INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

May 9, 2007

Forward-looking Statements

This interim MD&A contains statements that constitute forward-looking statements and forward-looking information (collectively, "forward looking statements") within the meaning of applicable securities legislation. These forward-looking statements include, among others, statements regarding: anticipated asset dispositions, estimated timing of production, expected royalty rates and taxes, the Company's outlook for major projects, business strategy and plans or budgets; impact of new accounting pronouncements, outcome of litigation; and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance. 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.

Undue reliance should not be placed on forward-looking statements. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements. These risks and uncertainties include:

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

-   risks and uncertainties involving geology of oil and gas deposits;

-   uncertainty of reserves estimates, reserves life and underlying reservoir risk;

-   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;

-   health, safety and environmental risks;

-   uncertainties as to the availability and cost of financing and changes in capital markets;

-   uncertainties related to the litigation process, such as possible discovery of new evidence of 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);

-   competitive actions of other companies, including increased competition from other oil and gas companies or companies providing alternative sources of energy;

-   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.

Readers are cautioned that the foregoing list of risks and uncertainties is not exhaustive. Additional information on these and other factors which could affect the Company's operations or financial results 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 - Risk Factors" and elsewhere in the Company's 2006 Annual Financial Report. 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.

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, except as required by law.

Advisory - Oil and Gas Information

Throughout this interim MD&A, the Company makes reference to production volumes. Where not otherwise indicated, such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments. In the U.S., net production volumes are reported after the deduction of these amounts.

Management’s Discussion and Analysis (MD&A)

(May 9, 2007)

This discussion and analysis should be read in conjunction with the Unaudited Interim Consolidated Financial Statements of Talisman Energy Inc. (the “Company”) as at March 31, 2007 and 2006, and the 2006 Audited Consolidated Financial Statements of the Company. All comparative percentages are between the quarters ended March 31, 2007 and 2006, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Talisman’s previously announced asset rationalization program is ongoing. The Company’s disposition of its indirect interest in Syncrude closed on January 2, 2007 for proceeds of $472 million, resulting in an after-tax gain of $277 million, which has been included in net income from discontinued operations. Non-core assets to be disposed of in Western Canada and the UK represented 9 mboe/d and 17 mboe/d, respectively, of production in the first quarter of 2007, the results of which have been included in net income from discontinued operations. The Western Canadian asset disposals are expected to close in the second quarter for proceeds of approximately $530 million. The Company’s disposition of its non-operated assets in the Brae area of the UK North Sea for consideration of US$550 million has an effective date of January 1, 2007 and is expected to close later in 2007. The resulting gain or loss on disposition of these assets will be recorded when the respective transactions close.

The prior period has been restated to reflect the results of discontinued operations. See note 2 to the Unaudited Interim Consolidated Financial Statements.

Quarterly Results Summary

			Three months ended
March 31,			2007	2006
Financial (millions of C$ unless otherwise stated)
Net income from continuing operations			211	126
Net income from discontinued operations			309	71
Net income			520	197
C$ per common share1
	Net income	- Basic	0.49	0.18
		- Diluted	0.48	0.17
Net income from continuing operations
		- Basic	0.20	0.11
		- Diluted	0.19	0.11
Production (daily average)
Oil and liquids (bbls/d)			243,389	278,906
Natural gas (mmcf/d)			1,204	1,168
Continuing operations (mboe/d)			444	474
Discontinued operations (mboe/d)			26	49
Total mboe/d (6mcf=1boe)			470	523
Total Production (boe) per common share1 - Basic			0.04	0.04

1.   All per share amounts have been retroactively restated to reflect the Company’s three-for-one share split.

Net income for the quarter of $520 million increased by 164% over the same period of 2006, due principally to the $277 million after-tax gain on sale of the Company’s indirect interest in Syncrude in the current year, whereas first quarter 2006 results were adversely affected by a $325 million tax charge related to an increase in the UK income tax rate. Net income from continuing operations was up 67% from 2006, primarily due to the UK tax charge in 2006, which was partially offset by the impact in the first quarter of 2007 of lower production and commodity prices and increased operating costs and depreciation, depletion and amortization (DD&A).

Company Netbacks ^1,2

		Three months ended
March 31,		2007	2006
Oil and liquids ($/bbl)
	Sales price	65.46	67.85
	Hedging (gain) loss	(1.07)	0.09
	Royalties	10.63	9.39
	Transportation	1.28	1.01
	Operating costs	16.50	11.71
		38.12	45.65
Natural gas ($/mcf)
	Sales price	7.35	8.52
	Hedging (gain) loss	(0.18)	(0.10)
	Royalties	1.45	1.73
	Transportation	0.26	0.30
	Operating costs	1.03	0.84
		4.79	5.75
Total $/boe (6mcf=1boe)
	Sales price	55.52	60.66
	Hedging (gain) loss	(1.09)	(0.22)
	Royalties	9.74	9.81
	Transportation	1.40	1.34
	Operating costs	11.70	8.84
		33.77	40.89

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

2.Includes impact of discontinued operations.

During the first quarter, the Company’s average netback was $33.77/boe, which was $7.12/boe or 17% lower than in 2006. Talisman’s realized price of $55.52/boe was 8% lower than 2006, principally the result of lower world oil prices and North American and international gas prices. Increased operating costs and transportation expenses were partly offset by lower royalties and increased hedging gains in the quarter.

Gross sales from continuing operations for the quarter ended March 31, 2007 were $2.2 billion, a 15% decrease from 2006, as lower production and commodity prices more than offset the positive impact of a weaker Canadian dollar.

Daily Average Production, Before Royalties

		Three months ended
March 31,		2007	2007 vs 2006 (%)	2006
Oil and liquids (bbls/d)
	North America	45,019	(5)	47,310
	United Kingdom 1	95,601	(14)	111,658
	Scandinavia 1	31,912	(19)	39,529
	Southeast Asia 1	49,549	(4)	51,845
	Other 1	21,308	(25)	28,564
		243,389	(13)	278,906
Natural gas (mmcf/d)
	North America	880	6	829
	United Kingdom	43	8	40
	Scandinavia	14	(13)	16
	Southeast Asia	267	(6)	283
		1,204	3	1,168
Continuing operations (mboe/d)		444	(6)	474
Discontinued operations
	North America
	- oil and liquids (bbls/d)	2,358	(73)	8,867
	- natural gas (mmcf/d)	41	(37)	65
	United Kingdom
	- oil and liquids (bbls/d)	6,147	(50)	12,204
	- natural gas (mmcf/d) 2	63	(40)	105
Discontinued operations (mboe/d)		26	(47)	49
Total mboe/d (6mcf=1boe)		470	(10)	523

1. Includes oil volumes produced into inventory, excludes volumes sold (out of) inventory, for the three months ended March 31, 2007 of (9,132) bbls/d, (3,907) bbls/d, 2,910 bbls/d and 10,347 bbls/d in the United Kingdom, Scandinavia, Southeast Asia and Other, respectively, and as at March 31, 2006 of (4,399) bbls/d, 1,648 bbls/d, 1,139 bbls/d and (780) bbls/d in the United Kingdom, Scandinavia, Southeast Asia and Other, respectively.

2. Includes gas acquired for injection and subsequent resale of 16 mmcf/d and 14 mmcf/d in 2007 and 2006 respectively.

The Company’s average oil and liquids production from continuing operations for the quarter was 243,389 bbls/d, down 13% from last year. In North America, oil and liquids production averaged 45,019 bbls/d during the quarter, down 5% from 2006, due primarily to natural declines. In the UK, oil and liquids production averaged 95,601 bbls/d, down 14% from 2006. The reduction was due principally to natural declines and a shutdown at Montrose/Arbroath to bring in a jackup drilling rig, as well as water injection restrictions at Claymore, in the quarter, which were partially offset by approximately 6.6 mbbls/d of production from the Auk/Fulmar acquisition that closed on December 1, 2006. In Scandinavia, oil and liquids production decreased to 31,912 bbls/d, a result of natural declines and water breakthrough on two Varg wells in 2006. Two successful infill wells were drilled in Brage and Gyda in the quarter (initial production of 10,900 bbls/d net to Talisman), which are expected to contribute to second quarter volumes. In Southeast Asia, oil and liquids production declined 2,296 bbls/d to 49,549 bbls/d. In Indonesia, production declined 2% to 11,122 bbls/d. Oil and liquids production in Malaysia/Vietnam was 30,791 bbls/d, down 13% from 2006 mainly due to natural declines. Production in Australia benefited from a successful optimization program that was completed mid-2006, averaging 7,636 bbls/d up 2,475 bbls/d. Production from Other areas decreased to 21,308 bbls/d, principally the result of a 53% decrease in production from Trinidad and Tobago to 5,359 bbls/d as production shut-in last November was brought onstream gradually over the quarter, increasing to an average of 6,744 bbls/d during March. In Algeria, production averaged 14,897 bbls/d, down 8% from 2006, due to gas handling constraints ahead of the Greater MLN injection expansion, expected to start up in the fourth quarter of 2007.

During the quarter, natural gas production from continuing operations increased 3% to an average of 1.2 bcf/d, as increases in North America were partially offset by reduced production volumes in Southeast Asia. In North America, natural gas production was 880 mmcf/d, an increase of 51 mmcf/d from last year. Contributing to this increase was a new well in Appalachia, two new wells in Monkman, the successful development and infill drilling program at Bigstone Wildriver, new compression in the Alberta Foothills and the commissioning of the Lynx and Palliser pipelines during the third quarter of 2006. In Southeast Asia, natural gas production was 267 mmcf/d, a decrease of 16 mmcf/d from last year. Production in Malaysia/Vietnam averaged 57 mmcf/d this quarter, a decrease of 30 mmcf/d due to decreased availability of sales gas resulting from delayed commissioning of the Bunga Raya-E gas processing facility. Indonesia gas production increased 7% over last year, averaging 210 mmcf/d, as a result of higher demand from buyers of Corridor gas.

Volumes reported in discontinued operations represent production from assets currently held for sale and production from assets disposed of, until the date of closing.

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. Volumes transferred into or sold out of inventory for the periods ended March 31, 2006 and 2007 have been separately identified in footnote 1 to the Daily Average Production, Before Royalties table above.

Prices and Exchange Rates¹

		Three months ended
March 31,		2007	2007 vs 2006 (%)	2006
Oil and liquids ($/bbl)
	North America	53.55	8	49.58
	United Kingdom	64.73	(9)	71.01
	Scandinavia	64.64	(12)	73.42
	Southeast Asia	77.10	5	73.49
	Other	69.41	(1)	70.43
		65.46	(4)	67.85
Natural gas ($/mcf)
	North America	7.66	(13)	8.79
	United Kingdom	7.72	(24)	10.11
	Scandinavia	4.44	26	3.51
	Southeast Asia	6.29	(11)	7.08
		7.35	(14)	8.52
Total $/boe (6mcf=1boe)		55.52	(8)	60.66
Hedging (gain) loss, not included in the above prices
	Oil and liquids ($/bbl)	(1.07)		0.09
	Natural gas ($/mcf)	(0.18)		(0.10)
	Total $/boe (6mcf=1boe)	(1.09)		(0.22)
Benchmark prices and foreign exchange rates
	WTI (US$/bbl)	58.16	(8)	63.48
	Brent (US$/bbl)	57.75	(7)	61.79
	NYMEX (US$/mmbtu)	6.96	(23)	9.08
	AECO (C$/gj)	7.07	(20)	8.79
US/Canadian dollar exchange rate		0.85	(1)	0.87
Canadian dollar / pound sterling exchange rate		2.29	13	2.02

1. Excludes synthetic oil

Talisman’s first quarter realized commodity price averaged $55.52/boe, down $5.14/boe from last year as the benchmark prices for both worldwide oil and North American natural gas were significantly lower than a year ago. However, narrowing North American oil price differentials more than offset the decline in WTI oil prices resulting in an 8% realized price increase. In Southeast Asia, oil prices increased by 5% to $77.10/bbl due to the timing of liftings.

The Company’s North American natural gas price decline of 13% was not as pronounced as the decline in AECO and NYMEX gas prices of 20% and 23%, respectively. The Company's sales portfolio was weighted more heavily to the monthly index, which outperformed the daily index in the current period. In the prior period, the Company was more heavily weighted to the daily index, which underperformed the monthly index.

For the quarter ended March 31, 2007, Talisman recorded net hedging gains on commodity-based derivative financial instruments of $46 million, associated with gains on oil and liquids of $1.07/bbl and on natural gas of $0.18/mcf, compared to gains of $10 million associated with gains on natural gas of $0.10/mcf, which more than offset losses on oil and liquids of $0.09/bbl during the same period in 2006. As of April 1, 2007, the Company had derivative and physical contracts for approximately 11% of its remaining 2007 estimated production. A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2006 Audited Consolidated Financial Statements and in note 9 to the March 31, 2007 Unaudited Interim Consolidated Financial Statements.

Royalties

	Three months ended
March 31,	2007		2006
	%	$ millions	%	$ millions
North America	19	159	21	179
United Kingdom	-	-	2	2
Scandinavia	-	1	-	1
Southeast Asia	39	174	37	194
Other	31	21	28	50
	18	355	16	426

The Company’s royalty expense from continuing operations for the first quarter was $355 million (18%), down $71 million from $426 million (16%) in 2006. This decrease in the total royalty expense is the result of decreases in both commodity prices and production. In North America, the royalty rate decreased due to decreased prices for natural gas. In Southeast Asia, the rate increase related principally to PM-305 in Malaysia where historical cost pools were fully recovered by the middle of 2006.

Unit Operating Expenses

		Three months ended
	March 31,	2007	2007 vs 2006	2006
		$/boe	(%)	$/boe
	North America	7.51	15	6.55
	United Kingdom	22.87	63	14.03
	Scandinavia	22.21	28	17.33
	Southeast Asia	4.25	15	3.70
	Other	4.64	35	3.43
Company ($/boe)		11.70	32	8.84

Total Operating Expenses

		Three months ended
March 31,		2007	2006
(millions of dollars)
	North America	131	108
	United Kingdom	240	165
	Scandinavia	76	69
	Southeast Asia	36	33
	Other	4	8
		487	383
Pipeline		20	15
Total		507	398

During the first quarter, total operating expenses from continuing operations increased by $109 million to $507 million. In North America, cost increases due primarily to increases in processing charges, chemicals and lease road maintenance contributed to a 20% increase in total operating costs to $131 million. The impact of increased expenditures more than offset the 3% increase in production, resulting in a 15% increase in the unit operating expense. In the UK, operating costs increased 45% to $240 million, due partly to the 13% strengthening of the pound sterling against the Canadian dollar, which resulted in an increase of about $29 million or $2.70/boe in the current quarter.

The Auk/Fulmar interests acquired in the fourth quarter of 2006 contributed $27 million and pushed the rate up $1.36/boe. In addition, increased third party fuel gas purchases resulted in an increase of $9 million or $0.83/boe. The cost increases together with a 13% reduction in production resulted in an increase in unit operating costs to $22.87/boe. Unit operating costs in the UK are expected to drop below $15.00/boe in the fourth quarter of 2007 with the addition of significant low cost production, mainly at Tweedsmuir. In Scandinavia, operating costs increased $7 million to $76 million, as a result of the 8% strengthening of the Norwegian kroner against the Canadian dollar, higher well maintenance costs and additional helicopter shuttling on Varg. Combined with a 19% decrease in production, Scandinavian unit operating costs increased 28% to $22.21/boe. In Southeast Asia, total operating costs were up $3 million to $36 million due primarily to higher maintenance costs. A 5% decrease in production impacted the unit costs, which increased 15% to $4.25/boe.

Transportation Expenses

	Three months ended
March 31,	2007		2006
	$/boe	$ millions	$/boe	$ millions
North America	0.96	18	1.16	22
United Kingdom	1.78	16	1.51	15
Scandinavia	3.00	9	2.24	8
Southeast Asia	1.31	11	1.20	11
Other	1.21	2	0.93	2
	1.40	56	1.34	58

During the current quarter, transportation expense from continuing operations decreased $2 million to $56 million due to decreased production.

Unit Depreciation, Depletion and Amortization (DD&A) Expense (includes accretion of ARO)

	Three months ended
March 31,	2007	2007 vs 2006	2006
($/boe)		(%)
North America	15.73	14	13.77
United Kingdom	15.53	40	11.12
Scandinavia	27.89	54	18.12
Southeast Asia	8.42	31	6.43
Other	10.56	15	9.20
	15.10	29	11.69

Total Depreciation, Depletion and Amortization (DD&A) Expense (includes accretion of ARO)

	Three months ended
March 31,	2007	2006
(millions of dollars)
North America	272	229
United Kingdom	156	123
Scandinavia	96	72
Southeast Asia	69	58
Other	10	23
	603	505

The 2007, first quarter DD&A expense from continuing operations was $603 million, up 19% from the same quarter of 2006. The DD&A rate in North America increased 14% to $15.73/boe, due to higher drilling and development costs, increased capital expenditures on Midstream Operations and increased land amortization costs. The total DD&A expense in the UK increased 27%, to $156 million, principally due to the 13% strengthening of the pound sterling against the Canadian dollar, an increase in the depletable base and the Auk/Fulmar acquisition, which in combination resulted in a 40% increase in the unit DD&A rate. In Scandinavia, total DD&A charges increased $24 million to $96 million, principally due to an increase in the depletable cost base and an 8% strengthening of the Norwegian kroner against the Canadian dollar, with a resultant DD&A rate of $27.89/boe, up 54% from 2006. The unit DD&A rate for Southeast Asia increased by 31%, due primarily to an increase in the depletable cost base. In Other, the DD&A charge decreased 57% to $10 million as a result of decreased production in Algeria and in Trinidad and Tobago.

Other ($ millions)

	Three months ended
March 31,	2007	2006
G&A	60	60
Dry hole expense	100	64
Stock-based compensation	42	46
Other expense	(15)	24
Interest costs capitalized	28	13
Interest expense	47	45
Loss on held-for-trading financial instruments	37	-
Other revenue	33	30

General and administrative (G&A) expense was flat over the same quarter of last year, but due to the decrease in total production, the per unit amount of $1.42 was 13% above 2006.

Dry hole expense for the first quarter of 2007 was $100 million, up $36 million from the prior year, and includes $40 million in North America, $41 million in the UK and $19 million in the rest of the world.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units as at March 31, 2007. The Company’s stock-based compensation expense is based on the difference between the Company’s share price and the exercise price of its stock options or cash units. During the first quarter of 2007, $42 million was expensed. The Company paid cash of $48 million ($68 million in 2006) to employees in settlement of fully accrued option liabilities for options exercised. Since the introduction of the cash feature, approximately 97% of options exercised have been exercised for cash, with only 3% exercised for shares, resulting in reduced dilution of shares.

Other expense of ($15) million includes realization of contingent consideration from a previously disposed asset of $30 million. Capitalized interest expense is associated with the Tweedsmuir, Wood, Blane, Yme and Rev development projects in the North Sea and the Northern Fields development in Malaysia. Tweedsmuir began production May 8, 2007, with Wood and Blane scheduled to come on production in the third quarter of 2007. The loss on held-for-trading financial instruments includes the fair value change in the quarter of commodity price derivatives that are not designated as hedges and the change in value of the Canadian Oil Sands Units which the Company received on disposition of its indirect interest in Syncrude. See notes 1 and 9 of the Unaudited Interim Consolidated Financial Statements. Other revenue of $33 million includes $25 million of pipeline and processing revenue.

Taxes ($ millions)

Effective Income Tax Rate

		Three months ended
March 31,		2007	2006
Income from continuing operations before taxes		441	963
Less PRT
	Current	72	82
	Deferred	(4)	3
Total PRT		68	85
		373	878
Income tax expense
	Current income tax	173	298
	Future income tax	(11)	454
Total income tax expense		162	752
Effective income tax rate		43%	85%

The effective tax rate is expressed as a percentage of pre-tax income adjusted for Petroleum Revenue Tax (PRT), which is deductible in determining taxable income. The Company’s effective tax rate for the current quarter is lower than in 2006 due primarily to the impact of last year’s $325 million UK income tax rate increase on petroleum profits from 40% to 50%. Exclusive of this one time non-cash adjustment, the 2006 first quarter’s effective rate was 49%. Lower revenues from decreased production and prices combined with increased operating costs and capital expenditures resulted in lower taxes during the current quarter. Reduced commodity prices and production in the UK also decreased PRT.

Capital Expenditures¹

	Three months ended
March 31,	2007	2007 vs 2006	2006
		(%)
(millions of dollars)
North America	622	(12)	703
United Kingdom	369	39	265
Scandinavia	125	136	53
Southeast Asia	111	85	60
Other	62	(38)	100
Corporate, IS and Administrative	11	22	9
	1,300	9	1,190
Acquisitions	4		3
Dispositions	-		(5)
Discontinued operations 2	(464)		22
Total	840	(31)	1,210

1.   Capital expenditures exclude corporate acquisitions.

2.   2007 includes proceeds on disposition of $472 million, comprised of $229 million in cash and $243 million in Canadian Oil Sands Trust units.

North America capital expenditures for the current quarter totalled $622 million, with exploration costs of $269 million and development costs of $353 million (including plant and equipment). These expenditures encompassed the drilling of 129 gas wells and 37 oil wells. Expenditures in the UK during the first quarter were comprised of $43 million on exploration spending and $326 million on development spending, which included the ongoing development of the Tweedsmuir (which came on production May 8, 2007), Wood and Duart fields. In Scandinavia, the Company spent $48 million on exploration and $77 million on development. In Southeast Asia, capital expenditures of $111 million included $58 million on exploration spending, principally on the successful Hai Su Trung well in Vietnam, and development spending of $53 million, primarily on the Northern Fields project in Malaysia. In Other, the Company spent $13 million on development activities in North Africa, $18 million on exploration and $7 million on development in Trinidad and Tobago and $24 million on exploration activities in the rest of the world. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2007 section of the Company’s December 31, 2006 MD&A.

Long-term Debt and Liquidity

At March 31, 2007, Talisman’s long-term debt was $4.9 billion ($4.7 net of cash), up from $4.6 billion ($4.5 net of cash) at year-end. During the quarter, the Company generated $1.1 billion of cash provided by operating activities and spent $1.3 billion on exploration and development. It also received divestiture proceeds of $229 million from the disposal of its indirect interest in Syncrude and repurchased 15.5 million shares for $299 million.

During the quarter, the Company repaid the $385 million 5.8% notes. At March 31, 2007, the Company had $1,265 million drawn against its available $2,016 million bank lines of credit.

At March 31, 2007, the Company had current assets of $2.3 billion and current liabilities of $3.3 billion, including assets and liabilities of discontinued operations. Current assets include 8.2 million units ($231 million market value at March 31, 2007) of Canadian Oil Sands Trust. Working capital movements are difficult to predict, but management anticipates that accounts receivable will rise later in the year, due primarily to increasing revenue from incremental gas sales in Indonesia and full production at Tweedsmuir.

At quarter-end, debt-to-debt plus book equity was 39%. For the 12 months ended March 31, 2007, the debt-to-cash provided by operating activities ratio was 1.21:1.

In March 2007, the Company renewed its normal course issuer bid (NCIB) with the Toronto Stock Exchange (TSX). Pursuant to the NCIB, the Company may repurchase up to 104,732,244 of its common shares (representing 10% of the public float outstanding at the time the normal course issuer bid was renewed) during the 12-month period commencing March 28, 2007 and ending March 27, 2008. Shareholders may obtain a copy of the Company's notice of intention to make a normal course issuer bid, free of charge, by accessing it on www.sedar.com or by emailing the Company at tlm@talisman-energy.com.

As at March 31, 2007, there were 1,048,521,605 common shares outstanding, increasing to 1,048,644,255 at May 7, 2007.

As at March 31, 2007, there were 60,348,824 stock options and 8,174,653 cash units outstanding. Subsequent to March 31, 2007, 2,321,201 stock options were exercised for cash, 122,650 stock options were exercised for shares, 11,835,160 stock options were granted and 205,960 were cancelled, with 69,534,173 stock options outstanding at May 7, 2007. Subsequent to March 31, 2007, 364,945 cash units were exercised, 2,637,020 cash units were granted and 2,140 cash units were cancelled, with 10,444,588 cash units outstanding at May 7, 2007.

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), Baa2 (stable) and BBB+, respectively. S&P has assigned a rating of BBB+ (with a negative outlook) to the Company.

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

Financial Instruments

Effective January 1, 2007, Talisman adopted the new CICA accounting standards related to Comprehensive Income (section 1530), Financial Instrument Recognition and Measurement (section 3855), Financial Instruments Disclosure and Presentation (section 3861) and Hedges (section 3865). These new standards require that all financial instruments be recorded at fair value on the balance sheet. As a result of adopting this standard at January 1, 2007, the Company realized the fair value of assets of $122 million and the fair value of liabilities of $18 million related to commodity price derivative contracts. The fair value of derivative contracts on the balance sheet at March 31, 2007 is presented as a current asset of $28 million, a current liability of $56 million and a long-term liability of $29 million.

The Company may use derivative instruments to manage commodity price, foreign exchange and interest rate risk. The Company may choose to designate derivative instruments as hedges. All derivative instruments in existence at December 31, 2006 continue to be designated as hedges, and as such the gains and losses on the changes in fair value of these contracts are included in other comprehensive income until realized.

To date, the Company has elected not to designate any commodity price derivative contracts entered into from January 1, 2007 as hedges for accounting purposes and consequently realizes changes in the fair value of such contracts in net income immediately, which will increase the volatility of net income. Since January 1, 2007, the Company has entered into several costless collar and swap natural gas derivative contracts. The change in fair value of these contracts in the period was a loss of $25 million and has been included in the loss on held-for-trading financial instruments in the period.

In addition to its commodity derivatives, the Company has a fixed-to-floating interest rate swap and a cross currency interest rate swap. These interest rate derivative contracts are designated as fair value hedges of a portion of the Company’s long-term debt. The hedged portion of the long-term debt and hedging items are re-measured at fair value each reporting period and the respective changes in fair value are recorded in net income. In the first quarter of 2007, the changes in fair value in the derivatives and long-term debt offset each other

and are expected to continue to have no net impact on net income in future periods. The effect of revaluing to fair value the hedged portion of long-term debt resulted in a decrease of $12 million in the debt balance at March 31, 2007, with a corresponding $12 million liability recorded in other long-term obligations for the fair value of the derivative contracts.

During the first quarter of 2007, the Company settled a portion of its 2007 WTI costless collar covering a notional volume of 10,000 bbls/d for a gain of $40 million. The gain on settlement, net of tax, is included in accumulated other comprehensive income and will be realized as a hedging gain in net income over the period ending December 31, 2007, the term of the original hedge.

See notes 1 and 9 of the Unaudited Interim Consolidated Financial Statements.

On January 2, 2007, the Company acquired 8.2 million units of Canadian Oil Sands Trust on the disposition of its indirect interest in Syncrude. These trust units have been classified as held-for-trading financial instruments and as such are re-measured at fair value each reporting period. The movement in fair value of these units in the quarter resulted in a loss of $12 million and is included in the loss on held-for-trading financial instruments in the period.

Sensitivities

Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated annualized impact of these factors on the Company’s financial performance for 2007 is summarized in the following table and is based on an average WTI oil price of US$64.25/bbl, a NYMEX natural gas price of US$7.70/mmbtu and exchange rates of C$1=US$0.88 and £1=C$2.26.

Approximate Impact for 2007
(millions of dollars)		Net Income	Cash Provided by Operating Activities
Volume changes
	Oil - 1,000 bbls/d	8	11
	Natural gas - 10 mmcf/d	9	17
Price changes1
	Oil - US$1.00/bbl	46	47
	Natural gas (North America)2 - C$0.10/mcf	14	19
Exchange rate changes
	US$ increased by US$0.01	40	68
	£ increase by C$0.023	(8)	2

1   The impact of commodity contracts outstanding as of April 1, 2007 has been included.

2   Price sensitivity on natural gas relates to North American natural gas only. The Company’s exposure to changes in the natural gas prices in UK, Scandinavia and Malaysia/Vietnam is not material. Most of the natural gas price in Indonesia 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.

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

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

		Three months ended
		2007	20061				20051
		Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30
Gross sales		2,224	2,166	2,165	2,272	2,613	2,625	2,415	1,890
Total revenue		1,948	1,878	1,848	1,879	2,227	2,184	2,009	1,579
Net income from continuing operations		211	345	402	544	126	446	366	291
Net income		520	598	525	685	197	533	430	340
Per common share ($)2
	Net income from continuing operations	0.20	0.32	0.37	0.49	0.11	0.40	0.33	0.27
	Diluted net income from continuing operations	0.19	0.32	0.36	0.48	0.11	0.40	0.32	0.26
	Net income	0.49	0.55	0.48	0.62	0.18	0.48	0.39	0.31
	Diluted net income	0.48	0.54	0.47	0.61	0.17	0.47	0.38	0.30

1.Prior periods have been restated to reflect the impact of discontinued operations. See note 2 to the Unaudited Interim Consolidated Financial Statements.

2.All per share amounts have been retroactively restated to reflect the Company’s three-for-one split in May 2006. See note 5 to the Unaudited Interim Consolidated Financial Statements.

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters ended March 31, 2007.

During the first quarter of 2007, gross sales increased by $58 million over the previous quarter due to the impact of increased commodity prices, which more than offset the 3% decrease in total production. Net income from continuing operations decreased $134 million from the previous quarter as the impact of the increase in gross revenue and decrease in dry hole and stock-based compensation expense was more than offset by increases in DD&A, operating costs and taxes and the gain on sale of a royalty interest in an undeveloped lease in the previous quarter.

During the fourth quarter of 2006, gross sales increased by $1 million over the previous quarter as the impact of reduced oil prices offset the 6% increase in total production. Net income from continuing operations decreased $57 million from the third quarter as increases in charges for dry holes, exploration, stock-based compensation, DD&A and operating costs more than offset the impact of reduced taxes and the gain on sale of a royalty interest in an undeveloped lease.

During the third quarter of 2006, gross sales decreased by $107 million over the previous quarter due to decreased natural gas prices and reduced production. Net income from continuing operations for the quarter decreased by $142 million, primarily due to the $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions recorded in the second quarter.

During the second quarter of 2006, gross sales decreased by $341 million over the previous quarter due to decreased production. Net income from continuing operations for the quarter increased by $418 million, primarily due to the impact of a $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions and the $325 million future tax charge in the first quarter.

In the first quarter of 2006, gross sales decreased by $12 million over the previous quarter. Net income from continuing operations for the quarter decreased by $320 million, primarily due to the impact of a one-time non-cash adjustment of $325 million related to a UK income tax rate increase.

During the fourth quarter of 2005, gross sales increased by $210 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea. Net income from continuing operations for the quarter increased by $80 million as the increased revenue combined with reduced stock-based compensation charges more than offset the impact of increases in operating, DD&A, royalty and tax expenses.

During the third quarter of 2005, higher commodity prices and production increased gross sales by $525 million. Net income from continuing operations for the quarter increased by $75 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 from continuing operations increased in the quarter as higher 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.

New Canadian Accounting Pronouncements

In December 2006, the Canadian Accounting Standards Board (AcSB) issued two new Sections in relation to financial instruments: Section 3862, Financial Instruments - Disclosures, and Section 3863, Financial Instruments - Presentation. Both sections will become effective for Talisman’s 2007 year end disclosure and will require increased disclosure regarding financial instruments.

In December 2006, the AcSB issued Section 1535, Capital Disclosures. This standard requires disclosure regarding what the Company defines as capital and its objectives, policy and processes for managing capital. This standard will be effective for Talisman’s 2007 year end disclosure.

Internal Control over Financial Reporting

There were no changes in Talisman’s internal controls over financial reporting during the first quarter of 2007 that materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Risks and Uncertainties

Litigation

On September 12, 2006, the United States District Court for the Southern District of New York (the Court) granted Talisman's Motion for Summary Judgment, dismissing the lawsuit brought against Talisman by the Presbyterian Church of Sudan and others, under the Alien Tort Claims Act. The lawsuit alleged 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. The plaintiffs have twice attempted to certify the lawsuit as a class action. In March 2005 and in September 2005, the Court rejected the plaintiffs' effort to certify two different classes (or groups) of plaintiffs. On July 19, 2006, the Second Circuit Court of Appeals denied the plaintiffs' request to appeal the Court's refusal to certify the lawsuit as a class action. The plaintiffs have appealed to the Second Circuit Court of Appeals, the Court's decision granting Talisman's Motion for Summary Judgment, its denial of class certification and its refusal to consider the plaintiffs' proposed third amended complaint. Talisman believes the lawsuit is entirely without merit and will continue to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Use of BOE Equivalents

Unless otherwise stated, references to production 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. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an approximate energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Talisman Energy Inc.
Product Netbacks
(unaudited)
		Three months ended March 31
(C$ - production before royalties)		2007	2006	2007	2006
		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	53.55	49.58	7.66	8.79
America	Hedging (gain)	(2.88)	-	(0.26)	(0.16)
	Royalties	11.06	10.60	1.45	1.81
	Transportation	0.47	0.59	0.19	0.23
	Operating costs	8.82	7.76	1.18	1.02
		36.08	30.63	5.10	5.89
United	Sales price	64.73	71.01	7.72	10.11
Kingdom	Hedging (gain)	(1.32)	0.21	-	-
	Royalties	0.78	0.69	0.27	0.67
	Transportation	1.71	1.38	0.37	0.36
	Operating costs	25.39	15.86	1.38	0.78
		38.17	52.87	5.70	8.30
Scandinavia	Sales price	64.64	73.42	4.44	3.51
	Hedging (gain)	-	-	-	-
	Royalties	0.32	0.32	-	-
	Transportation	2.59	1.55	1.42	2.04
	Operating costs	23.86	18.51	-	-
		37.87	53.04	3.02	1.47
Southeast	Sales price	77.10	73.49	6.29	7.08
Asia	Royalties	32.53	29.97	2.00	2.12
	Transportation	0.37	0.22	0.39	0.38
	Operating costs	5.93	5.22	0.40	0.34
		38.27	38.08	3.50	4.24
Other	Sales price	69.41	70.43	-	-
	Royalties	21.25	20.08	-	-
	Transportation	1.21	0.93	-	-
	Operating costs	4.66	3.44	-	-
		42.29	45.98	-	-
Total Company	Sales price	65.46	67.85	7.35	8.52
	Hedging (gain)	(1.07)	0.09	(0.18)	(0.10)
	Royalties	10.63	9.39	1.45	1.73
	Transportation	1.28	1.01	0.26	0.30
	Operating costs	16.50	11.71	1.03	0.84
		38.12	45.65	4.79	5.75
Unit operating costs include pipeline operations for the United Kingdom.
Netbacks do not include synthetic oil.

Talisman Energy Inc.
Product Netbacks (1)
(unaudited)
		Three months ended
		March 31
(US$ - production net of royalties)		2007	2006 (2)
North	Oil and liquids (US$/bbl)
America	Sales price	45.71	42.93
	Hedging (gain)	(3.10)	-
	Transportation	0.51	0.65
	Operating costs	9.49	8.55
		38.81	33.73
	Natural gas (US$/mcf)
	Sales price	6.54	7.62
	Hedging (gain)	(0.27)	(0.17)
	Transportation	0.20	0.25
	Operating costs	1.25	1.11
		5.36	6.43
United Kingdom	Oil and liquids (US$/bbl)
	Sales price	55.26	61.49
	Hedging (gain)	(1.14)	0.18
	Transportation	1.47	1.21
	Operating costs	21.94	13.87
		32.99	46.23
	Natural gas (US$/mcf)
	Sales price	6.59	8.76
	Transportation	0.33	0.33
	Operating costs	1.22	0.72
		5.04	7.71
Scandinavia	Oil and liquids (US$/bbl)
	Sales price	55.19	63.59
	Hedging (gain)	-	-
	Transportation	2.22	1.35
	Operating costs	20.46	16.11
		32.51	46.13
	Natural gas (US$/mcf)
	Sales price	3.79	3.04
	Transportation	1.21	1.77
		2.58	1.27
Southeast Asia	Oil and liquids (US$/bbl)
	Sales price	65.82	63.65
	Transportation	0.55	0.32
	Operating costs	8.76	7.63
		56.51	55.70
	Natural gas (US$/mcf)
	Sales price	5.37	6.13
	Transportation	0.49	0.47
	Operating costs	0.49	0.42
		4.39	5.24
Other	Oil (US$/bbl)
	Sales price	59.28	60.81
	Transportation	1.49	1.12
	Operating costs	5.73	4.08
		52.06	55.61
Total Company	Oil and liquids (US$/bbl)
	Sales price	55.88	58.74
	Hedging (gain)	(1.08)	0.09
	Transportation	1.29	1.02
	Operating costs	16.64	11.81
		39.03	45.82
	Natural gas (US$/mcf)
	Sales price	6.27	7.37
	Hedging (gain)	(0.20)	(0.11)
	Transportation	0.27	0.32
	Operating costs	1.09	0.91
		5.11	6.25
1 Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty volumes.
2 Unit operating costs include pipeline operations for the North Sea. Prior years have been restated accordingly.
Netbacks do not include synthetic oil.