CALGARY, Alberta – July XX, 2005

EX-1 2 f2qfinalfull.htm 2Q INTERIM FINANCIAL STATEMENTS CALGARY, Alberta – July XX, 2005 – Talisman Energy Inc

N E W S R E L E A S E

TALISMAN ENERGY GENERATES $2 BILLION

IN CASH FLOW YEAR TO DATE

SETS NEW RECORD FOR A QUARTER

CALGARY, Alberta – July 28, 2005 – Talisman Energy Inc. today reported its second quarter operating and financial results.

Cash flow for the quarter was $993 million ($2.70/share), an increase of 30% compared to $761 million ($1.98/share) a year earlier and $960 million ($2.59/share) in the first quarter of 2005. Cash flow to June 30 was $1,953 million ($5.29/share) compared to $1,531 million ($3.99/share) a year ago, an increase of 28%.

Net income for the quarter was $340 million ($0.93/share) compared to $193 million ($0.50/share) a year ago and $258 million ($0.70/share) in the previous quarter. Net income to June 30 was $598 million ($1.62/share) compared to $411 million ($1.07/share) a year ago.

Earnings from operations for the quarter increased 93%, totaling $428 million ($1.16/share) during the quarter versus $222 million ($0.58/share) a year earlier and $377 million ($1.02/share) in the first quarter of 2005. Earnings from operations adjusts for non-operational impacts on earnings such as the mark-to-market effect of changes in share prices on stock based compensation expense and changes to tax rates and is calculated to better illustrate Talisman’s performance on an internally consistent basis.

Production averaged 444,000 boe/d, an increase of 2% over the same quarter of 2004, but slightly lower than the first quarter due to maintenance and plant turnarounds. Natural gas production averaged 1,292 mmcf/d in the quarter, an increase of 4% over the second quarter of 2004. Talisman’s North American natural gas production averaged 911 mmcf/d, an increase of 3% over the comparable quarter a year ago. Oil and liquids production averaged 228,977 bbls/d, similar to production in the second quarter of 2004.

“Talisman continues to deliver extremely good financial results on the back of steady year over year volume growth, with production per share up 7% year to date,” said Dr. Jim Buckee, President and Chief Executive Officer. “Drilling results in North America continue to be very good, with a number of promising wells about to test. Tweedsmuir, our major field development in the North Sea, is on schedule for first production early in 2007. The South Angsi field in Malaysia will commence production within the next few weeks. We also expect to spud our first onshore well in Trinidad during the third quarter.

“With fewer plant turnarounds, South Angsi startup and increasing natural gas volumes, we expect production volumes in the 450,000-470,000 boe/d range for the third quarter and an additional increase of approximately 30,000 boe/d in the fourth quarter. Our production estimate for the year is 455,000-475,000 boe/d.

“Earnings from operations were $1.16 per share in the quarter, compared to a consensus number or ‘street estimate’ of $1.07 per share. WTI oil prices averaged approximately US$53/bbl during the quarter as world oil demand continues to grow against limited spare capacity. With virtually no oil hedges, these high prices are translating into record cash flow for our shareholders.

“I now expect Talisman to generate about $4.4 billion in cash flow for 2005, or approximately $12 per share based on an average US$55/bbl WTI oil price, US$7.50/mmbtu NYMEX gas price and an 80 cent Canadian dollar in the second half of the year.”

Talisman Second Quarter Summary

•

In North America, the Company drilled 56 successful gas wells and 31 oil wells (99% success rate).

•

In Appalachia, the Drumm #1 well came on production in July at an initial rate of 10 mmcf/d.

•

Two deep wells are currently being drilled at Monkman.

•

In Norway, a successful development well was completed in the Varg field, commencing oil production at 5,000 bbls/d in addition to a successful water injector.

•

At Gyda in Norway, the A31 well was completed and commenced oil production at a constrained rate of 6,000 bbls/d.

•

The Tweedsmuir project in the North Sea is on schedule with the first development well completed during the quarter. A second well is nearing total depth. First production for the project is expected in early 2007.

•

Offshore Malaysia and Vietnam, the Company was granted additional acreage adjacent to Block PM3-CAA.

•

Development drilling was completed at South Angsi in Malaysia. The topsides were installed on the platform and first production is expected in early August.

•

In Vietnam, a wholly owned Talisman subsidiary signed a Petroleum Contract for a 60% interest in Block 15-2/01.

•

In Indonesia, gas production increased by 30% (from a year earlier) to 177 mmcf/d.

•

Expansion of the Corridor facilities and the pipeline to West Java are on schedule for production in the first quarter of 2007.

•

In Trinidad, site preparation is underway for Talisman’s first onshore well (expected to spud in the third quarter).

•

In Qatar, the Company expects to spud its first exploration well in the fourth quarter.

•

Exploration wells drilling in Colombia and Peru are close to total depth and results should be known this quarter.

•

Talisman increased its semi-annual dividend by 13.33% to seventeen cents (C$0.17) per share.

Cash flow

Below is a reconciliation of cash provided by operating activities calculated in accordance with generally accepted accounting principles (GAAP) to cash flow (which is a non-GAAP measure of financial performance). Please refer to the section in this press release entitled Advisory - Non-GAAP Financial Measures for further explanation and details.

($ millions)	Three months ended		Six months ended
June 30,	2005	2004 (restated)	2005	2004 (restated)
Cash provided by operating activities	1,081	796	1,953	1,701
Changes in non-cash working capital	(88)	(35)	-	(170)
Cash flow	993	761	1,953	1,531

Earnings from operations

To assist in understanding the Company’s earnings from operations, the following table adjusts the Company’s net income as set forth in the financial statements as at June 30, 2005, for certain items of a non-operational nature, on an after-tax basis. Talisman’s reported results may not be comparable to similarly titled measures by other companies. The Company uses this data to evaluate performance of core operational exploration and production activities on a basis comparable between periods.

($ millions, except per share amounts)

	Three months ended		Six months ended
June 30,	2005	2004 (restated)	2005	2004 (restated)
Net income	340	193	598	411
Stock-based compensation ¹	78	45	194	67
Tax effects of unrealized foreign exchange gains on foreign denominated debt ²	10	(10)	13	(19)
Tax rate reductions and other	-	(6)	-	(38)
Earnings from operations ³	428	222	805	421
Amounts per share – basic ³	1.16	0.58	2.18	1.10
Amounts per share – diluted ^{3, 4}	1.14	0.56	2.13	1.07

Footnotes:

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at June 30, 2005, 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.

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

This is a non-GAAP measure. Reference is made to “Advisory – Non-GAAP Financial Measures” in this press release.

Since the introduction in mid-2003 of a cash payment feature attached to the outstanding stock options, approximately 97% of options have been exercised using the cash payment feature.

Management’s Discussion and Analysis (MD&A)

(July 27, 2005)

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.

Exploration and Operations Review

North America

During the second quarter of 2005, Talisman participated in 88 gross wells (47 operated) resulting in a total of 56 gas and 31 oil wells (success rate of 99 %). Included in the 88 wells were 21 exploration wells which resulted in 19 gas wells and one oil well.

Production averaged 207,769 boe/d during the quarter. Gas production averaged 911 mmcf/d, 17 mmcf/d (2%) below the previous quarter and 26 mmcf/d (3%) higher than second quarter of 2004. Gas volumes were down from the first quarter due to plant turnarounds and wet weather which delayed the tie-in of some new wells. Liquids production averaged 55,916 bbls/d, virtually unchanged from the first quarter of 2005 and 2% below the same period last year. This decrease in liquids production is in line with expectations. Natural gas continues to be the focus of the Company’s exploration and development activities in North America.

During the quarter, Talisman participated in five (gross) gas wells in the Alberta Foothills. The scheduled Ram River gas plant turnaround reduced production during the quarter to 134 mmcf/d, 6% below the prior quarter. Current production is 147 mmcf/d.

In Monkman, production averaged 101 mmcf/d, 6% lower than the previous quarter, due in part to unscheduled pipeline repairs; however, production was 77% above the second quarter of 2004. The Brazion b-60-E well (TLM 80%), which commenced production in December at 66 mmcf/d, consistently produced in the range of 50 to 60 mmcf/d (gross sales gas) during the quarter. One Triassic well was cased in the second quarter and two Paleozoic prospect wells are drilling. Current production at Monkman is approximately 110 mmcf/d (net to Talisman).

Production in the Edson area averaged 45,630 boe/d, 7% above the first quarter of 2005 and an increase of 15% over the same period last year. Gas production increased to 244 mmcf/d, 31 mmcf/d higher than the second quarter of 2004, with a new monthly production record of 246 mmcf/d in May 2005. This area includes Bigstone/Wild River, Edson and West Whitecourt.

Bigstone/Wild River’s quarterly production of 20,400 boe/d was up 9% over the prior quarter and 13% over the second quarter of last year. Nine wells were drilled in the quarter with a 100% success rate. In May, Bigstone/Wild River also set a new monthly production record of 115 mmcf/d.

Second quarter production in the Edson core area averaged 14,967 boe/d, 7% above last quarter and an increase of 26% over the same period in 2004. Seven wells were drilled during the quarter and all were successful.

Talisman Midstream Operations (TMO) transported and processed an average of 402 mmcf/d during the quarter, a 3% increase over the preceding quarter. In April, TMO applied for an EUB license to construct the 72 kilometer, 12 inch Lynx Pipeline (TMO 45%). This line will gather up to 130 mmcf/d of sour gas from the greater Grande Cache area and is targeted for commissioning in the second quarter of 2006. The Cutbank Complex achieved record throughput of 163 mmcf/d in June after a plant expansion (TMO 50%) at Musreau added 30 mmcf/d of processing capacity.

In Central Alberta, quarterly production was 4,220 boe/d, 73% above the first quarter of 2005 and an increase of 52% over the same period last year. Gas production increased to 16 mmcf/d, 6 mmcf/d higher than second quarter 2004, with a new monthly production record of 18 mmcf/d in June 2005. A 2004 Banff formation well, Ferrier 9-3-42-10W5(TLM 73.7%), came on stream in April. The Company intends to drill three more Banff wells in 2005.

In Appalachia, Fortuna Energy Inc., Talisman's wholly owned subsidiary, participated in five gas wells in the second quarter, all of which are waiting on completion and testing. The Drumm #1 well (FEI 99.2%), which was drilled in 2004, came on stream in July with an initial production rate of 10 mmcf/d (gross sales gas). Fortuna’s gas production during the quarter averaged 112 mmcf/d, 8 mmcf/d below the first quarter, but 19 mmcf/d above the second quarter of 2004. A high-pressure pipeline to the Ryers Creek meter station was commissioned in May 2005 and has facilitated an increase of approximately 8 mmcf/d of gas production.

North Sea

Production in the North Sea averaged 135,500 boe/d during the quarter, compared to 149,000 boe/d in the first quarter and 142,200 boe/d a year ago. Production was down as a result of major planned turnarounds at the Claymore and Buchan platforms and unplanned outages at Ross/Blake and Galley. The Ross/Blake outage was caused by production chemistry issues and the fields have been back on production at plan rates through the third quarter to date. The outage at Galley was caused by riser problems which will be resolved by mid-August.

Unit operating costs increased to $17.05/boe as a result of the planned turnarounds at Claymore and Buchan, increased Norwegian production, two unplanned workovers at Claymore and the production chemistry issues at Ross/Blake.

In Norway, a successful development well was drilled in the Varg field, with oil production commencing at 5,000 bbls/d and a water injector was completed (currently injecting 35,000 barrels of water per day). Another development well is currently drilling at Varg. At Gyda, the A31 well was completed and started production at a constrained rate of 6,000 bbls/d of dry oil.

The Tweedsmuir project continued on schedule for first production in early 2007; the first development well has been completed and the second well is nearing total depth. In addition, one development well is currently drilling at each of the Clyde and Orion fields.

Malaysia/Vietnam

Production in Malaysia/Vietnam averaged 39,200 boe/d in the quarter compared to 41,000 boe/d in the first quarter and 41,400 boe/d during the second quarter of 2004.

Two development wells were completed in Block PM-3 CAA during the quarter. The South Angsi development on Block PM-305 continued with the completion of eight development wells which confirmed expected reserves. The topsides were successfully installed on the production platform, on time. The FSO vessel is due in the field at the end of July and first production is expected in the first week of August.

During the quarter Talisman’s subsidiary acquired additional land (148,000 acres) adjacent to Block PM-3 CAA. Talisman has committed to a 3D seismic program and one exploration well.

On April 26, a wholly owned subsidiary of Talisman signed a Petroleum Contract for a 60% interest in Block 15-2/01 offshore Vietnam. Preparations are underway to begin a 3D seismic survey.

Indonesia

Production in Indonesia averaged 34,600 boe/d in the quarter compared to 32,800 boe/d in the first quarter and 37,200 boe/d a year earlier. Natural gas sales averaged 177 mmcf/d (versus 155 mmcf/d in the first quarter and 137 mmcf/d in the second quarter of 2004) with increased demand from Corridor gas buyers. The expansion of the Corridor facilities and the pipeline to West Java are proceeding as expected for production start in the first quarter of 2007.

Trinidad

Production in Trinidad averaged 11,300 boe/d in the second quarter. The Canteen platform commenced production in late April and one development well was completed in the quarter.

In the onshore Eastern Block, site preparation and rig up started for drilling two exploration wells; the first well is expected to spud during the third quarter.

Algeria

Production in Algeria averaged 16,100 boe/d and reservoir performance continues to be good. Expansion of the Greater MLN facilities was sanctioned. Joint development agreements for the MLSE field in the southeast corner of Block 405 were progressed.

Rest of the World

In Qatar, activity was focused on completing the processing and interpretation of 3D seismic on Block 10. The first exploration well is expected to spud during the fourth quarter of 2005.

Both the Tangara-1 side track in Colombia and the Situche Centrale well in Peru are nearing total depth.

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

For further information, please contact:

David Mann, Senior Manager, Corporate & Investor Communications

Phone:

403-237-1196 Fax: 403-237-1210

E-mail:

tlm@talisman-energy.com

Forward-looking Statements

This news release contains statements and estimates concerning future production and timing of production, cash flow and cash flow per share, earnings from operations, business plans for drilling, exploration and development, estimated future commodity prices and exchange rates, target dates for bringing production from certain facilities onstream and for commissioning of a pipeline and a compressor expansion (as well as additional capacity following expansion), planned expansion of facilities and outlook for major projects, the anticipated affects of new accounting pronouncements, the anticipated effects of litigation against Talisman and/or other expectations, beliefs, plans, goals, objectives, assumptions and statements about future events or performance. These statements and estimates constitute "forward-looking statements" or “forward-looking information” within the meaning of applicable securities legislation.

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

Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements. These risks and uncertainties include:

•

the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;

•

risks and uncertainties involving geology of oil and gas deposits;

•

the uncertainty of reserves estimates and reserves life;

•

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

•

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

•

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

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

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

•

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

•

general economic conditions;

•

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

•

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

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

information on these and other factors, which could affect the Company's operations or financial results, are included in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", "- Liquidity and Capital Resources", and "- Outlook for 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 available at www.sedar.com and the United States Securities and Exchange Commission and available at www.sec.gov.

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, Note Regarding Production Volumes

Throughout this news release, 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 release, 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.

Advisory – Canadian Dollars and GAAP

Dollar amounts are presented in Canadian dollars unless otherwise indicated. Unless otherwise indicated, financial information is presented in accordance with Canadian generally accepted accounting principles that may differ from generally accepted accounting principles in the US.

Advisory – Non-GAAP Financial Measures

This release includes references to terms such as cash flow, cash flow per share and earnings from operations. These terms are not defined by Generally Accepted Accounting Principles in either Canada or the US and do not have any standardized meanings. Consequently these are referred to as non-GAAP measures. Talisman’s reported results of cash flow, cash flow per share and earnings from operations are not likely to be comparable to similarly titled measures by other companies.

This press release discusses Talisman’s cash flow. It is presented because management believes the information is useful to investors because it is used internally and may be seen as a financial indicator of a company’s ability to generate cash to internally fund exploration and development activities, fund dividend programs and service debt. It is also used by research analysts to value and compare oil and gas exploration and development companies, and is frequently included in published research when providing investment recommendations. Cash flow, therefore, is an additional measure of liquidity, but is not a measure of performance under GAAP and should not be considered as an alternative to cash provided by operating activities. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period.

Earnings from operations is calculated by adjusting the Company’s net income per the financial statements, for certain items of a non-operational nature, on an after-tax basis. The Company uses this data to evaluate performance of core operational activities on a comparable basis between periods. To assist in understanding the Company’s earnings from operations, net income per the financial statements has been adjusted for certain items of a non-operational nature, on an after-tax basis.

Talisman Energy Inc.
Highlights
(unaudited)

	Three months ended		Six months ended
	June 30		June 30
	2005	2004	2005	2004
Financial		(restated¹)		(restated¹)
(millions of Canadian dollars unless otherwise stated)
Cash flow	993	761	1,953	1,531
Net income	340	193	598	411
Exploration and development expenditures	666	509	1,415	1,123
Per common share (dollars)
Cash flow	2.70	1.98	5.29	3.99
Net income	0.93	0.50	1.62	1.07
Production
(daily average)
Oil and liquids (bbls/d)
North America	53,042	54,024	53,646	54,632
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	-
Synthetic oil	2,874	2,894	2,449	2,972
Total oil and liquids	228,977	229,579	232,217	229,857
Natural gas (mmcf/d)
North America	911	885	920	879
North Sea	101	103	115	118
Southeast Asia	280	256	277	243
Total natural gas	1,292	1,244	1,312	1,240
Total mboe/d	444	437	451	437
Prices (2)
Oil and liquids ($/bbl)
North America	48.16	41.39	47.33	39.45
North Sea	60.24	47.27	58.72	44.43
Southeast Asia	67.60	50.19	63.87	47.16
Algeria	65.40	49.09	63.27	46.74
Trinidad	58.90	-	58.44	-
Crude oil and natural gas liquids	58.58	46.42	56.98	43.78
Synthetic oil	68.42	50.55	63.27	47.14
Total oil and liquids	58.71	46.47	57.04	43.83
Natural gas ($/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
Total natural gas	7.31	6.47	7.02	6.30
Total ($/boe) (includes synthetic)	51.52	42.83	49.80	40.98

(1) Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants ("CICA") accounting standard for financial instruments. The changes to this standard required the Company's preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. See not 1 to the Interim Consolidated Financial Statements.
(2) Prices are before hedging.

Talisman Energy Inc.
Consolidated Balance Sheets
(unaudited)

	June 30	December 31
(millions of Canadian dollars)	2005	2004
Assets		(restated
Current		note 1)
Cash and cash equivalents	149	38
Accounts receivable	931	836
Inventories	84	78
Prepaid expenses	17	18
	1,181	970

Accrued employee pension benefit asset	59	61
Other assets	75	64
Goodwill (note 2)	638	466
Property, plant and equipment	11,469	10,847
	12,241	11,438
Total assets	13,422	12,408


Liabilities
Current
Accounts payable and accrued liabilities (notes 3, 5 and 6)	1,455	1,302
Income and other taxes payable	416	341
	1,871	1,643

Deferred credits	81	70
Asset retirement obligations (note 3)	1,311	1,272
Other long-term obligations (notes 5 and 6)	115	35
Long-term debt (note 7)	2,732	2,457
Future income taxes	2,281	2,100
	6,520	5,934
Contingencies and commitments (notes 8 and 10)
Shareholders' equity
Common shares (note 4)	2,613	2,666
Contributed surplus	70	71
Cumulative foreign currency translation	(116)	(76)
Retained earnings	2,464	2,170
	5,031	4,831
Total liabilities and shareholders' equity	13,422	12,408

See accompanying notes.

Talisman Energy Inc.
Consolidated Statements of Income
(unaudited)

	Three months ended		Six months ended
(millions of Canadian dollars	June 30		June 30
except per share amounts)	2005	2004	2005	2004
		(restated		(restated
Revenue		note 1)		note 1)
Gross sales	2,080	1,705	4,057	3,258
Less hedging loss	18	102	33	162
Gross sales, net of hedging	2,062	1,603	4,024	3,096
Less royalties	352	287	673	541
Net sales	1,710	1,316	3,351	2,555
Other	38	21	74	43
Total revenue	1,748	1,337	3,425	2,598

Expenses
Operating	357	299	681	577
Transportation	44	46	96	94
General and administrative	52	41	102	80
Depreciation, depletion and amortization	439	409	880	798
Dry hole	51	44	97	123
Exploration	57	52	100	96
Interest	41	47	83	94
Stock-based compensation (note 5)	111	64	277	94
Other	(19)	13	5	16
Total expenses	1,133	1,015	2,321	1,972
Income before taxes	615	322	1,104	626
Taxes
Current income tax	213	90	398	141
Future income tax	28	6	31	17
Petroleum revenue tax	34	33	77	57
	275	129	506	215
Net income	340	193	598	411

Per common share ( Canadian dollars)
Net income	0.93	0.50	1.62	1.07
Diluted net income	0.91	0.50	1.58	1.05
Average number of common shares outstanding (millions)	367	384	369	384
Diluted number of common shares outstanding (millions)	375	390	377	390

See accompanying notes.


Consolidated Statements of Retained Earnings
(unaudited)

	Three months ended		Six months ended
	June 30		June 30
(millions of Canadian dollars)	2005	2004	2005	2004
		(restated		(restated
		note 1)		note 1)
Retained earnings, beginning of period	2,186	2,070	2,170	1,852
Net income	340	193	598	411
Common share dividends	(62)	(58)	(62)	(58)
Purchase of common shares (note 4)	-	-	(242)	-
Retained earnings, end of period	2,464	2,205	2,464	2,205

See accompanying notes.

Talisman Energy Inc.
Consolidated Statements of Cash Flows
(unaudited)

	Three months ended		Six months ended
	June 30		June 30
(millions of Canadian dollars)	2005	2004	2005	2004
		(restated		(restated
Operating		note 1)		note 1)
Net income	340	193	598	411
Items not involving cash (note 9)	596	516	1,255	1,024
Exploration	57	52	100	96
	993	761	1,953	1,531
Changes in non-cash working capital	88	35	-	170
Cash provided by operating activities	1,081	796	1,953	1,701
Investing
Capital expenditures
Exploration, development and corporate	(671)	(517)	(1,424)	(1,138)
Acquisitions	(65)	(279)	(301)	(300)
Proceeds of resource property dispositions	15	-	16	4
Changes in non-cash working capital	(76)	(130)	(52)	(134)
Cash used in investing activities	(797)	(926)	(1,761)	(1,568)
Financing
Long-term debt repaid	(937)	(239)	(1,009)	(436)
Long-term debt issued	790	-	1,281	-
Short-term borrowings	-	555	-	555
Common shares issued (purchased)	1	-	(298)	2
Common share dividends	(62)	(58)	(62)	(58)
Deferred credits and other	4	12	8	162
Changes in non-cash working capital	(1)	(3)	(3)	(6)
Cash (used in) provided by financing activities	(205)	267	(83)	219
Effect of translation on foreign currency cash and cash equivalents	4	(6)	2	(9)
Net increase in cash and cash equivalents	83	131	111	343
Cash and cash equivalents, beginning of period	66	310	38	98
Cash and cash equivalents, end of period	149	441	149	441

See accompanying notes.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

The Interim Consolidated Financial Statements of Talisman Energy Inc. (“Talisman” or the “Company”) have been prepared by management in accordance with Canadian generally accepted accounting principles. Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. The Interim Consolidated Financial Statements should be read in conjunction with the audited Annual Consolidated Financial Statements and the notes thereto in Talisman’s Annual Report Financial Review for the year ended December 31, 2004.

1. Significant Accounting Policies

The Interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the Consolidated Financial Statements for the year ended December 31, 2004 except for the following:

1a) Preferred Securities

Effective January 1, 2005 the Company retroactively adopted 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. Previously preferred securities charges were charged directly to retained earnings but under these changes to the accounting standard they would have been charged to interest expense. In addition, since the preferred securities would have been treated as debt, the balance would have been revalued at each balance sheet date with the offsetting movement reflected in the cumulative foreign currency translation account. As a result there would not have been a gain on the redemption of the preferred securities. There was no impact to the 2005 results as the preferred securities were fully redeemed in 2004.

The adjustment required to the December 31, 2004 consolidated balance sheet to implement this change in accounting is as follows:

	As previously reported	Adjustments	As restated
Cumulative foreign currency translation	(150)	74	(76)
Retained earnings	2,244	(74)	2,170

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

	As previously reported	Adjustments	As restated
Future income taxes	2,127	2	2,129
Long-term debt	2,203	392	2,595
Preferred securities	431	(431)	-
Cumulative foreign currency translation	(114)	88	(26)
Retained earnings	1,903	(51)	1,852

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

The adjustment required to the December 31, 2002 consolidated balance sheet to implement this change in accounting is as follows:

	As previously reported	Adjustments	As restated
Other assets	99	3	102
Future income taxes	2,282	(9)	2,273
Long-term debt	2,997	476	3,473
Preferred securities	431	(431)	-
Cumulative foreign currency translation	140	4	144
Retained earnings	1,143	(37)	1,106

The adjustment to the income statement for the three months ended June 30, 2004 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	41	6	47
Future income tax (recovery)	8	(2)	6
Net income	197	(4)	193
Preferred securities charges, net of tax	(4)	4	-
Gain on redemption of preferred securities, net of tax	7	(7)	-
Net income available to common share holders	200	(7)	193

Per common share (Canadian dollars)
Net income	.52	(.02)	.50
Diluted net income	.51	(.01)	.50

The adjustment to the income statement for the six months ended June 30, 2004 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	79	15	94
Future income tax (recovery)	23	(6)	17
Net income	420	(9)	411
Preferred securities charges, net of tax	(9)	9	-
Gain on redemption of preferred securities, net of tax	23	(23)	-
Net income available to common share holders	434	(23)	411

Per common share (Canadian dollars)
Net income	1.13	(.06)	1.07
Diluted net income	1.11	(.06)	1.05

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

The adjustment to the income statement for the year ended December 31, 2004 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	158	15	173
Future income tax (recovery)	(105)	(6)	(111)
Net income	663	(9)	654
Preferred securities charges, net of tax	(9)	9	-
Gain on redemption of preferred securities, net of tax	23	(23)	-
Net income available to common share holders	677	(23)	654

Per common share (Canadian dollars)
Net income	1.77	(.06)	1.71
Diluted net income	1.74	(.06)	1.68

The adjustment to the income statement for the year ended December 31, 2003 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	137	41	178
Future income tax (recovery)	(48)	(5)	(53)
Net income	1,012	(36)	976
Preferred securities charges, net of tax	(22)	22	-
Net income available to common share holders	990	(14)	976

Per common share (Canadian dollars)
Net income	2.56	(.03)	2.53
Diluted net income	2.53	(.03)	2.50

The adjustment to the income statement for the year ended December 31, 2002 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	164	45	209
Future income tax (recovery)	175	(18)	157
Net income	544	(27)	517
Preferred securities charges, net of tax	(24)	24	-
Net income available to common share holders	520	(3)	517

Per common share (Canadian dollars)
Net income	1.29	-	1.29
Diluted net income	1.27	-	1.27

1b) Reclassification

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in the current period.

2. Goodwill

During the first six months of 2005, the Company’s Goodwill changed as follows:

Opening balance at January 1, 2005	466
Acquired during the period	184
Foreign currency translation effect	(12)
Closing balance at June 30, 2005	638

During the first quarter of the year the Company completed the acquisition of all outstanding shares of Pertra A.S. The purchase price of $215 million has been assigned to property plant and equipment ($257 million), future income tax liability ($156 million), asset retirement obligations ($44 million), and the remainder to goodwill ($158 million).

During the second quarter the Company completed the acquisition of a non-working interest in the Brage oil field in the North Sea. The purchase price of $59 million has been assigned to property plant and equipment ($88 million), future income tax liability ($26 million), asset retirement obligations ($29 million), and the remainder to goodwill ($26 million).

3. Asset Retirement Obligations

During the first six months of 2005, the Company’s asset retirement obligations changed as follows:

ARO liability at January 1, 2005¹	1,295
Liabilities incurred during period	73
Liabilities settled during period	(18)
Accretion expense	38
Revisions in estimated cash flows	2
Foreign currency translation	(56)
ARO liability at June 30, 2005¹	1,334

1 Included in January 1, 2005 and June 30, 2005 liabilities are $23 million of short-term reclamation costs recorded in accounts payable on the balance sheet for a net ARO liability of $1,272 and $1,311 respectively.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

4. Share Capital

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

Continuity of common shares (year to date)	2005
	Shares	Amount
Balance at January 1,	375,185,290	$2,666
Issued upon exercise of stock options	101,750	4
Purchased	(8,016,400)	(57)
Balance at June 30,	367,270,640	$2,613

Pursuant to a normal course issuer bid renewed in March 2005, Talisman may repurchase up to 18,437,285 common shares representing 5% of the outstanding common shares of the Company at the time the normal course issuer bid was renewed. During the first three months of 2005 the Company repurchased 8,016,400 common shares, of which, 949,200 common shares were repurchased under the renewed normal course issuer bid, for $299 million.

5. Stock Options

Continuity of stock options (year to date)	2005
	Number of	Average
	Options	Exercise Price
Outstanding at January 1	20,788,375	19.58
Granted during the period	5,838,830	42.03
Exercised for common shares	(101,750)	13.95
Exercised for cash payment	(2,697,972)	17.62
Expired/forfeited	(135,857)	28.21
Outstanding at June 30	23,691,626	25.31
Exercisable at June 30	7,902,676	17.32

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

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Cash units

In addition to the Company’s stock option plans Talisman’s subsidiaries issue stock appreciation rights under the cash unit plans. Cash units are similar to stock options except that the holder does not have a right to purchase the underlying share of the Company.

Continuity of cash units (year to date)	2005
	Number of	Average
	Cash Units	Exercise Price
Outstanding at January 1	1,526,640	21.34
Granted during the period	981,135	42.02
Expired/forfeited	(12,500)	26.03
Outstanding at June 30	2,495,275	29.45
Exercisable at June 30	9,900	19.81

For the three months ended June 30, 2005 the Company recorded stock-based compensation expense of $111 million (2004 - $64 million). Of the total expense $32 million (2004 - $24 million) relates to options exercised for cash, the remaining $79 million (2004 - $40 million) is primarily a result of the 11% (2004 - 13%) increase in the Company’s share price during the period, and the corresponding impact on the mark-to-market liability of the vested and prorated vested options and cash units outstanding.

For the six months ended June 30, 2005 the Company recorded stock-based compensation expense of $277 million (2004 - $94 million). Of the total expense $67 million (2004 - $51 million) relates to options exercised for cash, the remaining $210 million (2004 - $43 million) is primarily a result of the 42% (2004 - 19%) increase in the Company’s share price during the period

	Three months ended June 30		Six months ended June 30
	2005	2004	2005	2004
Average exercise price	$ 45.51	$ 29.29	$ 42.41	$ 27.62
Average grant price	18.32	16.43	17.62	15.14
Average gain per option	$ 27.19	$ 12.86	$ 24.79	$ 12.48
Number of options	1,156,230	1,872,202	2,697,972	4,075,483
Cash expense ($millions)	32	24	67	51

Of the total mark-to-market liability for stock options and cash units of $436 million as at June 30, 2005 (December 31, 2004 - $223 million), $407 million (December 31, 2004 - $223 million) is included in accounts payable and accrued liabilities.

6. Other Long-Term Obligations

Other long-term obligations include the long-term portion of the mark-to-market liability for stock based compensation of $29 million (December 31, 2004 - $nil), pension and other long-term obligations $42 million (December 31, 2004 - $35) and discounted obligations on capital leases of $44 million (December 31, 2004 - $nil).

During the period the Company entered into a leasing arrangement for the modification, refitting and use of a floating storage and off-loading vessel (FSO). This vessel will be deployed related to the South Angsi development in Malaysia.

The modifications to the FSO are substantially complete and an element of the leasing arrangement has been defined by the Company as a capital lease. The future minimum lease payments are US $3 million in 2005 followed by US $5 million for each of the next four years and US $34 million for the remainder of the lease. The imputed rate of interest on the lease is 6% and the lease expires in 2016. Of the total discounted liability of $49 million, $5 million is included in accounts payable and accrued liabilities.

7. Long-Term Debt

	June 30, 2005		December 31, 2004
Bank Credit Facilities (Canadian $ denominated)		-		328
Debentures and Notes (unsecured)
US$ denominated (US$1,325 million)		1,624		993
Canadian $ denominated		559		559
£ denominated (£250 million)		549		577
	$	2,732	$	2,457

In May 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.

8. Financial Instruments

Interest rate derivative contracts

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. These contracts have been designated as a hedge of the fair value of a portion (US $300 million) of the total US $375 million note issued. In accordance with the Company’s accounting policies, derivative contracts that have been designated as a hedge are recorded at cost and subsequent gains and losses in the fair value of these derivatives are not reflected in the Consolidated Financial Statements until realized. Payments or receipts on these swap contracts are recognized in income concurrently with those on the hedged transaction and are recorded in the Consolidated Statements of Income and Cash Flows as interest expense and cash provided by operating activities respectively.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Commodity based sales contracts

The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales. The following tables summarize commodity price derivative contracts and fixed price sales contracts outstanding at June 30, 2005:

Crude oil price derivative contracts

Fixed price swaps	Remainder 2005
(WTI oil index)
Volumes (bbls/d)	6,000
Price (US$/bbl)	26.97

Physical natural gas contracts (North America)

Fixed price sales	Remainder 2005	2006	2007
Volumes (mcf/d)	14,650	14,650	14,650
Weighted average price ($/mcf)	3.22	4.16	4.29

9. Selected Cash Flow Information
	Three months ended June 30		Six months ended June 30
	2005	2004 (restated note 1)	2005	2004 (restated note 1)
Net income	340	193	598	411
Items not involving cash
Depreciation, depletion and amortization	439	409	880	798
Property impairments	3	-	26	-
Dry hole	51	44	97	123
Net (gain) loss on asset disposals	(2)	-	(3)	3
Stock-based compensation	79	40	210	43
Future taxes and deferred petroleum revenue tax	26	13	39	32
Other	-	10	6	25
	596	516	1,255	1,024
Exploration	57	52	100	96
	993	761	1,953	1,531

The cash interest and taxes paid for the six months ended June 30 were as follows:

	2005	2004
Interest paid	68	60
Income taxes paid	330	98

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

10. Contingencies and commitments

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

11. Segmented Information
	North America (1)				North Sea (2)				Southeast Asia (3)
	Three months		Six months		Three months		Six months		Three months		Six months
	ended		ended		ended		ended		ended		ended
	June 30		June 30		June 30		June 30		June 30		June 30
	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004
Revenue
Gross sales	894	791	1,723	1,516	703	586	1,438	1,123	328	276	620	514
Hedging	18	37	33	57	-	65	-	105	-	-	-	-
Royalties	173	159	339	302	14	8	24	17	116	102	225	177
Net sales	703	595	1,351	1,157	689	513	1,414	1,001	212	174	395	337
Other	21	19	42	36	16	2	31	7	1	-	1	-
Total revenue	724	614	1,393	1,193	705	515	1,445	1,008	213	174	396	337
Segmented expenses
Operating	117	105	223	201	214	166	404	324	18	23	36	45
Transportation	16	19	33	37	18	14	37	32	7	11	21	21
DD&A	235	187	463	363	151	166	315	328	29	49	60	93
Dry hole	21	31	39	62	16	13	33	38	5	(1)	6	-
Exploration	28	24	49	47	15	8	20	14	3	6	6	8
Other	(7)	(2)	(9)	(14)	6	11	37	13	2	1	(1)	2
Total segmented expenses	410	364	798	696	420	378	846	749	64	89	128	169
Segmented income before taxes	314	250	595	497	285	137	599	259	149	85	268	168
Non-segmented expenses
General and administrative
Interest
Stock-based compensation
Currency translation
Total non-segmented expenses
Income before taxes
Capital expenditures
Exploration	127	120	300	254	51	47	73	87	10	6	24	15
Development	133	132	408	375	235	86	397	152	64	38	126	82
Midstream	12	2	16	3	-	-	-	-	-	-	-	-
Exploration and development	272	254	724	632	286	133	470	239	74	44	150	97
Property acquisitions
Midstream acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment			6,422	6,214			3,345	3,074			1,197	1,050
Goodwill			291	291			245	75			102	100
Other			546	419			344	347			280	221
Segmented assets			7,259	6,924			3,934	3,496			1,579	1,371
Non-segmented assets
Total assets (5)
	Three months		Six months						Three months		Six months
	ended		ended						ended		ended
	June 30		June 30						June 30		June 30
(1) North America	2005	2004	2005	2004	(2) North Sea				2005	2004	2005	2004
Canada	647	550	1,241	1,097	United Kingdom				559	479	1,195	938
US	77	64	152	96	Netherlands				14	7	28	16
Total revenue	724	614	1,393	1,193	Norway				132	29	222	54
Canada			5,960	5,738	Total revenue				705	515	1,445	1,008
US			462	476	United Kingdom						2,821	2,858
Property, plant and equipment (5)			6,422	6,214	Netherlands						41	41
					Norway						483	175
					Property, plant and equipment (5)						3,345	3,074
(4) Trinidad commenced production in 2005. Prior year's figures have been reclassified from Other to conform with the method of presentation adopted in 2005.
(5) Current year represents balances as at June 30, prior year represents balances as at December 31.

Algeria				Trinidad (4)				Other				Total
Three months		Six months		Three months		Six months		Three months		Six months		Three months		Six months
ended		ended		ended		ended		ended		ended		ended		ended
June 30		June 30		June 30		June 30		June 30		June 30		June 30		June 30
2005	2004	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004

95	52	175	105	60	-	101	-	-	-	-	-	2,080	1,705	4,057	3,258
-	-	-	-	-	-	-	-	-	-	-	-	18	102	33	162
38	18	70	45	11	-	15	-	-	-	-	-	352	287	673	541
57	34	105	60	49	-	86	-	-	-	-	-	1,710	1,316	3,351	2,555
-	-	-	-	-	-	-	-	-	-	-	-	38	21	74	43
57	34	105	60	49	-	86	-	-	-	-	-	1,748	1,337	3,425	2,598

5	5	12	7	3	-	6	-	-	-	-	-	357	299	681	577
3	2	5	4	-	-	-	-	-	-	-	-	44	46	96	94
10	7	19	14	14	-	23	-	-	-	-	-	439	409	880	798
-	-	-	-	9	-	12	-	-	1	7	23	51	44	97	123
-	-	-	-	2	14	3	14	9	-	22	13	57	52	100	96
-	-	-	-	-	-	-	-	(3)	-	(3)	-	(2)	10	24	1
18	14	36	25	28	14	44	14	6	1	26	36	946	860	1,878	1,689
39	20	69	35	21	(14)	42	(14)	(6)	(1)	(26)	(36)	802	477	1,547	909

												52	41	102	80
												41	47	83	94
												111	64	277	94
												(17)	3	(19)	15
												187	155	443	283
												615	322	1,104	626

-	-	-	-	7	8	15	23	21	19	41	43	216	200	453	422
2	1	4	4	4	50	11	85	-	-	-	-	438	307	946	698
-	-	-	-	-	-	-	-	-	-	-	-	12	2	16	3
2	1	4	4	11	58	26	108	21	19	41	43	666	509	1,415	1,123
												59	268	295	294
												-	-	-	-
												(16)	(2)	(20)	(12)
												4	8	8	16
												713	783	1,698	1,421
		167	178			275	182			63	149			11,469	10,847
		-	-			-	-			-	-			638	466
		49	36			17	11			20	-			1,256	1,034
		216	214			292	193			83	149			13,363	12,347
														59	61
														13,422	12,408
				Three months		Six months
				ended		ended
				June 30		June 30
(3) Southeast Asia				2005	2004	2005	2004
Indonesia				98	84	177	170
Malaysia				109	85	206	158
Vietnam				6	5	13	9
Total revenue				213	174	396	337
Indonesia						335	327
Malaysia						840	701
Vietnam						22	22
Property, plant and equipment (5)						1,197	1,050

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.
Production net of royalties¹
(unaudited)

	Three months ended		Six months ended
	June 30		June 30
	2005	2004	2005	2004

Oil and liquids (bbls/d)
North America	42,276	42,901	42,510	43,498
North Sea	117,135	123,420	121,988	123,106
Southeast Asia	16,079	20,334	16,466	20,742
Algeria	9,719	7,600	9,206	7,054
Trinidad	9,335	-	8,153	-
Synthetic oil (Canada)	2,744	2,767	2,343	2,834
Total oil and liquids	197,288	197,022	200,666	197,234

Natural gas (mmcf/d)
North America	731	705	738	702
North Sea	92	101	107	109
Southeast Asia	197	186	192	187
Total natural gas	1,020	992	1,037	998

Total mboe/d	367	362	373	364

1. Information provided per US reporting practice of calculating production after deduction of royalty volumes.

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.

Talisman Energy Inc.
Consolidated Financial Ratios
June 30, 2005
(unaudited)

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


The asset coverage ratios are calculated as at June 30, 2005.
The interest coverage ratios are for the 12 month period then ended.

Interest coverage (times)
Income (1)			9.33
Cash flow (2)			24.09
Asset coverage (times)
Before deduction of future income taxes and deferred credits (3)			4.23
After deduction of future income taxes and deferred credits (4)			2.84

(1) Net income plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(2) Cash flow plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(3) Total assets minus current liabilities; divided by long-term debt.
(4) Total assets minus current liabilities and long-term liabilities excluding long-term debt; divided by long-term debt.