N E W S R E L E A S E

EX-5 6 q3mda.htm TLM Q3 MD&A N E W S R E L E A S E

INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

NOVEMBER 1, 2005

Forward-looking Statements

This interim MD & A contains statements about expected royalty rates and taxes, anticipated sources of financing for the proposed acquisition of Paladin Resources plc, 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;

•

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);

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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 September 30, 2005 and 2004 and the 2004 Audited Consolidated Financial Statements. All comparative percentages are between the quarters ended September 30, 2005 and 2004, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Quarterly results summary (unaudited)

	Three months ended			Nine months ended
September 30,	2005		2004	2005	2004
Financial (millions of C$ unless otherwise stated)
Net income¹		430	122	1,028	533
Exploration and development expenditures		784	687	2,199	1,810
C$ per common share
Net income¹– Basic		1.17	0.32	2.79	1.39
– Diluted		1.14	0.31	2.73	1.37
Production, before royalties (daily average)
Oil and liquids (bbls/d)		242,884	218,441	235,811		226,024
Natural gas (mmcf/d)		1,307	1,263	1,310		1,248
Total mboe/d (6mcf=1boe)		461	429	454		434
Production(boe) per common share– Basic		0.115	0.103	0.336		0.310

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 third quarter of 2005 increased 252% over the prior year to $430 million, primarily related to improved commodity prices and a 7% increase in production.

For the nine months ended September 30, 2005, boe production per common share of 0.336 was 9% higher than the corresponding period of 2004, and within the range of the Company’s guidance.

Company Netbacks¹ (unaudited)

	Three months ended		Nine months ended
September 30,	2005	2004²	2005	2004²
Oil and liquids ($/bbl)
Sales price	71.51	53.30	62.01	46.87
Hedging expense	1.08	7.15	0.89	4.68
Royalties	9.89	7.86	8.56	6.84
Transportation	0.88	0.95	0.86	0.89
Operating costs	11.60	11.58	11.63	10.49
	48.06	25.76	40.07	23.97
Natural gas ($/mcf)
Sales price	8.43	6.15	7.49	6.25
Hedging expense	-	0.10	-	0.09
Royalties	1.79	1.25	1.57	1.24
Transportation	0.26	0.25	0.26	0.26
Operating costs	0.79	0.68	0.74	0.66
	5.59	3.87	4.92	4.00
Total $/boe (6mcf=1boe)
Sales price	61.54	45.19	53.76	42.35
Hedging expense	0.56	3.91	0.46	2.67
Royalties	10.30	7.68	8.96	7.12
Transportation	1.20	1.23	1.19	1.20
Operating costs	8.32	7.86	8.16	7.34
	41.16	24.51	34.99	24.02

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 third quarter, the Company’s average netback was $41.16/boe, 68% 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 $61.54/boe which was 36% higher than in 2004. This realized price increase and decreased hedging losses more than offset increases in royalties and operating expenses, resulting in an increase in the netback of $16.65/boe.

Gross sales for the quarter ended September 30, 2005 were $2.6 billion, an increase of $818 million or 46% over 2004. Higher commodity prices combined with new production from Trinidad, increased oil and liquids production in the North Sea and increased natural gas production in Southeast Asia and North America to more than offset the impact of a stronger Canadian dollar.

Daily average production, before royalties (unaudited)

	Three months ended		Nine months ended
September 30,	2005	2004	2005	2004
Oil and liquids (bbls/d)
North America	55,908	57,049	56,032	57,418
North Sea	124,139	111,301	123,550	119,818
Southeast Asia	36,509	36,047	30,881	35,853
Algeria	15,789	14,044	15,466	12,935
Trinidad	10,539	-	9,882	-
	242,884	218,441	235,811	226,024
Natural gas (mmcf/d)
North America	913	892	917	884
North Sea¹	99	98	110	111
Southeast Asia	295	273	283	253
	1,307	1,263	1,310	1,248
Total mboe/d (6mcf=1boe)	461	429	454	434

Includes gas acquired for injection and subsequent resale of 18 mmcf/d and 12 mmcf/d in the third quarter and year to date periods of 2005, respectively, and of 3 mmcf/d and 6 mmcf/d in the third quarter and year to date periods of 2004.

The Company’s daily average oil and liquids production for the third quarter was 242,884 bbls/d, an increase of 24,443 bbls/d or 11% over the same period last year. In Trinidad, where first oil production commenced earlier this year, third quarter production averaged 10,539 bbls/d. In the North Sea, oil and liquids production averaged 124,139 bbls/d, up 12% from 2004 as production increases from development drilling and asset acquisitions over the past year more than offset the impact of natural declines. Southeast Asia oil and liquids production in the current quarter averaged 36,509 bbls/d, up 1% from 2004 as new production during the quarter from PM-305 in Malaysia averaged 8,602 bbls/d to more than offset the impact of the expiry of the Tanjung concession. PM-305 (South Angsi field) commenced production in mid August and produced an average of 17,656 bbls/d during the month of September. Algeria production averaged 15,789 bbls/d, up 12% from the same period in 2004 when operational issues reduced production at the Greater MLN facilities. In North America, oil and liquids production averaged 55,908 bbls/d during the third quarter, down 2% from 2004, as expected, due to natural declines and the Company’s continued focus on natural gas.

During the third quarter, natural gas production averaged 1.3 bcf/d, 3% above last year, due to production increases in both North America and Southeast Asia. In North America, natural gas production was 913 mmcf/d, an increase of 21 mmcf/d or 2% over last year, with production increases in Monkman, up 35 mmcf/d to 101 mmcf/d, Bigstone/Wild River, up 17 mmcf/d to 109 mmcf/d and West Whitecourt, up 8 mmcf/d to 53 mmcf/d, more than offsetting decreases resulting from higher turnarounds in the quarter, natural declines in other areas and the impact on production of weather related flooding in the Southern Alberta Foothills. In Southeast Asia, natural gas production was 295 mmcf/d, an increase of 22 mmcf/d or 8% over last year. Indonesia natural gas production increased 33% or 47 mmcf/d over last year averaging 188 mmcf/d with higher Corridor sales to Caltex and Singapore Power. Production in Malaysia/Vietnam averaged 107 mmcf/d this quarter, down 19% from the same period last year due to commercial constraints. North Sea natural gas production averaged 99 mmcf/d during the quarter, up 1% from the prior year.

Prices and Exchange Rates (unaudited)

	Three months ended		Nine months ended
September 30,	2005	2004	2005	2004
Oil and liquids ($/bbl)
North America	60.92	45.47	51.86	41.46
North Sea	74.36	54.57	64.01	47.59
Southeast Asia	76.86	56.95	69.05	50.46
Algeria	72.00	63.98	66.27	53.03
Trinidad	71.86	-	63.26	-
	71.51	53.30	62.01	46.87
Natural gas ($/mcf)
North America	9.15	6.63	7.98	6.77
North Sea	6.08	4.88	6.49	5.35
Southeast Asia	6.98	5.03	6.29	4.81
	8.43	6.15	7.49	6.25
Total $/boe (6mcf=1boe)	61.54	45.19	53.76	42.35
Hedging loss not included in the above prices Oil and liquids ($/bbl)	1.08	7.15	0.89	4.68
Natural gas ($/mcf)	-	0.10	-	0.09
Total $/boe (6mcf=1boe)	0.56	3.91	0.46	2.67
Benchmark prices and foreign exchange rates WTI (US$/bbl)	63.31	43.88	55.61	39.11
Brent (US$/bbl)	61.64	41.54	53.74	36.29
NYMEX (US$/mmbtu)	8.25	5.84	7.12	5.83
AECO (C$/gj)	7.75	6.32	7.03	6.34
US/Canadian dollar exchange rate	0.832	0.765	0.817	0.753
Canadian dollar / pound sterling exchange rate	2.144	2.379	2.257	2.419

Excludes synthetic oil

Talisman’s third quarter realized commodity price averaged $61.54/boe, up 36% from last year. The WTI price for oil averaged US$63.31/bbl, as a tightly stretched global refining system, coupled with hurricane related damage in the US Gulf, continuing strong demand in India and China, and ongoing geopolitical anxiety in the Middle East contributed to this 44% increase over 2004. The impact of this increase was partially offset by a 9% stronger Canadian dollar, which resulted in a 34% increase in the Company’s realized price for oil and liquids to $71.51/bbl.

The Company’s realized North American natural gas sales price during the quarter was $9.15/mcf, an increase of 38% over 2004, as the supply/demand balance was tight due to a hot summer in North America, the effect of strong crude oil prices and the impact of shut in production due to the hurricanes in the US Gulf.

For the quarter ended September 30, 2005, Talisman recorded net hedging losses on commodity based derivative financial instruments of $24 million, all associated with oil and liquids ($1.08/bbl), compared to losses of $142 million for oil and liquids ($7.15/bbl) and $11 million for natural gas ($0.10/mcf) during the same period in 2004. As of October 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 September 30, 2005 Interim Consolidated Financial Statements.

Royalties¹ (unaudited)

	Three months ended
September 30,	2005		2004
	%	$ millions	%	$ millions
North America	20	216	20	154
North Sea	1	13	2	9
Southeast Asia	35	154	36	113
Algeria	38	40	31	26
Trinidad	16	11	-	-
	17	434	17	302
	Nine months ended
September 30,	2005		2004
	%	$ millions	%	$ millions
North America	20	555	20	456
North Sea	2	37	2	27
Southeast Asia	36	379	35	289
Algeria	39	110	38	71
Trinidad	15	26	-	-
	17	1,107	17	843

Royalty rates do not include synthetic oil

The Company’s royalty expense for the third quarter was $434 million, up from $302 million 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. It is anticipated that during the fourth quarter, the royalty rate in Malaysia’s PM3-CAA project will approach 60% due to the recovery of cost pools associated with the oil development. However, PM 305 has an initial rate of 14% and therefore, the fourth quarter Malaysia rate is expected to remain relatively unchanged. Algeria total expense increased due to increased commodity prices and production. The Algerian government’s total take for the third quarter including royalties and taxes equalled approximately 51%, similar to 2004.

Operating Expense (unaudited)

	Three months ended
September 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	6.13	116	5.31	99
North Sea	15.78	204	14.97	176
Southeast Asia	2.76	22	3.75	28
Algeria	4.25	6	3.86	5
Trinidad	2.83	2	-	-
	8.32	350	7.86	308
Synthetic oil	23.69	7	20.70	6
Pipeline		5		5
		362		319
	Nine months ended
September 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	5.69	320	5.19	287
North Sea	15.51	601	13.02	494
Southeast Asia	2.73	58	3.44	74
Algeria	4.34	18	3.41	12
Trinidad	3.13	8	-	-
	8.16	1,005	7.34	867
Synthetic oil	29.84	22	20.09	17
Pipeline		16		12
		1,043		896

During the third quarter, total operating expenses increased from last year by $43 million to $362 million. Unit operating costs averaged $8.32/boe, up from $7.86/boe last year. Total North Sea operating expenses increased $28 million. North Sea unit operating costs increased $0.81/boe to $15.78/boe, due to higher unit costs from the new production at the Varg field in Norway and a special insurance charge related to hurricane Katrina, partially offset by gains related to foreign exchange and reduced shut downs and maintenance in the U.K. sector. In North America, unit operating costs increased due to higher processing fees, maintenance and plant turnarounds. Unit operating costs in Southeast Asia were down 26% to $2.76/boe due to increased production from Corridor and the expiry of the Tanjung and Jambi concessions. Algeria unit operating costs increased 10% to $4.25/boe due to increased insurance and labour costs.

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

	Three months ended
September 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	12.57	241	10.26	195
North Sea	11.59	149	13.08	154
Southeast Asia	4.92	39	6.51	49
Algeria	6.69	10	6.04	7
Trinidad	13.01	13	-	-
	10.66	452	10.25	405
	Nine months ended
September 30,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	12.33	704	9.94	558
North Sea	12.00	464	12.71	482
Southeast Asia	4.65	99	6.62	142
Algeria	6.83	29	6.06	21
Trinidad	13.26	36	-	-
	10.74	1,332	10.11	1,203

The 2005 third quarter DD&A expense was $452 million, up 12% 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 as well as increased land amortization costs. The North Sea DD&A expense was down $5 million as the decrease in the per unit DD&A rate resulting from the increased reserves and gains on foreign exchange more than offset the increase in production. The DD&A rate for Southeast Asia decreased 24% to $4.92/boe, as a result of increased reserves in Malaysia/Vietnam and the expiry of the Tanjung concession. This decreased rate more than offset the impact of a 5% increase in boe production and resulted in a 20% decrease in DD&A expense to $39 million. The per unit DD&A rate in Algeria increased as a result of a higher proportion of production from the higher rate MLN fields, which coupled with a 12% increase in production to increase the DD&A expense to $10 million.

Other ($ millions) (unaudited)

September 30,	Three months ended		Nine months ended
September 30,	2005	2004	2005	2004
G&A	41	39	143	119
Dry hole expense	67	99	164	222
Stock-based compensation	235	70	512	164
Transportation	50	48	146	142
Other expense (income)	4	(1)	9	15
Interest costs capitalized	6	4	12	9
Interest expense	38	41	121	135
Other revenue	41	22	115	65

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

Dry hole expense for the third quarter of 2005 was $67 million and included $37 million in North America.

Other revenue of $41 million included $35 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 September 30, 2005 and is based on the difference between the Company’s share price and its stock options or cash units exercise price. The $235 million expense for the current quarter is due in part to 1.4 million options being exercised for cash at an average share price of $57.24 and an average exercise price of $18.14 for a cash expense of $56 million. The remaining $179 million expense for the current quarter is a result of a 24% increase in the Company’s share price to $56.88 and the corresponding impact on the mark-to-market liability of the 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 relatively unchanged during the third quarter of this year.

Taxes ($ millions) (unaudited)

Effective Income Tax Rate

September 30,	Three months ended		Nine months ended
September 30,	2005	2004	2005	2004¹
Income before taxes	861	264	1,965	890
Less PRT Current Deferred	47 1	63 (25)	116 9	105 (10)
Total PRT	48	38	125	95
	813	226	1,840	795
Income tax expense
Current income tax	345	133	743	274
Future income tax	38	(29)	69	(12)
Total income tax expense	383	104	812	262
Effective income tax rate	47%	46%	44%	33%

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 an increased proportion of taxable income being generated in higher tax jurisdictions (e.g. Norway). During 2005, current tax increased to $345 million as a result of both higher commodity prices and increased production, which also increased PRT on North Sea operations.

Capital expenditures ($ millions) (unaudited)

	Three months ended		Nine months ended
September 30,	2005	2004	2005	2004
North America	520	357	1,251	1,085
North Sea	352	156	1,089	581
Southeast Asia	79	80	229	177
Algeria	7	3	12	7
Trinidad	23	43	49	152
Other	46	46	87	88
	1,027	685	2,717	2,090

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

North America capital expenditures for the current quarter comprised $146 million on exploration, $217 million on development activities and $157 million on acquisitions. Exploration and development drilling resulted in 62 net gas wells and 36 net oil wells. Expenditures in the North Sea during the third quarter comprised $42 million on exploration and $217 million on development, which included the ongoing development of the Tweedsmuir field, in addition to a net $93 million for property acquisitions. In Southeast Asia, capital expenditures of $79 million included $18 million of exploration spending and development spending of $61 million on Block PM 3 and South Angsi in Block PM-305. In Trinidad, third quarter expenditures included $21 million of exploration spending and development spending of $2 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 September 30, 2005, long-term debt, net of cash, was $2.2 billion, down from $2.4 billion at year end. At September 30, 2005, Talisman’s long-term debt was $2.6 billion, up from $2.5 billion at year-end. The sources and uses of funds included 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 33%, down from 35% at the end of June 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 C$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 8,016,400 common shares were repurchased under the renewed NCIB. Between September 30, 2005 and October 14, 2005, the Company repurchased an additional 1,072,700 common shares at an average price of C$51.46.

As at September 30, 2005, there were 367,328,015 common shares outstanding, decreasing to 366,255,315 as at October 30, 2005. During the third quarter, the Company declared a semi-annual dividend of $0.17 per share on the Company’s common shares, payable on December 30, 2005, to shareholders of record at the close of business on December 9, 2005.

During October 2005, 141,226 stock options were exercised for cash, 19,900 were cancelled, with 22,076,417 stock options outstanding at October 30, 2005.

On October 20, 2005 Talisman reached an agreement with Paladin Resources plc (“Paladin”) on the terms of a cash offer by Talisman Energy Resources Limited (“Talisman Resources”), a wholly-owned subsidiary of Talisman, for all of the shares of Paladin valuing the existing shares of Paladin at approximately £1,218 million (C$2,521 million). The offer document for the offer was posted to Paladin shareholders on October 28, 2005. Talisman has a committed bridge financing facility, which it intends to use to finance purchases of shares under the offer.

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 September 30, 2005.

	Three months ended
	2005			2004					2003
	Sept. 30	June 30	March 31	Dec. 31	Sept. 30	June 30	March 31		Dec. 31
Gross sales	2,606	2,080	1,977	1,827	1,788	1,705	1,554	1,351
Total revenue	2,189	1,748	1,677	1,401	1,355	1,337	1,262	1,128
Net income ^{1, 2}	430	340	258	121	122	193	218	104
Per common share amounts (C$)
Net income ^{1, 2}	1.17	0.93	0.70	0.32	0.32	0.50	0.57	0.27
Diluted net income ^{1, 2}	1.14	0.91	0.68	0.31	0.31	0.50	0.56	0.27

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 September 30, 2005.

During the third quarter of 2005, revenue rose over the previous quarter as escalating commodity prices combined with higher production to increase revenue by $526 million. Net income for the quarter increased by $90 million, as the increased revenue more than offset the impact of increases in stock-based compensation, royalty and tax expenses.

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. The Company may hedge a portion of the volumes related to the Paladin acquisition. The impact of this new accounting standard on the Company’s results will be dependent on the level of additional volumes hedged.

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 August 30, 2005, the Court denied Talisman's motion for Court approval to appeal the Court's prior denial of Talisman's motion for judgment on the pleadings, which sought dismissal of the lawsuit. Also on August 30, 2005, the Court declined to dismiss the lawsuit in response 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. On September 20, 2005, the Court denied, for the second time, the plaintiffs' motion to certify the lawsuit as a class action. On October 5, the plaintiffs filed papers to appeal. The Company has filed papers opposing the plaintiffs’ appeal. 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 September 30				Nine months ended September 30
(C$ - production before royalties)		2005	2004 (1)	2005	2004	2005	2004 (1)	2005	2004
		Oil and liquids ($/bbl)		Natural gas ($/mcf)		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	60.92	45.47	9.15	6.63	51.86	41.46	7.98	6.77
America	Hedging	4.89	7.28	-	0.14	3.89	5.05	-	0.12
	Royalties	12.83	9.51	1.82	1.29	10.83	8.53	1.58	1.35
	Transportation	0.50	0.53	0.19	0.20	0.49	0.50	0.18	0.20
	Operating costs	7.22	6.64	0.96	0.81	6.87	6.40	0.88	0.79
		35.48	21.51	6.18	4.19	29.78	20.98	5.34	4.31
North Sea	Sales price	74.36	54.57	6.08	4.88	64.01	47.59	6.49	5.35
	Hedging	-	10.31	-	-	-	6.41	-	-
	Royalties	0.76	0.49	0.48	0.46	0.65	0.40	0.49	0.44
	Transportation	1.20	1.28	0.47	0.32	1.15	1.16	0.54	0.34
	Operating costs	17.33	16.57	0.68	0.69	17.15	14.58	0.75	0.49
		55.07	25.92	4.45	3.41	45.06	25.04	4.71	4.08
Southeast	Sales price	76.86	56.95	6.98	5.03	69.05	50.46	6.29	4.81
Asia	Royalties	28.73	23.37	2.14	1.39	27.29	21.01	1.93	1.19
	Transportation	0.27	0.20	0.42	0.40	0.20	0.24	0.40	0.42
	Operating costs	4.14	6.60	0.29	0.25	4.18	5.57	0.30	0.27
		43.72	26.78	4.13	2.99	37.38	23.64	3.66	2.93
Algeria	Sales price	72.00	63.98			66.27	53.03
	Royalties	27.37	20.15			25.95	20.12
	Transportation	1.62	1.79			1.65	1.81
	Operating costs	4.25	3.86			4.34	3.41
		38.76	38.18			34.33	27.69
Trinidad	Sales price	71.86	-			63.26	-
	Royalties	11.16	-			9.49	-
	Operating costs	2.83	-			3.13	-
		57.87	-			50.64	-
Total Company	Sales price	71.51	53.30	8.43	6.15	62.01	46.87	7.49	6.25
	Hedging	1.08	7.15	-	0.10	0.89	4.68	-	0.09
	Royalties	9.89	7.86	1.79	1.25	8.56	6.84	1.57	1.24
	Transportation	0.88	0.95	0.26	0.25	0.86	0.89	0.26	0.26
	Operating costs	11.60	11.58	0.79	0.68	11.63	10.49	0.74	0.66
		48.06	25.76	5.59	3.87	40.07	23.97	4.92	4.00

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 Netbacks (1)
(unaudited)

		Three months ended		Nine months ended
		September 30		September 30
(US$ - production net of royalties)		2005	2004 (2)	2005	2004 (2)
North	Oil and liquids (US$/bbl)
America	Sales price	50.69	34.78	42.46	31.22
	Hedging	5.16	7.06	4.03	4.78
	Transportation	0.53	0.51	0.51	0.48
	Operating costs	7.51	6.43	7.09	6.07
		37.49	20.78	30.83	19.89
	Natural gas (US$/mcf)
	Sales price	7.62	5.07	6.54	5.10
	Hedging	-	0.13	-	0.11
	Transportation	0.19	0.19	0.18	0.19
	Operating costs	1.00	0.77	0.90	0.74
		6.43	3.98	5.46	4.06
North Sea	Oil and liquids (US$/bbl)
	Sales price	61.92	41.76	52.44	35.83
	Hedging	-	7.96	-	4.87
	Transportation	1.01	0.99	0.95	0.88
	Operating costs	14.59	12.78	14.17	11.07
		46.32	20.03	37.32	19.01
	Natural gas (US$/mcf)
	Sales price	5.05	3.72	5.30	4.03
	Transportation	0.43	0.27	0.48	0.28
	Operating costs	0.62	0.59	0.66	0.41
		4.00	2.86	4.16	3.34
Southeast Asia	Oil and liquids (US$/bbl)
	Sales price	64.18	43.62	56.70	38.03
	Transportation	0.35	0.25	0.28	0.31
	Operating costs	5.48	8.56	5.66	7.19
		58.35	34.81	50.76	30.53
	Natural gas (US$/mcf)
	Sales price	5.81	3.85	5.15	3.62
	Transportation	0.50	0.43	0.48	0.42
	Operating costs	0.35	0.26	0.35	0.27
		4.96	3.16	4.32	2.93
Algeria	Oil (US$/bbl)
	Sales price	59.91	49.03	54.21	40.05
	Transportation	2.17	1.94	2.22	2.20
	Operating costs	5.68	4.18	5.84	4.14
		52.06	42.91	46.15	33.71
Trinidad	Oil (US$/bbl)
	Sales price	59.77	-	51.74	-
	Operating costs	2.79	-	2.99	-
		56.98	-	48.75	-
Total Company	Oil and liquids (US$/bbl)
	Sales price	59.56	40.80	50.81	35.31
	Hedging	1.04	6.40	0.85	4.11
	Transportation	0.85	0.85	0.82	0.78
	Operating costs	11.21	10.36	11.04	9.22
		46.46	23.19	38.10	21.20
	Natural gas (US$/mcf)
	Sales price	7.02	4.70	6.13	4.71
	Hedging	-	0.10	-	0.08
	Transportation	0.28	0.24	0.27	0.24
	Operating costs	0.84	0.65	0.77	0.62
		5.90	3.71	5.09	3.77

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.