Repsol Oil & Gas Canada (TLM) 40-F 2005 FY Annual report (Canada)

Exhibit 99.6

MANAGEMENT’S DISCUSSION AND ANALYSIS

March 13, 2006

Management’s Discussion and Analysis

March 13, 2006

HIGHLIGHTS

(millions of Canadian dollars unless otherwise stated)	2005		2004		2003
Net income (1)	1,561		654		976
Dividends	125		114		90
Per share (Canadian dollars)
Net income (1)	4.24		1.71		2.53
Dividends	0.34		0.30		0.23
Production (mboe/d)	470		438		398
Production per share (boe/share)	0.47		0.42		0.38
Average sales price ($/boe)	56.67		42.75		38.51
Gross sales	9,554		6,874		5,610
Operating costs ($/boe)	8.41		7.26		6.98
DD&A, exploration and dry hole expense	2,359		2,199		1,899
Cash provided by operating activities (1)	4,871		3,119		2.554
Exploration and development spending	3,179		2,538		2,180
Total assets	18,339		12,408		11,780
Total long-term debt (1)	4,263		2,457		2,595
Proved reserves additions (before acquisitions and divestitures) (mmboe)	203		265		143
Proved reserves (mmboe)	1,639		1,488		1,362
Reserves replacement ratio (2)	120	%	166	%	99	%

(1)Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants (“CICA”) accounting standard for financial instruments. These changes to this standard require that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. Prior years’ amounts have been restated accordingly. See note 2 to the Consolidated Financial Statements.

(2)See the MD&A section entitled Reserves Replacement for method of calculation.

This Management’s Discussion and Analysis (MD&A) dated March 13, 2006, should be read in conjunction with the Consolidated Financial Statements of the Company. The Company’s Consolidated Financial Statements and the financial data included in the MD&A have been prepared in accordance with accounting principles generally              accepted in Canada. A summary of the differences between accounting principles generally accepted in Canada (Canadian GAAP) and those generally accepted in the United States (US GAAP) is contained in note 21 to the Consolidated Financial Statements.

Talisman follows the successful efforts method to account for oil and gas exploration and development costs, as described in the Application of Critical Accounting Policies and the Use of Estimates section of this MD&A. The alternative method of accounting for oil and gas exploration and development costs is the full cost method. The differences between the full cost and successful efforts methods of accounting make it difficult to compare net income between companies that use different methods of accounting.

Unless otherwise stated, references to production and reserves represent Talisman’s working interest share (including royalty interests and net profits interests) before deduction of royalties. Throughout this MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. Boe’s 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 necessarily represent a value equivalence at the wellhead.

Dollar amounts included in the MD&A are expressed in Canadian dollars unless otherwise indicated. All comparative percentages are between the years ended December 31, 2005 and December 31, 2004, unless stated otherwise.

Talisman Energy Inc’s subsidiaries conduct business in various parts of the world. Talisman Energy Inc.’s financial statements are prepared on a consolidated basis. For ease of reference, throughout this MD&A the terms “Talisman” and the “Company” are used to refer collectively to Talisman Energy Inc., its direct and indirect subsidiaries and partnership interests held by Talisman Energy Inc. and its subsidiaries, unless the context indicates otherwise.

Information relating to changes in the Company’s reporting segments in 2005 and 2006 is included in the section entitled Segmented Results Review of this MD&A.

Additional information relating to the Company, including the Company’s Annual Information Form, can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com. The Company’s annual report on Form 40-F may be found in the EDGAR database at www.sec.gov.

2

Talisman’s Performance Highlights in 2005

In 2005, production averaged a record 470 mboe/d (7% higher than 2004), with the Company exiting the year producing 543 mboe/d in December. Net income for the year was a record $1.6 billion ($4.24/share), 139% higher than 2004. In 2005, the increase in net income was due to higher oil and natural gas prices, increased production and decreases in both hedging losses and dry hole expenses, partially offset by the impact of the stronger Canadian dollar in relation to its US counterpart and increases in royalties, operating expenses, DD&A, stock-based compensation and taxes.

During 2005, nine million shares were repurchased at an average price of $39.01/share, long term debt increased to $4.26 billion with the acquisition of Paladin Resources plc (now Paladin Resources Limited and referred to as “Paladin”) and the Company increased its semi-annual dividend rate by 13.3% to $0.17/share.

The consolidation of the Paladin assets occurred on November 18, 2005, producing approximately 45 mboe/d from that date forward. The acquisition was completed in January 2006.

Operational highlights for the year included the completion of the offshore South Angsi oilfield development in Block PM 305 in Malaysia, the exploration discoveries near the Ross and Balmoral fields in the North Sea, ongoing development of the Tweedsmuir fields and drilling successes in the northern Alberta Foothills.

In 2005, production per share increased 11% over the previous year. Talisman spent $3.2 billion on exploration and development activities and participated in drilling 722 successful wells in 2005. During 2004 and 2003, production averaged 438 mboe/d and 398 mboe/d, respectively. Excluding Sudan operations, production averaged 385 mboe/d in 2003.

In 2005, Talisman added 203 mmboe of proved reserves, before acquisitions and dispositions, replacing 120% of production. Including acquisition and disposition activity, the Company added 320 mmboe of proved reserves, replacing 189% of production.

2006 OUTLOOK SUMMARY

Talisman anticipates 2006 production growth of approximately 10 – 16%. Additional discussion of management’s estimates and assumptions for 2006 can be found in the MD&A section entitled Outlook for 2006.

•Production is expected to average 515,000 – 545,000 boe/d, prior to planned acquisitions or dispositions.

•Production increases are expected in most of the Company’s geographic segments with the majority coming from international projects.

•Exploration and development spending is expected to be $4.4 billion (including $2 billion in North America and $1.6 billion in the North Sea).

•The Tweedsmuir and Tweedsmuir South fields in the UK sector of the North Sea are expected to start production towards the end of the first quarter of 2007 (adding approximately 45,000 boe/d from that point forward).

•Long-term debt is expected to decrease to approximately $3.6 – $4 billion through the application of excess cash from operating activities.

2005 VARIANCES

Net Income

(millions of dollars)
2004 Net income (1)	654
Favourable (unfavourable)
Cash items variance
Oil and liquids volumes	243
Oil and liquids prices	1,800
Oil and liquids foreign exchange price impact	(426	)
Natural gas volumes	134
Natural gas prices	1,223
Natural gas foreign exchange price impact	(294	)
Hedging – Commodities	403
Royalties	(471	)
Other revenue	80
Operating expense	(261	)
Transportation expense	(14	)
Interest expense	7
Current taxes (including Petroleum Revenue Tax)	(605	)
General and administrative	(18	)
Stock-based compensation payments	(71	)
Other	26
Total cash items variance	1,756
Non-cash items
Depreciation, depletion and amortization expense	(193	)
Dry hole expense	70
Exploration expense	(37	)
Future taxes (including Petroleum Revenue Tax)	(322	)
Stock-based compensation (non-cash)	(391	)
Other	24
Total non-cash items variance	(849	)
2005 Net income	1,561

(1)Effective January 1, 2005, the Company retroactively adopted certain changes to the CICA accounting standard for financial instruments. These changes to this standard require that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. Prior years’ amounts have been restated accordingly. See note 2 to the Consolidated Financial Statements.

The significant variances from 2004 as summarized in the net income variance table are:

•Higher commodity prices and increased production more than offset the impact of the strengthening Canadian dollar and higher royalties.

•Reduced hedging losses, as a result of reduced hedging activity, in spite of increased commodity prices.

•Operating expense increased with a change in the production mix, additional volumes, maintenance and well workovers.

3

•Current taxes rose as a result of increased commodity prices and higher production and a greater proportion of taxable income in higher tax jurisdictions.

•Cash stock-based compensation payments increased by $71 million.

•Depreciation, depletion and amortization (“DD&A”) expense increased $193 million largely due to higher worldwide production and increased costs in North America.

•The non-cash portion of the stock-based compensation expense increased by $391 million (before tax) due to a 90% increase in Talisman’s share price.

CORPORATE RESULTS REVIEW

Revenue

Revenues from oil, liquids and natural gas sales in 2005 were $9.6 billion, up 39% over last year, due to higher oil and liquids prices ($1,374 million), natural gas prices ($929 million), oil and liquids volumes ($243 million) and natural gas volumes ($134 million). As a result of decreased hedging activity, hedging losses in 2005 were $403 million less than in 2004.

Daily Production Volumes

	2005	2004	2003
Oil and liquids (mbbls/d)
North America	56.3	57.4	59.6
North Sea (1)	132.7	121.9	113.1
Southeast Asia and Australia (1)	35.5	35.6	24.4
North Africa (1)	15.4	13.5	6.6
Trinidad and Tobago (1)	10.1	—	—
Sudan	—	—	13.0
	250.0	228.4	216.7
Natural gas (mmcf/d)
North America	915	885	864
North Sea (2)	120	114	109
Southeast Asia and Australia	284	260	117
	1,319	1,259	1,090
Total (mboe/d at 6:1)	470	438	398
Production per share (boe/share)	0.47	0.42	0.38

(1)Includes unlifted oil volumes as at December 31, 2005 of 3,670 bbls/d, 1,004 bbls/d, 650 bbls/d and 175 bbls/d in the North Sea, Southeast Asia and Australia, North Africa and Trinidad and Tobago, respectively.

(2)Includes gas acquired for injection and subsequent resale of 15 mmcf/d, 5 mmcf/d and 7 mmcf/d in 2005, 2004 and 2003, respectively.

Production

In 2005, production averaged a record 470 mboe/d, a 7% increase over last year’s average of 438 mboe/d. Production per share increased by 11%. Production in 2003, excluding Sudan, was 385 mboe/d.

Natural gas production in North America averaged 915 mmcf/d, an increase of 30 mmcf/d over 2004. This 3% production growth reflects Talisman’s drilling success. In 2005, 685 wells were drilled with a 97% success rate.

Significant production increases were recorded in Monkman, up 33 mmcf/d to 104 mmcf/d, Bigstone/Wild River, up 15 mmcf/d to 109 mmcf/d and Appalachia, which averaged 105 mmcf/d, up 16 mmcf/d. North America oil and liquids average production was 56,304 bbls/d during the year, down 2% from 2004 due to decline rates and the Company’s continued focus on natural gas.

Oil and liquids production in the North Sea in 2005 averaged 132,716 bbls/d, a 9% increase over 2004. During the fourth quarter of 2005, the Company acquired the Paladin assets, which added 4,082 boe/d for the full year 2005 and exploration assets including those in the UK Central North Sea and Norway. The Company also acquired a 70% interest in the Varg field producing assets in Norway, as well as additional exploration acreage.Talisman drilled 28 successful oil and gas wells, including successful programs at Clyde, Claymore, Tartan, Gyda and Varg. During the fourth quarter, production averaged 159,918 bbls/d, up 29% over the third quarter. North Sea natural gas production increased 6% to 120 mmcf/d. Production averaged 198mboe/d during December.

Southeast Asia and Australia produced 35,476 bbls/d of oil and liquids in 2005, relatively unchanged from 2004. During December, the average was 54,954 bbls/d. The Paladin acquisition added the SE Sumatra and the Offshore NW Java Blocks in Indonesia, which together averaged 5,326 bbls/d in December, and Australia properties, which averaged 5,846 bbls/d in the same month. Total production for the year in Malaysia/Vietnam increased to 28,000 bbls/d from 22,388 bbls/d the previous year. The South Angsi PM-305 field came onstream in mid-August of 2005, averaging 6,472 bbls/d for the year and 17,244 bbls/d in December. Indonesia oil and liquids production averaged 6,790 bbls/d, down 49% from 2004, due to the expiry of the Tanjung and Jambi production sharing contracts (PSCs). Australia averaged 686 bbls/d for the year.

Natural gas production in Southeast Asia and Australia increased 9% to 284 mmcf/d in 2005. In Malaysia/Vietnam, natural gas production from PM-3 CAA was 107 mmcf/d in 2005, down 11% from the previous year due to commercial constraints. Natural gas sales in Indonesia averaged 177 mmcf/d with higher demand for Corridor gas from Caltex and Singapore Power.

North Africa oil production averaged 15,377 bbls/d in 2005, up 14% from 13,537 bbls/d in 2004, when operational issues reduced production at the Greater MLN facilities in Algeria. The Paladin acquisition during the fourth quarter added producing properties in Tunisia, which averaged 116 bbls/d for the year. During the month of December, production averaged 17,207 bbls/d, including 991 bbls/d from Tunisia.

Trinidad and Tobago averaged 10,111 bbls/d in 2005, with first oil in January.

In the Company’s international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted and sold to third parties. The continued growth of Talisman’s international operations, combined with the rise in oil prices, has increased the value of unlifted oil volumes as at December 31, 2005. Accordingly, the Company has changed its practice for recording revenue. Unlifted oil volumes are now recorded as inventory, at cost. Had this change not been initiated, net income in 2005 would have been $43 million higher, $21 million of which relates to prior years. These volumes have been separately identified in footnote 1 to the Daily Production Volumes table above.

4

Commodity Prices (1)

	2005	2004	2003
Oil and liquids ($/bbl)
North America	52.62	42.11	35.78
North Sea	64.78	48.29	39.72
Southeast Asia and Australia	68.79	51.29	41.35
North Africa	66.71	51.17	39.01
Trinidad and Tobago	63.40	—	—
Sudan	—	—	43.89
	62.78	47.45	39.09
Natural gas ($/mcf)
North America	9.05	6.83	6.58
North Sea	7.08	5.55	4.77
Southeast Asia and Australia	6.40	4.74	5.72
	8.30	6.28	6.30
Company $/boe (6 mcf:1 boe)	56.67	42.75	38.51
Hedging loss excluded from the above prices
Oil and liquids ($/bbl)	0.85	5.42	2.05
Natural gas ($/mcf)	—	0.07	0.08
Total $/boe (6mcf:1boe)	0.46	3.02	1.34
Benchmark prices
WTI (US$/bbl)	56.70	41.40	30.99
Dated Brent (US$/bbl)	54.52	38.22	28.83
NYMEX (US$/mmbtu)	8.55	6.09	5.44
AECO (C$/gj)	8.04	6.44	6.35
US$/C$ exchange rate	0.83	0.77	0.71
C$/Pound sterling exchange rate	2.21	2.38	2.29

(1)Prices exclude gains or losses related to hedging activities and do not include synthetic oil.

World oil prices continued to reach new record levels during 2005, with WTI averaging US$56.70/bbl, up 37% over the 2004 WTI average of US$41.40/bbl. North American natural gas prices increased 40% over 2004 with NYMEX gas prices averaging US$8.55/mmbtu.

More than 90% of the Company’s revenues are either received in US dollars or are closely referenced to US dollars. The Company converts these revenues to Canadian dollars for reporting purposes. The 7% strengthening of the Canadian dollar against the US dollar reduced Talisman’s reported oil and liquids price by $4.65/bbl to $62.78/bbl, a 32% increase over 2004, compared to the 37% increase in WTI (from US$41.40 in 2004 to US$56.70 during 2005). Talisman’s North America oil and liquids price averaged $52.62/bbl, up 25% from last year. The Company’s North Sea oil and liquids price averaged $64.78/bbl, up 34% over 2004. The Company’s Southeast Asia and Australia oil and liquids price averaged $68.79/bbl, up 34% over 2004. The Company’s North Africa oil price averaged $66.71/bbl, up 30% over 2004, as the price was impacted by the timing of production liftings.

Talisman’s average natural gas price in North America increased 33% to $9.05/mcf. The strengthening of the Canadian dollar during 2005 reduced Talisman’s reported North America natural gas price by $0.66/mcf. The Company’s North Sea natural gas price increased 28% to $7.08/mcf.

The Company’s natural gas price in Southeast Asia and Australia averaged $6.40/mcf, up 35% from 2004. Sales from Malaysia/Vietnam, where prices are referenced to the Singapore fuel oil spot market, averaged $4.13/mcf in 2005. Gas production from Malaysia/Vietnam accounted for 38% of Southeast Asia and Australia gas production during the year, down from 46% in 2004. A large portion of Corridor gas production, representing approximately 59% of the Company’s 2005 gas sales in Southeast Asia and Australia, is exchanged for Duri crude oil on an energy equivalence basis and is sold offshore with payment in US dollars and averaged $8.11/mcf.

The Company’s average sales prices are before a net oil hedging loss of $77 million or $0.85/bbl ($0.46/boe). The physical and financial commodity price contracts outstanding at year end are disclosed in notes 11 and 12 to the Consolidated Financial Statements with additional discussion in the MD&A section entitled Derivative Financial Instruments and Commodity Sales Contracts. Additional discussion of the expected impact of commodity price contracts on the Company’s 2006 results can be found in the Outlook for 2006 section of this MD&A. The Company’s accounting policy with respect to derivative financial instruments and commodity contracts is disclosed in note 1(k) to the Consolidated Financial Statements.

Royalties(1)

	2005		2004		2003
	Rates (%)	$millions	Rates (%)	$millions	Rates (%)	$millions
Oil and liquids
North America	21	214	20	174	21	155
North Sea	1	35	1	19	—	(3	)
Southeast Asia and Australia	40	351	41	277	39	143
North Africa	39	135	38	97	49	46
Trinidad and Tobago	15	35	—	—	—	—
Sudan	—	—	—	—	46	97
	14	770	14	567	14	438
Natural gas
North America	20	602	19	425	21	432
North Sea	7	21	8	18	6	11
Southeast Asia and Australia	30	202	25	114	5	13
	21	825	19	557	18	456
	17	1,595	16	1,124	16	894

(1) Royalty rates do not include synthetic oil.

5

The consolidated royalty expense in 2005 was $1,595 million (17%), an increase of $471 million or 42% from $1,124 million (16%) in 2004, as a result of higher commodity prices, increased volumes and rate increases in Southeast Asia and Australia. The Company’s oil and liquids royalty rate remained constant at 14%, while the amount of royalties paid increased by 36% to $770 million. This increase is due primarily to a combination of higher prices, production increases in Southeast Asia and Australia and North Africa, and first oil production in Trinidad and Tobago. Natural gas royalties for 2005 increased 48% to $825 million due to increases in both volumes and rates in North America and Southeast Asia and Australia.

In North America, natural gas royalties increased 42% to $602 million, averaging 20%, up from 19% in 2004. This increase in expense reflects a 33% increase in realized unit prices coupled with a 3% increase in production.

In Southeast Asia and Australia, the natural gas royalty rate was 30%, up from 25% in 2004, as a result of the impact of the payout of cost recovery pools at Corridor in 2004. Under the terms of the Corridor PSC, after the Company has recovered its historical capital costs, the Government of Indonesia increases its share of production, which results in a higher royalty rate. Corridor’s natural gas royalty rate averaged 32% during 2005, compared to 29% in the prior year. The Southeast Asia and Australia royalty rate was also impacted by Malaysia/Vietnam volumes at a royalty rate of 24%. Under the terms of the PSC in Malaysia, 60% of gas production is available for cost recovery. The government receives 10% of production as royalty and the remaining 30% profit gas is split 50% to the government and 50% to the working interest owners. This results in a total royalty of 25%, which is combined with a 13% royalty rate in Vietnam for a blended rate of 24%. This royalty rate is expected to continue until the Malaysia gas cost pools are recovered in 2009, based on current forecasts of production and prices.

Oil and liquids royalties in Southeast Asia and Australia averaged 40% in 2005, compared to 41% in 2004. Total royalty expense increased 27% to $351 million as price increases, coupled with production increases in Malaysia/Vietnam, more than offset the impact of production decreases in Indonesia related to the expiry of the Jambi and Tanjung concessions. Malaysia/Vietnam royalties are tied to production, price and cost levels and reached 37% in 2005, up from 35% last year. Under the terms of the PSC in Malaysia, 50% of oil production is available for cost recovery. The government receives 10% of production as royalty and the remaining 40% profit oil is split with 70% going to the government and 30% to the working interest owners. This results in a royalty of 38%, which combined with an 18% royalty rate in Vietnam results in a blended rate of 37%. This royalty rate will continue to increase as the Malaysia oil cost pools are recovered. Based on current forecasts of production and prices, the rate is expected to increase to approximately 41% in 2006 and to 48% in 2007.

In North Africa, the royalty expense increased by 39% to $135 million as production increased 14% from last year, while the rate increased from 38% last year to 39% in 2005.

Under the terms of the Algeria PSC, Talisman is subject to a total government take of 51%, part of which is income tax, during the first five years of production. During the first four years of production, Talisman receives accelerated production entitlement. During the fifth year of the agreement, any accelerated production entitlement received by Talisman during the first four years in excess of 49% on a cumulative basis reverts to the government. Accordingly, during the first four years of production, Talisman records a deferred royalty expense and liability for any production entitlement received in excess of 49%. During 2005, Talisman recorded a drawdown of deferred Algerian royalties of $14 million, for a total of $18 million to date. In both 2005 and 2004, total taxes and royalties combined to average a rate of 51%.

In the North Sea, royalties increased for both oil and gas due to production and price increases as the rates remained relatively flat.

Operating Expenses and Unit Operating Costs

	2005		2004		2003
	$/bbl	$millions	$/bbl	$millions	$/bbl	$millions
Oil and liquids
North America	7.24	142	6.75	135	6.28	131
North Sea (1)	17.14	808	14.06	627	12.05	498
Southeast Asia and Australia	4.48	56	5.57	73	7.22	64
North Africa	4.52	24	3.51	17	5.07	12
Trinidad and Tobago	2.94	11	—	—	—	—
Sudan	—	—	—	—	3.73	18
	11.81	1,041	10.32	852	9.25	723

	$/mcf	$millions	$/mcf	$millions	$/mcf	$millions
Natural gas
North America	0.90	300	0.79	257	0.75	237
North Sea	0.82	36	0.55	23	0.37	14
Southeast Asia and Australia	0.30	31	0.27	25	0.50	22
	0.76	367	0.66	305	0.69	273
Company ($/boe)	8.41	1,408	7.26	1,157	6.98	973
Synthetic oil	30.36	30	20.67	23	22.63	22
Pipeline	—	21	—	18	—	21
	—	1,459	—	1,198	—	1,039

(1) During 2005, North Sea pipeline costs were reclassified to operating expenses. Prior years have been restated accordingly.

6

Total operating expenses for the Company during 2005 were $1.5 billion, 22% higher than last year, with the North Sea accounting for almost 75% of the $261 million year-over-year increase. On a per unit basis, oil and liquids costs increased 14% to $11.81/bbl and natural gas costs averaged $0.76/mcf, a 15% increase from 2004.

North America oil and liquids operating costs increased 5% during 2005 with increases in maintenance and well workovers. On a per unit basis, costs increased 7% to $7.24/bbl. Unit operating costs for natural gas increased 14% to $0.90/mcf with higher third party processing fees, maintenance and well workover costs partially offset by the lower unit operating costs ($0.23/mcf) in Appalachia.

In 2005, North Sea operating expenses were up $194 million or 30% over last year, due in part to acquisitions, partially offset by a 7% strengthening in the Canadian dollar against the pound sterling. These acquisitions resulted in increased operating expenses of $130 million. Unit operating costs averaged $15.54/boe which reflects increased repairs and maintenance costs related to unscheduled shutdowns at Ross/Blake, increased well workover costs, vessel lease costs, fuel, chemical and insurance costs. Costs in Norway reflect higher workover costs and the impact of acquired new production at Varg and Brage.

Southeast Asia and Australia unit operating costs decreased 13% to $2.94/boe, as increased production of lower unit cost volumes from Corridor and PM-305 in Malaysia replaced the higher unit cost volumes from the expired concessions in Tanjung and Jambi. Oil and liquids unit costs averaged $4.48/bbl, down 20% from the prior year. In Malaysia/Vietnam, unit costs averaged $2.81/bbl, a 34% increase from 2004, due to new production volumes from PM-305. Indonesia unit costs decreased 3%, to $11.12/bbl. Southeast Asia and Australia natural gas unit costs averaged $0.30/mcf, 11% more than 2004. In Indonesia, where gas sales represented 62% of the total for Southeast Asia and Australia versus 54% in 2004, unit costs decreased from $0.38/mcf to $0.32/mcf in 2005. Malaysia/Vietnam gas unit costs averaged $0.26/mcf as production for 2005 was 107 mmcf/d, down from 119 mmcf/d in 2004.

North Africa total operating costs in 2005 were $24 million, an increase of $7 million over the previous year. Unit operating costs averaged $4.52/bbl, up 29% from 2004 due to increased power and maintenance costs.

Trinidad and Tobago operating costs were $11 million or $2.94/bbl during 2005, the first year of production.

Transportation Expenses

	2005		2004		2003
	$/bbl	$millions	$/bbl	$millions	$/bbl	$millions
Oil and liquids
North America	0.50	10	0.49	10	0.48	10
North Sea	1.19	57	1.14	51	1.16	48
Southeast Asia and Australia	0.09	1	0.23	3	0.41	4
North Africa	1.65	9	1.76	9	1.77	4
	$/mcf		$/mcf		$/mcf
Natural gas
North America	0.19	65	0.20	66	0.21	67
North Sea	0.50	22	0.35	14	0.37	15
Southeast Asia and Australia	0.41	42	0.41	39	0.77	33
		206		192		181

During 2005, transportation expenses increased $14 million or 7% over 2004, primarily due to increased volumes and new volumes acquired at Gyda and Brage in the North Sea, where transportation expense averaged $1.49/mcf.

Depreciation, Depletion and Amortization Expense (includes accretion of ARO)

	2005		2004		2003
	$/boe	$millions	$/boe	$millions	$/boe	$millions
North America	12.42	946	10.47	785	9.26	688
North Sea	12.23	670	12.83	661	12.85	616
Southeast Asia and Australia	4.98	144	6.02	174	5.92	95
North Africa	6.80	36	5.99	30	6.99	17
Trinidad and Tobago	13.11	47	—	—	—	—
Sudan	—	—	—	—	3.98	19
	10.88	1,843	10.29	1,650	9.87	1,435

7

The Company’s 2005 DD&A expense increased $193 million or 12% to $1.8billion, with a per unit rate of $10.88/boe. DD&A rates in North America increased to $12.42/boe primarily due to higher drilling costs, increased capital expenditures on infrastructure projects as well as increased land amortization costs. The increase in rates combined with a 2% increase in boe production resulted in a 21% increase in the total DD&A expense to $946 million. In the North Sea, total expense increased 1% to $670 million, as the impact of an 8% increase in total boe production was partially offset by a decrease in the DD&A rates due to 2004 reserve additions and a weaker pound sterling relative to the Canadian dollar. Total DD&A expense for Southeast Asia and Australia decreased by $30 million or 17% as increased reserves in Malaysia/Vietnam and the expiry of the Tanjung concession lowered the per unit rate to $4.98/boe. This 17% rate reduction more than offset the impact of the 5% increase in boe production. Total DD&A expense for North Africa increased 20% to $36 million as a result of a 14% increase in production, which included an increased proportion of production from the higher rate MLN fields.

For additional information relating to DD&A, refer to the MD&A section entitled “Application of Critical Accounting Policies and Use of Estimates” and to notes 5 and 6 to the Consolidated Financial Statements.

Dry Hole Expense

(millions of dollars)	2005	2004	2003
North America	122	128	135
North Sea	53	109	69
Southeast Asia and Australia	11	25	9
North Africa	—	4	1
Trinidad and Tobago	21	12	—
Other (1)	34	33	37
	241	311	251

(1) In 2005, Other includes Colombia, Qatar and Peru.

During 2005, the Company incurred dry hole expenses of $241 million, $70 million lower than last year. In North America, dry hole expense was $122 million. In the North Sea, a total of seven wells were expensed for a total of $53 million. The Company also wrote off four wells in Malaysia/Vietnam, three in Trinidad and Tobago and five wells in the rest of the world.

Under the successful efforts method of accounting for oil and gas activities, the costs of unsuccessful and non-commercial exploration wells are written off to dry hole expense in the year such determination is made. Until such determination is made, the costs are included in non-depleted capital. At year end, $450 million of costs relating to exploration wells were included in non-depleted capital and not subject to DD&A pending final determination. The majority of the related wells were drilled in 2005, (2004 – $284 million; 2003 – $283 million).

Exploration Expense

(millions of dollars)	2005	2004	2003
North America	128	123	87
North Sea	53	28	21
Southeast Asia and Australia	40	20	17
Trinidad and Tobago	5	21	35
Other (1)	49	46	53
	275	238	213

(1) In 2005, Other includes Colombia, Peru, Qatar and Alaska.

Exploration expense consists of geological and geophysical costs, seismic, land lease rentals and indirect exploration expenses. These costs are expensed as incurred under the successful efforts method of accounting. The majority of the $37 million increase to $275 million relates to increased exploration activity in the North Sea, particularly in Norway, and in Southeast Asia and Australia.

Corporate and Other

(millions of dollars)	2005	2004(1)	2003(1)
G & A expense	201	183	152
Interest expense	166	173	178
Capitalized interest	19	13	24
Stock-based compensation	633	171	185
Other revenue	165	85	76
Other expense	39	89	16

(1)Effective January 1, 2005, the Company retroactively adopted certain changes to the CICA accounting standard for financial instruments. These changes to this standard require that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. See note 2 to the Consolidated Financial Statements.

General and administrative (G&A) expense increased due to additional personnel, salary increases and administrative costs. On a unit basis, G&A was $1.17/boe (2004 – $1.14/boe; 2003 – $1.05/boe).

The sum of interest on long-term debt and capitalized interest remained relatively flat at $185 million during 2005. Interest capitalized in 2005 is associated with the Tweedsmuir development project in the North Sea, which is scheduled to come on production towards the end of the first quarter of 2007.

Other revenue includes pipeline and custom treating revenues of $141 million for 2005, compared to $73 million in 2004. Pipeline revenues in the North Sea increased $61 million due to higher sales of volumes acquired for injection and subsequent resale. Other expense during 2005 included property impairments in the North Sea of $31 million, the majority of which was associated with the North Saltire Property.

Stock-Based Compensation

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at December 31, 2005. The Company’s stock-based compensation expense is based on the difference between the Company’s share price and its stock options, or cash units exercise price. As a result of record high share prices throughout the year, $633 million was expensed in 2005, of which $480 million was non-cash and $153 million cash. Over the course of the year, the average exercise price of all outstanding options increased from $19.58 per share to $26.14 per share, with a total of 21.5 million options outstanding at December 31, 2005. See note 8 to the Consolidated Financial Statements.

The Company’s stock option plans were amended during 2003 to provide employees and directors who hold stock options with the choice upon exercise to purchase a share of the Company at the stated exercise price or to receive a cash payment in exchange for surrendering the option. The cash payment is equal to the appreciated value of the stock option as determined based on the difference between the option’s exercise price and the Company’s share price approximately at the time of surrender. The cash payment alternative is expected to result in reduced shareholder dilution in the future as it is anticipated that most holders of the stock options (now and in the future) will elect to take a cash payment. Such cash payments made by the Company to stock option holders are deductible by the Company for income tax purposes, making these plans more cost effective.

8

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

Additional stock-based compensation expense or recoveries in future periods is dependent on the movement of the Company’s share price and the number of outstanding options and cash units.

Income Taxes

The Company’s effective tax rate for 2005, after deducting Petroleum Revenue Tax (PRT), was 44% compared to 36% in 2004 and 15% in 2003. A number of events in the past three years have affected the Company’s effective tax rates, including the recent acquisitions of producing assets in Norway, tax rate reductions in Canada and the sale of the Company’s indirectly held interest in the Greater Nile Oil Project in Sudan in 2003.

Effective Income Tax Rate

(millions of dollars)	2005	2004(1)		2003(1)
Income before tax	2,984	1,150		1,244
Less PRT
Current	150	124		72
Future	39	5		20
	189	129		92
	2,795	1,021		1,152
Income tax expense/(recovery)
Current	1,058	478		229
Future	176	(111	)	(53	)
	1,234	367		176
Effective income tax rate (%)	44	36		15

(1)Effective January 1, 2005, the Company retroactively adopted certain changes to the CICA accounting standard for financial instruments. These changes to this standard require that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. See note 2 to the Consolidated Financial Statements.

In 2005, future tax expense increased $287 million, to $176 million. In 2004, the Company recorded a future tax recovery of $50 million due to a reduction in Canadian federal and provincial tax rates, compared to a $160 million recovery of future taxes in 2003 for both Canadian rates.

A normalized effective tax rate after removing the impact of the Canadian tax rate changes, the tax on unrealized foreign exchange gains on foreign denominated debt and the impact of the gain on disposal of the Sudan operations would have been 42% in 2005, 38% in 2004 and 36% in 2003. The increase in the 2005 effective tax rate results in part from a higher proportion of income from jurisdictions with higher tax rates, e.g. Norway. Foreign exchange rate fluctuations over the past two years have resulted in taxes on gains related to inter-company loans and non-Canadian dollar denominated debt, for which there is no corresponding component of the unrealized gain reflected in income before taxes. See note 15 to the Consolidated Financial Statements for additional information on the Company’s income taxes.

Current income tax expense increased to $1,058 million in 2005, due primarily to higher commodity prices and volumes, which resulted in increases in current taxes of $222 million in Norway, $157 million in Southeast Asia and Australia, $67 million in the UK, $53 million in North America and $14 million in North Africa. In Trinidad and Tobago, production first came onstream during 2005 and current income tax expense was $64 million.

In December 2005, the UK government announced an income tax rate increase on petroleum profits from 40% to 50%, which the Company expects to be enacted during the second quarter of 2006 resulting in a one time non-cash “catch-up” expense estimated to be approximately $300 million.

The UK government levies PRT on North Sea fields, which received development approval before April 1993, based on gross profit after allowable deductions, including capital and operating expenditures. PRT, which is deductible for purposes of calculating corporate income tax, increased as a result of both higher prices and volumes on fields in the UK subject to PRT. In addition to the UK, PRT is levied in other countries, where $14 million was recorded during 2005.

Capital Spending(1), (3)

(millions of dollars)	2005	2004	2003
North America	1,763	1,500	1,580
North Sea	1,392	721	693
Southeast Asia and Australia	305	235	316
North Africa	27	8	34
Trinidad and Tobago	72	191	130
Other (2)	134	125	95
Corporate, IS and Administrative	28	26	38
	3,721	2,806	2,886

(1)Includes expenditures for exploration, development and asset acquisitions net of dispositions, but excludes corporate acquisitions and the Sudan disposition in 2003.

(2)In 2005, Other includes Colombia, Peru, Qatar and Alaska.

(3)Includes interest costs, which are capitalized on major development projects until facilities are completed and ready for use.

Natural gas continues to be the focus of the Company’s capital investment activities in North America, supplemented by low risk oil projects. Of the $1.8 billion of capital spending in North America, $658 million related to exploration activities and development accounted for $951 million. The Company participated in 495 gas wells and 171 oil wells in North America and had a success rate of 97%. Exploration and development spending was concentrated in the predominantly gas producing core areas in the Alberta Foothills, Greater Arch, Deep Basin, Monkman/BC Foothills, Edson and Appalachia regions. In addition, the Company spent $154 million on property acquisitions, net of dispositions.

Total capital spending in the North Sea was $1.4 billion including $165 million for exploration, $867 million for development and $360 million for net property acquisitions. Development activity included the ongoing development of the Tweedsmuir project and drilling and recompletion activity within the Clyde, Tartan, Piper and Claymore fields. In addition, development expenditures were incurred in Norway on the Gyda and Varg fields. A total of 25 successful development wells were drilled during 2005 in the North Sea. Also, a total of three exploration wells were drilled including the 13/23b-5 well, adjacent to the Ross and Blake fields. During 2005, the Company completed a number of acquisitions, the most significant of which were Varg, Andrew and Brage. The corporate acquisition of Paladin during the fourth quarter of 2005 added producing assets in the UK, Norway and Denmark, as well as exploration acreage.

Malaysia/Vietnam accounted for $250 million of the $305 million of total capital spending in Southeast Asia and Australia, with the South Angsi field development in PM-305 and on-going PM-3 CAA development. Talisman participated in 10 successful development wells in Malaysia/Vietnam during 2005. In addition, six successful exploration wells were drilled in Malaysia/Vietnam. A total of $55 million was spent in Indonesia, primarily on the Suban phase 2 development to supply natural gas to West Java in 2007.

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Capital spending in North Africa totaled $27 million in 2005, with Talisman participating in nine successful wells in Algeria and one in Tunisia.

In Trinidad and Tobago, a total of $72 million was spent primarily on Angostura development and the Eastern Block onshore exploration activity.

During 2005, the Company spent $49 million in Alaska on seismic and preparations for the 2006 drilling program. Talisman spent $24 million in Colombia on exploration drilling during 2005, as well as $20 million on exploration drilling in Peru and $14 million on seismic and exploration drilling in Qatar.

Information related to details and funding of the 2006 capital expenditures program is included in the Outlook for 2006 section of this MD&A.

Reserves Replacement

Talisman drilled 722 successful wells in 2005 and increased its total proved reserves by 10% to 1,639 mmboe at the end of 2005. The Company replaced 189% of conventional production from all sources and 120% before acquisitions and divestitures. Drilling related reserve additions totalled 203 mmboe. Talisman also acquired 117 mmboe of proved reserves. Talisman’s net proved reserves increased by 9% to 1,312 mmboe.

Proved oil and liquids reserves increased 19% to 736 mmbbls. Talisman added a total of 208 mmbbls from all sources, including 152 mmbbls in the North Sea, 34mmbbls in Southeast Asia and Australia, 12 mmbbls in North Africa and 10 mmbbls in North America. The majority (53%) of these reserves additions were through discoveries, additions, extensions and revisions. The North Sea (54%) and North America (24%) account for the majority of Talisman’s year end oil and liquids reserves. These are predominantly high quality crude oil and natural gas liquids. Talisman has virtually no heavy oil or bitumen reserves.

Talisman’s proved natural gas reserves increased by 4% in 2005, totaling 5.4 tcf at year end. Talisman’s North American natural gas reserves were 2.7 tcf at year end, up 3% from the previous year. In North America, the Company added 361 bcf through the drill bit (108% of production), minor net asset acquisitions (16 bcf) and upward revisions to existing reserves (29 bcf) offset by record natural gas production (334 bcf). These numbers include Fortuna’s natural gas reserves in the northeastern US, which totalled 142 bcf at year end, with the addition of 21 bcf through drilling activities.

Talisman’s proved international natural gas reserves at year end were 2.7 tcf and accounted for 50% of the Company’s total proved natural gas reserves, with Southeast Asia and Australia constituting 41% of total worldwide natural gas reserves.

Over the past three years, Talisman has added 611 mmboe of proved reserves through discoveries, additions and extensions (including revisions) and acquired 173 mmboe of proved reserves, net of dispositions (not including the impact of the sale of Talisman’s indirect interest in the Greater Nile Oil Project in Sudan). Approximately 80% of Talisman’s proved reserves have been independently evaluated over the past three years.

The reserves replacement ratio of 120% (before acquisitions) was calculated by dividing the sum of changes (revisions of estimates, improved recovery and discoveries) to estimated proved oil and gas reserves during 2005 by the Company’s 2005 conventional production. The reserves replacement ratio of 189% was calculated by dividing the sum of changes (revisions of estimates, improved recovery, discoveries, acquisitions and dispositions) to estimated proved oil and gas reserves during 2005 by the Company’s 2005 conventional production.

The Company’s management uses reserves replacement ratios, as described above, as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that a reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely, based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not include the cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.

Liquidity and Capital Resources

Talisman’s long-term debt at year end was $4.26 billion ($4.1 billion, net of cash), up from $2.5 billion at the end of last year. During 2005, the Company generated $4.9 billion of cash provided by operating activities and spent $3.2 billion on exploration and development and a net $3.1 billion on acquisitions. In addition, the Company repurchased nine million common shares and paid dividends of $125 million. At year end, the Company had not drawn against its available $1,345 million bank lines of credit. In addition, drawings to a total of $548 million are available in the form of letters of credit. In December 2005, the Company filed as part of a registration statement a debt shelf prospectus in the US under the Multi-Jurisdictional Disclosure System under which it may issue up to US$2 billion of debt securities in the US public debt market and simultaneously filed a medium term note shelf prospectus in Canada under which it may issue up to $1 billion of medium term note securities in the Canadian public debt market.

The Company repurchased 9,089,100 common shares under its normal course issuer bid (NCIB) during 2005 for a total of $355 million ($39.01/share). In March 2005, the Company renewed its NCIB to permit the purchase of up to 18,437,285 common shares, representing 5% of the total common shares outstanding at the time of the renewal. Of the total, 2,021,900 common shares were repurchased under the renewed NCIB. The NCIB expires in March 2006 and the Company has received Board of Directors’ approval to renew the NCIB for another year. This will allow the Company to repurchase up to 5% of the Company’s common shares outstanding at the time of renewal.

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

Subsequent to year end, Talisman issued long term debt under both the US and Canadian debt shelf prospectuses, completing a US$500 million offering of 5.85% notes due February 1, 2037 and a $350 million offering of 4.44% notes due January 27, 2011. Interest on both notes is payable semi annually. The $350 million offering was immediately swapped into US$304 million 5.054% debt. The proceeds from these note offerings were used to repay a portion of the amounts outstanding under the acquisition credit facility discussed below.

At December 31, 2005, the Company had current assets of $1.6 billion and current liabilities of $3 billion. Working capital movements are difficult to predict, but management does not anticipate a substantial change during 2006.

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In connection with the funding of the acquisition of Paladin, the Company arranged a $2,605 million (£1,300 million), unsecured non-revolving credit facility (bridge financing facility). At December 31, 2005, $1,848 million was drawn on this facility. Subsequent to year end, and following the repayment of a portion of the credit facility with the proceeds of the note offerings completed in January 2006, the total borrowings under the bridge financing facility (which requires refinancing by October2006) were reduced to $990 million. This amount, along with any reductions in the 2005 year end working capital deficiency, is expected to be funded from excess cash provided by operating activities, draws on existing credit facilities or proceeds from net asset dispositions. Borrowings may be made in US dollars or pounds sterling in the form of bankers’ acceptances or LIBOR-based loans.

Two common share dividends were paid in 2005 for a total of $125 million (an aggregate of $0.34/share). The Company’s dividend is determined semi-annually by the Board of Directors. At year end, there were 366 million common shares outstanding, down from 375 million at December 31, 2004. As at February 28, 2006, there were 366 million common shares outstanding, as well as 20,845,591 stock options outstanding.

At the end of 2005, Talisman’s ratio of debt to cash provided by operating activities was 0.9:1 and its ratio of debt to debt plus equity was 43%.

For additional information regarding the Company’s liquidity and capital resources, refer to note 7 to the Consolidated Financial Statements. In addition, refer to the Sensitivities table included in the Outlook Section of this MD&A for possible 2006 impacts of various factors on the Company’s estimated 2006 net income and cash provided by operating activities.

Talisman’s investment grade senior unsecured long-term debt credit ratings from Dominion Bond Rating Service (DBRS), Moody’s Investor Service, Inc. (Moody’s) and Standard & Poor’s (S&P) are BBB (high), Baa1 (under review for downgrade) and BBB+ (with a negative outlook), respectively.

Commitments and Off Balance Sheet Arrangements

As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the Consolidated Financial Statements at year end. The principal commitments of the Company are in the form of debt repayments; abandonment obligations; lease commitments relating to corporate offices and ocean-going vessels; firm commitments for gathering, processing and transmission services; minimum work commitments under various international agreements; other service contracts and fixed price commodity sales contracts.

Additional disclosure of the Company’s debt repayment obligations and significant commitments can be found in notes 7 and 12 to the Consolidated Financial Statements. A discussion of the Company’s derivative financial instruments and commodity sales contracts can be found in the next section of this MD&A.

The following table includes the Company’s expected future payment commitments as at December 31, 2005 and estimated timing of such payments.

			Payments due by period (1), (2) (millions of dollars)
Commitments	Recognized in financial statements	Total	Less than 1 year	1-3 years	4-5 years	6-10 years	11-15 years	After 15 years
Long-term debt	Yes – Liability	4,263	12	1,172	707	792	501	1,079
Abandonment obligations (3)	Yes – Partially accrued as liability	3,114	40	56	34	141	656	2,187
Office leases	Yes – Partially accrued as liability	207	28	48	44	86	1	—
Ocean-going vessel leases	No	124	59	20	12	30	3	—
Transportation and processing commitments	No	1,044	155	193	139	289	184	84
Minimum work commitments (4)	No	391	319	53	19	—	—	—
Other service contracts	No	1,043	311	590	116	21	5	—
Stock options and cash units (5)	Yes – Partially accrued as liability	840	627	213	—	—	—	—
Total		11,026	1,551	2,345	1,071	1,359	1,350	3,350

(1)Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivative contracts.

(2)Payments denominated in foreign currencies have been translated at the December 31, 2005 exchange rate.

(3)The abandonment obligation represents management’s probability weighted, undiscounted best estimate of the cost and timing of future dismantlement, site restoration and abandonment obligations based on engineering estimates and in accordance with existing legislation and industry practice.

(4)Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration or drilling obligations.

(5)The liability for stock options and cash units recognized on the balance sheet is based on the Company’s year end stock price and the number of options and cash units outstanding, adjusted for vesting terms. The amount included in this table includes the full value of unvested options and cash units. Timing of payments is based on vesting and expiry. Actual payments are dependent on the Company’s stock price at the time of exercise.

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Derivative Financial Instruments and Commodity Sales Contracts

The Company manages its exposure to fluctuations in foreign exchange rates, interest rates, electricity costs and commodity prices in part through the use of derivative financial instruments and commodity sales contracts. The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 1(k) to the Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at December 31, 2005, including their respective fair values, are detailed in notes 11 and 12 to the Consolidated Financial Statements.

During 2005, the Company had commodity price derivative financial instruments covering 6,000 bbls/d or 2% of the Company’s 2005 worldwide oil and liquids production. This resulted in a net decrease to recorded sales of $77 million (2004 – $480 million decrease; 2003 – $194 million decrease). During the fourth quarter of 2005, the Company entered into natural gas price derivative contracts and assumed various crude oil and natural gas derivative contracts as a result of the acquisition of Paladin. The fair value of derivative contracts acquired was a liability of $147 million. Virtually all of the acquired derivative contracts qualify for hedge accounting and, as such, subsequent unrealized changes in the fair value of these contracts are deferred and realized in income over the remaining term of the contracts. At December 31, 2005, the Company had outstanding commodity price derivative contracts that cover approximately 8,000 bbls/d (5%) of the Company’s anticipated 2006 North Sea oil and liquids production. An additional 68 mmcf/d (7%) of anticipated 2006 North American natural gas and 3 mmcf/d (2%) of North Sea gas production have been committed under fixed price commodity sales contracts. The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales. See notes 11 and 12 to the Consolidated Financial Statements for additional details regarding the contracts outstanding at year end.

In order to support the Company’s investments in natural gas projects outside North America and the North Sea, Talisman has entered into a number of long-term sales contracts. In conjunction with the PM-3 CAA development project, the Company has entered into a long-term firm supply contract for approximately 100 mmcf/d, at prices referenced to the Singapore fuel oil spot market. The majority of Talisman’s Corridor natural gas production in Indonesia is currently sold to Caltex under long-term sales agreements, with the majority of the natural gas sales exchanged for crude oil on an energy equivalent basis. The crude oil received from Caltex is then sold offshore. Sales to Singapore from Corridor are also under long-term sales agreements referenced to the spot price of fuel oil in Singapore. During 2004, the Company signed a long term contract to sell 2.3 tcf of Corridor natural gas to West Java, over a 17-year period with gas sales commencing in 2007, at a price of US$1.91/mcf, with no associated transportation costs. The Company’s share of sales will be approximately 810 bcf based on its 36% interest. The Company anticipates having sufficient production to meet all future delivery commitments.

Effective January 1, 2004, the Company’s US dollar cross currency and interest rate swap contracts were no longer designated as hedges of the £250 million Eurobond, which resulted in a revaluation of this debt and a deferred gain of $17 million which is being amortized over the period to 2009. The swap contracts were terminated in 2004 for net cash proceeds of $138 million and resulted in an additional gain of $15 million. The termination of these contracts did not accelerate recognition of the deferred gain into income.

In order to hedge a portion of the fair value risk associated with the US$375 million 5.125% notes due 2015, the Company entered into fixed to floating interest rate swap contracts with a total notional amount of US$300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three-month US$ LIBOR plus 0.433% while receiving payments of 5.125% semi-annually. These contracts have been designated as a hedge of the fair value of a portion (US$300 million) of the total US$375 million notes issued in May 2005.

In order to facilitate the exchange of the acquisition credit facility from pounds sterling into the Company’s functional currency (US$) the Company entered into forward contracts to buy UK pounds sterling (GBP) and sell US dollars. At December 31, 2005 foreign currency contracts were in place for £725 million at an average rate of 1.7543US/£. Subsequent to year end, additional contracts were executed and the amount outstanding under the acquisition facility (£938 million) was exchanged for US$1,646 million resulting in an average exchange rate of 1.7552.

As a result of the acquisition of Paladin, Talisman acquired a foreign exchange derivative contract to swap US$15.1 million to Norwegian Kroner (NOK) at a rate of 6.4475 NOK/US on March 31, 2006. The fair value of the contract acquired was less than $1 million and is not designated as a hedge and, therefore, is recorded at fair value.

The Company has established a system of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties. The Board of Directors has authorized the Company to enter into commodity derivative agreements, which in aggregate do not exceed 40% of total estimated production. With the current high commodity prices and the Company’s strong balance sheet, management does not believe the capital expenditure program is under significant risk and has not actively renewed the derivatives program.

SEGMENTED RESULTS REVIEW

Talisman is an independent international upstream oil and gas company whose main business activities include exploration, development, production, transporting and marketing of crude oil, natural gas and natural gas liquids. Note 20 to the Consolidated Financial Statements provides segmented financial information that forms the basis for much of the following discussion and analysis. The Company’s operations in 2005 were conducted principally in five geographic segments: North America, the North Sea, Southeast Asia and Australia, North Africa and Trinidad and Tobago, where the Angostura field began production in January 2005. Beginning in the first quarter of 2006, changes will be made to the reporting segments as outlined in the Outlook for 2006 section of the MD&A. The segment entitled Southeast Asia and Australia includes Indonesia, Malaysia/Vietnam and Australia for the year ended December 31, 2005, but only Indonesia and Malaysia/Vietnam in both 2004 and 2003. Similarly, the segment entitled North Africa includes both Algeria and Tunisia for the year ended December 31, 2005, but only Algeria in both 2004 and 2003. Exploration is being advanced in other areas outside the principal geographic segments, including Alaska, Colombia, Qatar and Peru. The Company’s indirectly held interest in the Greater Nile Oil Project in Sudan was sold on March 12, 2003. The following is a brief summary of the financial results of each geographic segment. The Company’s pre-tax segmented income as discussed below is before corporate general and administration, interest, stock-based compensation, taxes and non-segmented foreign exchange gains and losses. Effective January 1, 2004, with the adoption of the new hedge accounting rules (see notes 1(k) and 11 to the Consolidated

12

Financial Statements) the Company allocates hedging gains and losses on the basis of the percentage of relative hedged production. More detailed analysis of the Company’s results can be found after this Segmented Results Review.

North America (excludes Alaska)

During 2005, the North America operations contributed $1.6 billion or 40% of the Company’s pre-tax segmented income of $4 billion, up 79% from $877 million (51% of $1.7 billion) in 2004. Gross sales in North America increased 33% to $4.1 billion due principally to higher commodity prices and natural gas production. North American production averaged 208,800 boe/d, up 2% over 2004, and represented 44% of the Company’s total production in 2005. Royalty expense increased 36% to $816 million due to higher commodity prices. North American operating expense increased 14% to $478 million due to increased natural gas volumes, higher processing fees, well workovers and maintenance costs. DD&A increased to $946 million, up from $785 million due to increased production, higher drilling costs, increased capital expenditures on infrastructure projects as well as increased land amortization costs. Total exploration and development spending for North America in 2005 was $1.6 billion, up 11% over 2004.

North Sea

The North Sea pre-tax segmented income increased to $1.6 billion and accounted for 40% of the Company’s pre-tax segmented income during 2005, up 226% from $486 million in 2004. North Sea gross sales increased 39% to $3.3 billion due primarily to higher prices and increased liquids production, resulting from acquisitions and development drilling. Production averaged 152,700 boe/d and represented 33% of the Company’s total production. This 8% increase in production also contributed to increases in operating expenses of $197 million and DD&A expense of $9 million. Royalty expense increased 51% to $56 million due to higher production and increased commodity prices. Dry hole expense decreased from $109 million to $53 million in 2005. Exploration and development spending for the North Sea was $1 billion, up 104% from 2004.

Southeast Asia and Australia

Southeast Asia and Australia contributed 16% ($649 million) to the Company’s pre-tax segmented income in 2005. Gross sales increased 36% to $1.5 billion with increased commodity prices and the startup of the PM 305 South Angsi field in Malaysia. Southeast Asia and Australia production averaged 82,800 boe/d, an increase of 5% over 2004 and represented 18% of the Company’s total production. Total operating expenses decreased 11% from 2004 to $87 million as a result of the increase in production mainly related to the low unit cost PM-3 CAA volumes, which offset the higher cost volumes from the Jambi and Tanjung concessions that expired in 2004 and early 2005. DD&A expense decreased 17% to $144 million as increased reserves in Malaysia/Vietnam and the expiry of the Tanjung concession lowered the per unit rate 17% to $4.98/boe. Capital spending for Southeast Asia and Australia was $305 million, up 20% from 2004.

North Africa

North Africa contributed 4% ($145 million, up 49% from 2004) to the Company’s pre-tax segmented income in 2005. Gross sales increased over 2004 by 37% to $349 million as the higher commodity prices combined with increased production. Production for 2005 averaged 15,400 bbls/d, up 14% over 2004, and represented 3% of the Company’s total production in 2005. Operating costs in 2005 increased 41% to $24 million as a result of higher power and maintenance costs. Capital spending for North Africa was $27 million, up $19 million from 2004 primarily related to the phase 2 expansion of the Greater MLN facilities.

Trinidad and Tobago

Trinidad and Tobago contributed 3% ($110 million) to the Company’s pre-tax segmented income in 2005, its first year of production. In 2005, gross sales were $229 million, production averaged 10,100 bbls/d, with operating and DD&A expenses at $11 million and $47 million, respectively. Capital spending for Trinidad and Tobago in 2005 was $72 million, down from $191 million the previous year when installation of producing field facilities was completed.

Other Exploration and Development

During 2005, the Company spent $134 million, the majority of which was in Alaska, Colombia, Peru and Qatar.

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Summary of Quarterly Results

The following is a summary of quarterly results of the Company for the eight most recently completed quarters:

			Three months ended
(millions of Canadian dollars, unless otherwise stated)	Total Year	Dec. 31		Sept. 30	June 30	March 31
2005
Gross sales	9,554	2,891		2,606	2,080	1,977
Total revenue	8,047	2,433		2,189	1,748	1,677
Net income (1)	1,561	533		430	340	258
Net income available to common shareholders	1,561	533		430	340	258
Total assets	18,339	18,339		14,126	13,422	13,233
Total long-term liabilities	9,512	9,512		6,435	6,520	6,563
Capital expenditures
Exploration	1,084	358		273	216	237
Development	2,095	622		511	450	512
Per common share (dollars)
Net income (1)	4.24	1.45		1.17	0.93	0.70
Diluted net income(5)	4.14	1.42		1.14	0.91	0.68
Daily average production
Oil and liquids (bbls/d) (3)	249,984	292,039		242,884	228,977	235,492
Natural gas (mmcf/d) (4)	1,319	1,344		1,307	1,292	1,332
Total (mboe/d)	470	516		461	444	457
2004 (Restated (2))
Gross sales	6,874	1,828		1,788	1,705	1,553
Total revenue	5,355	1,402		1,355	1,337	1,261
Net income (1), (2)	654	121		122	193	218
Net income available to common shareholders (2)	654	121		122	193	218
Total assets	12,408	12,408		12,407	13,007	12,290
Total long-term liabilities	5,934	5,934		5,883	6,100	6,061
Capital expenditures
Exploration	952	250		280	200	222
Development	1,586	478		407	309	392
Per common share (dollars)
Net income (1), (2)	1.71	0.32		0.32	0.50	0.57
Diluted net income (2), (5)	1.68	0.31		0.31	0.50	0.56
Daily average production
Oil and liquids (bbls/d)	228,434	235,612		218,441	229,579	230,136
Natural gas (mmcf/d) (4)	1,259	1,292		1,263	1,244	1,236
Total (mboe/d)	438	451		429	437	436

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

(2)For 2004, net income available to common shareholders, net income per share and diluted net income per share have been restated to treat preferred securities as debt rather than equity. See note 2 to the Consolidated Financial Statements.

(3)Includes unlifted oil volumes as at December 31, 2005 of 5,499 bbls/d.

(4)Includes gas acquired for injection and subsequent resale of 15 mmcf/d in 2005, with 8 mmcf/d, 9 mmcf/d, 18 mmcf/d and 23 mmcf/d during each of the quarters ended March, June, September and December, respectively and 5 mmcf/d in 2004, with 8 mmcf/d, 8 mmcf/d, 3 mmcf/d and 3 mmcf/d during each of the quarters ended March, June, September and December, respectively.

(5)Diluted net income per common share is calculated using the treasury stock method, which gives effect to the potential dilution that could occur if stock options were exercised in exchange for common shares. However, since inception of the Company’s Stock Appreciation Rights Plan, only approximately 3% of stock options have been exercised for common shares, therefore, the dilution was insignificant.

The following discussion highlights some of the more significant factors that impacted net income in the eight most recently completed quarters.

During the fourth quarter of 2005, gross sales rose by $285 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea. Net income for the quarter increased by $103 million, as the increased revenue combined with reduced stock-based compensation charges to more than offset the impact of increases in operating, depreciation, depletion and amortization, royalty and tax expenses.

During the third quarter of 2005, higher commodity prices and production increased gross sales by $526 million. Net income for the quarter increased by $90 million, as the increased revenue more than offset the impact of increases in stock-based compensation, royalty and tax expenses.

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

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

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

In the third quarter of 2004, gross sales rose as the increase in oil prices more than offset the reduction in production, resulting from maintenance shutdowns. Net income in the third quarter declined from the previous quarter, as the increase in gross sales was more than offset by increases in hedging losses, dry hole costs, exploration expenses and current income taxes. In the first two quarters of 2004, gross sales continued to rise due to increases in both commodity prices and production, partially offset by increased hedging losses. These factors combined with the benefit of tax rate reductions to increase net income in the first quarter of 2004 over the last quarter of 2003. A higher charge for stock-based compensation and reduced tax rate reductions resulted in a drop in net income during the second quarter of 2004 from the previous quarter.

Application of Critical Accounting Policies and the Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates. Actual results could differ materially from those estimates. A summary of significant accounting policies adopted by Talisman can be found in note 1 to the Consolidated Financial Statements. In assisting the Company’s Audit Committee to fulfill its financial statement oversight role, management regularly meets with the Committee to review the Company’s significant accounting policies, estimates and any significant changes thereto, including those discussed below.

Management believes the most critical accounting policies, including judgments in their application, which may have an impact on the Company’s financial results relate to the accounting for property, plant and equipment, asset retirement obligation and goodwill. The rate at which the Company’s assets are depreciated or otherwise written off and the asset retirement liability provided for, with the associated accretion expensed to the income statement, are subject to a number of judgments about future events, many of which are beyond management’s control. Reserves recognition is central to much of the accounting for an oil and gas company as described below.

Reserves Recognition

Underpinning Talisman’s oil and gas assets and goodwill are its oil and gas reserves. Detailed rules and industry practice, to which Talisman adheres, have been developed to provide uniform reserves recognition criteria. However, the process of estimating oil and gas reserves is inherently judgmental. There are two principal sources of uncertainty: technical and commercial. Technical reserves estimates are made using available geological and reservoir data as well as production performance data.

As new data becomes available, including actual reservoir performance, reserves estimates may change. Reserves can also be classified as proved or probable with decreasing levels of certainty as to the likelihood that the reserves will be ultimately produced.

Reserves recognition is also impacted by economic considerations. In order for reserves to be recognized, they must be reasonably certain of being produced under existing economic and operating conditions, which is viewed as being at year end commodity prices with a cost profile based on current operations. In particular, in international operations, consideration includes the status of field development planning and gas sales contracts. As economic conditions change, primarily as a result of changes in commodity prices and, to a lesser extent, operating and capital costs, marginally profitable production, typically experienced in the later years of a field’s life cycle, may be added to reserves or conversely may no longer qualify for reserves recognition.

The Company’s reserves and revisions to those reserves, although not separately reported on the Company’s balance sheet or income statement, impact the Company’s reported net income through the depletion depreciation and amortization of the Company’s property, plant and equipment (PP&E), asset and goodwill impairments and the provision for future asset retirement obligations.

The Reserves Committee of Talisman’s Board of Directors reviews the Company’s reserves booking process and related public disclosures and the report of the internal qualified reserves evaluator (IQRE). The primary responsibilities of the Reserves Committee of the Board of Directors include, amongst other things, reviewing the Company’s reserves booking process and recommending to the Board of Directors, the Company’s annual statement of reserves data and other oil and gas information. The IQRE reports the Company’s annual reserves data to the Reserves Committee and delivers a regulatory certificate regarding proved reserves and their related future net cash flows.

Depreciation, Depletion and Amortization Expense (DD&A)

A significant portion of the Company’s PP&E is amortized based on the unit of production method with the remaining assets being amortized equally over their expected useful lives. The unit of production method attempts to amortize the asset’s cost over its proved oil and gas reserves base. Accordingly, revisions to reserves or changes to management’s view as to the operational life span of an asset will impact the Company’s future DD&A expense.

As outlined in the Company’s DD&A accounting policy and PP&E notes (notes 1(d) and 5 to the Consolidated Financial Statements), $3.2 billion (2004 – $1.2 billion) of the Company’s PP&E is not currently subject to DD&A. Approximately 16% of these costs relate to the Tweedsmuir development project ($500 million) in the North Sea, due to come on production in early 2007, at which time amortization will commence. The remainder of the $3.2 billion of non-depleted capital relates to the costs of other development projects ($725 million), which will be amortized when production commences, the costs of acquired unproved reserves ($1.6 billion) and incomplete drilling activities, including those wells under evaluation or awaiting commencement of production ($450 million). Uncertainty exists with the treatment of these costs. For example, if the evaluation of the acquired probable reserves or recently drilled exploration wells were determined to be unsuccessful, the associated capitalized costs would be expensed in the year such determination is made, except that in the case of acquired probable reserves associated with producing fields, these costs would be amortized over the reserve base of the associated producing field. Accordingly, the rate at which these costs are written off depends on management’s view of the likelihood of the existence of economically producible reserves.

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During the fourth quarter of 2004, the expected useful lives of certain productive assets changed, resulting in a reduction in the DD&A expense of $12 million.

Successful Efforts Accounting

Talisman uses the successful efforts method to account for its oil and gas exploration and development costs. Acquisition costs and development costs are capitalized and depleted using the unit of production method. Costs of drilling unsuccessful exploration wells (dry hole costs) and all other exploration costs, including geological and geophysical costs, are expensed.

The alternative method of accounting for oil and gas exploration and development costs is the full cost method. Under this method, costs of unsuccessful exploration wells as well as all other exploration costs are capitalized and added to the PP&E balance to be depleted on a unit of production basis in the future. In addition, future development costs are depleted over the total proved reserves.

The differences between the full cost and successful efforts methods of accounting make it difficult to compare net income between companies that use different methods of accounting.

Asset Impairments

The Company’s oil and gas assets and goodwill are subject to impairment tests. An impairment charge is recorded in the year an asset is determined to be impaired under the successful efforts method. Individual oil and gas assets are considered impaired under the successful efforts method if their fair value falls below their carrying value. Goodwill is considered to be impaired if its fair value, principally determined based on discounted cash flows, falls below its carrying value. Both tests require management to make assumptions regarding cash flows well into the distant future that are subject to revisions due to changes in commodity prices, costs, recoverable reserves, production profiles and, in the case of goodwill, discount rates. During the past three years, isolated asset impairments have occurred (2005 – $31 million; 2004 – $31 million; 2003 – $30 million), however, it is possible that future impairments may be material.

Purchase Price Allocations

The costs of corporate and asset acquisitions are allocated to the acquired assets and liabilities based on their fair value at the time of acquisition. In many cases the determination of fair value requires management to make certain assumptions and estimates regarding future events. Typically in determining fair value, management develops a number of possible future cash flow scenarios to which probabilities are judgmentally assigned. The allocation process is inherently subjective and impacts the amounts assigned to the various individually identifiable assets and liabilities as well as goodwill. The acquired assets and liabilities may span multiple geographical segments and may be amortized at different rates, or not at all as in the case of goodwill or, initially, for acquired probable reserves. Accordingly, the allocation process impacts the Company’s reported assets and liabilities and future net income due to the impact on future depreciation, depletion and amortization expense and impairment tests.

Goodwill, as determined by the purchase price allocation method, represents the excess purchase price over the fair value of identifiable assets and liabilities acquired in business combinations. Goodwill is not amortized but is subject to ongoing annual impairment reviews, or more frequently as economic events dictate, based on the fair value of reporting units. The Company’s reporting units for goodwill are consistent with the geographic segments included in note 20 to the Consolidated Financial Statements.

Goodwill is allocated to the reporting units on the basis of the excess of the fair value of the reporting unit over the identifiable assets and liabilities of the reporting unit. During 2005, Talisman acquired Paladin for $2.6 billion in cash and assumed long-term debt. The acquisition has been accounted for using the purchase method and the Paladin results have been included in the Consolidated Financial Statements of the Company from the date of acquisition. Also during 2005, the Company completed a number of oil and gas property and corporate acquisitions for a total cost of $536 million, comprised of $532 million in cash and assumed working capital and $4 million of properties exchanged. See note 3 to the Consolidated Financial Statements for details.

Asset Retirement Obligations

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with abandonment and reclamation activities. Estimates of the associated costs are subject to uncertainty associated with the method, timing and extent of future retirement activities. Accordingly, the annual expense associated with future abandonment and reclamation activities is impacted by changes in the estimates of the expected costs and reserves. Changes to these estimates in the past two years have resulted in the following: as at December 31, 2005, a reduction of $191 million in the discounted ARO liability related to an increase in life of reserves in the North Sea was offset by increases in the liability of $59 million and $21 million for North America and rest of world, respectively, related to changes in cost estimates; and at December 31, 2004, a reduction of $66 million in the discounted ARO liability related to an increase in life of reserves in the North Sea was offset by increases in the liability of $22 million for North America, related to change in cost estimates. The total undiscounted abandonment liability is currently estimated at $3.1 billion, which is based on management’s probability weighted estimate of costs and in accordance with existing legislation and industry practice.

As indicated in the MD&A section entitled New Canadian Accounting Pronouncements, the accounting for Asset Retirement Obligations was adopted on a retroactive basis effective January 1, 2004. Under these accounting requirements, the fair value of the Company’s Asset Retirement Obligations (ARO) has been recorded as a liability on the Company’s balance sheet. In determining the fair value of the Company’s ARO liability, management developed a number of possible abandonment scenarios to which probabilities were assigned based on management’s reasonable judgment. At December 31, 2005, the discounted fair value of the Company’s ARO liability is $1.3 billion, (2004 – $1.3 billion). As an indication of possible future changes in the estimated liability, if all of the Company’s abandonment obligations could be deferred by one additional year, the fair value of the liability would have decreased by approximately $30 million.

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Foreign Exchange Accounting

Talisman’s worldwide operations expose the Company to transactions denominated in a number of different currencies, which are required to be translated into one currency for financial statement reporting purposes. Talisman’s foreign currency translation policy, as detailed in note 1(i) to the Consolidated Financial Statements, is designed to reflect the economic exposure of the Company’s operations to the various currencies. The adoption of the US dollar, effective for 2002, as the Company’s functional currency is a reflection of Talisman’s overall exposure to US dollar denominated transactions, assets and liabilities; oil prices are largely denominated in US dollars as is much of the Company’s corporate debt and international capital spending and operating costs. However, the Company’s operations in the UK and Canada are largely self-sufficient (self-sustaining) and their economic exposure is more closely tied to their respective domestic currencies. Accordingly, these operations are measured in UK pounds sterling and Canadian dollars, respectively. Currently, the Company’s foreign exchange translation exposure principally relates to US dollar denominated UK and Canadian oil sales.

As part of the adoption by the Company as at January 1, 2004 of the new accounting guideline on Hedging Relationships, AcG 13 and effective January 2004, the Eurobond debt, denominated in UK pounds sterling, and the Company’s Canadian dollar debt were designated as hedges of the Company’s net investments in the UK and Canadian self-sustaining operations, respectively. As such, the unrealized foreign exchange gains and losses resulting from the translation of this debt are deferred and included in a separate component of shareholders’ equity described as cumulative foreign currency translation.

Production Sharing Contractual Arrangements

A significant portion of the Company’s operations outside North America and the North Sea are governed by production sharing contracts (PSCs). Under PSCs, Talisman, along with other working interest holders, typically bears all risk and costs for exploration, development and production. In return, if exploration is successful, Talisman recovers the sum of its investment and operating costs (“cost oil”) from a percentage of the production and sale of the associated hydrocarbons. Talisman is also entitled to receive a share of the production in excess of cost oil (“profit oil”). The sharing of profit oil varies between the working interest holders and the government from contract to contract. The cost oil, together with the Company’s share of profit oil, represents Talisman’s hydrocarbon entitlement (working interest less royalties). Talisman records gross production, sales and reserves based on its working interest ownership. The difference between the Company’s working interest ownership and its entitlement is accounted for as a royalty expense. In addition, certain of the Company’s contractual arrangements in foreign jurisdictions stipulate that income taxes are paid out of the respective national oil company’s entitlement share of production. The Company includes such amounts in income tax expense at the statutory tax rate in effect at the time of production.

The amount of cost oil required to recover Talisman’s investment and costs in a PSC is dependent on commodity prices and, consequently, Talisman’s share of profit oil is also impacted. Accordingly, the amount of royalty paid by Talisman over the term of a PSC and the corresponding net after royalty oil and gas reserves booked by the Company are dependent on the amount of initial investment and past costs yet to be recovered and anticipated future costs, commodity prices and production. As a result, when year end prices increase, the amount of net after royalty reserves the Company books may decrease and vice versa.

NEW CANADIAN ACCOUNTING PRONOUNCEMENTS

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

Exchange of Non-monetary Assets

The CICA has issued a new standard, effective January 1, 2006 on a prospective basis, requiring all non-monetary transactions to be measured at fair value rather than book value if the transaction has commercial substance. Under current rules, a transaction is a non-monetary transaction if the cash component is less than 10% of the value exchanged. Under the new standard, a transaction will have commercial substance if it causes an identifiable and measurable change in the economic circumstances of the entity. For example, if a property that is currently producing is swapped for undeveloped land, there would be an identifiable and measurable change in the economic circumstances of the assets swapped and this transaction would be measured at fair value under the new rules.

Other Comprehensive Income/Financial Instruments

The CICA has issued a new standard on accounting for financial instruments. The standard harmonizes Canadian rules with current International and US rules, while permitting alternatives not available under US GAAP. The standard introduces the concept of “Other Comprehensive Income” to Canadian GAAP. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or other comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to other comprehensive income and be brought into net income at the time the underlying hedged item is settled. Any ineffectiveness in the hedging relationship will be brought into net income during the period. This standard will be effective for Talisman’s 2007 reporting. Any instruments that do not qualify for hedge accounting will be marked to market with the adjustment (tax affected) flowing through the income statement.

Talisman has hedges in place related to the Paladin acquisition that carry into 2007. See note 11 to the Consolidated Financial Statements for details.

Variable Interest Entities

Having harmonized GAAP between Canada and the US, Variable Interest Entities rules are designed to catch off-balance sheet financing structures and force companies to consolidate the Variable Interest Entities (VIE) and report the debt on their balance sheet. The rules are quite complicated and have been written with broad applicability. An entity is a Variable Interest Entity if there is insufficient equity at risk in the entity and the equity holders are not exposed to residual expected losses or returns. These entities are to be consolidated by the Primary Beneficiary who is the company that will absorb the majority of any expected losses or residual income.

An example of a VIE would be a lease arrangement whereby the leasing company establishes a new subsidiary capitalized primarily with debt and the lessee guarantees a return back to the leasing company. The lessee would be required to consolidate the subsidiary, resulting in the debt being reported on the lessee’s balance sheet.

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Talisman will continue to review its arrangements to determine if there are any VIE’s that might require consolidation. Arrangements such as Floating Production and Storage Offloading (FPSO) leases are the most likely candidates for potential VIE’s. Management has not identified any VIE arrangements to date that would require a change in accounting treatment.

Leasing Arrangements

The Emerging Issues Committee (EIC) of the CICA has issued EIC 150 regarding the identification of leasing arrangements. The Committee reached a consensus that widens the scope of what is considered a lease. Arrangements entered into prior to the December 9, 2004 date are unaffected. The Company has reviewed arrangements, such as take or pay contracts or ship or pay contracts and has concluded that the impact of EIC 150 has not been significant to date.

Business combinations

Concurrently with the joint Financial Accounting Standards Board/International Accounting Standards Board (FASB/IASB) project, the CICA has coordinated a project addressing the business combinations accounting standard. The proposals under this standard will require the fair value of the acquired business to be measured on the date control is obtained. The full value of the assets and liabilities acquired will be recorded at fair value on the acquirer’s balance sheet, including the fair value of any contingent consideration, with the non-controlling interest in these assets and liabilities included in shareholders’ equity. Subsequent acquisitions of the non-controlling interest in the acquired company will be subject to gains and losses. All acquisition and integration costs must be expensed as incurred and cannot be recognized as a liability on acquisition. The standard is expected to be finalized in 2006, with an effective date as of January 1, 2007.

Outlook for 2006(1)

	Estimated for 2006	Actual 2005
Cash provided by operating activities	$ 5.2 – 5.6 billion	$ 4.9 billion

Exploration and development spending	Estimated for 2006			Actual 2005
(millions of dollars)	Exploration	Development	Total E&D	Total E&D
North America	748	1,237	1,985	1,609
United Kingdom	148	1,062	1,210	864
Norway	129	276	405	168
Southeast Asia and Australia	95	345	440	305
North Africa	—	65	65	27
Trinidad and Tobago	45	20	65	72
Other (2)	230	—	230	134
	1,395	3,005	4,400	3,179
Production (daily average)		Lower 2006 estimate	Upper 2006 estimate	Actual 2005
Oil and liquids (bbls/d)
North America		54,000	56,000	56,304
United Kingdom		109,000	113,000	107,020
Norway		45,000	49,000	25,696
Southeast Asia and Australia		53,000	59,000	35,476
North Africa		16,000	18,000	15,377
Trinidad and Tobago		7,000	9,000	10,111
		284,000	304,000	249,984
Natural gas (mmcf/d)
North America		935	955	915
United Kingdom (3)		135	140	111
Norway		10	15	9
Southeast Asia and Australia		305	355	284
		1,385	1,445	1,319
Barrels of oil equivalent (mboe/d)		515	545	470
Commodity price and exchange rate assumptions			Estimate for 2006	Actual 2005
US$/bbl WTI oil price			57.00	56.70
US$/mmbtu NYMEX natural gas price			9.00	8.55
US$/C$ exchange rate			0.84	0.83
C$/£ exchange rate			2.10	2.21

(1)A 2006 estimate of net income and net income per share has not been provided due to the inherent difficulties of estimating certain non-cash expenses, such as dry hole, property impairments and non-cash stock-based compensation. The Outlook for 2006 excludes acquisitions and dispositions, notably the planned disposition of 10,000 – 15,000 boe/d of non-core assets in Western Canada and the North Sea.

(2)Other includes Alaska, Colombia, Peru and Qatar.

(3)Includes gas acquired for injection and subsequent resale (of 23, 23, and 5 mmcf/d in lower 2006 estimate, upper 2006 estimate and actual 2005, respectively).

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Talisman expects to increase production 10 – 16% in 2006. Production for 2006 is expected to average approximately 515,000 – 545,000 boe/d before planned asset sales, with most of the increase coming from Norway, Malaysia/Vietnam and the UK.

Unit operating costs are expected to be marginally higher than in 2005. However, unit production costs, in addition to being impacted by currency exchange rates, are dependent on achieving expected production levels. Net capital spending is expected to be $4.4 billion and excludes significant corporate and asset acquisitions. The Company anticipates participating in the drilling of 685 North America and 183 international wells during 2006 (gross).

North America (excludes Alaska)

In 2006, natural gas will continue to be the focus of the Company’s exploration activities in North America, including deep gas exploration in Western Canada and the ongoing drilling program in Appalachia, supplemented by low risk oil projects. North American natural gas production in 2006 is expected to increase between 2 – 4% to average between 935 – 955 mmcf/d, while oil and liquids is expected to average 54,000 – 56,000 bbls/d, as the Company will spend approximately 92% of the North America budget on natural gas exploration and development. The Company expects to spend approximately $2.0 billion on capital projects and drilling in 2006, up from the $1.6 billion spent in 2005. The Company plans to participate in approximately 685 wells in 2006, including eight high impact exploration wells. Unit operating costs are expected to increase slightly to approximately $6.15/boe due to higher ad valorem taxes in Appalachia and increased processing and power costs.

The North Sea

Talisman’s North Sea assets include producing fields and exploration acreage in several areas of the North Sea, the principal ones being the UK and Norway. (For the purposes of this Outlook discussion, the “United Kingdom” includes interests in Germany and the Netherlands and “Norway” includes interests in Denmark). The Company’s North Sea strategy is to focus on development projects and exploration opportunities adjacent to core operated properties and infrastructure.

The United Kingdom

Production in the UK North Sea is expected to average 109,000 – 113,000 bbls/d and 135 – 140 mmcf/d in 2006. Capital spending is planned to increase by 40% over 2005, to approximately $1.2 billion, with 88% related to development projects. The Company plans to drill 34 gross development wells and up to 11 gross exploration wells. This increase in spending is driven by new properties from the Paladin acquisition and the ongoing program to develop the Tweedsmuir field, with first production expected towards the end of the first quarter of 2007. UK North Sea 2006 unit operating expenses are expected to approximate the 2005 amount. At planned exchange rates (approximately £1=C$2.10) unit operating costs are expected to be in the $15.65 – 17.60/boe range.

Norway

Norway production is expected to average 45,000 – 49,000 bbls/d and 10 – 15 mmcf/d in 2006. Capital spending is planned at $405 million, with 68% related to development projects. The Company plans to drill 11 gross development wells and up to eight gross exploration wells. Unit operating costs are expected to be in the $14.80 – 16.70/boe range.

Southeast Asia and Australia

Natural gas sales in Indonesia are expected to average 190 – 210 mmcf/d in 2006. Total planned capital spending of $85 million in Indonesia during 2006 includes the completion of the Phase 2 expansion of the gas processing facilities at Suban in the Corridor PSC, two gas wells to be drilled at Suban and the drilling of up to six gross exploration wells. Oil and liquids production in Indonesia is expected to average 11,000 – 13,000 bbls/d with the addition of the Paladin assets in SE Sumatra and offshore NW Java.

During 2006, Talisman’s oil and liquids production in Malaysia/Vietnam is expected to average between 36,000 – 38,000 bbls/d. Natural gas production is expected to average 115 – 125 mmcf/d during 2006.

Total development capital spending during 2006 in Malaysia/Vietnam is expected to be approximately $266 million. The commencement of the PM-3 CAA Northern Fields development is planned in 2006, with spending of $127 million. First production is planned for the second quarter of 2008. A total of 16 gross development wells are planned for 2006 (five in the Bunga Tulip Field development, four in PM-3 CAA, six in East Bunga Kekwa-Cai Nuoc Unit Area and one in PM - 314) for a total of $67 million. A total of $84 million on exploration activities is planned with three PM-3 CAA wells, an appraisal well in Bunga Tulip and two PM-314 wells. In addition, Talisman plans to drill one exploration well in Block 15-2/01 in Vietnam in 2006.

In Australia in 2006, oil and liquids production is expected to average 6,000 - 8,000 bbls/d, with capital spending of $5 million to participate in two exploration wells and one development well.

Operating costs in Southeast Asia and Australia are expected to increase to approximately $3.30/boe in 2006.

North Africa

Production from the Ourhoud and MLN fields in Algeria, together with production in Tunisia is expected to average 16,000 – 18,000 bbls/d in 2006. Unit operating costs are expected to fall due to higher production. A capital budget of $65 million is estimated and in Algeria includes drilling 24 development wells, the Phase II expansion of the Greater MLN facility and the El Merk project sanctioning, with first oil in mid-2009. Three development wells and three exploration wells are planned in Tunisia.

Trinidad and Tobago

Capital spending is budgeted at $65 million, with approximately two-thirds directed towards exploration, with the drilling of four exploration wells, including three onshore wells and five development wells. Production in Trinidad and Tobago is expected to average 7,000 – 9,000 bbls/d.

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Other

The Company is exploring in South America where it expects to spend $17 million in 2006 on exploration activities in Peru and Colombia. The Company has budgeted $105 million in Alaska during 2006 primarily to drill up to two exploration wells and conduct further exploration activities. The Company also plans to spend an estimated $34 million in Qatar, which will include the drilling of up to two exploration wells in Block 10.

At year end, Talisman has committed approximately 7% of its anticipated 2006 North American natural gas production under commodity sales contracts at an average price of $9.77/mcf, and 2% of its anticipated 2006 North Sea natural gas production under commodity sales contracts at an average price of £5.27/mcf. In addition, approximately 5% of the Company’s anticipated 2006 North Sea oil and liquids production is hedged at an average price of US$32.69/bbl.

A summary of the contracts outstanding at year end can be found in notes 11 and 12 to the Consolidated Financial Statements. Additional discussion of the Company’s commodity price hedging program can be found in the MD&A section entitled Derivative Financial Instruments and Commodity Sales Contracts.

Liquidity

The Company’s 2006 year end debt position is anticipated to decrease to approximately $3.6 – 4 billion, with cash from operating activities in excess of capital spending and dividend payments. Significant acquisitions or dispositions, a change from expected commodity prices, working capital movements or changes in the amount of share repurchases would impact the Company’s projected 2006 year end net debt position.

Sensitivities

Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated impact of these factors on the Company’s 2006 financial performance is summarized in the following table and is based on a WTI oil price of US$57/bbl, a NYMEX natural gas price of US$9/mmbtu and exchange rates of C$1=US$0.84 and £1=C$2.10.

Approximate Impact in 2006

(millions of dollars)	Net Income		Cash Provided by Operating Activities
Volume changes
Oil – 1,000 bbls/d	6		9
Natural gas – 10 mmcf/d	10		17
Price changes (1)
Oil – US$1/bbl	50		54
Natural gas
(North America) (2)  – C$0.10/mcf	15		20
Exchange rate changes
US$ increased by US$0.01	44		73
£ increase by C$0.025	(4	)	4

(1)The impact of commodity contracts outstanding for 2006 has been included.

(2)Price sensitivity on natural gas relates to North American natural gas only. The Company’s exposure to changes in North Sea and Malaysia/Vietnam natural gas prices is not material. Most of the Indonesia natural gas price is based on the price of crude oil and, accordingly, has been included in the price sensitivity for oil except for a small portion, which is sold at a fixed price.

RISKS AND UNCERTAINTIES

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.

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.

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.

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.

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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 health, safety and environment (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.

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 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.

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 the Alien 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 plaintiffs’ motion to certify the lawsuit as a class action. On October 5, 2005, the plaintiffs filed papers to appeal the decision denying class action status. The Company has filed papers opposing the plaintiffs’ appeal. Talisman believes the lawsuit is entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

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 cleanup 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.

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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 more 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 Kyoto Protocol, with a reduction commitment of 12.5% below 1990 levels by 2008 – 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 – 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 – 2007. Details regarding the UK government’s NAP for phase two of the EU ETS (2008 – 2012) are as yet uncertain.

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.

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 of proximity of pipeline capacity; the availability of drilling and other equipment; the ability to access lands; weather; unexpected costs increases; accidents; the availability of skilled labour; and regulatory matters.

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 time frames. 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.

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 service for oil and gas drilling and production equipment and services, the transportation 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.

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 favourable to Talisman and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with the contracts.

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 or United Kingdom pound 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.

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.

Disclosure Controls and Procedures

At the end of the period covered by this MD&A, an evaluation was carried out under the supervision of and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operations of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by the Company in reports that it files with or submits to the Canadian securities administrators is recorded, processed, summarized and reported within the time periods required.

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It should be noted that, while the Company’s Chief Executive Officer and Chief Financial Officer believe that the Company’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Company’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

ADVISORY

Forward-looking statements

This MD&A contains 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 MD&A, including among other places, under the headings “2006 Outlook Summary,” “Outlook for 2006” and “Risks and Uncertainties.” These statements include, among others, statements regarding:

•estimates of production and operations or financial performance;

•estimates and prices of future sales;

•business plans for drilling, exploration and development;

•the estimated amounts and timing of capital expenditures;

•estimates of unit operating costs;

•business strategy and plans or budgets;

•royalty rates and exchange rates;

•the merits 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 MD&A 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”, “goal” , “objective” 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 MD&A. 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 MD&A, Talisman assumed a US$57/bbl West Texas Intermediate oil price, a US$9/mmbtu New York Mercantile Exchange natural gas price, a US$/Canadian$ exchange rate of $0.84 and a Canadian$/British £ rate of 2.10.

This MD&A also discusses cash provided by operating activities and anticipated debt for 2006. The material assumptions used in determining estimates of cash provided by operating activities are: the anticipated production volumes described in the “2006 Outlook” section of this MD&A; estimates of realized sales prices, which are in turn driven by benchmark prices, quality differentials and the impact of exchange rates; estimated royalty rates; estimated operating expenses; estimated transportation expenses; estimated general and administrative expenses; estimated interest expense, including the level of capitalized interest; anticipated cash payments made by the Company upon surrender of outstanding stock options using the cash payment feature, which in turn is dependent on the trading level of the Company’s common shares and the number of stock options surrendered or exercised; and the anticipated amount of cash income tax and petroleum revenue tax. The material assumptions used in determining estimates of year end debt are: the anticipated amount of cash provided by operating activities; anticipated capital expenditures; the amount of anticipated dividend payments; movements in working capital; and estimated year end exchange rates.

Forecast production volumes are based on the midpoint of the estimated production range. Statements regarding estimated future production and production growth, as well as estimated financial results which are derived from or depend upon future production estimates (such as cash provided by operating activities), do not reflect the impact of any potential asset dispositions. The completion of any contemplated asset dispositions is contingent on various factors, including favourable market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approvals for such dispositions. The amount of taxes and cash payments made upon surrender of existing stock options is inherently difficult to predict.

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;

•the ability of the Company to integrate any assets it has acquired or may acquire or the performance of those assets;

•health, safety and environmental risks;

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•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 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);

•changes in 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.

We caution that the foregoing list of risks and uncertainties is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results are included: (1) under the heading “Risk Factors” in the Company’s Annual Information Form; and (2) under the heading “Management’s Discussion and Analysis – Risks and Uncertainties” and elsewhere in the Company’s 2005 Annual Report Financial Review. 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 (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.

ADVISORY

Reserves Data and Other Oil and Gas Information

Talisman’s disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities, which permits Talisman to provide disclosure in accordance with US disclosure requirements. The information provided by Talisman may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). Talisman’s proved reserves have been calculated using the standards contained in Regulation S-X of the SEC. US practice is to disclose net proved reserves after deduction of estimated royalty burdens, including net profits interests. Talisman makes additional voluntary disclosure of gross proved reserves. Probable reserves, which Talisman also voluntary discloses, have been calculated using the definition for probable reserves set out by the Society of Petroleum Engineers/World Petroleum Congress. Further information on the differences between the US requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in Talisman’s Annual Information Form.

The exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data in this MD&A reflects Talisman’s estimates of its reserves. While Talisman annually obtains an independent audit of a portion of its reserves, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this MD&A.

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