		2004				2003
	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30
Gross sales	2,080	1,977	1,827	1,788	1,705	1,554	1,351	1,272
Total revenue	1,748	1,677	1,401	1,355	1,337	1,262	1,128	1,077
Net income ^{1, 2}	340	258	121	122	193	218	104	121
Per common share amounts (Cdn dollars)
Net income ^{1, 2}	0.93	0.70	0.32	0.32	0.50	0.57	0.27	0.31
Diluted net income ^{1, 2}	0.91	0.68	0.31	0.31	0.50	0.56	0.27	0.31

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

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters ended June 30, 2005.

In the second quarter of 2005, revenue rose over the previous quarter due to increased commodity prices, which were partially offset by reduced production. Net income increased in the quarter as the increased revenue combined with reductions in stock based compensation charges, transportation and other expenses to more than offset the impact of increases in operating costs, royalties, taxes, dry hole costs and exploration expenses.

During the first quarter of 2005, revenue rose over the last quarter of 2004, as a result of higher commodity prices, increased production and reduced hedging losses. Net income increased in the quarter as the increased revenue, combined with reductions in dry hole costs, exploration expenses, impairments, DD&A and G&A to more than offset the impact of increases in stock based compensation charges, royalties, operating costs and taxes.

During the fourth quarter of 2004, revenue increased over the previous quarter as increases in total volumes combined with higher gas prices to more than offset the impact of a stronger Canadian dollar and increased hedging losses. Net income remained relatively constant in the quarter as reductions in stock-based compensation, operating expenses and dry hole costs were offset by increases in DD&A, impairments and G&A expenses as well as a loss on disposal of fixed assets.

In the third quarter of 2004, 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 hole costs, 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 lower tax rate reductions resulted in a slight drop in net income during the second quarter of 2004 from the previous quarter.

New Canadian Accounting Pronouncements

The Canadian Institute of Chartered Accountants (CICA) has issued a number of accounting pronouncements, some of which may impact the Company’s reported results and financial position in future periods.

Comprehensive Income / Financial Instruments / Hedges

The CICA issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments (CICA 3855) and Hedges (CICA 3865), which will be effective for the reporting of year-end 2007. The new standards will bring Canadian rules in line with current rules in the US. The standards will introduce the concept of “Comprehensive Income” to Canadian GAAP and will require that an enterprise (a) classify items of comprehensive income by their nature in a financial statement and (b) display the accumulated balance of comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to comprehensive income and be brought into net income at the time the underlying hedged item is settled. It is expected that this standard will be effective for Talisman’s 2007 reporting. Any instruments that do not qualify for hedge accounting will be marked to market with the adjustment (tax effected) flowing through the income statement.

Talisman currently does not have a significant hedging program in place and therefore does not anticipate the impact of this new accounting standard to be material to the Company.

Risks and Uncertainties

Litigation

Talisman continues to be subject to a lawsuit brought by the Presbyterian Church of Sudan and others commenced in November 2001 under the Alien Tort Claims Act in the United States District Court for the Southern District of New York. The lawsuit alleges that the Company conspired with, or aided and abetted, the Government of Sudan to commit violations of international law in connection with the Company's now disposed of interest in oil operations in Sudan. On March 25, 2005, the Court refused to certify the lawsuit as a class action. On June 13, 2005, the plaintiffs filed papers re-defining the proposed class and seeking certification of the lawsuit as a new class action. The Company continues to oppose the certification of the lawsuit as a class action. On June 13, 2005, the Court denied Talisman's motion for judgment on the pleadings, which sought dismissal of the lawsuit on the grounds that the Court lacked subject matter jurisdiction to hear the lawsuit. The Company has sought Court approval to appeal. To date, no decision has been rendered by the Court in respect to the filing of a Statement of Interest by the US Department of Justice, expressing the US Government's view that the lawsuit interferes with US-Canada relations. Talisman believes the lawsuit is entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Talisman Energy Inc.
Product Netbacks
(unaudited)

		Three months ended		Three months ended		Six months ended		Six months ended
		June 30		June 30		June 30		June 30
(C$ - production before royalties)		2005	2004¹	2005	2004	2005	2004¹	2005	2004
		Oil and liquids ($/bbl)		Natural gas ($/mcf)		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	48.16	41.39	7.72	7.08	47.33	39.45	7.39	6.85
America	Hedging (gain)	3.68	4.81	-	0.16	3.39	3.93	-	0.11
	Royalties	9.77	8.52	1.53	1.44	9.82	8.04	1.46	1.38
	Transportation	0.54	0.48	0.18	0.20	0.49	0.49	0.17	0.20
	Operating costs	7.18	6.67	0.88	0.80	6.75	6.28	0.84	0.78
		26.99	20.91	5.13	4.48	26.88	20.71	4.92	4.38
North Sea	Sales price	60.24	47.27	6.27	5.17	58.72	44.43	6.67	5.55
	Hedging (gain)	-	5.74	-	-	-	4.65	-	-
	Royalties	0.78	0.60	0.53	0.13	0.60	0.36	0.49	0.43
	Transportation	1.11	1.11	0.61	0.31	1.13	1.11	0.57	0.34
	Operating costs	18.89	13.87	0.68	0.58	17.05	13.68	0.78	0.41
		39.46	25.95	4.45	4.15	39.94	24.63	4.83	4.37
Southeast	Sales price	67.60	50.19	6.36	4.85	63.87	47.16	5.91	4.68
Asia	Royalties	27.46	21.77	1.88	1.33	26.34	19.80	1.82	1.08
	Transportation	0.25	0.28	0.24	0.43	0.16	0.27	0.39	0.43
	Operating costs	4.34	5.30	0.31	0.28	4.21	5.04	0.30	0.28
		35.55	22.84	3.93	2.81	33.16	22.05	3.40	2.89
Algeria	Sales price	65.40	49.09			63.27	46.74
	Royalties	25.81	17.34			25.21	20.10
	Transportation	1.68	1.84			1.67	1.82
	Operating costs	3.28	4.75			4.39	3.15
		34.63	25.16			32.00	21.67
Trinidad	Sales price	58.90	-			58.44	-
	Royalties	10.03	-			8.55	-
	Operating costs	2.80	-			3.29	-
		46.07	-			46.60	-
Total Company	Sales price	58.58	46.42	7.31	6.47	56.98	43.78	7.02	6.30
	Hedging (gain)	0.86	4.31	-	0.12	0.79	3.49	-	0.08
	Royalties	8.32	6.71	1.53	1.31	7.86	6.35	1.45	1.23
	Transportation	0.86	0.87	0.22	0.26	0.85	0.87	0.25	0.26
	Operating costs	12.49	10.32	0.74	0.68	11.66	9.96	0.72	0.65
		36.05	24.21	4.82	4.10	35.82	23.11	4.60	4.08

1. Unit operating costs include pipeline operations for the North Sea. Prior years have been restated accordingly.
Netbacks do not include synthetic oil.

Talisman Energy Inc.
Product Netbacks¹
(unaudited)

		Three months ended		Six months ended
		June 30		June 30
(US$ - production net of royalties)		2005	2004²	2005	2004²
North	Oil and liquids (US$/bbl)
America	Sales price	38.73	30.43	38.33	29.45
	Hedging (gain)	3.71	4.46	3.46	3.67
	Transportation	0.54	0.44	0.50	0.46
	Operating costs	7.24	6.19	6.89	5.90
		27.24	19.34	27.48	19.42
	Natural gas (US$/mcf)
	Sales price	6.21	5.21	5.99	5.12
	Hedging (gain)	-	0.15	-	0.11
	Transportation	0.18	0.19	0.17	0.19
	Operating costs	0.89	0.74	0.84	0.74
		5.14	4.13	4.98	4.08
North Sea	Oil and liquids (US$/bbl)
	Sales price	48.45	34.74	47.58	33.14
	Hedging (gain)	-	4.27	-	3.47
	Transportation	0.90	0.83	0.92	0.83
	Operating costs	15.38	10.34	13.96	10.30
		32.17	19.30	32.70	18.54
	Natural gas (US$/mcf)
	Sales price	5.05	3.80	5.41	4.16
	Hedging (gain)	-	-	-	-
	Transportation	0.53	0.24	0.50	0.28
	Operating costs	0.59	0.44	0.68	0.33
		3.93	3.12	4.23	3.55
Southeast Asia	Oil and liquids (US$/bbl)
	Sales price	54.38	36.89	51.75	35.19
	Transportation	0.34	0.37	0.22	0.35
	Operating costs	5.87	6.94	5.80	6.51
		48.17	29.58	45.73	28.33
	Natural gas (US$/mcf)
	Sales price	5.11	3.57	4.78	3.49
	Transportation	0.27	0.46	0.46	0.43
	Operating costs	0.36	0.30	0.35	0.28
		4.48	2.81	3.97	2.78
Algeria	Oil (US$/bbl)
	Sales price	52.57	36.02	51.23	34.89
	Transportation	2.23	2.07	2.24	2.38
	Operating costs	4.35	5.32	5.92	4.11
		45.99	28.63	43.07	28.40
Trinidad	Oil (US$/bbl)
	Sales price	47.32	-	47.23	-
	Operating costs	2.71	-	3.09	-
		44.61	-	44.14	-
Total Company	Oil and liquids (US$/bbl)
	Sales price	47.12	34.12	46.16	32.67
	Hedging (gain)	0.81	3.70	0.74	3.02
	Transportation	0.80	0.74	0.80	0.76
	Operating costs	11.66	8.87	10.94	8.69
		33.85	20.81	33.68	20.20
	Natural gas (US$/mcf)
	Sales price	5.88	4.75	5.68	4.71
	Hedging (gain)	-	0.11	-	0.07
	Transportation	0.23	0.24	0.26	0.24
	Operating costs	0.76	0.63	0.74	0.61
		4.89	3.77	4.68	3.79

1. Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty volumes.
2. Unit operating costs include pipeline operations for the North Sea. Prior years have been restated accordingly.
Netbacks do not include synthetic oil.