Repsol Oil & Gas Canada 40F 2005 Annual report | TLM Filing

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Exhibit 99.5

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2005

March 13, 2006

TABLE OF CONTENTS

			Page
FORWARD-LOOKING STATEMENTS			1
NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION			2
EXCHANGE RATE INFORMATION			3
DEFINITIONS			3
CORPORATE STRUCTURE			4
GENERAL DEVELOPMENT OF THE BUSINESS			4
	North America		4
	International and Frontier		5
DESCRIPTION OF THE BUSINESS			6
	North America		6
		Canada	7
		United States	10
		Landholdings, Production and Productive Wells	10
	International and Frontier		11
		North Sea	11
		Southeast Asia and Australia	17
		North Africa	21
		Trinidad and Tobago	23
		Colombia	24
		Peru	24
		Qatar	25
		Alaska	25
		Other	25
	Productive Wells and Acreage		26
	Drilling Activity		27
	Reserves Estimates		30
	Other Oil and Gas Information		32
		Continuity of Net Proved Reserves	32
		Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves	34
		Results of Operations from Oil and Gas Producing Activities	37
		Capitalized Costs Relating to Oil and Gas Activities	38
		Costs Incurred in Oil and Gas Activities	39
		Product Netbacks (Net)	40
	Supplemental Oil and Gas Information		42
		Continuity of Gross Proved Reserves	42
		Product Netbacks (Gross)	44
	Additional Information		46
	Competitive Conditions		46
	Social Responsibility and Environmental Protection		46
	Employees		47
DESCRIPTION OF CAPITAL STRUCTURE			47
	Share Capital		47
	Ratings		47
MARKET FOR THE SECURITIES OF THE COMPANY			48
	Trading Price and Volume		48
DIVIDENDS			49
PRIOR SALES OF DEBT SECURITIES			49
DIRECTORS AND OFFICERS			49
	Directors		49
	Officers		52
	Shareholdings of Directors and Executive Officers		52
	Conflicts of Interest		53
AUDIT COMMITTEE INFORMATION			53
LEGAL PROCEEDINGS			53
RISK FACTORS			53
TRANSFER AGENTS AND REGISTRARS			56
INTERESTS OF EXPERTS			56
ADDITIONAL INFORMATION			56
SCHEDULE A – REPORT ON RESERVES DATA BY TALISMAN'S INTERNAL QUALIFIED RESERVES EVALUATOR			57
SCHEDULE B – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE			58
SCHEDULE C – AUDIT COMMITTEE INFORMATION			60

Unless the context indicates otherwise, a reference in this Annual Information Form to "Talisman" or the "Company" includes direct or indirect subsidiaries of Talisman Energy Inc. and partnership interests held by Talisman Energy Inc. and its subsidiaries. Consolidated information as at December 31, 2005 includes Paladin Resources Limited (formerly Paladin Resources plc) and its subsidiaries.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains or incorporates by reference statements that constitute forward-looking statements or forward-looking information (collectively "forward-looking statements") within the meaning of applicable securities legislation.

Forward-looking statements are included throughout this Annual Information Form including, among other places, under the headings "General Development of the Business", "Description of the Business", "Directors and Officers", "Legal Proceedings" and "Risk Factors". These statements include, among others, statements regarding:

•: business strategy and plans or budgets;
•: business plans for drilling, exploration and development;
•: the estimated amounts and timing of capital expenditures;
•: the estimated timing of development, including new production;
•: the anticipated schedule for commissioning of pipelines;
•: royalty rates and exchange rates;
•: planned asset dispositions and acquisitions and their timing;
•: the merits and timing or anticipated outcome of pending litigation; and
•: other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

Statements concerning oil and gas reserves contained in this Annual Information Form under the headings "Description of the Business – Reserves Estimates" and elsewhere 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. Often, but not always, forward-looking statements use words or phrases such as: "expects", "does not expect" or "is expected", "anticipates" or "does not anticipate", "plans" or "planned", "estimates" or "estimated", "projects" or "projected", "forecasts" or "forecasted", "believes", "intends", "likely", "possible", "probable", "scheduled", "positioned", "goals" or "objectives", or state that certain actions, events or results "may", "could", "would", "might" or "will" be taken, occur or be achieved.

Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking statements throughout this Annual Information Form. In particular, statements which discuss business plans for drilling, exploration and development in 2006 assume that the extraction of crude oil, natural gas and natural gas liquids remains economic. For the purposes of preparing this Annual Information Form, Talisman assumed a US$57/bbl West Texas Intermediate oil price, a US$9.00/mmbtu New York Mercantile Exchange natural gas price, a Canadian$/US$ exchange rate of 0.84 and a British £/Canadian$ exchange rate of 2.10.

Undue reliance should not be placed on forward-looking statements. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by Talisman 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;
•: the outcome and effects of completed acquisitions, as well as any future acquisitions and dispositions;

A N N U A L I N F O R M A T I O N F O R M1

•: the ability of the Company to integrate assets it has acquired or may acquire or the performance of those assets;
•: health, safety and environmental risks;
•: uncertainties as to the availability and cost of financing and changes in capital markets;
•: 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);
•: competitive actions of other companies, including increased competition from other oil and gas companies or companies providing alternative sources of energy;
•: changes to general economic and business conditions;
•: the effect of acts of, or actions against, international terrorism;
•: the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;
•: results of the Company's risk mitigation strategies, including insurance and any hedging programs; and
•: the Company's ability to implement its business strategy.

Readers are cautioned 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 is included under the heading "Risk Factors", in the Report on Reserves Data by Talisman's Internal Qualified Reserves Evaluator and the Report of Management and Directors on Oil and Gas Disclosure, (which reports are attached as schedules to this Annual Information Form), and elsewhere in this Annual Information Form. Additional information may also be found in the Company's other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (the "SEC").

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.

NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

National Instrument 51-101 ("NI 51-101") of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. NI 51-101 and its companion policy specifically contemplate the granting of exemptions from some of the disclosure standards prescribed by NI 51-101 to companies that are active in the United States ("US") capital markets to permit the substitution of the disclosures required by the SEC rules in order to provide for comparability of oil and gas disclosure with that provided by US and other international issuers. Talisman has obtained an exemption from Canadian securities regulatory authorities to permit it to provide disclosure in accordance with the relevant US requirements. Accordingly, most of the reserves data and other oil and gas information included in this Annual Information Form is disclosed in accordance with US disclosure requirements. Such information, as well as the information that Talisman discloses in the future in reliance on the exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.

The primary differences between the US requirements and the NI 51-101 requirements are that (i) SEC rules normally permit disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (ii) SEC rules require that the reserves and future net revenue be estimated under existing economic and operating conditions, whereas NI 51-101 requires disclosure of proved reserves and the associated future net revenue on a constant basis, and of proved, probable and proved plus probable reserves and the associated future net revenue on a forecast basis. The definitions of proved reserves differ, but Talisman does not believe that the differences in the definitions would result in any material difference in its reserves estimates for that category. The Canadian Oil and Gas Evaluation Handbook ("COGEH", the reference source for the definition of proved reserves under NI 51-101) states that the differences in the estimated proved reserves quantities based on constant prices should not be material.

Talisman has disclosed proved reserves (including continuity of reserves) using the standards contained in US Regulation S-X and the standardized measure of discounted future net cash flows from proved reserves determined in accordance with Statement No. 69 of the US Financial Accounting Standards Board ("FAS 69"). US practice is to disclose net proved reserves, after deduction of estimated royalty burdens and including net profit interests. In addition, notwithstanding that Talisman is not required to disclose probable reserves, it has done so using the definition for probable reserves set out by the Society of Petroleum Engineers/World Petroleum Congress ("SPE/WPC"). Talisman does not believe that the differences in the SPE/WPC and NI 51-101 definitions of probable reserves would result in any material difference in its estimates of probable reserves disclosed in this Annual Information Form.

2 A N N U A L I N F O R M A T I O N F O R M

EXCHANGE RATE INFORMATION

Except where otherwise indicated, all dollar amounts in this Annual Information Form are stated in Canadian dollars. The following table sets forth the US/Canada exchange rates on the last trading day of the years indicated as well as the high, low and average rates for such years. The high, low and average exchange rates for each year were identified or calculated from spot rates in effect on each trading day during the relevant year. The exchange rates shown are expressed as the number of US dollars required to purchase one Canadian dollar. These exchange rates are based on those published on the Bank of Canada's website as being in effect at approximately noon on each trading day (the "Bank of Canada noon rate").

	Year ended December 31
	2005	2004	2003

Year end	0.8577	0.8308	0.7738
High	0.8690	0.8493	0.7738
Low	0.7872	0.7159	0.6350
Average	0.8258	0.7697	0.7156

DEFINITIONS

The abbreviations set forth below have the following meanings:

	bbls		barrels
	bcf		billion cubic feet
	boe		barrels of oil equivalent
	bbls/d		barrels per day
	mbbls/d		thousand barrels per day
	mcf		thousand cubic feet
	mmbbls		million barrels
	mmbtu		million British Thermal Units
	mmcf/d		million cubic feet per day
	liquids or NGLs		natural gas liquids

Natural gas is converted to oil equivalent at the ratio of 6 mcf to 1 boe. The boe measure may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Gross acres means the total number of acres in which Talisman has a working interest. Net acres means the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Gross production means Talisman's interest in production volumes (through working interests, royalty interests and net profits interests) before the deduction of royalties. Net production means Talisman's interest in production volumes after deduction of royalties payable by Talisman.

Gross wells means the total number of wells in which Talisman owns a working interest. Net wells means the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

A N N U A L I N F O R M A T I O N F O R M3

CORPORATE STRUCTURE

Talisman Energy Inc. is incorporated under theCanada Business Corporations Act. The Company's registered and principal office is located at Suite 3400, 888 Third Street S.W., Calgary, Alberta T2P 5C5.

The following table sets forth the material operating subsidiaries owned directly or indirectly by Talisman, their jurisdictions of incorporation and the percentage of voting securities beneficially owned, controlled or directed by Talisman as at December 31, 2005.

Name of Subsidiary	Jurisdiction of Incorporation	Percentage of Voting Securities Owned¹

Talisman Energy (UK) Limited¹	England and Wales	100%
Talisman North Sea Limited	England and Wales	100%
Talisman (Corridor) Ltd.	Barbados	100%
Petromet Resources Limited	Ontario, Canada	100%
Fortuna Energy Inc.	Delaware, US	100%
Talisman Malaysia Limited	Barbados	100%
Talisman Expro Limited²	England and Wales	100%
Talisman Resources (Norway) Limited²	England and Wales	100%

Notes:

1: With the exception of Talisman Energy (UK) Limited, none of the above subsidiaries has any non-voting securities outstanding. All of the non-voting securities of Talisman Energy (UK) Limited are directly or indirectly held by Talisman.
2: Talisman Expro Limited and Talisman Resources (Norway) Limited are indirect subsidiaries acquired through the acquisition of Paladin Resources plc. See "General Development of the Business".

The above table does not include all of the subsidiaries of Talisman. The assets, sales and operating revenues of unnamed operating subsidiaries individually did not exceed 10%, and in the aggregate did not exceed 20%, of the total consolidated assets or total consolidated sales and operating revenues, respectively, of Talisman as at, and for the year ended, December 31, 2005.

Talisman Energy Inc. and Petromet Resources Limited ("Petromet"), an indirect subsidiary of Talisman, are partners in an Alberta general partnership named Talisman Energy Canada (the "Partnership"). Talisman is the managing partner of the Partnership. Substantially all of Talisman's Canadian oil and gas operations are carried on through the Partnership.

GENERAL DEVELOPMENT OF THE BUSINESS

Talisman is an independent, Canadian based, international upstream oil and gas company whose main business activities include exploration, development, production, transportation and marketing of crude oil, natural gas and natural gas liquids. The Company's reporting segments are North America, the North Sea, Southeast Asia and Australia, North Africa and Trinidad and Tobago, where there are ongoing production, development and exploration activities. The Company is active in a number of other international and frontier areas, including Alaska, Colombia, Gabon, Peru, Qatar and Romania.

During the past three years, Talisman has developed its business and diversified its interests through a combination of exploration, development, acquisitions and dispositions as described below. Internationally, the Company's exploration strategy is to pursue significant high impact opportunities to grow production and create shareholder value.

NORTH AMERICA

In January 2003, an indirect subsidiary of the Company acquired natural gas properties, working interests, production and facilities in New York State. The same subsidiary subsequently acquired all of Belden & Blake Corporation's Trenton-Black River assets in New York, Pennsylvania, Ohio and West Virginia in June 2004 resulting in ownership of approximately 433,000 additional gross acres. The June 2004 acquisition effectively doubled the subsidiary's existing net acreage held in the area. The indirect subsidiary of the Company currently owns approximately 978,000 gross acres.

In July 2003, a subsidiary of Talisman acquired various midstream assets in the Deep Basin area of northwestern Alberta through the purchase of Vista Midstream Solutions Ltd.

In March 2005, the Partnership and a Talisman subsidiary collectively acquired the securities of a partnership now known as Talisman Findley Partnership, which increased the working interests in sixty-three wells in the Alberta Foothills on average from 15% to 57% and added approximately 128,000 gross undeveloped acres in the northern portion of the Alberta Foothills.

4 A N N U A L I N F O R M A T I O N F O R M

INTERNATIONAL AND FRONTIER

In March 2003, Talisman completed the sale of its indirect interest in the Greater Nile Oil Project in Sudan to ONGC Videsh Limited, a subsidiary of India's national oil company. An indirect subsidiary of Talisman had held a 25% interest in the Greater Nile Oil Project, which had been acquired in 1998.

In 2003, first oil sales began from the Ourhoud field (Talisman 2%) in Algeria. In June 2003, production commenced from the Greater MLN field (Talisman 35%).

In 2003, the Company completed the PM-3 Commercial Arrangement Area ("PM-3 CAA") Phase 2/3 Development Project offshore Malaysia/Vietnam. Oil production from this project began in September 2003 and gas production and sales commenced in November 2003. Talisman Malaysia Limited signed a production sharing contract in March 2004 for Block PM-314 offshore Malaysia.

In December 2003, Talisman's subsidiary acquired additional interests in the Ross, Renee and Rubie fields in the United Kingdom sector of the North Sea ("UK North Sea"). In early 2004, a Talisman subsidiary acquired an operated interest in the Galley field in the UK North Sea. In May 2004, Talisman's subsidiaries acquired additional interests in the Flotta Catchment Area. In a separate transaction completed in November 2004 the subsidiary acquired additional interests in the Buchan area and also reduced its interest in the MacCulloch field. In 2005, the Company acquired minor additional interests in non-operated assets in the UK North Sea.

In September 2003, one of Talisman's subsidiaries acquired the operated interests and associated assets of BP Norge AS in the Gyda field in the Norwegian sector of the North Sea (the "Norwegian North Sea"). Two additional licenses were awarded later in 2003. In February 2004, Talisman's subsidiary acquired an interest from ConocoPhillips Skandinavia AS in two more licences, including the Blane discovery. In December 2004, the subsidiary was awarded interests in five more licences in the Norwegian North Sea.

In 2003, the Company began the Angostura development project in Trinidad and Tobago on offshore Block 2(c). Development continued through 2004 with production beginning in January 2005. Plans to develop gas on Block 2(c) are underway. Exploration is continuing in the onshore Eastern Block and in the offshore Howler assessment area and Block 3(a).

Talisman announced in August 2004 an agreement for the sale of 2.3 trillion cubic feet of natural gas from the Corridor production sharing contract in Indonesia. Talisman's subsidiary has a 36% interest in the production sharing contract.

In the fourth quarter of 2004, Talisman Energy (UK) Limited acquired all of the outstanding shares of Intrepid Energy Beta Limited, which included an interest in a number of exploration licenses in the United Kingdom, Netherlands and German sectors of the North Sea.

Through separate transactions occurring in 2004 and 2005, a subsidiary of Talisman acquired interests in over 450,000 gross acres of land in the North Slope of Alaska.

In February 2005, Talisman Energy (UK) Limited acquired all of the outstanding shares in Pertra AS ("Pertra"), now Talisman Production Norge AS, resulting in the addition of producing and undeveloped fields in the Varg area, as well as several blocks of operated and non-operated exploration acreage in the Norwegian North Sea.

In April 2005, Talisman Vietnam 15-2/01 Ltd., a Talisman subsidiary, signed a petroleum contract for Block 15-2/01 offshore Vietnam. The subsidiary holds a 60% interest in the Block, which is comprised of 700,000 acres offshore Vietnam.

In June 2005, a Talisman subsidiary acquired a non-operated interest in the producing Brage and Sognefjord fields in the Norwegian North Sea.

Also in June 2005, a Talisman subsidiary was granted additional acreage along the south-eastern border of Block PM-3 CAA offshore Malaysia/Vietnam. In August 2005, oil production commenced from the South Angsi field in Block PM-305 offshore Malaysia.

On October 20, 2005, Talisman reached an agreement with Paladin Resources plc (now Paladin Resources Limited and referred to as "Paladin"), a public United Kingdom based oil and gas exploration and production company, on the terms of a cash offer by a wholly owned subsidiary of Talisman, for all of the shares of Paladin at an aggregate price of approximately £1,218 million. On November 18, 2005, Talisman effectively acquired control of Paladin pursuant to the offer, and subsequently acquired all remaining shares of Paladin. The acquisition of Paladin continues Talisman's North Sea strategy and provides the Company with additional international opportunities that management believes are well suited to Talisman's operating style and skills. Paladin's portfolio of production and exploration assets (predominantly located in the Norwegian, United Kingdom and Danish sectors of the North Sea, as well as Australia, Indonesia and Tunisia) are integrated under the heading "Description of Business."

Talisman announced in December 2005 that it intends to dispose of approximately 10,000 to 15,000 boe/d of production from non-core assets in Western Canada and the North Sea by mid-2006. Third party advisors have been engaged to further discussions with potential purchasers of these assets.

A N N U A L I N F O R M A T I O N F O R M5

In February 2006, Talisman reached an agreement to enter into exclusive negotiations to acquire approximately an 86% interest in the Fulmar field and a 100% interest in the Auk field, both located in the Central North Sea. The completion of this transaction is subject to agreement of final terms and receipt of co-venturer and government approvals.

Since 2002, Talisman, through various subsidiaries, has acquired non-operated interests in several blocks of exploration acreage in the Andean fold and thrust belts of Colombia and Peru. In 2005, the Company continued its ongoing exploration program on this acreage. Subsequent to year end, Talisman announced that its subsidiary had participated in an oil discovery in Block 64 in the Marañon Basin in Peru. The Company is currently evaluating options in Peru, including additional drilling.

In February 2006, a subsidiary of the Company concluded a joint venture agreement for various interests in Alaska. The Company was also advised in March 2006 that its bid for an additional 119,680 acres in the Smith Bay Area of Alaska had been successful, subject to government approval.

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

DESCRIPTION OF THE BUSINESS

Talisman is one of the largest independent oil and gas producers in Canada. The Company's main business activities include exploration, development, production, transportation and marketing of crude oil, natural gas and natural gas liquids. Each of Talisman's current areas of operations has exploration and development potential, which Talisman expects will provide future growth.

All information in this section relating to assets owned or held by Talisman is as of December 31, 2005, unless otherwise indicated. Activity for 2005 includes activity of Paladin and its subsidiaries only from the date of acquisition (November 18, 2005).

NORTH AMERICA

Talisman anticipates that it will spend approximately $2.0 billion on exploration and development in Canada and the US in 2006. (Exploration in Alaska is not currently managed through the North America management group and therefore does not form part of these expenditures.) Of this, over 92% is expected to be directed towards development of natural gas opportunities. The Company plans to participate in drilling approximately 685 gross wells in 2006.

In the past three years, the Company's production growth has been achieved mainly through drilling activities. The Company intends to dispose of approximately 10,000 to 15,000 boe/d of production from non-core assets in Western Canada and the North Sea by mid-2006. Additional strategic asset acquisitions and dispositions will be evaluated throughout the year.

6 A N N U A L I N F O R M A T I O N F O R M

CANADA

In Canada, the Company's strategy is to continue oil and natural gas exploration and development by exploring a diverse range of opportunities that capitalize on previous successes in several deep gas plays throughout the Western Canada Sedimentary Basin ("WCSB"). Talisman expects to spend a significant portion (20%) of its 2006 capital program on higher-risk/higher-reward technical thrust belt plays (Monkman and Alberta Foothills) and 32% on multi-zoned scalable plays (Bigstone/Wild River, Edson and West Whitecourt). Talisman anticipates that utilization of existing infrastructure and a high level of operatorship will continue to enable Talisman to maintain control over costs, production and capital spending.

Exploration and development activities will focus on medium to deep gas opportunities in the WCSB to take advantage of Talisman's expertise in these areas. The majority of this activity is expected to be in the Edson area, Alberta Foothills, Greater Arch, Monkman/BC Foothills, Deep Basin and Southern Alberta Foothills. Talisman employs a "total rock volume" approach which the Company believes can add substantially to the overall reserves and production life, and to a lesser extent, increase well productivity to complement existing conventional plays. A multi-disciplinary team has been set up with a mandate to identify new conventional and unconventional plays in the WCSB.

Talisman's Canadian exploration and development operations are organized around 13 core producing areas in Alberta, British Columbia, Ontario and Saskatchewan, which accounted for 93% of the Company's Canadian production in 2005. The balance comprises production from joint venture properties and synthetic oil production from Talisman's 1.25% indirect interest in the Syncrude joint venture. Of the 13 core areas the following seven are the principal gas production areas: Edson area (in turn comprised of Bigstone/Wild River, Edson and West Whitecourt), Alberta Foothills, Greater Arch, Monkman/BC Foothills, Deep Basin, Lac La Biche and Ontario offshore. The following seven core areas are the principal oil production areas: Chauvin, Carlyle, Greater Arch, Shaunavon, Southern Alberta Foothills, Ontario onshore and Central Alberta. Within its core areas, Talisman operates approximately 80% of its production with high working interests in a large number of facilities.

Seven of the more active core areas accounted for approximately 79% of the Company's total Canadian production in 2005: Alberta Foothills, Edson area, Greater Arch, Deep Basin, Monkman/BC Foothills, Southern Alberta Foothills and Chauvin. Each of these areas is described in greater detail below.

A N N U A L I N F O R M A T I O N F O R M7

Alberta Foothills

Alberta Foothills is Talisman's largest natural gas producing area. Major operated facilities in the Alberta Foothills area include an 80% interest in the Cordel dehydration facility and associated pipelines, interests ranging from 62% to 100% in the Erith pipeline and related facilities, a 58% interest in the Lovett River/Redcap pipeline system and a 39% interest in the Chungo/Bighorn gas gathering system. Talisman has non-operated interests in Basing, Voyager, Stolberg and Brown Creek pipelines and associated facilities. Talisman currently has over 50 mmcf/d sales gas (Company share) awaiting completion of infrastructure in the northern portion of the Alberta Foothills. Two major Midstream pipeline projects, Lynx and Palliser, are expected to be commissioned in 2006. Construction started in mid October 2005 on the 72 kilometre Lynx Pipeline (Talisman 45%), which will gather up to 130 mmcf/d of sour gas from the Greater Grande Cache area. In the Palliser area, construction is underway on a 45 mmcf/d pipeline system (Talisman 100%), which will deliver gas into the Duke Grizzly system. The Company expects that capital spending in 2006 in the Alberta Foothills area will be approximately $306 million. Of this amount, approximately $105 million will be spent on infrastructure and participation in drilling 35 wells. The northern portion of the Alberta Foothills accounts for sixty percent of the expected capital spending and two-thirds of the wells expected to be drilled.

Edson Area

The properties comprising the larger Edson area (Bigstone/Wild River, Edson and West Whitecourt) are detailed below. Capital spending in the Edson area in 2006 is expected to be approximately $644 million, which includes plans to participate in drilling 249 wells and includes approximately $102 million for infrastructure.

Bigstone/Wild River

Talisman holds operated interests ranging from 64% to 100% in the Bigstone West and Wild River gas plants. The Company is continuing to focus on infill drilling in the Wild River area. The Company expects that capital spending in 2006 in the Bigstone/Wild River area will be approximately $278 million and plans to participate in drilling 99 wells, 86% of which will be drilled in the Wild River area.

Edson

Talisman holds operated interests ranging from 59% to 100% in the Edson and Medicine Lodge gas plants and a 100% interest in the Edson plant cogeneration facility. Talisman is currently focusing on exploring and exploiting opportunities identified in 2005 in the Edson core area. The Company expects that capital spending in 2006 in the Edson core area will be approximately $274 million and plans to participate in drilling 95 wells.

West Whitecourt

Talisman holds a 51% operated interest in the McLeod River gas plant as well as non-operated interests ranging from 10% to 12% in the Kaybob South Amalgamated and the West Whitecourt gas plants. Talisman is continuing to focus on development drilling in the West Whitecourt area. Additional compression and line looping are required to increase the gas production from the area. The Company expects that capital spending in 2006 in the West Whitecourt area will be approximately $92 million and plans to participate in drilling 55 wells.

Greater Arch

The Greater Arch is Talisman's second largest natural gas producing area. Talisman holds operated interests ranging from 42% to 100% in gas plants at Teepee Creek, Belloy, Boundary Lake, George and Josephine, as well as interests in a number of other non-operated gas plants in the area. The Company has a large inventory of opportunities to explore which are adjacent to existing infrastructure. Talisman's average operated interest in oil and gas properties in the Greater Arch area is 82%. The Company expects that capital spending in 2006 in the Greater Arch area will be approximately $168 million and plans to participate in drilling 84 wells.

Deep Basin

Talisman holds a 50% to 100% working interest in the Cutbank complex, consisting of the Cutbank and Musreau A and B gas plants, five major field compression stations and an extensive gas gathering system, all of which ran close to capacity throughout 2005. Talisman also holds 7% to 8% non-operated interests in the South Wapiti, Wapiti Deep Cut and Narraway gas plants. In November 2005, Talisman tied-in a successful gas well in this area which produced at a rate of up to 18 mmcf/d sales gas (Company share) at year end. The Company expects that capital spending in 2006 in the Deep Basin area will be approximately $161 million and plans to participate in drilling 34 wells along the prospective multi-zone exploration fairway.

Monkman/BC Foothills

In the Monkman/BC Foothills area, Talisman holds 55% to 77% operated interests in the Bullmoose, Sukunka and West Sukunka dehydration plants, 29% to 32% non-operated interests in the Murray River and Brazion dehydration plants and a 50% interest in the Mink Highhat Gathering System. In

8 A N N U A L I N F O R M A T I O N F O R M

2004, Talisman drilled the b-60-E/93-P-5 well ("b-60-E") in the Brazion area, which produced an average 39 mmcf/d sales gas (Company share) or 49 mmcf/d gross sales gas in 2005 and on March 7, 2005 it attained its maximum production of approximately 58 mmcf/d sales gas (Company share) or 72 mmcf/d gross sales gas. In the fourth quarter of 2005, Talisman tested two Triassic wells, which in combination, tested at 42 mmcf/d gross raw gas. Both wells are expected to be tied-in in 2006. The Company expects that capital spending in 2006 in the Monkman/BC Foothills area will be approximately $104 million and plans to participate in drilling seven wells, two of which are deep wells.

Southern Alberta Foothills

Talisman holds a 100% interest in the Little Chicago gas plant and 76% to 100% interests in the Turner Valley Units 3, 4, 5 and 7. In 2005, a successful multi-leg horizontal oil well drilling program in Turner Valley was completed. The three-year experimental nitrogen injection project is now complete. The Company expects that capital spending in 2006 in the Southern Alberta Foothills area will be approximately $74 million and plans to participate in drilling 17 wells.

Chauvin

Chauvin is Talisman's largest domestic oil producing property. Talisman also has a 100% interest in the Chauvin Custom Treating Facility. The Company expects that capital spending in 2006 in the Chauvin area will be approximately $40 million and plans to participate in drilling 49 wells.

Other

In Ontario, Talisman currently has natural gas production offshore Lake Erie and oil production onshore. Talisman has a 100% interest in the Renwick, North Wheatley (East), Rochester and Hillman central facilities. In addition, Talisman holds interests ranging from 65% to 100% in the Morpeth, Port Stanley, Port Alma, Port Maitland, Rochester and Nanticoke gas plants. The Company expects that capital spending in 2006 in Ontario will be approximately $17 million and plans to participate in drilling five onshore oil wells and 25 offshore gas wells.

In 2004, Talisman drilled a successful gas well in Central Alberta, which tested at 18 mmcf/d gross raw gas. Production from this well commenced at approximately 15 mmcf/d sales gas (Company share) in the first quarter of 2005 and averaged 14 mmcf/d sales gas (Company share) throughout 2005. Follow up drilling to this well has not been successful; however, evaluation of this play is still ongoing. The Company expects that capital spending in 2006 in the Central Alberta area will be approximately $10 million and plans to participate in drilling 11 wells.

The Company is exploring the potential for producing coal bed methane on existing lands in Alberta. Appraisal drilling and prospect evaluation commenced in 2002. The main focus in 2006 will continue to be the development of coal bed methane horizontal drilling and production technology to determine large-scale commercial viability within the Mannville formation. The Company expects that capital spending in 2006 in this area will be approximately $53 million and plans to participate in drilling 35 wells.

In Quebec, Talisman entered into two farm-in agreements and an option to purchase agreement in 2005 to gain access to approximately 900,000 gross acres. In the first farm-in agreement, Talisman has committed to drill a well in the first half of 2006 to earn an exploration permit of approximately 33,000 gross acres and the option to earn an interest in the remaining 153,000 gross acres. The second farm-in agreement requires Talisman to commence a 2D seismic program in the first quarter of 2006 for an opportunity to earn an interest in approximately 712,000 gross acres. The option to purchase agreement provides the opportunity to acquire a further interest in approximately 17,300 gross acres (a portion of the acreage included in the second farm-in agreement). The Company expects that capital spending in 2006 in Quebec will be approximately $6 million.

Talisman Midstream Operations

The Company's Midstream Operations operates over 769 kilometres of gathering pipelines, interconnected with multiple processing plants and downstream pipelines with an average throughput of approximately 420 mmcf/d in 2005. The Company's 100% owned Central Foothills Gas Gathering System, the Columbia Minehead Gas Gathering System, and other midstream pipeline and processing assets ranging from 50% to 100% ownership, support the exploration and development programs in the Alberta Foothills, Edson and Deep Basin areas and also provide transportation and processing revenues. The Company spent approximately $71 million in 2005 to expand and optimize midstream assets as well as initiate the development of the Lynx, Medlodge, and Palliser pipelines that will add approximately 130 kilometres of gathering system and connect the northern portion of Alberta Foothills gas to markets. Talisman expects that capital spending in 2006 will be approximately $123 million which includes plans to complete the Palliser and Lynx pipeline systems and to expand and optimize the remaining midstream systems in 2006.

Synthetic Oil

Talisman holds a 1.25% indirect interest in the Syncrude oil sands project (the "Syncrude Project") through the Canadian Oil Sands Limited Partnership. The Syncrude Project is a joint venture established to recover shallow deposits of tar sands using open pit mining methods in order to extract the crude bitumen and to upgrade it to a high-quality, light (32° API) sweet, synthetic crude oil. The upgrading process uses a combination of delayed coking and hydrotreating technologies to produce a synthetic crude oil that appropriately equipped refineries can use as a feedstock. The

A N N U A L I N F O R M A T I O N F O R M9

Syncrude Project, located near Fort McMurray, Alberta, exploits portions of the Athabasca oil sands deposit to produce Syncrude Sweet Blend®. Syncrude is in the final phases of the third stage of a large expansion program. Stage 3 is expected to cost $8.4 billion to increase capacity from the current level of 90 mmbbls/year to approximately 128 mmbbls/year. The expansion is expected to startup in early 2006 with production increasing to full capacity by 2008. Talisman expects that its capital spending in 2006 related to the Syncrude Project, including expansion and sustaining capital, will be approximately $9 million.

UNITED STATES

Fortuna Energy Inc. ("Fortuna"), a subsidiary of Talisman, operates in the Appalachia area of upstate New York. Fortuna holds a 100% operated interest in the Pinehill and Catlin Hill dehydration facilities as well as a 49% to 100% interest in a number of operated meter stations and pipelines. Fortuna increased production primarily from deep horizontal Trenton-Black River formation gas wells in the Appalachia area (upstate New York) from 60 mmcf/d sales gas (Company share) in 2003 to 105 mmcf/d sales gas (Company share) in 2005. Fortuna expects that capital spending in 2006 in the Appalachia area will be approximately $109 million and plans to participate in drilling 40 wells.

Talisman's subsidiary, Fortuna (US) L.P., continues to explore for oil and gas in the western US. Fortuna (US) L.P. expects its capital spending in 2006 in the US will be approximately $45 million and plans to participate in drilling up to four wells.

LANDHOLDINGS, PRODUCTION AND PRODUCTIVE WELLS

The following tables set forth Talisman's North American landholdings, production and productive wells as at December 31, 2005.

NORTH AMERICA Property			Developed Acreage (thousand acres)		Undeveloped Acreage (thousand acres)		Total Acreage (thousand acres)

			Gross	Net	Gross	Net	Gross	Net

North America
	Canada
		Alberta Foothills	159.2	76.5	527.6	315.1	686.8	391.6
		Edson Area	964.9	493.9	828.0	566.1	1,792.9	1,060.0
		Greater Arch	714.8	337.5	1,281.1	897.9	1,995.9	1,235.4
		Deep Basin	261.8	66.3	520.7	341.2	782.5	407.5
		Monkman/BC Foothills	77.8	41.6	770.7	470.3	848.5	511.9
		Southern Alberta Foothills	30.5	25.1	135.5	100.4	166.0	125.5
		Chauvin	98.7	80.1	82.2	44.6	180.9	124.7
		Other¹	1,115.7	708.4	4,315.4	1,502.3	5,431.1	2,210.7
	United States²		31.9	28.3	1,580.0	1,266.1	1,611.9	1,294.4

Total³			3,455.3	1,857.7	10,041.2	5,504.0	13,496.5	7,361.7

Synthetic Oil			13.5	2.3	474.7	84.3	488.2	86.6

Notes:

1: "Other" includes Ontario and minor properties in Canada, but excludes Scotian Slope, synthetic oil and coal leases in British Columbia.
2: "United States" excludes Alaska.
3: Fee acreage comprises 4% of total gross number of acres and 5% of the net number of acres. Fee acreage for Gross Undeveloped totals 556.5; Gross Developed totals 66.1; Net Undeveloped totals 368.5; and Net Developed totals 22.1.

10 A N N U A L I N F O R M A T I O N F O R M

NORTH AMERICA Property			Oil & Liquids Production (bbls/d)		Natural Gas Production (mmcf/d)		Productive Wells^1,2,3 as at December 31, 2005

			Gross⁴	Net⁴	Gross⁵	Net⁵	Gross	Net

North America
	Canada
		Alberta Foothills	207	147	147.1	112.4	226	99.9
		Edson Area	4,992	3,695	234.8	187.6	1,223	850.7
		Greater Arch	7,741	6,174	138.5	108.0	1,433	786.8
		Deep Basin	1,508	1,357	44.9	33.6	539	110.7
		Monkman/BC Foothills	–	–	103.6	84.0	69	40.8
		Southern Alberta Foothills	2,914	2,391	20.0	15.5	255	172.3
		Chauvin	16,132	13,595	16.0	12.8	1,992	1,330.4
		Other⁶	20,117	15,254	105.1	89.0	4,864	2,255.3
	United States⁷		–	–	104.7	89.7	56	50.0

Total			53,611	42,613	914.7	732.6	10,657	5,696.9

Synthetic Oil			2,693	2,587	–	–	–	–

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Includes wells containing multiple completions as follows:

	Oil Wells	Gas Wells

Gross	558	1,205
Net	292.6	654.3

3: One or more completions in the same bore hole is counted as one well. A well is classified as an oil well if one of the multiple completions in a given well is an oil completion.
4: Includes approximately 741 bbls/d of liquids attributable to royalty interests and net profits interests.
5: Includes approximately 10.7 mmcf/d of gas attributable to royalty interests and net profits interests.
6: "Other" includes Ontario and minor properties in Canada.
7: "United States" excludes Alaska.

INTERNATIONAL AND FRONTIER

Talisman's international and frontier strategy focuses on opportunities in sedimentary basins that have a proven hydrocarbon system with significant reserves, production and exploration potential.

Talisman produces substantial oil and gas volumes from the North Sea (which includes the United Kingdom, Norwegian, Netherlands, Danish and German sectors), with ongoing exploration and development activities in the area. Talisman is active in Southeast Asia and Australia, which includes Indonesia, Malaysia, Vietnam, Papua New Guinea and Australia. In addition to the current oil and gas production in this region, development projects are expected to result in significant oil and gas production growth. Talisman has producing interests in North Africa (Algeria and Tunisia) and in Trinidad and Tobago. The Company also has exploration interests in other areas including Alaska, Colombia, Gabon, Peru, Qatar and Romania.

NORTH SEA

Talisman's North Sea strategy is to develop commercial hubs around core operated properties and infrastructure and to deliver growth by extending the life of these assets through low risk development opportunities, sub-sea tie-back developments, exploration, secondary recovery, cost reduction and increased third-party tariff revenue. The Company also has a portfolio of non-operated assets.

Talisman's North Sea assets, which are held principally by Talisman Energy (UK) Limited, Talisman North Sea Limited and Talisman Energy Norge AS, include producing fields and exploration acreage in several areas of the North Sea. Talisman's North Sea interests also include those assets acquired through the purchase of Paladin, which are held primarily through Talisman Expro Limited in respect of assets in the UK North Sea, through Talisman Resources (Norway) Limited and Paladin Resources Norge AS in respect of assets in the Norwegian North Sea and through Talisman Oil Denmark Limited in respect of assets in the Danish sector of the North Sea. Talisman has three core North Sea operating areas: the Mid-North Sea Area ("MNS Area"), the Flotta Catchment Area ("FCA Area") and Norway. In addition, Talisman has operated and non-operated interests and a number of new venture exploration licences acquired through the purchase of Paladin. At the end of 2005, Talisman operated approximately 67% of its North Sea production.

In 2006, Talisman's capital program in the North Sea is expected to be approximately $1.6 billion, with $277 million directed to exploration spending and $1,338 million directed to development (net of deferred acquisition costs). The Company's 2006 North Sea drilling program includes participation in up to 19 exploration and 45 development wells. Capital expenditures are also directed at a number of field development programs

A N N U A L I N F O R M A T I O N F O R M11

that are expected to significantly increase production in 2007 and 2008. The Company intends to dispose of approximately 10,000 to 15,000 boe/d of production from non-core assets in Western Canada and the North Sea by mid-2006.

In February 2006, Talisman reached an agreement to enter into exclusive negotiations with Shell U.K. Limited and Esso Exploration and Production UK Limited to acquire approximately 86% (combined) interest in the Fulmar field (Blocks 30/11b and 30/16s) and 100% interest in the Auk field (Blocks 30/16n and 30/16t). The transaction is conditional on agreement of the final terms and receipt of co-venturer and government approvals. If the transaction is completed, Talisman is expected to assume operatorship in 2006.

MNS Area Properties

Talisman holds interests ranging from 13% to 100% in a number of production facilities and pipelines in the MNS Area.

Clyde Area

The Company owns various operated interests in the Clyde area, including a 95% operated interest in the Clyde field and production platform, a 94% operated interest in the Orion field and a 13% non-operated interest in the Fulmar field. In 2005, Talisman drilled two development wells in the Clyde area. In February 2005, operations were completed on the Jenny exploration well at Block 30/13c with the wellbore plugged and abandoned after minor oil shows. Talisman made an oil discovery by drilling the Medwin Terrace exploration prospect. The Company expects that capital spending in 2006 in the Clyde area will be approximately $118 million. The 2006 development program includes drilling three wells, plus the implementation of a produced water reinjection program ("PWRI") to meet water emission regulations expected to become effective January 1, 2007. Talisman will also be participating in one exploration well in the area.

Buchan Area

The Company holds an average 99% operated working interest in the Buchan field, the Hannay field, the Buchan floating production platform and the tie-in to the Forties pipeline. In October 2002 and November 2003, Talisman drilled two exploration wells, resulting in new oil discoveries adjacent to the Buchan field. Talisman holds a 94% interest in the discovered Tweedsmuir and Tweedsmuir South fields. The Tweedsmuir development continued through 2005 with the drilling of three development wells (including two injection wells) and the installation of subsea and

12 A N N U A L I N F O R M A T I O N F O R M

platform facilities. The development is planned for completion in 2006 with first oil production expected in the first quarter of 2007. At year end 2005, the Company was participating in an exploration well that was subsequently plugged and abandoned in January 2006. The Company expects that capital spending in 2006 in the Buchan area will be approximately $424 million and includes plans to drill two exploration prospects.

Ross/Blake Area

In the Ross/Blake area, Talisman holds a 69% operated working interest in the Ross field and a 54% non-operated interest in the Blake field, both fields being sub-sea tie-backs to Bleo Holm, the leased Floating, Production, Storage and Offloading vessel ("FPSO"). During 2005, significant modifications were made to the FPSO to address calcium naphthenate build-ups which occurred early in the year. In late 2005, Talisman assumed operatorship of the FPSO. In November 2005, Talisman made an oil discovery at the 100% owned Blake Terrace prospect. The Company expects that capital spending in 2006 in the Ross/Blake area will be approximately $31 million and plans to drill one development well in the Blake area and to participate in up to four exploration wells.

Beatrice Area

Talisman holds a 100% operated interest in the Beatrice Alpha, Bravo and Charlie platforms, as well as the Beatrice/Nigg pipeline and the Nigg terminal. In 2005, Talisman commenced construction of an offshore wind farm demonstrator project adjacent to the Beatrice fields, which is expected to start up in the third quarter of 2006. The Company expects development spending in 2006 in the Beatrice area will be approximately $58 million and plans to implement a PWRI program and to install additional downhole pumping capacity.

Other MNS Area Properties

Talisman holds a 60% operated interest in the Beauly field located in Block 16/21c of the MNS. No capital spending is planned for the Beauly area in 2006.

Flotta Catchment Area

Talisman presently holds interests ranging from 14% to 100% in a number of production facilities and pipelines in the FCA Area, including an 80% interest in the Flotta terminal.

Piper Area

Talisman presently holds an 80% operated working interest in the Piper, Saltire, Chanter and Iona fields and a 14% non-operated interest in the MacCulloch field. In 2005, an unsuccessful exploration well was drilled on the North Saltire prospect. The Company expects that capital spending in 2006 in the Piper area will be approximately $39 million and plans to drill one development well on the Chanter field. In addition, modifications will be made to the Piper platform as part of the Tweedsmuir development.

Claymore Area

Talisman holds a 72% to 100% operated working interest in the Claymore field and an 80% operated working interest in the Scapa field. In 2005, Talisman drilled two development wells on the Claymore field. The Company expects that capital spending in 2006 in the Claymore area will be approximately $84 million, which includes funding for three development wells, gas compression modifications and a PWRI program.

THP Area

Talisman's subsidiary holds a 100% operated working interest in the Tartan field and in the Highlander and Petronella sub-sea tie-back satellite fields; and a 67% operated interest in the Galley field (collectively, "THP Area"). In 2005, Talisman drilled three development wells and one unsuccessful exploration well in the THP Area. The Company expects that capital spending in 2006 in the THP Area will be approximately $101 million and plans to drill one exploration and two development wells. In addition, Talisman intends to develop the Duart North field, the Tartan "Hot Lens" sands and redevelop the Galley field.

Other FCA Area Properties

Talisman's subsidiary holds a 78% and 41% operated working interest in the Renee and Rubie fields, respectively. Both fields are sub-sea tie-backs to the Ivanhoe/Rob Roy field in which Talisman has a 23% non-operated interest. Capital spending by the Company in other FCA Area properties in 2006 is expected to be minimal.

A N N U A L I N F O R M A T I O N F O R M13

Paladin UK Properties

Through the acquisition of Paladin, a Talisman subsidiary holds interests ranging from 20% to 59% in a number of additional production facilities and pipelines in the UK North Sea.

Montrose/Arbroath Area

Talisman's subsidiary holds a 59% operated working interest in each of the Arbroath, Arkwright, Brechin, Montrose and Wood fields acquired through the Paladin acquisition. In 2006, Talisman plans to develop the Wood field with first oil production expected in 2007. The Company expects that capital spending in 2006 in the Montrose/Arbroath Area will be approximately $200 million which includes plans to drill one exploration well and five development wells.

Other Paladin UK Properties

Talisman's subsidiary holds a 25% operated interest in each of the Blane (UK) and Enoch fields and a 52% operated interest in the Fiddich field acquired through the Paladin acquisition. The Company expects that capital spending in 2006 on these properties will be approximately $107 million and plans to participate in drilling four development wells (three of which are shared with the "Other Norway Properties" section below). In addition, Talisman plans to develop the Blane and Enoch fields with first oil production from both fields expected in early 2007.

Norway Properties

Talisman's subsidiaries hold interests ranging from 1% to 70% in a number of production facilities and pipelines in Norway. The principal areas include the Gyda and Varg fields.

Gyda Area

Talisman's subsidiary holds a 61% operated interest in the Gyda field and associated assets. In 2005, the Company drilled two development wells. The Company expects that capital spending in 2006 in the Gyda area will be approximately $154 million and plans to drill up to five exploration and two development wells. In addition, Talisman plans to install gas lift facilities and to implement a PWRI program.

Varg Area

Talisman's subsidiaries hold operated interests ranging from 65% to 70% in the Varg area and associated assets. In February 2005, Talisman Energy (UK) Limited acquired all of the outstanding shares of Pertra, resulting in the addition of the producing Varg field and undeveloped Varg South field as well as several blocks of operated and non-operated exploration acreage. Subsequent to this purchase, Talisman's subsidiary disposed of a minor portion of the interests acquired in the Varg field. The Company drilled four development wells (including one injection well) in the Varg field in 2005. The Company expects that capital spending in 2006 in the Varg area will be approximately $90 million and plans to drill one development well and to commence development of the Varg South field with first production expected in the fourth quarter of 2007.

Other Norway Properties

Talisman's subsidiaries hold 18% and 70% operated interests in the Blane (Norway) and Yme fields, respectively and 35%, 34%, 27% and 1% non-operated interests in the Sognefjord, Brage, Veslefrikk and Huldra fields, respectively. The majority of these interests were acquired through the acquisition of Paladin. In 2005, the Company drilled one unsuccessful exploration well and spudded another, which was subsequently abandoned in early 2006. The Company expects that capital spending in 2006 in these areas will be approximately $148 million and plans to participate in drilling three exploration wells and seven development wells (three of which are shared with the "Other Paladin UK Properties" section above).

In the Danish sector of the North Sea, Talisman acquired a 30% non-operated working interest in the Siri field through the Paladin acquisition. The Company expects that capital spending in 2006 will be $13 million and plans to participate in drilling one development well.

Non-Operated Interest Properties

Brae Area

Talisman's non-operated producing interests in the Brae area range from 13% to 18%. Talisman also holds a 9% non-operated interest in the Brae-St. Fergus gas pipeline and terminal. In 2005, Talisman participated in three development wells in the Brae area. The Company expects that capital spending in 2006 in the Brae area will be approximately $19 million and plans to participate in drilling six development wells.

Other Non-Operated Interest Properties

Talisman's subsidiaries hold various non-operated producing interests in the following fields in the United Kingdom: Balmoral (15%), Stirling (15%), Glamis (15%), Andrew (10%), Wytch Farm (5%), Wareham (5%), Alba (2%), Caledonia (3%), Goldeneye (8%) and Bittern (2%). In 2005, Talisman

14 A N N U A L I N F O R M A T I O N F O R M

participated in drilling nine development wells (including one injection well) and two unsuccessful exploration wells. The Company expects that capital spending in 2006 at its other non-operated interest properties will be approximately $14 million and plans to participate in drilling seven development wells.

Talisman's subsidiary holds non-operated producing interests in the Netherlands sector of the North Sea ranging from 2% to 20%. The Company's interests are in the E, F, G and K sectors. In 2005, the Company participated in drilling two development wells. The Company expects that capital spending in the Netherlands sector in 2006 will be approximately $10 million and plans to participate in drilling one exploration well and five development wells.

In the German sector of the North Sea, Talisman's subsidiary holds a 50% non-operated working interest in one offshore licence covering portions of blocks C, D, G and H. The Company expects capital spending in 2006 in this sector will be approximately $5 million and plans to participate in an exploration well in the sector.

Landholdings, Production and Productive Wells

The following tables set forth Talisman's North Sea landholdings, production and productive wells as at December 31, 2005.

NORTH SEA Property		Developed Acreage (thousand acres)		Undeveloped Acreage (thousand acres)			Total Acreage (thousand acres)

		Gross	Net	Gross		Net	Gross	Net

Mid-North Sea Area
	Clyde Area	26.4	21.5	173.7		102.1	200.1	123.6
	Buchan Area	21.2	20.4	174.5		92.9	195.7	113.3
	Ross/Blake Area	35.2	21.8	242.8		122.0	278.0	143.8
	Beatrice Area	14.5	14.5	26.7		26.7	41.2	41.2
	Other MNS	3.6	1.3	69.3		29.4	72.9	30.7
Flotta Catchment Area
	Piper Area	37.9	24.8	97.2		56.1	135.1	80.9
	Claymore Area	22.0	17.4	72.7		65.6	94.7	83.0
	THP Area	21.7	21.7	116.6		67.4	138.3	89.1
	Other FCA	9.8	5.2	66.0		21.2	75.8	26.4
Paladin UK Properties
	Montrose/Arbroath	45.5	26.8	142.5		78.6	188.0	105.4
	Other Paladin UK Properties	5.8	1.1	65.0		15.6	70.8	16.7
Norway
	Gyda Area	50.7	37.5	708.4		384.8	759.1	422.3
	Varg Area	25.1	16.6	566.0		185.6	591.1	202.2
	Other¹	82.7	24.8	2,666.8		977.5	2,749.5	1,002.3

Non-Operated Interests
	Brae Area	35.8	7.8	50.3	��	11.0	86.1	18.8
	Other Non-Operated Interests²	380.3	93.1	2,362.3		1,187.2	2,742.6	1,280.3

Total		818.2	356.3	7,600.8		3,423.7	8,419.0	3,780.0

Notes:

1: "Other" includes Denmark.
2: "Other Non-Operated Interest" includes the Netherlands and Germany.

A N N U A L I N F O R M A T I O N F O R M15

NORTH SEA Property		Oil & Liquids Production (bbls/d)		Natural Gas Production (mmcf/d)		Productive Wells^1,2,3 as at December 31, 2005

		Gross	Net	Gross	Net	Gross	Net

Mid-North Sea Area
	Clyde Area	11,720	11,720	0.9	0.9	24	22.4
	Buchan Area	9,828	9,421	0.3	0.3	12	10.9
	Ross/Blake Area	16,168	16,168	4.3	4.3	20	12.0
	Beatrice Area	3,724	3,724	–	–	28	28.0
	Other MNS	1,162	1,162	0.4	0.4	1	0.6
Flotta Catchment Area
	Piper Area	15,719	15,719	0.1	0.1	34	21.9
	Claymore Area	20,506	20,506	–	–	36	26.9
	THP Area	12,005	12,005	4.1	4.1	28	24.7
	Other FCA	2,126	2,126	–	–	14	4.0
Paladin UK Properties
	Montrose/Arbroath	1,446	1,446	0.1	0.1	30	17.7
	Other Paladin UK Properties
Norway
	Gyda	8,449	8,449	7.5	7.5	21	12.7
	Varg	13,338	13,338	–	–	13	8.5
	Other⁴	3,909	3,890	1.5	1.5	60	12.1
Non-Operated Interests
	Brae Area	8,113	7,081	75.7	67.9	77	10.6
	Other Non-Operated Interests⁵	4,503	4,503	25.1	25.1	180	9.9

Total		132,716	131,258	120.0	112.2	578	222.9

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Includes wells containing multiple completions as follows:

	Oil Wells	Gas Wells

Gross	21	–
Net	2.4	–

3: One or more completions in the same bore hole is counted as one well. A well is classified as an oil well if one of the multiple completions in a given well is an oil completion.
4: "Other" includes Denmark.
5: "Other Non-Operated Interest" includes the Netherlands.

16 A N N U A L I N F O R M A T I O N F O R M

SOUTHEAST ASIA AND AUSTRALIA

The Company's interests in Southeast Asia and Australia include operations in Indonesia, Malaysia, Vietnam and Australia and exploration acreage with existing discoveries in Papua New Guinea.

Indonesia

In Indonesia, Talisman and its subsidiaries are continuing the development of the major natural gas discoveries at Corridor in order to deliver future production growth, the exploitation of existing oil properties and exploration activity.

Talisman plans to spend approximately $85 million in Indonesia in 2006, primarily to participate in drilling six exploration wells and 41 development wells and to continue Suban Phase 2 of the Corridor gas facility expansion.

Corridor PSC

Talisman (Corridor) Ltd. ("TCL"), a subsidiary of Talisman, has a 36% non-operated interest in the Corridor production sharing contract ("Corridor PSC Block") and field production facilities. Production from Corridor began in 1998 with gas sales to PT Caltex Pacific Indonesia ("Caltex"). Gas sales to Caltex were augmented pursuant to an agreement signed in 2000. In September 2003, TCL commenced gas sales to Gas Supply Pte. Ltd., located in Singapore, under the terms of a 20-year gas sales agreement. Talisman Transgasindo Ltd. has an indirect 6% interest in the Grissik to Duri pipeline and in the Grissik to Singapore pipeline which was completed in 2003.

In August 2004, ConocoPhillips (Grissik) Ltd., as representative of the Corridor PSC Block contractors, entered into an agreement for the sale of gas to PT Perusahaan Gas Negara (Persero), Tbk., the Indonesian national gas transmission and distribution company. This agreement enables the sale of 2.3 trillion cubic feet (gross sales) of natural gas from the Corridor PSC Block to the West Java market over a 17-year period commencing in

A N N U A L I N F O R M A T I O N F O R M17

the first quarter of 2007. In 2005, the Suban Phase 2 gas expansion project commenced and includes the installation of two new 200 mmcf/d capacity gas trains, additional pipelines and infrastructure in the Corridor PSC Block.

The Company expects that capital spending in 2006 in the area will be approximately $55 million to participate in the drilling of two development wells and to continue the Suban Phase 2 development, expected to be onstream in 2007.

Other Properties

Talisman's subsidiaries hold a 40% non-operated interest in the Corridor Technical Assistance Contract (the "Corridor TAC Block") and a 50% operated interest in the Ogan Komering production sharing contract (the "OK Block"). Through the acquisition of Paladin, Talisman acquired a 7% non-operated interest in the Southeast Sumatra Block ("SES Block") and a 2% non-operated interest in the offshore North West Java Block ("ONWJ Block"). The SES Block contains 33 producing fields while the ONWJ Block contains 35 producing fields. In 2005, the Company participated in one unsuccessful exploration well on the SES Block.

In January 2005, the enhanced oil recovery contract at Jambi expired, in which Talisman's subsidiary held a 40% interest.

Also in January 2005, Talisman's subsidiary participated in an unsuccessful exploration well on the offshore Nila production sharing contract. Subsequently, the subsidiary relinquished its non-operated interest.

The Company expects that capital spending in 2006 in these areas will be approximately $30 million with plans to drill up to six exploration wells and 39 development wells.

Malaysia and Vietnam

In Malaysia and Vietnam, the Company's strategy is to develop oil and natural gas fields and to deliver production growth through exploration and development. The Company operates three of its five working interest properties in Malaysia and Vietnam, being Block PM-3 CAA/Block 46-Cai Nuoc, Block PM-305 and Block PM-314. Block 46/02 and Block 15-2/01 are each operated by a joint operating company. Total Malaysia and Vietnam capital spending in 2006 is expected to be approximately $350 million.

Block PM-3 CAA and 46-Cai Nuoc

Two of Talisman's subsidiaries hold interests in Block PM-3 CAA and associated production facilities in Malaysia and Vietnam: Talisman Malaysia Limited ("TML") (26%) and Talisman Malaysia (PM3) Limited (15%). Talisman Vietnam Limited, another subsidiary, holds a 33% operated interest in the adjacent Block 46-Cai Nuoc area in Vietnam. Part of that area and part of the PM-3 CAA were unitized in 1998 to become the East Bunga Kekwa-Cai Nuoc unit. In 2005, additional acreage was granted to Block PM-3 CAA along the south-eastern border of the block.

In 2005, Phase 2/3 development drilling continued with the drilling of nine wells (including three injection wells) in the non-unit area and a successful two-well exploration program in the PM-3 CAA and Block 46-Cai Nuoc areas. Natural gas is sold under a long-term contract to Petroliam Nasional Berhad and Vietnam Oil and Gas Corporation, the national oil and gas companies of Malaysia and Vietnam, respectively. In 2006, the Company plans to commence development of the PM-3 CAA Northern Fields with first oil and gas production expected in 2008. Also in 2006, the Bunga Tulip field development and Phase 2/3 facility enhancement are expected to be completed with first oil production from the Bunga Tulip field in late 2006.

The Company expects that capital spending in 2006 in the area will be approximately $262 million and plans to drill four exploration wells, 15 development wells and to develop the Northern Fields.

Block PM-305

TML holds a 60% operated working interest in the Block PM-305 production sharing contract offshore Malaysia. In 2003, the Company made an oil discovery 10 kilometres south of the Angsi field. In 2005, the South Angsi development was completed which included the drilling of seven development wells (including three injection wells). First oil production commenced in August 2005. Also in 2005, Talisman drilled two successful exploration wells as part of a four-well program.

The Company expects that capital spending in 2006 in the area will be approximately $3 million.

Block PM-314

TML holds a 60% operated working interest in the Block PM-314 production sharing contract. In 2005, the Company drilled one successful exploration well. The Company expects that capital spending in 2006 in the area will be approximately $36 million and includes plans to drill up to two exploration wells, one development well, and to develop the newly discovered Naga Kecil field.

Block 46/02

Talisman (Vietnam 46/02) Ltd. holds a 30% interest in the Truong Son Joint Operating Company ("JOC"), with the remainder held by the wholly owned exploration and production subsidiaries of the national petroleum companies of Vietnam and Malaysia. In 2005, the Company drilled one successful appraisal well. The Company expects that capital spending in 2006 in Block 46/02 will be approximately $8 million primarily to commence development of the Song Doc field, which was discovered in 2003, with first oil production expected in 2007.

18 A N N U A L I N F O R M A T I O N F O R M

Block 15-2/01

Talisman (Vietnam 15-2/01) Ltd. ("Talisman 15-2/01"), a subsidiary of Talisman, and Petro Vietnam signed a petroleum contract for Block 15-2/01 offshore Vietnam in 2005. Talisman 15-2/01 holds a 60% interest in Block 15-2/01, with the remaining 40% held by the wholly-owned exploration and production subsidiary of the national petroleum company of Vietnam.

The Company expects that capital spending in 2006 in Block 15-2/01 will be approximately $41 million and includes plans to drill one exploration well, with a second exploration well expected to be spudded at the end of the year.

Australia

The Company acquired interests in Australia through the acquisition of Paladin. Talisman's subsidiary holds 40% and 33% non-operated interests in the Laminaria and Corallina fields, respectively. The Company also acquired a 25% non-operated interest in the JPDA 03-01 contract area. There was minimal activity in Australia in 2005. The Company expects that capital spending in 2006 in Australia will be approximately $5 million and includes plans to participate in drilling up to two exploration wells and one development well.

Papua New Guinea

The Company holds an operated interest in offshore Papua New Guinea Block PRL-1 (48%), which contains a natural gas discovery, and in Block PPL-244 (35%), which is exploration acreage. The Company expects minor capital expenditures in Papua New Guinea in 2006.

Landholdings, Production and Productive Wells

The following tables set forth Talisman's Southeast Asia and Australia landholdings, production and productive wells as at December 31, 2005.

SOUTHEAST ASIA AND AUSTRALIA Property		Developed Acreage (thousand acres)		Undeveloped Acreage (thousand acres)		Total Acreage (thousand acres)

		Gross	Net	Gross	Net	Gross	Net

Indonesia
	Corridor PSC	150.5	54.2	407.6	146.7	558.1	200.9
	Other¹	361.1	53.7	4,092.2	337.9	4,453.3	391.6
Malaysia and Vietnam
	Block PM-3 CAA and 46-Cai Nuoc	224.4	92.5	277.3	113.7	501.7	206.2
	Block PM-305	43.9	26.3	499.8	299.9	543.7	326.2
	Block PM-314	–	–	2,309.8	1,385.9	2,309.8	1,385.9
	Block 46/02	–	–	3,023.6	907.1	3,023.6	907.1
	Block 15-2/01	–	–	699.8	419.9	699.8	419.9

Australia		9.2	3.6	488.9	140.9	498.1	144.5

Papua New Guinea		–	–	858.2	325.1	858.2	325.1

Total		789.1	230.3	12,657.2	4,077.1	13,446.3	4,307.4

Note:

1: "Other" includes Corridor TAC Block, OK Block, SES Block and ONWJ Block.

A N N U A L I N F O R M A T I O N F O R M19

SOUTHEAST ASIA AND AUSTRALIA Property		Oil & Liquids Production (bbls/d)		Natural Gas Production (mmcf/d)		Productive Wells^1,2,3 as at December 31, 2005

		Gross	Net⁴	Gross	Net⁴	Gross	Net

Indonesia
	Corridor PSC	2,324	817	168.1	113.7	120	42.9
	Other⁵	4,466	2,243	8.9	3.9	1,017	182.0
Malaysia and Vietnam
	Block PM-3 CAA and 46-Cai Nuoc	21,528	12,099	106.8	80.8	46	18.8
	Block PM-305	6,472	5,561	–	–	6	3.6
	Block PM-314	–	–	–	–	–	–
	Block 46/02	–	–	–	–	–	–
	Block 15-2/01	–	–	–	–	–	–
Australia		686	686	–	–	8	3.1
Papua New Guinea		–	–	–	–	–	–

Total		35,476	21,406	283.8	198.4	1,197	250.4

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Includes wells containing multiple completions as follows:

	Oil Wells	Gas Wells

Gross	81	4
Net	11.6	0.1

3: One or more completions in the same bore hole is counted as one well. A well is classified as an oil well if one of the multiple completions in a given well is an oil completion.
4: Interests of the Indonesian, Malaysian and Vietnam governments, other than working interests or income taxes, are accounted for as royalties.
5: "Other" includes Corridor TAC Block, OK Block, SES Block and ONWJ Block.

20 A N N U A L I N F O R M A T I O N F O R M

NORTH AFRICA

The Company's interests in North Africa include operations in Algeria and Tunisia.

Algeria

Talisman (Algeria) B.V., a subsidiary of Talisman, holds a 35% non-operated working interest in Block 405a under a production sharing contract with Algeria's National Oil Company, Sonatrach. Block 405a contains the Greater Menzel Lejmat North ("Greater MLN") fields, a portion of the Ourhoud field, a portion of the EMK field and the Menzel Lejmat Southeast ("MLSE") field. In February 2005, the Company relinquished a portion of Block 405a and all of Block 215.

The Company expects that capital spending in 2006 in Algeria will be approximately $65 million, which includes funding for 24 development wells, the Greater MLN Phase 2 development and commencement of the El Merk project described below.

Greater MLN

Greater MLN facilities include a central processing facility ("CPF") and compression for gas injection. Crude oil is pipelined to the Mediterranean coast for export. Phase 2 expansion of the CPF for full pressure maintenance of additional MLN reservoirs is currently underway with Phase 2 commissioning expected in 2007. One development well was drilled in 2005. The Company expects that capital spending in 2006 in the Greater MLN area will be approximately $50 million and includes plans to participate in drilling nine development wells.

In 2005, the Company signed a pre-unit agreement for the EMK field which straddles Block 405a and Block 208. The Company also signed a Memorandum of Understanding for the joint construction and operation of shared process facilities for the EMK field plus four other fields located in Block 212 and Block 208 (collectively, the "El Merk project"). Two development wells were drilled in the EMK field in 2005 with four planned for 2006. First oil production is expected in 2009.

A N N U A L I N F O R M A T I O N F O R M21

Ourhoud

Production at the Ourhoud field (Talisman 2%) commenced in December 2002 with first oil sales in 2003. Production from Ourhoud is anticipated to remain at plateau levels throughout 2006. Development drilling is ongoing with eight wells drilled in 2005 (including two injection wells) and 11 wells planned for 2006.

Tunisia

Talisman acquired interests in the Borj El Khadra Permit in Tunisia through the acquisition of Paladin. The Company's subsidiary holds a 5% non-operated interest in the Adam concession portion of the permit (which contains the Adam, Dalia, Hawa and Nour fields) and a 10% interest in the remainder of the permit.

In 2006, the Company expects to participate in drilling three exploration wells and three development wells. The Company expects minor capital expenditures in 2006.

Landholdings, Production and Productive Wells

The following tables set forth Talisman's North African landholdings, production and productive wells as at December 31, 2005.

NORTH AFRICA Property		Developed Acreage (thousand acres)		Undeveloped Acreage (thousand acres)		Total Acreage (thousand acres)

		Gross	Net	Gross	Net	Gross	Net

Algeria
	Greater MLN¹	11.2	3.9	–	–	11.2	3.9
	Ourhoud	65.6	1.3	–	–	65.6	1.3

Tunisia		3.9	0.2	804.7	79.5	808.6	79.7

Total North Africa		80.7	5.4	804.7	79.5	885.4	84.9

Note:

1: "Greater MLN" includes MLSE acreage.

NORTH AFRICA Property		Oil & Liquids Production (bbls/d)		Natural Gas Production (mmcf/d)		Productive Wells^1,2,3 as at December 31, 2005

		Gross	Net⁴	Gross	Net⁴	Gross	Net

Algeria
	Greater MLN	10,768	6,562	–	–	32	7.6
	Ourhoud	4,493	2,785	–	–	37	0.7
Tunisia		116	102	–	–	8	0.4

Total North Africa		15,377	9,449	–	–	77	8.7

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Includes wells containing multiple completions as follows:

	Oil Wells	Gas Wells

Gross	2	–
Net	0.1	–

3: One or more completions in the same bore hole is counted as one well. A well is classified as an oil well if one of the multiple completions in a given well is an oil completion.
4: Interests of the Algerian and Tunisian governments, other than working interests or income taxes, are accounted for as royalties.

22 A N N U A L I N F O R M A T I O N F O R M

TRINIDAD AND TOBAGO

Talisman holds a 25% non-operated interest in the Angostura development area of Block 2(c) and a 36% interest in the Howler assessment area located to the south and retained for further exploration. The 36% interest is comprised of the 25% original interest plus an additional 11% interest, subject to a reinstatement right. In February 2006, the Company relinquished the retained exploration area of Block 2(c), retaining only the Howler assessment area.

The Greater Angostura Project located in Block 2(c) was sanctioned in 2003 and in 2004 the installation of all field facilities was completed, including a central processing platform and three wellhead platforms. Oil production commenced in January 2005, with oil exported to a new onshore oil terminal located west of Galeota Point in south-eastern Trinidad and Tobago. Phase 1 development was completed in 2005 with the drilling of three additional development wells (including two injection wells). Also in 2005, Talisman completed operations on one unsuccessful well and drilled an unsuccessful exploration well in the exploration portion of Block 2(c). Phase 2 of the Angostura Project is expected to provide for first gas production in 2009.

Talisman's subsidiary, Talisman (Trinidad Block 3a) Ltd., holds a 30% interest in the production sharing contract on Block 3(a), immediately to the east of Block 2(c). The Company is currently renegotiating the production sharing contract and joint operating agreement for Block 3(a) which may result in a reduction of Talisman's working interest and well commitments.

In 2002, Talisman (Trinidad) Petroleum Ltd., a Talisman subsidiary, acquired the right to earn an operated 65% interest in the onshore Eastern Block. This block is comprised of approximately 108,000 gross acres, of which the Government of Trinidad and Tobago holds the mineral rights to

A N N U A L I N F O R M A T I O N F O R M23

approximately 95,000 acres and the balance is freehold title. In September 2005, the Company spudded its first exploration well on the Eastern Block, which was still drilling at year end.

The Company expects that capital spending in 2006 in Trinidad and Tobago will be approximately $65 million and plans to participate in drilling up to four exploration and five development wells.

Landholdings, Production and Productive Wells

The following tables set forth Talisman's Trinidad and Tobago landholdings, production and productive wells as at December 31, 2005.

TRINIDAD AND TOBAGO Property		Developed Acreage (thousand acres)		Undeveloped Acreage (thousand acres)		Total Acreage (thousand acres)

		Gross	Net	Gross	Net	Gross	Net

Offshore
	Block 2(c)	23.5	5.9	39.8	14.2	63.3	20.1
	Block 3(a)	–	–	151.7	45.5	151.7	45.5
Onshore
	Eastern Block	–	–	108.3	70.4	108.3	70.4

Total Trinidad and Tobago		23.5	5.9	299.8	130.1	323.3	136.0

TRINIDAD AND TOBAGO Property		Oil & Liquids Production (bbls/d)		Natural Gas Production (mmcf/d)		Productive Wells¹ as at December 31, 2005

		Gross	Net²	Gross	Net²	Gross	Net

Offshore
	Block 2(c)	10,111	8,545	–	–	12	3.0
	Block 3(a)	–	–	–	–	–	–
Onshore
	Eastern Block	–	–	–	–	–	–

Total Trinidad and Tobago		10,111	8,545	–	–	12	3.0

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Interests of the government of Trinidad and Tobago, other than working interests or income taxes, are accounted for as royalties.

COLOMBIA

In Colombia, Talisman (Colombia) Oil & Gas Ltd., a subsidiary of Talisman, is participating in an exploration program in a known hydrocarbon basin.

The subsidiary holds a 70% non-operated interest in the Acevedo Block in the Upper Magdalena Valley region. Interests in the Huila Norte and Altamizal blocks were relinquished in 2005. In the Acevedo Block, the subsidiary is currently carrying out an environmental remediation program. During 2005, the Company was awarded a 35% non-operated and 100% operated interest in the El Conchal and El Caucho Blocks, respectively, held under Technical Evaluation Agreements.

In the Llanos Foothills region of north-central Colombia, the subsidiary holds a 30% non-operated interest in the Tangara and Mundo Nuevo blocks. In July 2004, the Tangara-1 exploration well was spudded on the Tangara Block and at year end 2005 drilling operations continued on the well, which is proceeding with a fourth sidetrack hole. Two of the joint venture parties are conducting the sidetrack as an exclusive operation. The Company retains the right to participate in appraisal or development if a discovery is made.

The Company expects that capital spending in 2006 in Colombia will be approximately $4 million in order to finish operations at Tangara-1 and to fund ongoing geologic and geophysical work.

PERU

In 2004, Talisman (Peru) Ltd., a subsidiary of Talisman, acquired a 25% non-operated interest in Peru's Block 64 in the Marañon Basin. During 2005, the Company acquired a 28% non-operated interest in the adjacent Block 101. Also during the year, the Situche Central well in Block 64 made an oil discovery. The Company is currently evaluating options in Peru, including additional drilling. The Company expects that capital spending in 2006 in Peru will be approximately $13 million.

24 A N N U A L I N F O R M A T I O N F O R M

QATAR

Talisman's subsidiaries hold a 100% interest in an Exploration and Production Sharing Agreement for offshore Block 10 in Qatar. In November 2005, the Company spudded its first exploration well offshore Qatar which was subsequently plugged and abandoned in January 2006.

The Company expects that capital spending in 2006 in Qatar will be approximately $34 million and plans to drill up to two exploration wells.

ALASKA

In June 2003, the Company's subsidiary, FEX L.P. ("FEX"), entered into an agreement with Total E&P USA, Inc. ("Total"), through which the Company earned a 30% interest in certain lands in the Caribou Region of the National Petroleum Reserve – Alaska ("NPR-A"). This represented the Company's initial entry into Alaska. In October 2004, the Company entered into a further agreement with Total whereby FEX acquired a 100% working interest in the Caribou lands. In June 2004, FEX participated in a lease sale covering the Northwest Planning Area of the NPR-A, acquiring a 100% interest in over 250,000 acres of land. In October 2004, FEX was successful at another lease sale, acquiring approximately 101,000 acres of State lands in the offshore Harrison Bay area. In November 2005, approximately another 11,000 acres was acquired in the Fox area of the Northeast NPR-A.

In total, the Company holds a 100% interest in approximately 417,000 acres, and an additional 46,500 net acres comprising various working interests in over 80,000 acres held by virtue of a joint venture agreement concluded in February 2006. In March 2006, the Company was advised that its bid for an additional 119,680 acres in the Smith Bay area had been successful. The award of the leases is subject to government approval.

In 2005, the Company pre-staged equipment and a drilling rig in preparation for the 2006 drilling campaign. FEX expects capital spending in 2006 in the Alaska area will be approximately $105 million for the drilling of two exploration wells in the NPR-A, and further exploration activity.

OTHER

Talisman's strategy is to expand activity in core producing areas and to add new ventures where appropriate. The Company actively investigates new ventures outside core producing areas and this will continue in 2006. Exploration interests in Gabon and Romania were acquired through the acquisition of Paladin. In 2006 the Company expects to participate in one exploration well and to acquire new seismic data in Gabon with minor capital expenditures.

A N N U A L I N F O R M A T I O N F O R M25

PRODUCTIVE WELLS AND ACREAGE

The following table shows the number of productive wells¹ in which the Company had a working interest, as well as developed and undeveloped acres assignable to such wells, as of December 31, 2005. Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

		Productive Wells¹ as at December 31, 2005		Acreage (thousand acres)

		Oil Wells²	Gas Wells²	Developed	Undeveloped

North America³
	Gross	5,518.0	5,139.0	3,468.8	10,515.9
	Net	2,945.1	2,751.8	1,860.0	5,588.3

North Sea
	Gross	538.0	40.0	818.2	7,600.8
	Net	218.9	4.0	356.3	3,423.7

SE Asia and Australia
	Gross	1,119.0	78.0	789.1	12,657.2
	Net	233.7	16.7	230.3	4,077.1

North Africa
	Gross	74.0	3.0	80.7	804.7
	Net	7.7	1.0	5.4	79.5

Trinidad and Tobago
	Gross	12.0	–	23.5	299.8
	Net	3.0	–	5.9	130.1

Other⁴
	Gross	–	–	–	16,701.5
	Net	–	–	–	5,773.5

Total
	Gross	7,261.0	5,260.0	5,180.3	48,579.9
	Net	3,408.4	2,773.5	2,457.9	19,072.2

Notes:

1: "Productive Wells" means producing wells and wells capable of production.
2: Includes wells containing multiple completions as follows:

	Oil Wells	Gas Wells

2004 Gross	542.0	970.0
Net	273.0	516.6
2005 Gross	662.0	1,209.0
Net	306.7	654.4

One: or more completions in the same bore hole is counted as one well. A well is classified as an oil well if one of the multiple completions in a given well is an oil completion.
3: "North America" acreage includes acreage related to Talisman's indirect interest in the Syncrude Project; however, "North America" productive wells does not include wells related to the Syncrude Project as it is considered a mining operation.
4: "Other" includes Alaska, Bahamas, Colombia, Gabon, Peru, Qatar, Romania and Scotian Slope.

26 A N N U A L I N F O R M A T I O N F O R M

DRILLING ACTIVITY

The following table sets forth the number of wells¹ Talisman has drilled and tested or participated in drilling and testing, and the net² interest of the Company in such wells for each of the last three fiscal years. The number of wells drilled refers to the number of wells completed at any time during the fiscal years, regardless of when drilling was initiated. The term "completion" refers to the installation of permanent equipment for the production of oil and gas, or, in the case of a dry hole, to reporting of abandonment to the appropriate agency. Drilling activity for 2005 includes activity of Paladin and its subsidiaries only from the date of acquisition (November 18, 2005). Numbers in 2003 and 2004 have not been adjusted to include historic Paladin activity.

Year Ended December 31, 2005			Exploration				Development				Total

			Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total

North America
	Canada	Gross	12.0	114.0	11.0	137.0	159.0	363.0	8.0	530.0	171.0	477.0	19.0	667.0
		Net	8.3	72.8	7.7	88.8	66.7	216.7	6.0	289.4	75.0	289.5	13.7	378.2
	United States⁵	Gross	–	18.0	–	18.0	–	–	–	–	–	18.0	–	18.0
		Net	–	13.0	–	13.0	–	–	–	–	–	13.0	–	13.0

North Sea
	United Kingdom	Gross	3.0	–	5.0	8.0	18.0	–	1.0	19.0	21.0	–	6.0	27.0
		Net	2.3	–	2.5	4.8	6.8	–	1.0	7.8	9.1	–	3.5	12.6
	Norway	Gross	–	–	1.0	1.0	5.0	–	–	5.0	5.0	–	1.0	6.0
		Net	–	–	0.7	0.7	3.2	–	–	3.2	3.2	–	0.7	3.9
	Other North Sea⁶	Gross	–	–	–	–	–	2.0	–	2.0	–	2.0	–	2.0
		Net	–	–	–	–	–	0.2	–	0.2	–	0.2	–	0.2

Southeast Asia and Australia
	Indonesia	Gross	–	–	2.0	2.0	–	–	–	–	–	–	2.0	2.0
		Net	–	–	0.3	0.3	–	–	–	–	–	–	0.3	0.3
	Malaysia/Vietnam	Gross	6.0	–	2.0	8.0	7.0	3.0	–	10.0	13.0	3.0	2.0	18.0
		Net	2.9	–	1.2	4.1	3.6	1.2	–	4.8	6.5	1.2	1.2	8.9
	Australia	Gross	–	–	–	–	–	–	–	–	–	–	–	–
		Net	–	–	–	–	–	–	–	–	–	–	–	–

North Africa
	Algeria	Gross	–	–	–	–	9.0	–	–	9.0	9.0	–	–	9.0
		Net	–	–	–	–	0.7	–	–	0.7	0.7	–	–	0.7
	Tunisia	Gross	1.0	–	–	1.0	–	–	–	–	1.0	–	–	1.0
		Net	0.1	–	–	0.1	–	–	–	–	0.1	–	–	0.1

Trinidad and Tobago		Gross	–	–	2.0	2.0	1.0	–	–	1.0	1.0	–	2.0	3.0
		Net	–	–	0.6	0.6	0.3	–	–	0.3	0.3	–	0.6	0.9

Other⁷		Gross	1.0	–	–	1.0	–	–	–	–	1.0	–	–	1.0
		Net	0.3	–	–	0.3	–	–	–	–	0.3	–	–	0.3

Total		Gross	23.0	132.0	23.0	178.0	199.0	368.0	9.0	576.0	222.0	500.0	32.0	754.0
		Net	13.9	85.8	13.0	112.7	81.3	218.1	7.0	306.4	95.2	303.9	20.0	419.1

A N N U A L I N F O R M A T I O N F O R M27

Year Ended December 31, 2004			Exploration				Development				Total

			Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total

North America
	Canada	Gross	16.0	123.0	15.0	154.0	121.0	301.0	23.0	445.0	137.0	424.0	38.0	599.0
		Net	13.4	64.0	11.5	88.9	66.9	183.0	18.6	268.5	80.3	247.0	30.1	357.4
	United States⁵	Gross	–	20.0	1.0	21.0	–	–	–	–	–	20.0	1.0	21.0
		Net	–	15.9	1.0	16.9	–	–	–	–	–	15.9	1.0	16.9

North Sea⁶		Gross	3.0	–	6.0	9.0	17.0	–	1.0	18.0	20.0	–	7.0	27.0
		Net	1.9	–	4.3	6.2	6.0	–	0.8	6.8	7.9	–	5.1	13.0

Southeast Asia
	Indonesia	Gross	–	–	2.0	2.0	9.0	–	–	9.0	9.0	–	2.0	11.0
		Net	–	–	0.7	0.7	3.8	–	–	3.8	3.8	–	0.7	4.5
	Malaysia/Vietnam	Gross	1.0	–	3.0	4.0	12.0	2.0	1.0	15.0	13.0	2.0	4.0	19.0
		Net	0.4	–	1.6	2.0	5.0	0.8	0.4	6.2	5.4	0.8	2.0	8.2

Algeria		Gross	–	–	–	–	3.0	–	–	3.0	3.0	–	–	3.0
		Net	–	–	–	–	0.1	–	–	0.1	0.1	–	–	0.1

Trinidad and Tobago		Gross	1.0	1.0	–	2.0	11.0	–	1.0	12.0	12.0	1.0	1.0	14.0
		Net	0.3	0.3	–	0.6	2.8	–	0.3	3.1	3.1	0.3	0.3	3.7

Other⁹		Gross	–	–	4.0	4.0	–	–	–	–	–	–	4.0	4.0
		Net	–	–	1.6	1.6	–	–	–	–	–	–	1.6	1.6

Total		Gross	21.0	144.0	31.0	196.0	173.0	303.0	26.0	502.0	194.0	447.0	57.0	698.0
		Net	16.0	80.2	20.7	116.9	84.6	183.8	20.1	288.5	100.6	264.0	40.8	405.4

Year Ended December 31, 2003			Exploration				Development				Total

			Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total	Oi1³	Gas³	Dry⁴	Total

North America
	Canada	Gross	14.0	147.0	21.0	182.0	190.0	225.0	21.0	436.0	204.0	372.0	42.0	618.0
		Net	9.4	100.9	15.6	125.9	101.0	132.7	18.2	251.9	110.4	233.6	33.8	377.8
	United States⁵	Gross	–	6.0	–	6.0	–	–	–	–	–	6.0	–	6.0
		Net	–	4.2	–	4.2	–	–	–	–	–	4.2	–	4.2

North Sea⁶		Gross	3.0	–	2.0	5.0	12.0	2.0	3.0	17.0	15.0	2.0	5.0	22.0
		Net	2.2	–	1.1	3.3	5.5	0.2	0.9	6.6	7.7	0.2	2.0	9.9

Southeast Asia
	Indonesia	Gross	–	1.0	2.0	3.0	6.0	–	–	6.0	6.0	1.0	2.0	9.0
		Net	–	0.4	0.5	0.9	2.6	–	–	2.6	2.6	0.4	0.5	3.5
	Malaysia/Vietnam	Gross	2.0	4.0	1.0	7.0	12.0	9.0	–	21.0	14.0	13.0	1.0	28.0
		Net	0.9	1.6	0.4	2.9	4.9	3.6	–	8.5	5.8	5.2	0.4	11.4

Algeria		Gross	1.0	–	–	1.0	11.0	–	–	11.0	12.0	–	–	12.0
		Net	0.4	–	–	0.4	0.6	–	–	0.6	1.0	–	–	1.0

Sudan		Gross	2.0	–	–	2.0	1.0	–	–	1.0	3.0	–	–	3.0
		Net	0.5	–	–	0.5	0.3	–	–	0.3	0.8	–	–	0.8

Trinidad and Tobago		Gross	1.0	2.0	–	3.0	–	–	–	–	1.0	2.0	–	3.0
		Net	0.4	0.6	–	1.0	–	–	–	–	0.4	0.6	–	1.0

Other¹⁰		Gross	–	–	1.0	1.0	–	–	–	–	–	–	1.0	1.0
		Net	–	–	0.3	0.3	–	–	–	–	–	–	0.3	0.3

Total		Gross	23.0	160.0	27.0	210.0	232.0	236.0	24.0	492.0	255.0	396.0	51.0	702.0
		Net	13.8	107.7	17.9	139.4	114.9	136.5	19.1	270.5	128.7	244.2	37.0	409.9

Notes:

1: The number of wells refers to gross wellbores, which is the total number of wells Talisman has drilled or participated in drilling, with a working interest. Service wells, including water injection, gas injection, water source and water disposal wells are not included. Multilaterals from the same wellbore are counted as a single wellbore. Stratigraphic test wells are included.
2: "Net" wellbores are the aggregate of the percentage working interest of the Company in each of the gross wellbores. Data is rounded to the nearest decimal place and summed.
3: A productive oil or gas well is an exploratory or development well that is not a dry well.
4: A dry well (hole) is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
5: "United States" excludes Alaska.
6: "Other North Sea" for 2005 includes Netherlands, Denmark and Germany.
7: "Other" for the year ended December 31, 2005 includes Peru.
8: "North Sea" for 2004 and 2003 includes the United Kingdom, Norway and the Netherlands.
9: "Other" for the year ended December 31, 2004 includes Alaska, Colombia and Peru.
10: "Other" for the year ended December 31, 2003 includes Scotian Slope.

28 A N N U A L I N F O R M A T I O N F O R M

The following table shows the number of wells in the process of drilling, suspended or in active completion stages as of December 31, 2005.

		Wells in the process of drilling, suspended or active completion¹

		Exploration	Development

North America
	Gross	73.0	193.0
	Net	45.0	98.0

North Sea
	Gross	2.0	8.0
	Net	0.5	3.4

Southeast Asia and Australia
	Gross	–	–
	Net	–	–

North Africa
	Gross	–	2.0
	Net	–	0.4

Trinidad and Tobago
	Gross	1.0	1.0
	Net	1.0	0.3

Other²
	Gross	2.0	–
	Net	1.7	–

Total
	Gross	78.0	204.0
	Net	48.2	102.1

Notes:

1: The number of wells refers to gross wellbores, which is the total number of wells Talisman has drilled or participated in drilling, with a working interest. Service wells, including water injection, gas injection, water source, and water disposal wells, are not included. Multilaterals from the same wellbore are counted as a single wellbore. Stratigraphic test wells are included.
2: "Other" includes Colombia and Qatar.

A N N U A L I N F O R M A T I O N F O R M29

RESERVES ESTIMATES

Talisman's oil and gas reserves are evaluated internally. The exemption under NI 51-101 described under "Note Regarding Reserves Data and Other Oil and Gas Information", in addition to permitting Talisman to provide disclosure in accordance with US standards, exempts Talisman from the requirement under NI 51-101 to have its reserves evaluated or audited by independent reserves evaluators. NI 51-101 and its companion policy specifically contemplate the granting of such an exemption to issuers such as Talisman who produce over 100,000 boe/d and are able to demonstrate the internal capability to generate reliable reserves data. The following discussion is provided pursuant to the requirements of the exemption.

Talisman understands that the purpose of the requirement under NI 51-101 for the involvement of independent qualified evaluators or auditors is to ensure that disclosure of reserves information reflects the conclusions of qualified professionals applying consistent standards and that such conclusions are not affected by adverse influences. Talisman believes that using independent evaluators or auditors would not materially enhance the reliability of its reserves estimates, in light of the expertise of its internal reserves evaluation personnel and the controls applied during its reserves evaluation process. Talisman believes that its internal resources are at least as extensive as, if not greater than, those which would be assigned by any independent evaluators or auditors engaged by the Company, and that its internal staff's knowledge of and experience with the Company's reserves enable the Company to prepare an evaluation at least equivalent to that of any independent evaluator or auditor.

As at December 2005, the Company's internal reserves evaluation staff included 104 persons with full-time or part-time responsibility for reserves evaluation with an average of approximately 19 full-time or part-time years of relevant experience in evaluating reserves, of whom 50 were "qualified reserves evaluators" for purposes of NI 51-101. The Company's internal reserves evaluation management personnel included approximately 27 persons with full-time or part-time responsibility for reserves evaluation management with an average of approximately 25 full-time or part-time years of relevant experience in evaluating and managing the evaluation of reserves, 15 of whom were qualified reserves evaluators for purposes of NI 51-101. The Company has appointed an Internal Qualified Reserves Evaluator ("IQRE") who reports directly to the Chief Executive Officer and who is responsible for the preparation and validation of the Company's reserves evaluation and the submission to the Company's Board of Directors of a report thereon as required by the NI 51-101 exemption. The Company's IQRE is Michael Adams, a graduate of Imperial College, London University with a BSc in Physical Chemistry and an MSc in Petroleum Engineering. Mr. Adams has over 30 years of petroleum engineering experience internationally and in North America. He is a professional engineer registered in Alberta and a chartered engineer registered in the UK.

Talisman has adopted a corporate policy which prescribes procedures and standards to be followed in preparing its reserves data. The following summarizes Talisman's current process for preparing and approving its publicly disclosed reserves data.

All of Talisman's proved reserves are evaluated annually. Talisman employs qualified, competent, experienced engineers to ensure consistently high levels of professionalism in the estimation of its reserves data. Technical, cost and economic assumptions underpinning reserves estimates are documented to provide a clear audit trail.

Talisman conducts formal reviews during the proved reserves estimation process to ensure: the reasonableness, completeness and accuracy of input data; the appropriateness of the technical sub-surface methodology; the full understanding of reserve movements; and the correct use of reserves classifications. All reserve estimates are reviewed and approved by the Executive Vice-Presidents of the operating areas and then submitted to the Company's executive operating committee, comprised of the Chief Executive Officer and all the Executive Vice-Presidents of the Company, for review and approval. In addition, the IQRE conducts a separate review to ensure the effectiveness of the disclosure controls and that the reserves estimates are free from material misstatement. The reserves data and the report of the IQRE are then reviewed by the Reserves Committee of the Board of Directors. The Reserves Committee and the IQRE have independent access to each other. Once approved by the Reserves Committee, the reserves data is submitted to the Board of Directors for final approval.

Notwithstanding that Talisman is exempt from the independent evaluator requirements of NI 51-101, Talisman obtains annual audits by independent external engineering consultants of its reserve estimates for some of its properties on a rotating basis. Over the past three years, the Company's estimates for approximately 80% of its current proved reserves (on a boe basis) have been independently audited which includes an independent audit of over 90% of Paladin's consolidated reserves for the year ended December 31, 2005. The audits have not revealed any material discrepancies. Talisman's Reserves Data Policy and Procedures Manual (the "Reserves Manual") was originally reviewed by external engineering consultants in 2003. The Reserves Committee of the Board of Directors approved minor changes to the details of some of Talisman's internal reserves processes in December 2005. Talisman also adopted new reserves software for its North American reserves estimating process in 2004. Talisman also conducts periodic internal audits of the procedures, records and controls relating to the preparation of reserves data.

Accordingly, Talisman considers the reliability of its internally generated reserves data to be not materially less than would be afforded by the independent evaluator requirements of NI 51-101.

30 A N N U A L I N F O R M A T I O N F O R M

The following table sets forth Talisman's estimates of its proved developed, proved undeveloped, total proved, probable and total proved plus probable reserves as at December 31, 2005.

			Proved Developed²		Proved Undeveloped³		Total Proved¹		Total Probable⁴		Total Proved and Probable

			Gross⁵	Net⁶	Gross⁵	Net⁶	Gross⁵	Net⁶	Gross⁵	Net⁶	Gross⁵	Net⁶

Oil and Natural Gas Liquids (millions of barrels)
	North America
		Canada	161.0	132.0	12.4	10.2	173.4	142.2	70.9	58.3	244.3	200.5
		United States	–	–	–	–	–	–	–	–	–	–
	North Sea										–	–
		United Kingdom	277.3	274.2	78.5	78.2	355.8	352.4	217.0	216.0	572.8	568.4
		Norway	31.1	31.1	9.1	9.1	40.2	40.2	83.5	83.5	123.7	123.7
		Other North Sea⁸	3.9	3.7	0.9	0.8	4.8	4.5	3.4	3.3	8.2	7.8
	Southeast Asia and Australia
		Indonesia⁷	24.0	10.4	11.5	3.6	35.5	14.0	16.0	6.1	51.5	20.1
		Malaysia/Vietnam⁷	33.3	15.0	29.3	15.3	62.6	30.3	47.0	18.4	109.6	48.7
		Australia	10.4	10.4	1.2	1.2	11.6	11.6	2.6	2.6	14.2	14.2
	North Africa						–	–			–	–
		Algeria	25.7	14.2	17.2	9.3	42.9	23.5	48.8	25.8	91.7	49.3
		Tunisia	0.5	0.4	0.3	0.2	0.8	0.6	–	–	0.8	0.6
	Trinidad and Tobago⁷		8.5	7.7	–	–	8.5	7.7	3.3	2.9	11.8	10.6

Total			575.7	499.1	160.4	127.9	736.1	627.0	492.5	416.9	1,228.6	1,043.9

Natural Gas (billions of cubic feet)
	North America
		Canada	2,086.8	1,652.1	478.3	382.4	2,565.1	2,034.5	1,280.0	1,012.7	3,845.1	3,047.2
		United States	139.7	119.7	2.0	1.7	141.7	121.4	55.7	48.4	197.4	169.8
	North Sea
		United Kingdom	142.6	134.0	44.8	43.9	187.4	177.9	110.4	108.7	297.8	286.6
		Norway	6.2	6.2	2.0	2.0	8.2	8.2	109.8	109.8	118.0	118.0
		Other North Sea⁸	40.9	40.9	12.3	12.3	53.2	53.2	42.1	42.1	95.3	95.3
	Southeast Asia and Australia
		Indonesia⁷	706.7	493.1	1,061.6	713.5	1,768.3	1,206.6	815.4	552.5	2,583.7	1,759.1
		Malaysia/Vietnam⁷	86.5	55.7	389.6	237.9	476.1	293.6	212.8	110.2	688.9	403.8
		Australia	–	–	–	–	–	–	–	–	–	–
	North Africa
		Algeria	–	–	–	–	–	–		–	–	–
		Tunisia	0.9	0.8	0.5	0.4	1.4	1.2	–	–	1.4	1.2
	Trinidad and Tobago⁷				215.2	213.6	215.2	213.6	77.6	75.7	292.8	289.3

Total			3,210.3	2,502.5	2,206.3	1,607.7	5,416.6	4,110.2	2,703.8	2,060.1	8,120.4	6,170.3

Synthetic Oil⁹ (millions of barrels)
	Canada		40.2	34.3	–	–	40.2	34.3	23.9	20.4	64.1	54.7

Notes:

1: "Proved" reserves have been estimated in accordance with the SEC definition set out in Rule 4-10(a) of Regulation S-X under the Securities Exchange Act of 1934 as follows: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

A N N U A L I N F O R M A T I O N F O R M31

2: "Proved Developed" reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
3: "Proved Undeveloped" reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only if it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
4: "Probable" reserves are less certain than proved reserves and have been estimated in accordance with the definition set out by the Society of Petroleum Engineers and the World Petroleum Congress ("SPE/WPC"). That is, probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable.
5: "Gross" proved reserves refer to the sum of (i) working interest reserves before deduction of royalty burdens payable, (ii) royalty interest reserves and (iii) net profits interests. Royalty interest reserves and net profits interests volumes for Canada were approximately 3.1 mmboe as at December 31, 2005. The inclusion of royalty interest and net profit interest volumes in gross reserves does not conform to COGEH standards applicable under NI 51-101.
6: "Net" reserves are the remaining reserves of Talisman, after deduction of estimated royalty burdens and including royalty interests and net profit interests in the amount set out in Note 5 above. The inclusion of net profit interest volumes in net reserves is consistent with SEC requirements for net reserves disclosure, but does not conform to COGEH standards applicable under NI 51-101.
7: Interests of various governments, other than working interests or income taxes, are accounted for as royalties. Royalties are reflected in "net" reserves using effective rates over the life of the contract.
8: "Other North Sea" includes Netherlands and Denmark.
9: The reserves volumes shown have been calculated by Talisman based on reserves estimates and production information published by the general partner of the limited partnership through which Talisman has an indirect 1.25% interest in the Syncrude project.

A report on reserves data by Talisman's IQRE and a report of management and directors on oil and gas disclosure are provided in Schedules A and B, respectively, to this Annual Information Form. The Company does not file estimates of its total oil and gas reserves with any US agency or federal authority other than the SEC.

OTHER OIL AND GAS INFORMATION

The tables in this section set forth oil and gas information prepared by Talisman in accordance with US disclosure standards, including FAS69.

CONTINUITY OF NET PROVED RESERVES¹

		North America²		North Sea³		Southeast Asia and Australia⁴		North Africa⁵		Sudan		Trinidad and Tobago		Total

Crude Oil and Liquids (mmbbls)
Total proved
	Proved reserves at December 31, 2002	164.1		247.6		36.1		13.9		94.3		18.9		574.9
	Discoveries, additions and extensions	13.1		8.3		17.0		2.3		–		–		40.7
	Purchase of reserves	1.1		21.1		–		–		–		–		22.2
	Sale of reserves	(4.6	)	–		–		–		(91.7	)	–		(96.3	)
	Net revisions and transfers	1.1		19.4		4.8		0.5		–		(0.8	)	25.0
	2003 Production	(16.4	)	(41.4	)	(5.4	)	(0.1	)	(2.6	)			(65.9	)

	Proved reserves at December 31, 2003	158.4		255.0		52.5		16.6		–		18.1		500.6
	Discoveries, additions and extensions	14.0		29.7		2.0		8.1		–		–		53.8
	Purchase of reserves	0.2		34.0		0.9		–		–		–		35.1
	Sale of reserves	(2.1	)	(3.3	)	–		–		–		–		(5.4	)
	Net revisions and transfers	(2.5	)	24.0		(1.3	)	0.3		–		(7.2	)	13.3
	2004 Production	(15.8	)	(44.3	)	(7.9	)	(3.1	)	–		–		(71.1	)

	Proved Reserves at December 31, 2004	152.2		295.1		46.2		21.9		–		10.9		526.3
	Discoveries, additions and extensions	10.6		44.4		16.4		4.7		–		(0.9	)	75.2
	Purchase of reserves	0.1		74.7		17.0		0.7		–		–		92.5
	Sale of reserves	–		(0.9	)	–		–		–		–		(0.9	)
	Net revisions and transfers	(5.2	)	31.7		(16.0	)	0.3		–		0.8		11.6
	2005 Production	(15.5	)	(47.9	)	(7.7	)	(3.5	)	–		(3.1	)	(77.7	)

	Proved Reserves at December 31, 2005	142.2		397.1		55.9		24.1		–		7.7		627.0

Proved Developed
	December 31, 2002	157.2		210.8		11.9		2.4		84.1		–		466.4
	December 31, 2003	155.4		211.8		18.6		14.6		–		–		400.4
	December 31, 2004	142.6		252.3		19.2		16.5		–		10.5		441.1
	December 31, 2005	132.0		309.0		35.8		14.6		–		7.7		499.1

32 A N N U A L I N F O R M A T I O N F O R M

CONTINUITY OF NET PROVED RESERVES¹

		North America²		North Sea³		Southeast Asia and Australia⁴		North Africa⁵	Sudan	Trinidad and Tobago		Total

Natural Gas (bcf)
Total proved
	Proved reserves at December 31, 2002	1,986.1		237.9		968.9		–	–	220.0		3,412.9
	Discoveries, additions and extensions	276.3		1.0		64.0		–	–	–		341.3
	Purchase of reserves	92.2		14.4		–		–	–	–		106.6
	Sale of reserves	(11.4	)	–		–		–	–	–		(11.4	)
	Net revisions and transfers	(14.9	)	19.8		(6.1	)	–	–	(9.0	)	(10.2	)
	2003 Production	(247.6	)	(37.5	)	(40.1	)	–	–	–		(325.2	)

	Proved reserves at December 31, 2003	2,080.7		235.6		986.7		–	–	211.0		3,514.0
	Discoveries, additions and extensions	370.6		8.0		521.9		–	–	–		900.5
	Purchase of reserves	19.1		0.1		–		–	–	–		19.2
	Sale of reserves	(57.1	)	(0.5	)	–		–	–	–		(57.6	)
	Net revisions and transfers	(19.2	)	(26.4	)	93.5		–	–	5.5		53.4
	2004 Production	(260.6	)	(39.5	)	(47.3	)	–	–	–		(347.4	)
	Proved reserves at December 31, 2004	2,133.5		177.3		1,554.8		–	–	216.5		4,082.1

	Discoveries, additions and extensions	274.9		23.4		81.7		–	–	–		380.0
	Purchase of reserves	11.7		61.3		30.8		1.2	–	–		105.0
	Sale of reserves	(1.1	)	–		–		–	–	–		(1.1	)
	Net revisions and transfers	2.5		13.5		(94.0	)	–	–	(2.9	)	(80.9	)
	2005 Production	(265.6	)	(36.2	)	(73.1	)	–	–	–		(374.9	)

	Proved reserves at December 31, 2005	2,155.9		239.3		1,500.2		1.2	–	213.6		4,110.2

Proved Developed
	December 31, 2002	1,746.9		210.0		471.6		–	–	–		2,428.5
	December 31, 2003	1,890.4		200.7		593.9		–	–	–		2,685.0
	December 31, 2004	1,788.2		150.0		624.0		–	–	–		2,562.2
	December 31, 2005	1,771.8		181.1		548.8		0.8	–	–		2,502.5

Notes:

1: For definitions of reserves, see the notes found on pages 31 and 32 of this Annual Information Form.
2: North American net proved reserves exclude synthetic crude oil reserves: 2002 – 36.7 mmbbls; 2003 – 35.8 mmbbls; 2004 – 35.2 mmbbls; and 2005 – 34.3 mmbbls.
3: North Sea for 2002 includes the United Kingdom and the Netherlands; for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
4: Southeast Asia and Australia for 2002, 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
5: North Africa for 2002, 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M33

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES

Future net cash flows were calculated by applying the respective year end prices to the Company's estimated future production of proved reserves and deducting estimates of future development, asset retirement, production and transportation costs and income taxes. Future costs have been estimated based on existing economic and operating conditions. Future income taxes have been estimated based on statutory tax rates enacted at year end. The present values of the estimated future cash flows were determined by applying a 10% discount rate prescribed by the Financial Accounting Standards Board.

In order to increase the comparability between companies, the standardized measure of discounted future net cash flows necessarily employs uniform assumptions that do not necessarily reflect management's best estimate of future events and anticipated outcomes. Accordingly, the Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair market value of the oil and gas properties. Actual future net cash flows will differ significantly from those estimated due to, but not limited to, the following:

•: production rates will differ from those estimated both in terms of timing and amount. For example, future production may include significant additional volumes from unproved reserves;
•: future prices and economic conditions will differ from those at year end. For example, changes in prices increased the discounted future net cash flows by $12.8 billion in 2005;
•: future production and development costs will be determined by future events and will differ from those at year end; and
•: estimated income taxes will differ in terms of amounts and timing dependent on the above factors, changes in enacted rates and the impact of future expenditures on unproved properties.

The standardized measure of discounted future net cash flows was prepared using the following prices:

		2005	2004	2003

Crude oil and liquids ($/bbl)
	North America	50.95	34.27	33.32
	North Sea¹	66.54	46.65	37.89
	Southeast Asia and Australia²	65.88	44.01	41.71
	North Africa³	68.14	48.71	38.91
	Trinidad and Tobago	64.17	42.67	39.12

		62.83	42.66	37.04

Natural Gas ($/mcf)
	North America	10.87	7.32	6.32
	North Sea¹	10.67	6.25	5.55
	Southeast Asia and Australia²	4.87	3.54	3.74
	Trinidad and Tobago	2.17	1.81	1.03

		8.03	5.47	5.17

Notes:

1: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
2: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
3: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

34 A N N U A L I N F O R M A T I O N F O R M

Discounted Future Net Cash Flows from Proved Reserves

As at December 31 (millions of Canadian dollars)		North America		North Sea²		Southeast Asia and Australia³		North Africa⁴		Trinidad and Tobago		Total

2005	Future Cash Inflows¹	30,776		28,975		11,039		1,651		976		73,417
	Future Costs
	Transportation	(649	)	(764	)	(661	)	(70	)	–		(2,144	)
	Production	(5,148	)	(10,576	)	(1,645	)	(243	)	(169	)	(17,781	)
	Development and asset retirement	(2,601	)	(3,953	)	(980	)	(94	)	(102	)	(7,730	)

	Future net inflows before income taxes	22,378		13,682		7,753		1,244		705		45,762
	Future income & production revenue taxes	(6,793	)	(6,497	)	(3,282	)	(423	)	(314	)	(17,309	)

	Future net cash flows	15,585		7,185		4,471		821		391		28,453
	10% discount factor	(6,330	)	(1,579	)	(1,899	)	(291	)	(161	)	(10,260	)

	Discounted future cash flows	9,255		5,606		2,572		530		230		18,193

2004	Future Cash Inflows¹	20,825		14,916		7,525		1,071		854		45,191
	Future Costs
	Transportation	(501	)	(494	)	(655	)	(61	)	–		(1,711	)
	Production	(4,847	)	(7,028	)	(1,235	)	(148	)	(128	)	(13,386	)
	Development and asset retirement	(2,138	)	(3,214	)	(770	)	(29	)	(114	)	(6,265	)

	Future net inflows before income taxes	13,339		4,180		4,865		833		612		23,829
	Future income & production revenue taxes	(3,650	)	(1,724	)	(1,959	)	(245	)	(262	)	(7,840	)

	Future net cash flows	9,689		2,456		2,906		588		350		15,989
	10% discount factor	(3,845	)	(302	)	(1,402	)	(165	)	(115	)	(5,829	)

	Discounted future cash flows	5,844		2,154		1,504		423		235		10,160

2003	Future Cash Inflows¹	18,444		11,032		5,930		645		928		36,979
	Future Costs
	Production	(4,958	)	(5,686	)	(1,107	)	(165	)	(122	)	(12,038	)
	Development and asset retirement	(1,490	)	(1,989	)	(697	)	(14	)	(248	)	(4,438	)

	Future net inflows before income taxes	11,996		3,357		4,126		466		558		20,503
	Future income & production revenue taxes	(3,664	)	(1,393	)	(1,601	)	(107	)	(299	)	(7,064	)

	Future net cash flows	8,332		1,964		2,525		359		259		13,439
	10% discount factor	(3,740	)	(147	)	(1,118	)	(86	)	(112	)	(5,203	)

	Discounted future cash flows	4,592		1,817		1,407		273		147		8,236

Notes:

1: Net oil and gas revenue derived from proved reserves is net of applicable royalties.
2: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
3: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
4: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M35

Principal Sources of Changes in Discounted Cash Flows

	2005		2004		2003

Sales of oil & gas produced, net of production costs	(6,193	)	(3,866	)	(3,308	)
Net change in prices	12,824		3,506		(3,200	)
Net change in transportation costs	68		(954	)
Net change in production costs	(1,163	)	410		(357	)
Net change in future development and asset retirement costs	(426	)	(638	)	(87	)
Development costs incurred during the year	1,256		623		672
Extensions, discoveries and improved recovery	3,267		2,386		1,229
Revisions of previous reserve estimates	802		(615	)	92
Net purchases and sales of reserves in place	3,250		150		(1,225	)
Accretion of discount	1,522		1,263		1,555
Net change in taxes	(6,934	)	(598	)	2,399
Other	(240	)	257		(44	)

Net change	8,033		1,924		(2,274	)
Balance, beginning of year	10,160		8,236		10,510

Balance, end of year	18,193		10,160		8,236

36 A N N U A L I N F O R M A T I O N F O R M

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years ended December 31 (millions of Canadian dollars)		North America	North Sea²	Southeast Asia and Australia³	Sudan	North Africa⁴	Trinidad and Tobago		Other		Total

2005
	Net oil and gas revenue derived from proved reserves¹	3,160	3,265	974	–	214	194		–		7,807
	Less:
	Production costs	442	845	87	–	24	11		–		1,409
	Transportation	74	79	43	–	9	–		–		205
	Exploration and dry hole expense	250	106	50	–	–	26		83		515
	Depreciation, depletion and amortization	906	709	144	–	36	47		–		1,842
	Tax expense (recovery)	548	826	270	–	55	61		(28	)	1,732

	Results of operations	940	700	380	–	90	49		(55	)	2,104

2004
	Net oil and gas revenue derived from proved reserves¹	2,304	2,038	729	–	156	–		–		5,227
	Less:
	Production costs	392	662	98	–	17	–		–		1,169
	Transportation	75	66	42	–	9	–		–		192
	Exploration and dry hole expense	251	138	45	–	4	33		78		549
	Depreciation, depletion and amortization	729	689	174	–	30	–		–		1,622
	Tax expense (recovery)	219	288	152	–	36	(11	)	(27	)	657

	Results of operations	638	195	218	–	60	(22	)	(51	)	1,038

2003
	Net oil and gas revenue derived from proved reserves¹	2,148	1,762	436	112	43	–		–		4,501
	Less:
	Production costs	367	528	87	18	12	–		–		1,012
	Transportation	78	63	36	–	4	–		–		181
	Exploration and dry hole expense	222	90	26	5	1	34		86		464
	Depreciation, depletion and amortization	647	635	95	–	17	–		–		1,394
	Tax expense (recovery)	328	237	77	30	3	(12	)	(31	)	632

	Results of operations	506	209	115	59	6	(22	)	(55	)	818

Notes:

1: Net oil and gas revenue derived from proved reserves is net of applicable royalties and reflects hedging activities.
2: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
3: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
4: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M37

CAPITALIZED COSTS RELATING TO OIL AND GAS ACTIVITIES

Years ended December 31 (millions of Canadian dollars)		North America	North Sea¹	Southeast Asia and Australia²	Sudan	North Africa³	Trinidad and Tobago	Other	Total

2005
	Proved properties	10,125	8,798	1,877	–	230	166	–	21,196
	Unproved properties	277	1,297	90	–	23	126	56	1,869
	Incomplete wells and facilities	82	6	41	–	–	28	43	200

		10,484	10,101	2,008	–	253	320	99	23,265
	Less: Accumulated depreciation, depletion and amortization	4,069	4,062	586	–	77	46	–	8,840

	Net capitalized costs	6,415	6,039	1,422	–	176	274	99	14,425

2004
	Proved properties	8,680	7,009	1,487	–	197	229	5	17,607
	Unproved properties	192	54	16	–	23	16	34	335
	Incomplete wells and facilities	49	3	46	–	–	35	12	145

		8,921	7,066	1,549	–	220	280	51	18,087
	Less: Accumulated depreciation, depletion and amortization	3,195	4,006	501	–	42	–	–	7,744

	Net capitalized costs	5,726	3,060	1,048	–	178	280	51	10,343

2003
	Proved properties	7,751	6,339	1,466	–	151	120	–	15,827
	Unproved properties	227	88	95	–	67	16	3	496
	Incomplete wells and facilities	31	1	22	–	–	1	5	60

		8,009	6,428	1,583	–	218	137	8	16,383
	Less: Accumulated depreciation, depletion and amortization	2,694	3,451	498	–	16	–	–	6,659

	Net capitalized costs	5,315	2,977	1,085	–	202	137	8	9,724

Notes:

1: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
2: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
3: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

38 A N N U A L I N F O R M A T I O N F O R M

COSTS INCURRED IN OIL AND GAS ACTIVITIES

Years ended December 31 (millions of Canadian dollars)		North America	North Sea¹	Southeast Asia and Australia²	Sudan		North Africa³	Trinidad and Tobago	Other	Total

2005
	Property acquisition costs
	Proved Unproved	222 130	1,987 1,269	220 64	– –		15 –	– –	– –	2,444 1,463
	Exploration costs	539	165	73	–		2	51	134	964
	Development costs	853	867	231	–		25	21	–	1,997
	Asset retirement costs	90	45	29	–		–	5	–	169

	Total costs incurred	1,834	4,333	617	–		42	77	134	7,037

2004
	Property acquisition costs
	Proved Unproved	77 165	233 71	– –	– –		– –	– –	– 39	310 275
	Exploration costs	459	150	54	–		–	34	86	783
	Development costs	785	357	201	–		8	158	–	1,509
	Asset retirement costs	36	51	3	–		–	7	–	97

	Total costs incurred	1,522	862	258	–		8	199	125	2,974

2003
	Property acquisition costs
	Proved Unproved	369 184	189 2	– –	– –		– –	– –	– 3	558 189
	Exploration costs	336	99	70	7		4	58	90	664
	Development costs	600	397	246	(5	)	30	72	–	1,340
	Asset retirement costs	125	285	5	–		–	–	–	415

	Total costs incurred	1,614	972	321	2		34	130	93	3,166

Notes:

1: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
2: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
3: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M39

PRODUCT NETBACKS (NET)^1,2

The following table provides information on product netbacks net of royalties, expressed in US Dollars.

		December 31

(US$ – production net of royalties)		2005		2004	2003

North America	Oil and liquids (US$/bbl)
	Sales price	43.55		32.44	25.64
	Hedging (gain)	4.16		5.81	2.21
	Transportation	0.52		0.48	0.44
	Operating costs	7.54		6.55	5.67

		31.33		19.60	17.32

	Natural gas (US$/mcf)
	Sales price	7.51		5.26	4.74
	Hedging (gain)	–		0.10	0.10
	Transportation	0.20		0.19	0.19
	Operating costs	0.93		0.76	0.68

		6.38		4.21	3.77

North Sea³	Oil and liquids (US$/bbl)
	Sales price	53.74		37.23	28.35
	Hedging (gain)	(0.02	)	5.77	1.43
	Transportation	1.00		0.89	0.83
	Operating costs	14.37		10.89	8.61

		38.39		19.68	17.48

	Natural gas (US$/mcf)
	Sales price	5.88		4.29	3.41
	Transportation	0.44		0.29	0.28
	Operating costs	0.73		0.47	0.28

		4.71		3.53	2.85

Southeast Asia and Australia⁴	Oil and liquids (US$/bbl)
	Sales price	57.24		39.49	29.66
	Hedging (gain)	–		–	2.78
	Transportation	0.12		0.30	0.48
	Operating costs	6.18		7.32	8.48

		50.94		31.87	17.92

	Natural gas (US$/mcf)
	Sales price	5.29		3.65	4.12
	Transportation	0.49		0.42	0.59
	Operating costs	0.35		0.27	0.38

		4.45		2.96	3.15

North Africa⁵	Oil (US$/bbl)
	Sales price	55.16		39.48	27.84
	Hedging (gain)	–		–	3.13
	Transportation	2.22		2.20	2.55
	Operating costs	6.09		4.41	7.06

		46.85		32.87	15.10

40 A N N U A L I N F O R M A T I O N F O R M

		December 31

(US$ – production net of royalties)		2005	2004	2003

Trinidad and Tobago	Oil (US$/bbl)
	Sales price	52.44	–	–
	Operating costs	2.86	–	–

		49.58	–	–

Sudan	Oil (US$/bbl)
	Sales price	–	–	31.33
	Operating costs	–	–	4.96

		–	–	26.37

Total Company	Oil and liquids (US$/bbl)
	Sales price	52.07	36.57	27.90
	Hedging (gain)	0.82	4.90	1.71
	Transportation	0.83	0.79	0.70
	Operating costs	11.36	9.25	7.72

		39.06	21.63	17.77

	Natural gas (US$/mcf)
	Sales price	6.89	4.84	4.50
	Hedging (gain)	–	0.07	0.07
	Transportation	0.28	0.25	0.25
	Operating costs	0.80	0.63	0.59

		5.81	3.89	3.59

Notes:

1: Pursuant to US reporting practices, netbacks are calculated using US$ and production after deduction of royalty volumes.
2: Unit operating costs include pipeline costs for the North Sea. Prior years have been restated accordingly. Netbacks do not include synthetic oil.
3: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
4: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
5: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M41

SUPPLEMENTAL OIL AND GAS INFORMATION

The following information is provided in addition to the information required under US disclosure standards.

CONTINUITY OF GROSS PROVED RESERVES¹

		North America²		North Sea³		Southeast Asia and Australia⁴		North Africa⁵		Trinidad and Tobago		Sudan		Total

Crude Oil and Liquids (mmbbls)
Total proved
	Proved reserves at December 31, 2002	199.1		249.7		60.6		27.4		19.2		160.9		716.9
	Discoveries, additions, and extensions	16.0		8.2		25.2		3.9		–		–		53.3
	Purchase of reserves	1.3		21.1		–		–		–		–		22.4
	Sale of reserves	(5.3	)	–		–		–		–		(156.1	)	(161.4	)
	Net revisions and transfers	(0.1	)	18.7		7.6		0.1		–		–		26.3
	2003 Production	(20.8	)	(41.3	)	(9.0	)	(2.4	)	–		(4.8	)	(78.3	)

	Proved reserves at December 31, 2003	190.2		256.4		84.4		29.0		19.2		–		579.2
	Discoveries, additions, and extensions	17.3		29.8		13.0		13.9		–		–		74.0
	Purchase of reserves	0.2		34.1		1.3		–		–		–		35.6
	Sale of reserves	(2.6	)	(3.3	)	–		–		–		–		(5.9	)
	Net revisions and transfers	(2.2	)	24.6		3.4		(0.7	)	(7.8	)	–		17.3
	2004 Production	(19.9	)	(44.6	)	(13.0	)	(5.0	)	–		–		(82.5	)

	Proved Reserves at December 31, 2004	183.0		297.0		89.1		37.2		11.4		–		617.7
	Discoveries, additions, and extensions	12.6		43.9		12.7		8.6		(0.1	)	–		77.7
	Purchase of reserves	0.2		74.9		22.1		0.8		–		–		98.0
	Sale of reserves	(0.0	)	(0.9	)	–		–		–		–		(0.9	)
	Net revisions and transfers	(2.8	)	34.3		(1.3	)	2.7		0.9		–		33.8
	2005 Production	(19.6	)	(48.4	)	(12.9	)	(5.6	)	(3.7	)	–		(90.2	)

	Proved reserves at December 31, 2005	173.4		400.8		109.7		43.7		8.5		–		736.1

Proved Developed
	December 31, 2002	190.0		212.6		19.7		4.8		–		143.4		570.5
	December 31, 2003	186.4		213.0		29.5		25.5		–		–		454.4
	December 31, 2004	171.0		254.0		39.9		27.9		11.0		–		503.8
	December 31, 2005	161.0		312.3		67.7		26.2		8.5		–		575.7

42 A N N U A L I N F O R M A T I O N F O R M

CONTINUITY OF GROSS PROVED RESERVES¹

		North America²		North Sea³		Southeast Asia and Australia⁴		North Africa⁵	Trinidad and Tobago		Sudan	Total

Natural Gas (bcf)
Total proved
	Proved reserves at December 31, 2002	2,593.4		262.1		1,528.3		–	223.5		–	4,607.3
	Discoveries, additions, and extensions	351.5		1.0		107.0		–	–		–	459.5
	Purchase of reserves	107.1		14.4		–		–	–		–	121.5
	Sale of reserves	(14.3	)	–		–		–	–		–	(14.3	)
	Net revisions and transfers	(77.0	)	17.5		(20.6	)	–	–		–	(80.1	)
	2003 Production	(315.8	)	(39.9	)	(42.7	)	–	–		–	(398.4	)

	Proved reserves at December 31, 2003	2,644.9		255.1		1,572.0		–	223.5		–	4,695.5
	Discoveries, additions, and extensions	478.5		8.0		765.3		–	–		–	1,251.8
	Purchase of reserves	22.8		0.1		–		–	–		–	22.9
	Sale of reserves	(72.7	)	(0.5	)	–		–	–		–	(73.2	)
	Net revisions and transfers	(113.2	)	(33.2	)	(58.7	)	–	(7.0	)	–	(212.1	)
	2004 Production	(324.9	)	(41.6	)	(95.2	)	–	–		–	(461.7	)

	Proved reserves at December 31, 2004	2,635.4		187.9		2,183.4		–	216.5		–	5,223.2
	Discoveries, additions, and extensions	361.0		24.0		129.1		–	–		–	514.1
	Purchase of reserves	16.8		61.3		38.9		1.4	–		–	118.4
	Sale of reserves	(1.2	)	–		–		–	–		–	(1.2	)
	Net revisions and transfers	28.6		14.1		(3.4	)	–	(1.3	)	–	38.0
	2005 Production	(333.8	)	(38.5	)	(103.6	)	–	–		–	(475.9	)

	Proved reserves at December 31, 2005	2,706.8		248.8		2,244.4		1.4	215.2		–	5,416.6

Proved Developed
	December 31, 2002	2,278.7		232.8		723.8		–	–		–	3,235.3
	December 31, 2003	2,404.0		220.1		920.9		–	–		–	3,545.0
	December 31, 2004	2,207.3		160.6		858.2		–	–		–	3,226.1
	December 31, 2005	2,226.5		189.7		793.2		0.9	–		–	3,210.3

Notes:

1: For definitions of reserves, see the notes found on pages 31 and 32 of this Annual Information Form.
2: North American gross proved reserves exclude synthetic crude oil reserves: 2002 – 43.2 mmbbls; 2003 – 42.3 mmbbls; 2004 – 41.2 mmbbls; 2005 – 40.2 mmbbls.
3: North Sea for 2002 includes the United Kingdom and the Netherlands; for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
4: Southeast Asia and Australia for 2002, 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
5: North Africa for 2002, 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M43

PRODUCT NETBACKS (GROSS)¹

The following table provides information on product netbacks on a gross basis expressed in Canadian dollars on a quarterly basis for the periods indicated.

		2005							2004					2003
				Three months ended						Three months ended
C$ Gross		Total Year		Dec 31		Sep 30	Jun 30	Mar 31	Total Year	Dec 31	Sep 30	Jun 30	Mar 31	Total Year

North	Oil and liquids ($/bbl)
America	Sales price	52.62		54.84		60.92	48.16	46.50	42.11	44.05	45.47	41.39	37.56	35.78
	Hedging	3.99		4.28		4.89	3.68	3.10	5.95	8.64	7.28	4.81	3.07	2.45
	Royalties	10.79		10.69		12.83	9.77	9.87	8.59	8.76	9.51	8.52	7.57	7.37
	Transportation	0.50		0.51		0.50	0.54	0.45	0.49	0.46	0.53	0.48	0.51	0.48
	Operating costs	7.24		8.33		7.22	7.18	6.32	6.75	7.79	6.64	6.67	5.90	6.28

		30.10		31.03		35.48	26.99	26.76	20.33	18.40	21.51	20.91	20.51	19.20

	Natural gas ($/mcf)
	Sales price	9.05		12.25		9.15	7.72	7.07	6.83	6.99	6.63	7.08	6.61	6.58
	Hedging	–		–		–	–	–	0.10	0.04	0.14	0.16	0.06	0.11
	Royalties	1.80		2.46		1.82	1.53	1.39	1.31	1.20	1.29	1.44	1.32	1.37
	Transportation	0.19		0.23		0.19	0.18	0.17	0.20	0.21	0.20	0.20	0.19	0.21
	Operating costs	0.90		0.95		0.96	0.88	0.79	0.79	0.80	0.81	0.80	0.77	0.75

		6.16		8.61		6.18	5.13	4.72	4.43	4.74	4.19	4.48	4.27	4.14

North	Oil and liquids ($/bbl)
Sea²	Sales price	64.78		66.53		74.36	60.24	57.29	48.29	50.26	54.57	47.27	41.55	39.72
	Hedging	(0.02	)	(0.07	)	–	–	–	7.36	10.02	10.31	5.74	3.55	2.01
	Royalties	0.71		0.84		0.76	0.78	0.43	0.43	0.52	0.49	0.60	0.13	(0.08	)
	Transportation	1.19		1.27		1.20	1.11	1.14	1.14	1.09	1.28	1.11	1.11	1.16
	Operating costs	17.14		17.14		17.33	18.89	15.32	14.06	12.61	16.57	13.87	13.49	12.05

		45.76		47.35		55.07	39.46	40.40	25.30	26.02	25.92	25.95	23.27	24.58

	Natural gas ($/mcf)
	Sales price	7.08		8.35		6.08	6.27	6.98	5.55	6.08	4.88	5.17	5.85	4.77
	Royalties	0.49		0.48		0.48	0.53	0.47	0.42	0.37	0.46	0.13	0.66	0.28
	Transportation	0.50		0.40		0.47	0.61	0.54	0.35	0.38	0.32	0.31	0.37	0.37
	Operating costs	0.82		0.96		0.68	0.68	0.86	0.55	0.72	0.69	0.58	0.28	0.37

		5.27		6.51		4.45	4.45	5.11	4.23	4.61	3.41	4.15	4.54	3.75

Southeast	Oil and liquids ($/bbl)
Asia and	Sales price	68.79		68.30		76.86	67.60	60.35	51.29	53.81	56.95	50.19	44.10	41.35
Australia³	Royalties	27.28		27.27		28.73	27.46	25.27	21.24	21.94	23.37	21.77	17.82	16.09
	Transportation	0.09		(0.12	)	0.27	0.25	0.08	0.23	0.18	0.20	0.28	0.25	0.41
	Operating costs	4.48		5.04		4.14	4.34	4.08	5.57	5.60	6.60	5.30	4.78	7.22

		36.94		36.11		43.72	35.55	30.92	24.25	26.09	26.78	22.84	21.25	17.63

	Natural gas ($/mcf)
	Sales price	6.40		6.72		6.98	6.36	5.44	4.74	4.55	5.03	4.85	4.50	5.72
	Royalties	1.95		1.98		2.14	1.88	1.75	1.19	1.20	1.39	1.33	0.81	0.29
	Transportation	0.41		0.43		0.42	0.24	0.55	0.41	0.38	0.40	0.43	0.42	0.77
	Operating costs	0.30		0.30		0.29	0.31	0.28	0.27	0.25	0.25	0.28	0.29	0.50

		3.74		4.01		4.13	3.93	2.86	2.87	2.72	2.99	2.81	2.98	4.16

44 A N N U A L I N F O R M A T I O N F O R M

		2005					2004					2003
			Three months ended					Three months ended
C$ Gross		Total Year	Dec 31	Sep 30	Jun 30	Mar 31	Total Year	Dec 31	Sep 30	Jun 30	Mar 31	Total Year

North	Oil ($/bbl)
Africa⁴	Sales price	66.71	68.02	72.00	65.40	60.90	51.17	46.50	63.98	49.09	44.62	39.01
	Hedging	–	–	–	–	–	–	–	–	–	–	2.23
	Royalties	25.72	25.00	27.37	25.81	24.53	19.65	18.48	20.15	17.34	22.59	19.18
	Transportation	1.65	1.65	1.62	1.68	1.65	1.76	1.64	1.79	1.84	1.80	1.77
	Operating costs	4.52	5.06	4.25	3.28	5.64	3.51	3.77	3.86	4.75	1.71	5.07

		34.82	36.31	38.76	34.63	29.08	26.25	22.61	38.18	25.16	18.52	10.76

Trinidad	Oil ($/bbl)
and	Sales price	63.40	63.78	71.86	58.90	–	–	–	–	–	–	–
Tobago	Royalties	9.82	10.73	11.16	10.03	–	–	–	–	–	–	–
	Operating costs	2.94	2.45	2.83	2.80	–	–	–	–	–	–	–

		50.64	50.60	57.87	46.07	–	–	–	–	–	–	–

Sudan	Oil ($/bbl)
	Sales price	–	–	–	–	–	–	–	–	–	–	43.89
	Royalties	–	–	–	–	–	–	–	–	–	–	20.34
	Operating costs	–	–	–	–	–	–	–	–	–	–	3.73

		–	–	–	–	–	–	–	–	–	–	19.82

Total	Oil and liquids ($/bbl)
Company	Sales price	62.78	64.62	71.51	58.58	55.40	47.45	49.10	53.30	46.42	41.15	39.09
	Hedging	0.85	0.77	1.08	0.86	0.72	5.42	7.53	7.15	4.31	2.67	2.05
	Royalties	8.64	8.81	9.89	8.32	7.41	6.84	6.85	7.86	6.71	6.00	5.59
	Transportation	0.86	0.86	0.88	0.86	0.84	0.88	0.84	0.95	0.87	0.87	0.83
	Operating costs	11.81	12.25	11.60	12.49	10.85	10.32	9.84	11.58	10.32	9.60	9.25

		40.62	41.93	48.06	36.05	35.58	23.99	24.04	25.76	24.21	22.01	21.37

	Natural gas ($/mcf)
	Sales price	8.30	10.63	8.43	7.31	6.73	6.28	6.38	6.15	6.47	6.13	6.30
	Hedging	–	–	–	–	–	0.07	0.03	0.10	0.12	0.04	0.08
	Royalties	1.71	2.14	1.79	1.53	1.37	1.21	1.12	1.25	1.31	1.15	1.14
	Transportation	0.27	0.29	0.26	0.22	0.28	0.26	0.26	0.25	0.26	0.25	0.28
	Operating costs	0.76	0.82	0.79	0.74	0.69	0.66	0.67	0.68	0.68	0.63	0.69

		5.56	7.38	5.59	4.82	4.39	4.08	4.30	3.87	4.10	4.06	4.11

Notes:

1: Unit Operating costs include pipeline costs for the North Sea. First quarter 2005 and prior periods have been restated accordingly. Netbacks do not include synthetic oil.
2: North Sea for 2003 and 2004 includes the United Kingdom, Norway and the Netherlands, but excludes Denmark.
3: Southeast Asia and Australia for 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.
4: North Africa for 2003 and 2004 includes Algeria, but excludes Tunisia.

A N N U A L I N F O R M A T I O N F O R M45

ADDITIONAL INFORMATION

Future commitments to buy, sell, exchange, process and transport oil or gas of the Company are described under note 12 entitled "Contingencies and Commitments" in the audited consolidated financial statements of the Company for the year ended December 31, 2004, which information is incorporated herein by reference.

COMPETITIVE CONDITIONS

The oil and gas industry, both within Canada and internationally, is highly competitive in all aspects of the business. The Company actively competes for the acquisition of properties, the exploration for and development of new sources of supply, the contractual services for oil and gas drilling and production equipment and services, the transporting and marketing of current production and industry personnel. With respect to the exploration, development and marketing of oil and natural gas, the Company's competitors include major integrated oil and gas companies, numerous other independent oil and gas companies, individual producers and operators and national oil companies. A number of the Company's competitors have financial and other resources substantially in excess of those available to the Company. In addition, oil and gas producers in general compete indirectly against others engaged in supplying alternative forms of energy, fuel and related products to consumers.

SOCIAL RESPONSIBILITY AND ENVIRONMENTAL PROTECTION

Social Policies

Talisman has formal policies and procedures that support the Company's commitment to corporate responsibility. Talisman's Policy on Business Conduct and Ethics (the "Ethics Policy"), a statement of the Company's ethical principles, is the foundation of the Company's corporate responsibility framework. Every employee of Talisman is required to read the Ethics Policy and understand how it relates to his or her business dealings as a condition of employment. In addition, each employee is required to complete at least annually a declaration confirming his or her compliance with the Ethics Policy or disclosing any deviations therefrom, which declarations are reviewed by the Chief Executive Officer and reported to the Board of Directors. In 2005, all permanent Talisman employees were required to complete ethics training.

In 2004, Talisman adopted a security policy (the "Security Policy"), which is in the process of being implemented. Both the Ethics Policy and the Security Policy incorporate the Voluntary Principles on Security and Human Rights.

Health, Safety and Environmental Protection

Talisman's corporate health, safety and environment ("HSE") policy commits to three fundamental principles: providing safe and healthy operations, continuous improvement of the Company's environmental performance and respecting the interests of neighbours and other stakeholders. Talisman maintains an integrated HSE management framework and processes to achieve its HSE objectives in a structured way. Internal guidance documents (standards and plans), programs, activities and service arrangements support the implementation of these management processes. Talisman's regional operations are empowered to organize their HSE programs and systems in ways that are locally meaningful and that address their unique risks and priorities. Talisman audits, both internally and externally, its operations periodically to support continuous improvement and demonstrate compliance. The Company also conducts environmental due diligence on applicable asset and corporate acquisitions to identify and properly account for pre-existing environmental liabilities.

The oil and gas industry is subject to safety and environmental regulation pursuant to extensive legislation, enacted by various levels of government, both in Canada and internationally. The Company maintains a comprehensive range of internal programs and controls to promote regulatory compliance and an appropriate level of safety and environmental protection across its operations. Public expectation regarding the industry's safety and environmental performance remains high and this continues to translate into new and generally more rigorous policies, legislation and regulations. Within jurisdictions and sectors, these regulatory instruments apply generally and do not typically influence competitive position.

The Company does not anticipate making extraordinary material expenditures for environmental compliance during 2006. However, it does expect to incur site restoration costs over a prolonged period as existing fields become fully produced. Talisman provides for future abandonment and reclamation costs in its financial statements in accordance with Canadian generally accepted accounting principles. Additional information regarding future abandonment and reclamation costs is set forth under note 12 entitled "Contingencies and Commitments" in the audited consolidated financial statements of the Company for the year ended December 31, 2005, which information is incorporated herein by reference.

More information about Talisman's social and environmental policies and its corporate responsibility performance is available on the Company's corporate web site at www.talisman-energy.com. The information available on the web site includes the Ethics Policy, Security Policy, Talisman's annual Corporate Responsibility Report and HSE management framework.

46 A N N U A L I N F O R M A T I O N F O R M

EMPLOYEES

At December 31, 2005, Talisman's permanent staff complement¹ was 2,138, as set forth in the table below.

		Permanent Staff complement¹ as at December 31, 2005

North America		1,542
North Sea		383
Southeast Asia and Australia		208
Trinidad and Tobago		4
Other²		1

Total		2,138

Notes:

1: Contractors and temporary staff are not included in complement numbers.
2: "Other" includes Qatar.

DESCRIPTION OF CAPITAL STRUCTURE

SHARE CAPITAL

The Company's authorized share capital consists of an unlimited number of common shares ("Common Shares") without nominal or par value and an unlimited number of first and second preferred shares. All of the Common Shares are fully paid and non-assessable. As at the date of this Annual Information Form no preferred shares are outstanding.

Holders of Common Shares are entitled to receive notice of and to attend all annual and special meetings of shareholders. Each Common Share carries with it the right to one vote. Subject to the rights of holders of other classes of shares of the Company who are entitled to receive dividends in priority to or rateable with the Common Shares, the Board of Directors may, in its sole discretion, declare dividends on the Common Shares to the exclusion of any other class of shares of the Company. In the event of liquidation, dissolution or winding-up of the Company or any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs, and subject to the rights of other classes of shares on a priority basis, the holders of Common Shares are entitled to participate rateably in any distribution of any assets of the Company.

The first preferred shares are issuable in one or more series, each series consisting of the number of shares and having the designation, rights, privileges, restrictions and conditions as are determined before issue by the Board of Directors of the Company. The first preferred shares rank on a parity with the first preferred shares of every other series with respect to declared or accumulated dividends and return of capital. In addition, the first preferred shares are entitled to a preference over the second preferred shares and the Common Shares with respect to the payment of dividends and the distribution of assets of the Company in the event of liquidation, dissolution or winding-up of the Company. The first preferred shares are not, except as required by law and as may be determined by the Board of Directors prior to the issuance of a series, entitled to notice of, or to vote at meetings of shareholders.

The second preferred shares are issuable in one or more series, each series consisting of the number of shares and having the designation, rights, privileges, restrictions and conditions as are determined before issue by the Board of Directors of the Company. The second preferred shares rank on a parity with the second preferred shares of every other series with respect to declared or accumulated dividends and return of capital. In addition, the second preferred shares are entitled to a preference over the Common Shares with respect to the payment of dividends and the distribution of assets of the Company in the event of liquidation, dissolution or winding-up of the Company. The second preferred shares are not, except as required by law and may be determined by the Board of Directors prior to the issuance of a series, entitled to notice of, or to vote at meetings of shareholders.

RATINGS

The Company's senior unsecured long-term debt securities have received a "Baa1" rating from Moody's Investors Service, Inc. ("Moody's") and a "BBB(high)" rating with a stable trend from Dominion Bond Rating Service Limited ("DBRS"). The rating from Moody's is under review for downgrade. Standard & Poor's Corporation ("S&P") has issued a long term corporate credit rating of BBB+ with a negative outlook. Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of payment and of the capacity of a company to meet its financial commitment on the rated obligation in accordance with the terms of the rated obligation.

The credit ratings accorded to the Company's senior unsecured long-term debt securities are not recommendations to purchase, hold or sell the debt securities and may be revised or withdrawn entirely at any time by a rating agency. Credit ratings may not reflect the potential impact of all risks or the value of the debt securities. In addition, real or anticipated changes in the rating assigned to the debt securities will generally affect the

A N N U A L I N F O R M A T I O N F O R M47

market value of the debt securities. There can be no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from least credit risk to greatest credit risk of such securities rated. Moody's applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its long term debt rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of that generic rating category. According to the Moody's rating system, debt securities rated Baa1 are subject to moderate credit risk. They are considered medium-grade and as such, may possess certain speculative characteristics.

S&P's credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. According to S&P's rating system, debt securities rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments on the obligations. A negative rating outlook means that a rating may be lowered.

DBRS' credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. Each rating category between AA and B is denoted by subcategories "high" and "low." The absence of either a "high" or "low" designation indicates that the rating is in the "middle" of the category. According to DBRS' rating system, long-term debt securities rated BBB are of adequate credit quality. Protection of interest and principal is considered acceptable, but entities so rated are fairly susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of such entity and its rated securities.

MARKET FOR THE SECURITIES OF THE COMPANY

The Common Shares of the Company are listed on the Toronto Stock Exchange ("TSX Exchange") and New York Stock Exchange under the trading symbol TLM. The Company's £250,000,000 6.625% Notes are listed on the London Stock Exchange.

TRADING PRICE AND VOLUME

The following sets out the high and low prices and the volume of trading for the Company's Common Shares (as traded on the TSX Exchange) for the periods indicated.

Year	Month	High	Low	Volume

2005	December	62.50	56.71	24,776,538
	November	59.02	50.87	34,391,753
	October	57.50	47.67	40,937,729
	September	59.72	47.16	32,288,231
	August	59.21	52.50	28,883,007
	July	55.10	47.16	31,555,535
	June	48.58	41.53	30,708,367
	May	43.25	36.67	28,720,335
	April	44.08	37.00	30,779,554
	March	44.05	38.42	38,404,669
	February	44.05	36.75	28,229,224
	January	37.47	31.50	32,803,616

48 A N N U A L I N F O R M A T I O N F O R M

DIVIDENDS

The Company paid semi-annual dividends over the last three-year period on its Common Shares as follows:

Date		Rate Per Common Share¹

June 30, 2003		$0.10
December 31, 2003		$0.13
June 30, 2004		$0.15
December 31, 2004		$0.15
June 30, 2005		$0.17
December 30, 2005		$0.17

Note:

1: On May 4, 2004, Talisman effected a three for one share split. The dividend rate per Common Share prior to this date has been adjusted to reflect this share split.

The Company's dividend policy is subject to semi-annual review by the Board of Directors.

PRIOR SALES OF DEBT SECURITIES

During the year ended December 31, 2005, the Company issued the following securities which are not listed or quoted on a marketplace:

Description of Security¹	Sale Price	Due Date

US$125 million face value of 5.75% Notes	US$98.69 per US$100 face value of securities	May 15, 2035
US$375 million face value of 5.125% Notes	US$99.914 per US$100 face value of securities	May 15, 2015

Note:

1: Subsequent to year end, the Company issued the following securities which are not listed or quoted on a market place:

Description of Security	Sale Price	Due Date

US$500 million face value of 5.85% Notes	US$99.418 per US$100 face value of securities	February 1, 2037
$350 million face value of 4.44% Medium Term Notes	$99.991 per $100 face value of securities	January 27, 2011

DIRECTORS AND OFFICERS

Information is given below with respect to each of the current directors and officers of the Company. The term of office of each director expires at the end of the 2006 annual meeting.

DIRECTORS

The directors of the Company are elected annually. The following table sets out the name, province or state and country of residence, year first elected or appointed to the Board and principal occupation within the past five years or more of each of the directors of the Company.

Name and Province or State and Country of Residence	Year First Became Director of the Company	Principal Occupation


Douglas D. Baldwin^2,^3,^4,⁶ Alberta, Canada	2001	Chairman of the Board of the Company; director of various corporations; from 1999 to 2001, President and Chief Executive Officer of TransCanada PipeLines Limited (pipeline and power company); from 1992 to 1998, Senior Vice-President and Director of Imperial Oil Limited (natural resource company); from 1988 to 1992, President and Chief Executive Officer, Esso Resources Canada Limited (natural resource company).
		Other Current Directorships⁷: TransCanada Corporation, TransCanada PipeLines Limited, UTS Energy Corporation and Citadel Group of Funds.
James W. Buckee^2,⁵ Alberta, Canada	1992	President and Chief Executive Officer of Talisman Energy Inc.; prior to May 1993, President and Chief Operating Officer of the Company; prior to August 1991, Manager, Planning of BP Exploration Company Ltd. (natural resource company).
		Other Current Directorships⁷: None.

A N N U A L I N F O R M A T I O N F O R M49

William R.P. Dalton Arizona, United States	2005⁹	Director of various corporations since 2004; Chief Executive of HSBC Bank plc (a British Clearing Bank) from 1998 to 2004; Executive Director of HSBC Holdings plc from 1998 to 2004; Global Head of Personal Financial Services for HSBC Group from 2002 to 2004; prior to 1998, held various positions in the Canadian operations of HSBC.
		Other current directorships⁷: First Choice Holidays plc
Kevin S. Dunne^3,^5,⁶ Tortola, British Virgin Islands	2003	Director of the Company; until March 2003, director of Talisman Energy Sweden AB (a wholly owned subsidiary of the Company); from 1984 until 2001, held various international senior and executive management positions with BP plc (international integrated oil and gas company) including General Manager, Abu Dhabi Company for Onshore Oil Operations (ADCO), a BP joint venture; 1991 to 1994, Corporate Associate President, BP Indonesia; and 1990 to 1991, Corporate Head of Strategy for the BP Group based in London.
		Other Current Directorships⁷: None.
Al L. Flood, C.M.^1,^4,⁸ Ontario, Canada	2000	Director of various corporations; from June 1999 to March 2000, Chairman of the Executive Committee of Canadian Imperial Bank of Commerce ("CIBC") (a Canadian chartered bank); prior to June 1999, Chairman and Chief Executive Officer of CIBC and held various positions in the domestic and international operations of CIBC.
		Other Current Directorships⁷: Falconbridge Limited
Dale G. Parker^1,^5,⁸ British Columbia, Canada	1993	Director of various corporations and public administration and financial institution advisor; prior to January 1998, President and Chief Executive Officer of Workers' Compensation Board of British Columbia; prior to November 1994, President of White Spot Limited (food services company) and Executive Vice-President of Shato Holdings Ltd. (food processing and services and real estate company); prior to November 1993, Executive Vice-President and Chief Financial Officer of Shato Holdings Ltd.; prior to November 1992, Chairman and Chief Executive Officer of British Columbia Financial Institutions Commission (regulator of financial institutions).
		Other Current Directorships⁷: None.
Lawrence G. Tapp^3,⁴ British Columbia, Canada	2001	Chairman of ATS Automation Tooling Systems Inc. (industrial automation company); director of various corporations; from 1995 to 2003, Dean of the Richard Ivey School of Business of the University of Western Ontario; from 1992 to 1995, Executive in Residence of the Faculty of Management and Adjunct Professor, University of Toronto; from 1985 to 1992, Vice Chairman, President and Chief Executive Officer of Lawson Mardon Group Limited (packaging conglomerate).
		Other Current Directorships⁷: ATS Automation Tooling Systems Inc., Call-Net Enterprises Inc., Wescast Industries Inc., CCL Industries Inc. and Mainstreet Equity Corp.

50 A N N U A L I N F O R M A T I O N F O R M

Stella M. Thompson^2,^4,⁵ Alberta, Canada	1995	Principal of Governance West Inc. (corporate governance consulting company); President of Stellar Energy Ltd. (energy and management consulting company); director of various corporations; prior to June 1991, Vice-President, Planning, Business Information & Systems of Petro-Canada Products (petroleum refining and marketing company).
		Other Current Directorships⁷: None.
Robert G. Welty^1,³ Alberta, Canada	2003	Chairman and director of Sterling Resources Ltd. ("Sterling") (oil and gas exploration and development company) since 1998; from 1998 to 2005, Chief Executive Officer of Sterling; 1996 to 1997, President, Escondido Resources (International) Ltd. (oil and gas exploration company); 1994 to 1995, President and Chief Executive Officer of Canadian Fracmaster Ltd. (oil field service company); 1992 to 1994, President and Chief Executive Officer of Bow Valley Energy Inc. (oil and gas exploration and development company); 1976 to 1988, President and Chief Executive Officer of Asamera Inc. (oil and gas exploration and development company).
		Other Current Directorships⁷: Sterling Resources Ltd. and Pan-Ocean Energy Corporation Limited.
Charles R. Williamson California, United States	2006¹⁰	Director of various corporations; from August to December 2005, Executive Vice-President, Chevron Corporation (integrated oil and gas company); from 2001 to September, 2005, Chairman and Chief Executive Officer of Unocal Corporation ("Unocal") (oil and gas exploration and development company); prior thereto, held various executive positions within Unocal, including Executive Vice President, International Energy Operations, and Group Vice President, Asia Operations.
		Other current directorships⁷: Weyerhaeuser Inc.
Charles W. Wilson^1,^2,⁶ Colorado, United States	2002	Director of various corporations; from 1993 to 1999, President and Chief Executive Officer of Shell Canada (integrated oil and gas company); from 1988 to 1993, Executive Vice President US Downstream Oil and Chemical of Shell Oil Company (integrated oil and gas company); prior to 1988, Vice President US Refining and Marketing of Shell Oil Company and held various positions in the domestic and international natural resource operations of Shell.
		Other Current Directorships⁷: ATCO Ltd., Akita Drilling Ltd., Big Rock Brewery Ltd. and Canadian Utilities Limited.

Notes:

1: Member of the Audit Committee
2: Member of the Executive Committee
3: Member of the Governance and Nominating Committee
4: Member of the Management Succession and Compensation Committee
5: Member of the Pension Funds Committee
6: Member of the Reserves Committee
7: Refers only to issuers that are reporting issuers or the equivalent in a foreign jurisdiction.
8: Messrs. Flood and Parker will be retiring from the Board of Directors at the conclusion of the 2006 shareholders' meeting.
9: Mr. Dalton was appointed to the Board of Directors in December 2005.
10: Mr. Williamson was appointed to the Board of Directors in March 2006.

A N N U A L I N F O R M A T I O N F O R M51

OFFICERS

The following table sets out the name, province and country of residence and office held with Talisman of each of the executive officers and Assistant Corporate Secretaries of the Company.

Name and Province or State and Country of Residence		Office


James W. Buckee Alberta, Canada		President and Chief Executive Officer
Ronald J. Eckhardt Alberta, Canada		Executive Vice-President, North American Operations
T. Nigel D. Hares Alberta, Canada		Executive Vice-President, Frontier and International Operations
Joseph E. Horler¹ Alberta, Canada		Executive Vice-President, Marketing
Michael D. McDonald Alberta, Canada		Executive Vice-President, Finance and Chief Financial Officer
Robert M. Redgate Alberta, Canada		Executive Vice-President, Corporate Services
M. Jacqueline Sheppard Alberta, Canada		Executive Vice-President, Corporate and Legal, and Corporate Secretary
John 't Hart Alberta, Canada		Executive Vice-President, Exploration
C. Tamiko Ohta Alberta, Canada		Assistant Corporate Secretary
Christine D. Lee Alberta, Canada		Assistant Corporate Secretary

Note:

1: Effective April 1, 2006 Mr. Horler will be retiring from Talisman.

In early 2003, the Company changed the titles of all its vice-presidents to better reflect the roles and responsibilities of their continuing offices. Mr. McDonald has held his current position since March 12, 2001. Prior to that date, he served as Vice-President, Business Development of the Company. Dr. 't Hart has held his current position since June 25, 2003. Prior to that, he served as Senior Manager, International Exploration of the Company since April 1, 2003 and prior to that, he served as Manager, International Exploration of the Company. Mr. Eckhardt has held his current position since October 1, 2003. Prior to that, he served as Vice-President, Southern District of North American Operations of the Company since January 23, 2003, and prior to that he served as Senior Manager, Western Operations and prior to that as Manager, Eastern Operations of the Company. All of the other executive officers of the Company have held their offices for at least five years.

Dale G. Parker, a director of the Company, was a director of Royal Oak Mines Inc., a publicly traded North American gold mining corporation, and a director of Agro Pacific Industries Ltd., a publicly traded agricultural corporation, when each corporation instituted proceedings under theCompanies' Creditors Arrangement Act (Canada) in 1999 and 2000, respectively. In 2003, Stella M. Thompson, a director of the Company, was a director of Laidlaw Inc., a public holding company, when it obtained an order in the United States Bankruptcy Court for the Western District of New York confirming its plan of reorganization and an order from the Ontario Superior Court of Justice under theCompanies' Creditors Arrangement Act (Canada) recognizing and implementing the plan in Canada. In 2003, a small, private technology company, for which Michael McDonald (an executive officer of the Company) served as a director, declared bankruptcy.

SHAREHOLDINGS OF DIRECTORS AND EXECUTIVE OFFICERS

As of March 1, 2006, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 408,261 Common Shares of the Company, represents 0.1% of the issued and outstanding Common Shares of the Company.

52 A N N U A L I N F O R M A T I O N F O R M

CONFLICTS OF INTEREST

Certain directors of the Company and its subsidiaries are associated with other reporting issuers or other corporations which may give rise to conflicts of interest. In accordance with theCanada Business Corporations Act, directors and officers of the Company are required to disclose to the Company the nature and extent of any interest that they have in a material contract or material transaction, whether made or proposed, with the Company, if the director or officer is: (a) a party to the contract or transaction; (b) is a director or an officer, or an individual acting in a similar capacity, of a party to the contract or transaction; or (c) has a material interest in a party to the contract or transaction.

As described in "Social Responsibility and Environmental Protection", Talisman has adopted the Ethics Policy which applies to all directors, officers and employees of Talisman and its subsidiaries. As required by the Ethics Policy, individuals representing Talisman must not enter into outside activities, including business interests or other employment, that might interfere with or be perceived to interfere with their performance at Talisman. In addition, Talisman officers and employees are required to abide by an internal Conflict of Interest in Employment Policy.

AUDIT COMMITTEE INFORMATION

Information concerning the Audit Committee of the Company, as required by Multilateral Instrument 52-110, is provided in Schedule C to this Annual Information Form.

LEGAL PROCEEDINGS

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation, including the litigation discussed below may be material or may be indeterminate and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not currently expected to have a material impact on the Company's financial position.

Talisman continues to be subject to a lawsuit brought by the Presbyterian Church of Sudan and others commenced in November 2001 under theAlien Tort Claims Act in the United States District Court for the Southern District of New York (the "Court"). The lawsuit, which is seeking class action status, 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 plaintiff's motion to certify the lawsuit as a class action. On October 5, 2005, the plaintiffs filed papers to appeal the decision denying class certification. The Company has filed papers opposing the plaintiff's appeal. Talisman believes the lawsuit to be entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

RISK FACTORS

Talisman is exposed to a number of risks inherent in exploring for, developing and producing crude oil and natural gas. This section describes the risks and other matters that would be most likely to influence an investor's decision to purchase securities of Talisman.

Uncertainty of Reserves Estimates

The process of estimating oil and gas reserves is complex and involves a significant number of decisions and assumptions in evaluating available geological, geophysical, engineering and economic data; therefore, reserves estimates are inherently uncertain. Talisman prepares all of its reserves information internally. The Company may adjust estimates of proved reserves based on production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond the Company's control. In addition, there are numerous uncertainties in forecasting the amounts and timing of future production, costs, expenses and the results of exploration and development projects. All estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and the standardized measure of discounted future net cash flows, prepared by different engineers or by the same engineers at different times, may vary substantially. Talisman's actual production, taxes and development and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances could be material.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reservoirs, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

A N N U A L I N F O R M A T I O N F O R M53

Ability to Find, Develop or Acquire Additional Reserves

The Company's future success depends largely on its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Exploration and development drilling may not result in commercially productive reserves. Successful acquisitions require an assessment of a number of factors, many of which are uncertain. These factors include recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain.

Political Risks

The Company's operations may be adversely affected by changes in governmental policies and legislation or social instability or other political or economic developments which are not within the control of Talisman including, among other things, a change in crude oil or natural gas pricing policy, the risks of war, terrorism, abduction, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, taxation policies, economic sanctions, the imposition of specific drilling obligations, the development and abandonment of fields, fluctuating exchange rates and currency controls. In addition, both Indonesia and Algeria are members of the Organization of Petroleum Exporting Countries ("OPEC"). Talisman's operations in these countries may therefore be impacted by the application of OPEC quotas. Various countries in which the Company is active, including Indonesia, Algeria, Colombia and Peru have been subject to recent economic or political instability and social unrest, military or rebel hostilities. In addition, Talisman regularly evaluates opportunities worldwide, and may in the future engage in projects or acquire properties in other nations that are experiencing economic or political instability and social unrest or military hostilities or are subject to United Nations or United States sanctions.

Operational Hazards and Responsibilities

Oil and gas drilling and producing operations are subject to many risks including the possibility of fire, explosions, mechanical failure, pipe failure, chemical spills, accidental flows of oil, natural gas or well fluids, sour gas releases, and other occurrences or accidents which could result in personal injury or loss of life, damage or destruction of properties, environmental damage, interruption of business, regulatory investigations and penalties and liability to third parties. The Company has developed a comprehensive HSE management framework to mitigate physical risks. The Company also mitigates insurable risks to protect against significant losses by maintaining a comprehensive insurance program, while maintaining levels and amounts of risk within the Company which management believes to be acceptable. Talisman believes its liability, property and business interruption insurance is appropriate to its business and consistent with common industry practice, although such insurance will not provide coverage in all circumstances.

Volatility of Oil and Natural Gas Prices

Talisman's financial performance is highly sensitive to prevailing prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have a material adverse effect on the Company's operations and financial condition, the value of its oil and natural gas reserves, and its level of spending for oil and gas exploration and development. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are largely beyond the Company's control. Oil prices are determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the availability of alternative fuel sources and weather conditions. Most natural gas prices realized by Talisman are affected primarily by North American supply and demand, weather conditions and by prices of alternative sources of energy. The development of oil and natural gas discoveries in offshore areas is particularly dependent on the outlook for oil and natural gas prices because of the large amount of capital expenditure required for development prior to commencing production.

A substantial and extended decline in the prices of crude oil or natural gas could result in delay or cancellation of drilling, development or construction programs, or curtailment in production or result in unutilized long-term transportation commitments all of which could have a material adverse impact on the Company. The amount of cost oil required to recover Talisman's investment and costs in various production sharing contracts is dependent on commodity prices, with higher commodity prices resulting in a lower amount of net after royalty oil and gas reserves booked by the Company.

Talisman conducts an annual assessment of the carrying value of its assets in accordance with Canadian generally accepted accounting principles ("GAAP"). If oil and natural gas prices decline, the carrying value of the Company's assets could be subject to downward revisions, which could adversely affect Talisman's reported income for the periods in which the revisions are made. However, Talisman believes that estimates of forward-looking prices it uses in its planning process are realistic.

54 A N N U A L I N F O R M A T I O N F O R M

Litigation

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Specific disclosure of current legal proceedings, and the risks associated with current proceedings and litigation generally, are disclosed under the heading "Legal Proceedings" in this Annual Information Form.

Environmental Risks

All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of laws and regulations in the countries in which Talisman does business. These regulatory regimes are laws of general application that apply to the Company's business in the same manner as they apply to other companies or enterprises in the energy industry. Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that pipelines, wells, facility sites and other properties associated with Talisman's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Certain types of operations, including exploration and development projects, may require the submission and approval of environmental impact assessments or permit applications. In some cases, exploration and development activities may be precluded or restricted due to designation of areas as environmentally sensitive areas. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean up costs and damages. Additionally, the Company's business is subject to the trend toward increased civil liability for environmental matters. Although Talisman currently believes that the costs of complying with environmental legislation and dealing with environmental civil liabilities will not have a material adverse effect on the Company's financial condition or results of operations, there can be no assurance that such costs in the future will not have such an effect. Talisman expects to incur site restoration costs over a prolonged period as existing fields are depleted. The Company provides for future abandonment and reclamation costs in its annual consolidated financial statements in accordance with Canadian GAAP. Additional information regarding future abandonment and reclamation costs is set forth in the notes to the annual consolidated financial statements.

In 1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol (the "Protocol"). The Protocol came into force on February 16, 2005 and requires certain nations to reduce their emissions of carbon dioxide and other greenhouse gases. Under the terms of the Protocol, Canada will be required to reduce its greenhouse gas ("GHG") emissions to 6% below 1990 levels over the period beginning in 2008 and ending in 2012. Currently, Canadian oil and gas producers are in discussions with the provincial and federal levels of government regarding implementation mechanisms for the industry. It is premature to predict what impact the Protocol could have on Canadian oil and gas producers (and specifically, if and in what manner it will be implemented) but it is likely that any mandated reduction in GHG emissions will result in increased costs.

The UK has also ratified the Protocol, with a reduction commitment of 12.5% below 1990 levels by 2008 to 2012. Talisman's UK installations are currently participating in the first phase of the European Union Emission Trading Scheme ("EU ETS"), which runs from 2005 to 2007, inclusive. The UK Government's National Allocation Plan ("NAP") for the first phase of the EU ETS was approved by the European Commission in 2005. The NAP specifies a cap on carbon dioxide emissions for the covered sectors, the methods for allocating emission allowances to covered installations and the number of emission allowances to be allocated to each covered installation. Cost of compliance is expected to be negligible during the period 2005 to 2007. Details regarding the UK Government's NAP for phase two of the EU ETS (2008 to 2012) are as yet uncertain.

Dependence on Other Operators

Other companies operate some of the assets in which Talisman has interests. As a result, Talisman may have limited ability to exercise influence over operations of these assets or their associated costs, which could adversely affect the Company's financial performance. The success and timing of Talisman's activities on assets operated by others will therefore depend on a number of factors that may be outside of the Company's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and the risk of management practices.

Project Completion Risks

Talisman manages a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic. Talisman's ability to complete projects depends upon numerous factors beyond the Company's control. These factors include: the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of drilling and other equipment; the ability to access lands; weather; unexpected cost increases; accidents; the availability of skilled labour; and regulatory matters.

Differences in Ownership Interests in Foreign Operations

In Canada and the United States, the state or private land owners own oil and gas rights and lease those rights to corporations who are responsible for the development of such rights within the time frames described in the leases. This practice differs distinctly in some foreign countries in which Talisman does or may do business in the future. In those countries, the state often grants interests in large tracts of lands or offshore fields and maintains control over the development of the oil and gas rights, in some cases through equity participation in the exploration and development of the rights. This usually includes the imposition of obligations on Talisman to complete minimum work within specified timeframes. Transfers of interests typically require a state approval, which may delay or otherwise impede transfers. In addition, if a dispute arises in Talisman's foreign operations, the Company may be subject to the exclusive jurisdiction of foreign arbitration tribunals or foreign courts.

A N N U A L I N F O R M A T I O N F O R M55

Competition

The petroleum industry is highly competitive. Specific disclosure regarding competition is disclosed under the heading "Competitive Conditions" in this Annual Information Form.

Exchange Rate Fluctuations

Talisman's consolidated financial statements are presented in Canadian dollars. Results of operations are affected primarily by the exchange rates between the Canadian dollar, the United States dollar and United Kingdom pounds sterling. These exchange rates have varied substantially in the last five years. Most of the Company's revenue is received in or is referenced to United States dollar denominated prices, while the majority of Talisman's expenditures are denominated in Canadian dollars, United States dollars and United Kingdom pounds sterling. A change in the relative value of the Canadian dollar against the United States dollar or the United Kingdom pound sterling would also result in an increase or decrease in Talisman's United States dollar or United Kingdom pound sterling denominated debt, as expressed in Canadian dollars and the related interest expense. Talisman is also exposed to fluctuations in other foreign currencies.

Hedging Programs

While Talisman currently has minimal commodity hedging contracts in place, it continues to monitor the Company's exposure to variations in commodity prices, interest rates and foreign exchange rates. The Company may in the future find it appropriate to enter into additional derivative financial instruments and physical delivery contracts to reduce such exposure. The terms of these instruments or contracts may limit the benefit of commodity price increases and changes in interest rates and currency value which are otherwise favorable to Talisman and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with the contracts.

Dependence on Management

The success of Talisman is dependent upon its management and the quality of its personnel. Failure to retain current employees or to attract and retain new employees with the necessary skills could have a materially adverse effect on Talisman's growth and profitability.

TRANSFER AGENTS AND REGISTRARS

Computershare Trust Company of Canada at 600, 530 - 8^th Avenue S.W., Calgary, Alberta, T2P 3S8, along with its co-transfer agent, Computershare Investor Services, LLC, is the transfer agent and registrar for the Common Shares of the Company. Computershare Trust Company of Canada also acts as trustee for various public debt securities. JP Morgan Chase, London Branch, of Trinity Tower, 9 Thomas More Street, London, E1W 1YT, United Kingdom, acts as trustee for the 6.625% unsecured notes listed on the London Stock Exchange. Bank of Nova Scotia Trust Company of New York of One Liberty Plaza, New York, New York, 10006 acts as trustee for various public debt securities. The Company has not retained transfer agents for any other outstanding securities.

INTERESTS OF EXPERTS

Talisman's auditor is Ernst & Young LLP, Chartered Accountants, Ernst & Young Tower, 1000, 440 - 2^nd Avenue S.W., Calgary, Alberta, T2P 5E9. The Company's audited consolidated financial statements for the year ended December 31, 2005 have been filed under National Instrument 51-102 in reliance on the report of Ernst & Young LLP, independent chartered accountants, given on their authority as experts in auditing and accounting. Ernst & Young LLP is independent in accordance with the Rules of Professional Conduct as outlined by the Institute of Chartered Accountants of Alberta.

Mr. Michael Adams, an employee of Talisman, has provided the report on reserves data attached as Schedule A to this Annual Information Form in his capacity as Talisman's Internal Qualified Reserves Evaluator. Mr. Adams owns less than 1% of the outstanding Common Shares.

ADDITIONAL INFORMATION

Additional information related to the Company may be found on SEDAR at www.sedar.com.

Additional information including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and securities authorized for issuance under equity compensation plans, is contained in the Company's management information circular for its most recent annual meeting of security holders that involved the election of directors. Additional financial information is provided in the Company's audited consolidated financial statements for the year ended December 31, 2005 and related annual management's discussion and analysis.

Copies of the Company's Annual Report may be obtained from Talisman's website at www.talisman-energy.com or upon request from:

Investor Relations and Corporate Communications Department

Talisman Energy Inc.
Suite 3400, 888 Third Street S.W.
Calgary, Alberta, T2P 5C5
E-Mail: tlm@talisman-energy.com

56 A N N U A L I N F O R M A T I O N F O R M

SCHEDULE A
REPORT ON RESERVES DATA BY TALISMAN'S
INTERNAL QUALIFIED RESERVES EVALUATOR

To the Board of Directors of Talisman Energy Inc. (the "Company"):

1.

The Company's staff and I have evaluated the Company's reserves data as at December 31, 2005. The reserves data, which has been prepared in accordance with US disclosure requirements, including the relevant definitions, legal requirements and standards of the United States Securities and Exchange Commission and the United States Financial Accounting Standards Board ("US Disclosure Requirements"), consist of the following:

(a): proved oil and gas reserves quantities estimated as at December 31, 2005; and
(b): the related standardized measure of discounted future net cash flows.

2.

The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) applied in such modified manner as we considered necessary to reflect the terminology and standards of the US Disclosure Requirements. We are not independent of the Company, within the meaning of the term "independent" under those standards.

4.

Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook as modified as set out above.

5.

The following sets forth the standardized measure of discounted future net cash flows (after deducting income taxes) attributed to proved oil and gas reserve quantities, calculated using a discount rate of 10%, included in the reserves data of the Company evaluated for the year ended December 31, 2005:

	Location of Reserves (country or foreign geographic area)		Standardized Measure of Discounted Future Net Cash Flows (millions of Canadian dollars, after income taxes, 10% discount rate)

	Canada		$8,603
	United States		$652
	North Sea		$5,606
	Southeast Asia and Australia		$2,572
	North Africa		$530
	Trinidad and Tobago		$230

			$18,193

6.: In our opinion, the reserves data evaluated by us have, in all material respects, been determined in accordance with the COGE Handbook applied in the modified manner as set out above.
7.: We have no responsibility to update our evaluation for events and circumstances occurring after the date of this report.
8.: Reserves data are estimates only and not exact quantities. In addition, the reserves data are based on judgements regarding future events. Accordingly, actual results will vary and the variations may be material.

(Signed)
Michael Adams
Internal Qualified Reserves Evaluator
Talisman Energy Inc.
Calgary, Alberta

March 13, 2006

A N N U A L I N F O R M A T I O N F O R M57

SCHEDULE B
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Management of Talisman Energy Inc. (the "Company") is responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data prepared in accordance with US disclosure requirements, including the relevant definitions, legal requirements and standards of the United States Securities and Exchange Commission and the United States Financial Accounting Standards Board ("US Disclosure Requirements"), which consist of the following:

(a): proved oil and gas reserve quantities estimated as at December 31, 2005; and
(b): the related standardized measure of discounted future net cash flows.

The Company's reserves evaluation staff, including our Internal Qualified Reserves Evaluator who is an employee of the Company, have evaluated the Company's reserves data. The report of the Internal Qualified Reserves Evaluator accompanies this report.

The Reserves Committee of the Board of Directors has:

(a): reviewed the Company's procedures for providing information to the Internal Qualified Reserves Evaluator;
(b): met with the Internal Qualified Reserves Evaluator to determine whether any restrictions placed by management affect the ability of the Internal Qualified Reserves Evaluator to report without reservation; and
(c): reviewed the reserves data with management and the Internal Qualified Reserves Evaluator.

The Reserves Committee of the Board of Directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved:

(a): the content and filing with securities regulatory authorities of the reserves data and other oil and gas information contained in the Annual Information Form accompanying this report;
(b): the filing of the report of the Internal Qualified Reserves Evaluator on the reserves data; and
(c): the content and filing of this report.

In our view, the reliability of the internally generated reserves data is not materially less than would be afforded by our involving independent qualified reserves evaluators or independent qualified reserves auditors to evaluate or audit and review the reserves data. The Company is therefore relying on an exemption, which it sought and was granted by securities regulatory authorities, from the requirement under securities legislation to involve independent qualified reserves evaluators or independent qualified reserves auditors.

The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer's reserves data are superior to that of the internal evaluators and (ii) the work of the independent qualified reserves evaluators or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In our view, neither of these factors applies in our circumstances.

58 A N N U A L I N F O R M A T I O N F O R M

Our view is based in large part on the following. Our reserves data were developed in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook applied in such modified manner as the Company considered necessary to reflect the terminology and standards of the US Disclosure Requirements. Our procedures, records and controls relating to the accumulation of source data and preparation of reserves data by our internal reserves evaluation staff have been established, refined and documented over many years. Our internal reserves evaluation staff includes approximately 104 persons with full-time or part-time responsibility for reserves evaluation with an average of approximately 19 full-time or part-time years of relevant experience in evaluating reserves, of whom 50 are qualified reserves evaluators for purposes of securities regulatory requirements. Our internal reserves evaluation management personnel includes approximately 27 persons with full-time or part-time responsibility for reserves evaluation management with an average of approximately 25 full-time or part-time years of relevant experience in evaluating and managing the evaluation of reserves, 15 of whom were qualified reserves evaluators for purposes of securities regulatory requirements.

Reserves data are estimates only, and are not exact quantities. In addition, the reserves data are based on judgements regarding future events. Accordingly, actual results will vary and the variations may be material.

(Signed)
James W. Buckee
President and Chief Executive Officer

(Signed)
Ronald J. Eckhardt
Executive Vice-President,
North American Operations

(Signed)
Charles W. Wilson
Director

(Signed)
Kevin S. Dunne
Director

March 13, 2006

A N N U A L I N F O R M A T I O N F O R M59

SCHEDULE C
AUDIT COMMITTEE INFORMATION

COMPOSITION OF AUDIT COMMITTEE

As at March 13, 2006, Talisman's Audit Committee consists of Al L. Flood, Dale G. Parker, Robert G. Welty (Chairman) and Charles W. Wilson. The Board of Directors has determined that all members of the Audit Committee are "independent" and "financially literate" as defined in Multilateral Instrument 52-110 ("MI 52-110"). In addition, in accordance with New York Stock Exchange corporate governance listing standards, the Board of Directors has determined that Robert G. Welty is an audit committee financial expert.

MI 52-110 states that a member of an audit committee is independent if the member has no direct or indirect material relationship with the issuer. A material relationship is a relationship which could, in the view of the issuer's Board of Directors, reasonably interfere with the exercise of a member's independent judgement.

In addition, an individual is considered financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the issuer's financial statements.

EDUCATION AND EXPERIENCE

The members of Talisman's Audit Committee have education and experience relevant to the performance of their responsibilities as Audit Committee members, which includes the following:

Al L. Flood held various positions in the Canadian Imperial Bank of Commerce ("CIBC"), including Chairman of the Executive Committee from 1999 to 2000, Chief Executive Officer and Chairman from 1992 to 1999, and director from 1989 to 2000. Mr. Flood currently serves on the board of directors of Falconbridge Limited. Mr. Flood is a graduate of the program for management development, Graduate School of Business, Harvard University. Mr. Flood will be retiring from the Board of Directors at the conclusion of the 2006 shareholders' meeting.

Dale G. Parker held various positions with the Bank of Montreal, including Executive Vice President & Group Executive, Commercial Banking. In 1985, he became President, Canadian Banking Operations for the Bank of British Columbia, and from 1987 to 1989, he served as Chairman, President and Chief Executive Officer of B.C. Bancorp (formerly the Bank of British Columbia). Mr. Parker also served as Chairman of the Financial Institutions Commission for British Columbia until 1994. Mr. Parker has served in executive capacities with other companies and institutions including President of White Spot Ltd. and President and Chief Executive Officer of the Worker's Compensation Board of British Columbia. Mr. Parker completed the three year Executive Development Program at McGill University and the Advanced Management Program at Harvard Business School. Mr. Parker will be retiring from the Board of Directors at the conclusion of the 2006 shareholders' meeting.

Robert G. Welty, Chairman of the Audit Committee, is currently Chairman and director of Sterling Resources Ltd. ("Sterling"), a publicly traded junior energy company with international activities. Mr. Welty served as Chief Executive Officer of Sterling from 1998 to 2005. He served as President, Chief Executive Officer and Director of Canadian Fracmaster Ltd., an international oilfield service and production company, from 1994 to 1995. Mr. Welty was also President, Chief Executive Officer and Director of Bow Valley Energy Inc. from 1992 to 1994, a Calgary based international oil and gas company which was subsequently acquired by Talisman. He currently serves on the board of directors of Sterling Resources Ltd. and Pan-Ocean Energy Corporation Limited. Mr. Welty holds a BA Honors, Economics (First Class) from Simon Fraser University and is a Chartered Accountant.

Charles W. Wilson held various positions with the Shell group of companies, including President, Chief Executive Officer and Director of Shell Canada Limited from 1993 to 1999, Executive Vice President U.S. Downstream Oil and Chemical of Shell Oil Company from 1988 to 1993 and Vice President U.S. Refining and Marketing of Shell Oil Company (1987 to 1988). He currently serves on the board of directors of ATCO Ltd., Akita Drilling Ltd., Big Rock Brewery Ltd. and Canadian Utilities Limited. Mr. Wilson has a BSc, Civil Engineering and a MS Engineering from the University of New Mexico.

60 A N N U A L I N F O R M A T I O N F O R M

AUDIT FEES AND PRE-APPROVAL OF AUDIT SERVICES

The following table presents fees for the audits of the Company's annual consolidated financial statements for 2005 and 2004 and for other services provided by Ernst & Young LLP:

	2005	2004

Audit fees	$2,607,100	$2,050,000
Audit-related fees	$386,000	$220,000
Tax fees	$624,800	$1,334,000
All other fees	–	$30,000

The audit-related fees are primarily for prospectus filings, pension plan audits, and attestation procedures related to cost certifications and government compliance. Tax fees are primarily for tax compliance and tax advisory services. All other fees are primarily for advisory services. The Audit Committee has concluded that the provision of tax services is compatible with maintaining Ernst & Young's independence.

Under the terms of reference of the Audit Committee which follow, the Audit Committee is required to review and pre-approve the objectives and scope of the external audit work and proposed fees. In addition, the Audit Committee is required to review and pre-approve all non-audit services, including tax services, the Company's external auditors are to perform.

During 2003, the Audit Committee implemented specific procedures regarding the pre-approval of services to be provided by the Company's external auditors. These procedures specify certain prohibited services that are not to be performed by the Company's external auditors. In addition, these procedures require that at least annually, prior to the period in which the services are proposed to be provided, the Company's management, in conjunction with the Company's external auditors, prepares and submits to the Audit Committee a complete list of all proposed services and related fees to be provided to the Company by the Company's external auditors. Under the Audit Committee pre-approval procedures, for those non-audit services proposed to be provided by the Company's external auditors that have not been previously approved by the Audit Committee, the Audit Committee has delegated to the Chairman of the Audit Committee the authority to grant pre-approvals of such services. The decision to pre-approve a service covered under this procedure is presented to the full Audit Committee at the next scheduled meeting. At each of the Audit Committee's regular meetings, the Audit Committee is provided an update as to the status of services previously approved.

Pursuant to these procedures since their implementation in 2003, 100% of each of the services relating to fees reported as audit-related, tax and all other were pre-approved by the Audit Committee or its delegate, the Chair of the Audit Committee.

The full text of the terms of reference for Talisman's Audit Committee follows.

TERMS OF REFERENCE
AUDIT COMMITTEE

MISSION STATEMENT

The Audit Committee's mission is to assist the Board in fulfilling its obligations by overseeing and monitoring the Company's financial accounting and reporting process and the integrity of the Company's financial statements and its internal control over financial reporting and the external financial audit process. To fulfill this mission, the Audit Committee has received this mandate and has been delegated certain authorities that it may exercise on behalf of the Board.

COMPOSITION

At the first meeting of the Board of Directors of the Company after the election of Directors at the annual meeting of shareholders, the Board shall appoint an Audit Committee comprised of not less than three and not more than six Directors of the Company. Each member of the Audit Committee shall be independent (as required by applicable securities laws and stock exchange rules). At least one member of the Audit Committee shall be an audit committee financial expert and all members of the Audit Committee shall have an appropriate level of financial literacy as required under applicable stock exchange rules and securities laws and determined by the Board from time to time. The Board may replace or remove from the Audit Committee any member at any time.

The Chair of the Audit Committee shall be appointed by the Board at the meeting of the Board referred to above. The Chair shall preside as chair at each Committee meeting, lead Committee discussion on meeting agenda items and report to the Board, on behalf of the Committee, with respect to the proceedings of each Committee meeting. The Audit Committee shall designate a Secretary to the Audit Committee who may be a member of the Audit Committee or an officer or employee of the Company. The Secretary shall keep minutes and records of all meetings of the Audit Committee. In the event that either the Chair or the Secretary is absent from any meeting, the members present shall designate any Director present to act as Chair and shall designate any Director, officer or employee of the Company to act as Secretary.

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MEETINGS

Meetings of the Audit Committee, including telephone conference meetings, shall be held at such time and place as the Chair of the Audit Committee may determine. Notice of meetings shall be given to each member not less than 24 hours before the time of the meeting, provided that meetings of the Audit Committee may be held without formal notice if all of the members are present and do not object to notice not having been given, or if those absent waive notice in any manner before or after the meeting.

Notice of meeting may be given verbally or delivered personally, given by mail, facsimile or other electronic communication and need not be accompanied by an agenda or any other material. The notice shall however specify the purpose or purposes for which the meeting is being held.

At the request of the auditor of the Company (the "Auditor"), the Chief Executive Officer, the Chief Financial Officer or a member of the Audit Committee, the Chair shall call and convene a meeting of the Audit Committee.

Any three members of the Audit Committee shall constitute a quorum.

The Audit Committee shall meet at least quarterly.

Representatives of the Auditor and management of the Company shall have access to the Audit Committee each in the absence of the other.

The Auditor shall be notified of all meetings of the Audit Committee and, when appropriate, it may attend and be heard at any such meeting and shall attend if requested to do so by a member of the Audit Committee.

Any matter the Audit Committee does not unanimously approve will be referred to the Board for consideration.

No alteration to the roles and responsibilities of the Audit Committee shall be effective without the approval of the Board of Directors.

The Audit Committee shall review the adequacy of these Terms of Reference on an annual basis and recommend any changes it considers appropriate to the Governance and Nominating Committee, which shall in light of the Company's governance structure and framework recommend any changes it considers appropriate to the Board of Directors.

ROLE AND RESPONSIBILITIES

A.: FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION

The Audit Committee shall:

1.

oversee the Company's financial reporting process on behalf of the Board and report on the results of these activities to the Board;

2.

review the Company's annual financial statements and, if determined to be satisfactory, recommend them to the Board for approval;

3.

review and, if determined to be satisfactory, recommend to the Board for approval the annual earnings press release and management's discussion and analysis of operations contained in the annual report and their consistency with the financial statements;

4.

review and, if determined to be satisfactory, approve the Company's interim financial statements prior to their publication, filing or delivery to security holders;

5.

review and, if determined to be satisfactory, approve all interim earnings press releases and management's discussion and analysis of operations which accompanies interim financial statements;

6.

ensure that adequate procedures are in place for the review of the Company's public disclosure of financial information extracted or derived from the Company's financial statements, other than the public disclosure referred to in items 2 to 5 above, and periodically assess the adequacy of those procedures;

7.

review the appropriateness of any report or opinion proposed to be rendered in connection with the year-end consolidated financial statements;

8.

review the nature, substance and appropriateness of significant accruals, reserves and other estimates;

9.

review the appropriateness of impairment provisions;

10.

review with the Auditor and with the management of the Company and, if determined to be satisfactory, approve on behalf of the Board all financial statements included in a prospectus or other similar document; and

11.

review and assess regularly:

(a): the quality and acceptability of accounting policies and financial reporting practices used by the Company;

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(b): any significant proposed changes in financial reporting and accounting policies and practices to be adopted by the Company;
(c): any new or pending developments, in accounting and reporting standards that may affect the Company;
(d): the key financial estimates and judgements of management that may be material to the financial reporting of the Company;
(e): policies related to financial disclosure risk assessment and management; and
(f): responses by management to material information requests from government or regulatory authorities which may have an impact on the financial reporting of the Company.

B.: EXTERNAL AUDIT

The Auditor shall be ultimately accountable to the shareholders of the Company, who shall be represented by the Board of Directors and the Audit Committee in their dealings with the Auditor. The Audit Committee shall recommend to the Board the auditor that will be proposed at the annual shareholders' meeting for appointment as the Auditor for the ensuing year. The Auditor shall report directly to the Audit Committee, which shall be responsible for compensation and retention of the Auditor and oversight of the Auditor's work (including resolution of disagreements between management and the Auditor regarding financial reporting).

At least annually, the Audit Committee shall require that the Auditor provide a formal written statement describing: (i) the firm's internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the Auditor and the Company.

With respect to (iii) above and for more clarity, annually the Audit Committee shall obtain a written letter from the Auditor pursuant to the Independence Standards Board standard #1 disclosing all relationships between the Auditor and its related entities and the Company and its related entities, and confirming the Auditor's independence from the Company.

The Audit Committee shall not recommend to the Board that an auditor be appointed as the Auditor if the Company's Chief Executive Officer, Chief Financial Officer or Controller was employed by the auditor and participated in any capacity in the Company's audit during the one-year period preceding the date of the initiation of the Company's audit for which the Audit Committee is recommending the appointment. The Audit Committee shall review management's policies for hiring partners, employees and former partners and employees of the Auditor and former external auditor of the Company. The Audit Committee further shall ensure the independence of the Auditor by reviewing, and discussing with the Board if necessary, any relationships that may adversely affect the independence of the Auditor.

The Audit Committee shall review the planning and results of external audit activities and the ongoing relationship with the Auditor. In this regard the Audit Committee shall:

1.

review and, if determined to be satisfactory, pre-approve the terms of the annual external audit engagement plan, including but not limited to the following:

(a): engagement letter;
(b): objectives and scope of the external audit work;
(c): materiality limit;
(d): areas of audit risk;
(e): staffing;
(f): timetable; and
(g): proposed fees;

2.

annually, or as otherwise required by the Audit Committee, review a written report from the Auditor on the critical accounting policies of the Company;

3.

review and, if determined to be satisfactory, pre-approve all non-audit services, including tax services, the Auditor is to perform, and it shall consider the impact the provision of such services could have on the independence of the external audit work. The Audit Committee may delegate this authority to grant pre-approvals to one or more designated members of the Audit Committee, provided that such delegates present their decisions to pre-approve services to the full Audit Committee at each of its scheduled meetings. The Audit Committee shall not permit the Auditor to perform any non-audit service prohibited by law applicable to the Company;

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4.

meet with the Auditor and management to discuss the Company's annual financial statements and the Auditor's report, the interim financial statements, and management's discussion and analysis relating to both the annual and interim financial statements. Meetings with the Auditor and management shall be held separately, periodically, as scheduled by the Audit Committee;

5.

review and advise the Board with respect to the plan, conduct and reporting of the annual external audit, including but not limited to the following:

(a): any audit problems or difficulties encountered, and management's response thereto, and any restriction imposed by management during the annual audit;
(b): any significant accounting or financial reporting issue;
(c): the Auditor's evaluation of the Company's system of internal controls and related procedures and documentation;
(d): the post audit or management letter containing any of the Auditor's findings or recommendations, including management's response thereto and the subsequent follow-up to any identified control weaknesses; and
(e): any other matters that the Auditor brings to the attention of the Audit Committee;

6.

prepare an Audit Committee report to be included in the Company's annual corporate governance disclosure; and

7.

fix the remuneration of the Auditor.

C.

INTERNAL AUDIT

The Audit Committee shall oversee the internal audit function of the Company and the relationship of the internal auditor with management. Periodically, the Audit Committee shall meet separately with each of the internal auditor and management. To assist the Board in fulfilling its oversight and monitoring obligations in this area, the Audit Committee shall:

1.: review and consider the appropriateness of the internal audit function and organizational framework;
2.: be involved in the appointment or removal of the internal auditor;
3.: support the independence of the internal audit function and the internal auditor;
4.: review and consider the appropriateness of the internal audit plan and resources; and
5.: review the findings of the internal auditor and consider the appropriateness of follow-up plans.
D.: INTERNAL FINANCIAL CONTROL AND INFORMATION SYSTEMS

The Audit Committee will review and obtain reasonable assurance that the internal financial control and information systems are operating effectively to produce accurate, appropriate and timely financial information. In this regard the Audit Committee will:

1.

obtain reasonable assurance by discussions with and reports from management, the internal auditor and the Auditor, that:

(a): the information systems, security of information and recovery plans are adequate and reliable; and
(b): the internal control systems and procedures are properly designed and effectively implemented;

2.

review the appointment of the Chief Financial Officer and adequacy of accounting and finance resources, as required; and

3.

ensure that direct and open communication exists among the Audit Committee, the Auditor and the internal auditor.

E.

INSURANCE

The Audit Committee shall review insurance coverage of significant business risks and uncertainties.

F.: SUBSIDIARIES

The Audit Committee shall receive a report on the Company's material Subsidiaries, as requested from time to time, concerning any material non-routine structures e.g. special purpose entities, off balance sheet items or partnership arrangements.

G.: INVESTIGATIONS AND ACCESS TO MANAGEMENT

The Audit Committee shall have the authority to direct and to supervise the investigation into any matter brought to its attention within the scope of its duties. It shall establish procedures for the receipt, retention and treatment of (i) complaints the Company may receive regarding accounting,

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internal accounting controls, or auditing matters, and (ii) confidential, anonymous submissions from Company employees expressing concern regarding questionable accounting or auditing matters.

The Audit Committee has the authority to engage independent counsel and other advisers having special competencies, as it determines necessary to carry out its duties. The Audit Committee shall determine the appropriate amount of funding the Company shall provide for compensation of any such advisors.

In carrying out its responsibilities, the Audit Committee shall have access to such members of the Company's management as appropriate, including the persons having responsibility for:

1.: insurable risks, foreign currency and interest rate exposure and related derivatives;
2.: tax exposures and related reserves;
3.: systems security and system integrity recovery plans;
4.: compliance with domestic and international regulatory requirements (such as the Corruption of Foreign Public Officials Act and Foreign Corrupt Practices Act) and material legal exposures;
5.: plans and actions taken with respect to commodity price hedging;
6.: financial accounting; and
7.: internal audit.

The Audit Committee shall receive from management copies of any report of a material nature from regulators or government bodies which is relevant to the responsibilities of the Audit Committee set out in this mandate and of management's responses thereto.

H.: GENERAL

The Audit Committee shall review corporate policies that are within the scope of the roles and responsibilities specified by these terms of reference prior to submission for approval by the Board; monitor compliance on a regular basis; and ensure these policies are periodically reviewed and kept current.

The Audit Committee shall perform such other duties as may be assigned to it by the Board from time to time or as may be required by applicable law and stock exchange requirements.

In respect of matters within its purview under this mandate and delegation, the Audit Committee shall assist the Board in its oversight of the Company's compliance with legal and regulatory requirements.

The Audit Committee shall report to the Board at each regularly scheduled Board meeting next succeeding any Committee meeting.

The Audit Committee shall evaluate its own performance annually.

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QuickLinks

ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2005
March 13, 2006
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION
EXCHANGE RATE INFORMATION
DEFINITIONS
CORPORATE STRUCTURE
GENERAL DEVELOPMENT OF THE BUSINESS
DESCRIPTION OF THE BUSINESS
DESCRIPTION OF CAPITAL STRUCTURE
MARKET FOR THE SECURITIES OF THE COMPANY
DIVIDENDS
PRIOR SALES OF DEBT SECURITIES
DIRECTORS AND OFFICERS
AUDIT COMMITTEE INFORMATION
LEGAL PROCEEDINGS
RISK FACTORS
TRANSFER AGENTS AND REGISTRARS
INTERESTS OF EXPERTS
ADDITIONAL INFORMATION
SCHEDULE A REPORT ON RESERVES DATA BY TALISMAN'S INTERNAL QUALIFIED RESERVES EVALUATOR
SCHEDULE B REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
SCHEDULE C AUDIT COMMITTEE INFORMATION
TERMS OF REFERENCE AUDIT COMMITTEE

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Repsol Oil & Gas Canada (TLM) Inactive 40-F2005 FY Annual report (Canada)

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