ex99_2.htm

Exhibit 99.2

INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE PERIOD ENDED JUNE 30, 2011

Management’s Discussion and Analysis (MD&A)

(July 28, 2011)

General

This interim MD&A should be read in conjunction with the unaudited interim condensed Consolidated Financial Statements of Talisman Energy Inc. (‘Talisman’ or ‘the Company’) as at and for the three month and six month periods ended June 30, 2011 and 2010, the 2010 MD&A and audited annual Consolidated Financial Statements of the Company and the MD&A and unaudited interim condensed Consolidated Financial Statements as at and for the three month periods ended March 31, 2011 and 2010.

All comparisons are between the quarters ended June 30, 2011 and 2010, unless stated otherwise. All amounts presented are in US$ million, unless otherwise stated. Abbreviations used in this interim MD&A are listed on the page headed ‘Abbreviations’. Additional information related to the Company, including its Annual Information Form, can be found on SEDAR at www.sedar.com.

Adoption of International Financial Reporting Standards (IFRS)

Talisman’s interim condensed Consolidated Financial Statements and the financial data included in the interim MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC) that are expected to be effective or available for early adoption by the Company as at December 31, 2011, the date of the Company’s first annual reporting under IFRS. The adoption of IFRS does not impact the underlying economics of Talisman’s operations or its cash flows.

Note 4 to the interim condensed Consolidated Financial Statements contains a detailed description of the Company’s adoption of IFRS, including a reconciliation of the Consolidated Financial Statements previously prepared under Canadian GAAP to those under IFRS for the following:

The Consolidated Balance Sheet at January 1, 2010 and at December 31, 2010;

The Consolidated Statements of Income, Comprehensive Income and Cash Flows for the three month and six month periods ended June 30, 2010 and the year ended December 31, 2010; and

The Consolidated Statement of Shareholders’ Equity at June 30, 2010.

The most significant impacts of the adoption of IFRS, together with details of the IFRS 1 exemptions taken, are described in the ‘IFRS First Time Adoption’ section of this interim MD&A.

Comparative information has been restated to comply with IFRS requirements, unless otherwise indicated.

Change in Reporting Conventions

Effective January 1, 2011, the Company changed its reporting currency from C$ to US$. This change to US$ reporting follows the strategic changes of recent years and recognizes the fact that a significant portion of the Company’s activities and transactions are conducted in US$. Accordingly, all financial amounts in this MD&A are presented in US$ unless otherwise indicated.

Effective January 1, 2011, the composition of the Company’s segments changed such that the activities in the UK and Norway are reported as a single ‘North Sea’ segment. This change reflects the fact that, from 2011, the UK and Norway businesses each operate a mature set of cash-generating assets sharing similar economic characteristics. Comparative period balances have been restated accordingly.

SECOND QUARTER 2011 PERFORMANCE HIGHLIGHTS

Cash provided by operating activities was $896 million for the quarter, up 4% compared to $860 million a year ago and $883 million in the first quarter;

Net income was $698 million versus $572 million in 2010 and a net loss of $326 million in the previous quarter;

Production for the quarter averaged 420,000 boe/d compared to 411,000 boe/d in 2010. Production from ongoing operations was up 13% compared to 372,000 boe/d a year ago;

Long-term debt net of cash and cash equivalents at June 30, 2011 was $3 billion versus $2.5 billion at March 31, 2011;

The Company closed a second transaction with Sasol Limited (Sasol), selling a 50% interest in its Cypress A Montney shale properties for C$1.05 billion, including certain future development costs;

Talisman acquired additional acreage in the Alberta Duvernay shale play, bringing its land position to 360,000 net acres;

The Company continues to deliver strong natural gas volumes in Southeast Asia, with price realizations of $9.78/mcf;

Talisman plans to drill a number of significant exploration wells in the second half of this year.

FINANCIAL HIGHLIGHTS

	Three months ended				Six months ended
June 30,	2011		2010		2011		2010
Financial
Net income		698		572		372		943
US$ per common share
- Basic- Basic		0.68		0.56		0.36		0.93
- Diluted1	0.50		0.50		0.26		0.79
Production (Daily Average - Gross)
Oil and liquids (mbbls/d)		175		182		186		195
Natural gas (mmcf/d)		1,470		1,376		1,478		1,372
Total mboe/d (6mcf = 1boe)		420		411		432		423

1.	Diluted net income per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options.

During the second quarter of 2011, net income increased as a result of higher commodity prices and a recovery on share-based payments.

Higher volumes were driven by increased natural gas volumes in North America and Southeast Asia, partially offset by maintenance shutdowns and natural declines.

DAILY AVERAGE PRODUCTION

	Three months ended
	Gross before royalties				Net of royalties
June 30,	2011		2010		2011		2010
Oil and liquids (mbbls/d)
North America		23		25		19		21
North Sea		96		100		95		99
Southeast Asia		33		44		15		24
Other		23		13		12		6
		175		182		141		150
Natural gas (mmcf/d)
North America		875		797		800		772
North Sea		56		91		56		91
Southeast Asia		500		488		352		337
Other		39		-		28		-
		1,470		1,376		1,236		1,200
Total (mboe/d)		420		411		347		350
Assets sold
North America		-		39		-		35
From ongoing operations (mboe/d)		420		372		347		315

	Six months ended
	Gross before royalties				Net of royalties
June 30,	2011		2010		2011		2010
Oil and liquids (mbbls/d)
North America		22		25		18		20
North Sea		109		114		108		113
Southeast Asia		33		42		15		24
Other		22		14		12		6
		186		195		153		163
Natural gas (mmcf/d)
North America		880		792		793		738
North Sea		69		100		69		100
Southeast Asia		497		480		348		337
Other		32		-		25		-
		1,478		1,372		1,235		1,175
Total (mboe/d)		432		423		359		359
Assets sold
North America		-		42		-		37
From ongoing operations (mboe/d)		432		381		359		322

Production represents gross production before royalties, unless noted otherwise. Production identified as net is production after deducting royalties.

Total production increased by 2% over the previous year due principally to increased gas volumes in North America and Southeast Asia, and additional volumes from Colombia as a result of completing the acquisition of a 49% interest in BP Exploration Company (Colombia) Limited (renamed Equión Energía Limited (Equión)) in January 2011. Production from ongoing operations increased by 13%.

In North America, natural gas production increased by 10%, due to successful development in the Pennsylvania Marcellus shale, Montney Farrell Creek and Eagle Ford.

In the North Sea, production decreased 9% due principally to lower production from the Rev, Varg and Brage fields in Norway due to natural declines and timing of shutdowns. This was offset by increased production from the UK with new production from the Auk North field which commenced in the fourth quarter of 2010, partially offset by lower production from the Tweedsmuir field as a result of the annual turnaround in the quarter.

In Southeast Asia, natural gas production increased due principally to better production efficiency in Malaysia. However, oil and liquids production was higher in the second quarter of 2010 due principally to a one off redetermination of the Company’s working interest in the unitized field in South Angsi PM305 in Malaysia, from 15% to 28.6%, which resulted in a one time increase of 7,000 boe/d.

In the rest of the world, production from Colombia accounted for the increase over 2010.

VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY

	Three months ended						Six months ended
June 30,	2011			2010			2011			2010
North Sea - bbls/d		(9,493	)		4,154			(68	)		1,566
Southeast Asia – bbls/d		7,824			2,711			7,056			2,104
Other – bbls/d		(4,555	)		(3,228	)		223			361
Total produced into (sold out of) inventory – bbls/d		(6,224	)		3,637			7,211			4,031
Total produced into (sold out of) inventory – mmbbls		(0.6	)		0.3			1.3			0.7
Inventory at June 30 - mmbbls		3.0			2.3			3.0			2.3

In the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted. The Company recognizes revenue and the related expenses on crude oil production when liftings have occurred. Volumes presented in the ‘Daily Average Production’ table above represent production volumes in the period, which include oil volumes produced into inventory and exclude volumes sold out of inventory.

Although inventory levels are higher compared to a year ago, most of this increase occurred in the first quarter of 2011 with the second quarter seeing a partial reversal of the inventory increase.

COMPANY NETBACKS1

	Three months ended
	Gross before royalties				Net of royalties
June 30,	2011		2010		2011		2010
Oil and liquids ($/bbl)
Sales price		111.88		75.77		111.88		75.77
Royalties		21.58		13.13		-		-
Transportation		1.30		1.20		1.61		1.45
Operating costs		27.03		20.62		33.49		24.95
		61.97		40.82		76.78		49.37
Natural gas ($/mcf)
Sales price		6.25		5.37		6.25		5.37
Royalties		1.23		0.81		-		-
Transportation		0.23		0.28		0.29		0.33
Operating costs		0.89		1.00		1.11		1.18
		3.90		3.28		4.85		3.86
Total $/boe (6mcf=1boe)
Sales price		68.47		51.48		68.47		51.18
Royalties		13.28		8.51		-		-
Transportation		1.35		1.47		1.67		1.76
Operating costs		14.36		12.47		17.84		14.87
		39.48		29.03		48.96		34.55

1.	Netbacks do not include pipeline operations.

	Six months ended
	Gross before royalties				Net of royalties
June 30,	2011		2010		2011		2010
Oil and liquids ($/bbl)
Sales price		107.77		75.71		107.77		75.71
Royalties		19.21		11.81		-		-
Transportation		1.23		1.11		1.50		1.32
Operating costs		23.94		20.24		29.14		23.98
		63.39		42.55		77.13		50.41
Natural gas ($/mcf)
Sales price		6.07		5.67		6.07		5.67
Royalties		1.19		0.89		-		-
Transportation		0.25		0.30		0.31		0.36
Operating costs		0.89		1.02		1.10		1.21
		3.74		3.46		4.66		4.10
Total $/boe (6mcf=1boe)
Sales price		67.08		53.18		67.08		53.20
Royalties		12.34		8.33		-		-
Transportation		1.38		1.49		1.69		1.76
Operating costs		13.31		12.60		16.41		14.95
		40.05		30.76		48.98		36.49

1.	Netbacks do not include pipeline operations.

During the second quarter, the Company’s average gross netback was $39.48/boe, 36% higher than in 2010. Talisman’s realized net sale price of $68.47/boe was 33% higher than 2010, due principally to higher global oil and liquids prices.

The Company’s realized net sale price includes the impact of physical commodity contracts, but does not include the impact of the financial commodity price derivatives discussed in the ‘Risk Management’ section of this MD&A.

The corporate royalty rate was 18%, up from 17% in 2010.

COMMODITY PRICES AND EXCHANGE RATES1

	Three months ended				Six months ended
June 30,	2011		2010		2011		2010
Oil and liquids ($/bbl)
North America		79.33		60.77		74.29		63.92
North Sea		117.04		78.07		110.28		77.62
Southeast Asia		118.74		79.29		118.01		77.86
Other		112.67		75.39		113.46		75.30
		111.88		75.77		107.77		75.71
Natural gas ($/mcf)
North America		4.22		4.62		4.14		5.10
North Sea		8.82		5.28		8.66		5.44
Southeast Asia		9.78		6.60		9.26		6.65
Other		3.04		-		4.03		-
		6.25		5.37		6.07		5.67
Company $/boe (6mcf=1boe)		68.47		51.48		67.08		53.18
Benchmark prices and foreign exchange rates
WTI (US$/bbl)		102.58		78.04		98.34		78.38
Dated Brent (US$/bbl)		117.36		78.30		111.16		77.27
Tapis (US$/bbl)		123.68		81.25		116.61		76.73
NYMEX (US$/mmbtu)		4.36		4.07		4.25		4.67
AECO (C$/gj)		3.55		3.69		3.56		4.19
C$/US$ exchange rate		0.97		1.03		0.98		1.03
UK£/US$ exchange rate		0.61		0.67		0.62		0.66

1.	Prices exclude gains or losses related to hedging activities.

Realized oil and liquids prices increased by 48%, which is in line with global oil and liquids prices but was also impacted by the timing of liftings. Corridor gas prices averaged $10.97/mcf, where 60% of sales are referenced to Duri crude oil and High Sulphur Fuel Oil on an energy equivalent basis. The Company’s reported prices includes the impact of physical commodity contracts which increased the North American reported price by $0.40/mcf in 2010. Most of the contracts have now expired.

EXPENSES

Unit Operating Expenses

	Three months ended
June 30,	Gross before royalties				Net of royalties
($/boe)	2011		2010		2011		2010
North America		6.57		8.94		7.29		9.46
North Sea		35.61		25.46		35.61		25.46
Southeast Asia		8.36		5.88		13.26		9.18
Other		7.63		4.91		13.17		10.24
		14.36		12.47		17.84		14.87

	Six months ended
June 30,	Gross before royalties				Net of royalties
($/boe)	2011		2010		2011		2010
North America		6.86		8.93		7.68		9.83
North Sea		28.85		24.07		28.85		24.07
Southeast Asia		8.26		5.94		13.08		9.03
Other		6.47		5.33		10.94		11.48
		13.31		12.60		16.41		14.95

Total Operating Expenses

	Three months ended				Six months ended
June 30,	2011		2010		2011		2010
($ millions)
North America		100		130		211		257
North Sea		357		259		617		567
Southeast Asia		75		62		147		123
Other		23		8		32		13
		555		459		1,007		960

Includes operating expenses related to sales volumes.

In North America, total operating expenses decreased relative to the same period last year due to the disposition of high cost assets, partially offset by higher shale volumes.

In the North Sea, total operating expenses increased in 2011 as a result of higher costs associated with annual turnarounds, reduced inventory levels and the weakening of the US$ against the UK£ and NOK.

In Southeast Asia, total operating expenses increased due to increased maintenance and well intervention costs in Malaysia and Indonesia.

In the rest of the world, operating expenses increased due to additional operations in Colombia.

Unit Depreciation, Depletion and Amortization (DD&A) Expense

	Three months ended
June 30,	Gross before royalties				Net of royalties
($/boe)	2011		2010		2011		2010
North America		13.29		12.26		14.73		12.98
North Sea		17.28		15.50		17.42		15.54
Southeast Asia		6.39		6.00		10.57		9.48
Other		10.34		5.43		17.01		9.35
		12.38		10.99		14.97		12.91

	Six months ended
June 30,	Gross before royalties				Net of royalties
($/boe)	2011		2010		2011		2010
North America		13.26		12.64		14.85		13.91
North Sea		16.78		16.51		16.86		16.54
Southeast Asia		6.34		6.06		10.44		9.29
Other		10.89		5.40		19.85		12.00
		12.34		11.72		14.92		13.81

Total DD&A Expense

	Three months ended				Six months ended
June 30,	2011		2010		2011		2010
($ millions)
North America		203		176		404		360
North Sea		181		157		367		385
Southeast Asia		63		67		125		131
Other		32		8		52		13
		479		408		948		889

Total DD&A expense was $479 million, up 17% from the same period in 2010, largely as a result of reduced inventory levels and DD&A expense associated with Colombia.

The DD&A expense in North America increased due to higher shale gas volumes.

The DD&A expense in the North Sea increased due to reduced inventory levels and a change in rates.

The DD&A expense in the rest of the world increased due to the additional production in Colombia.

Corporate and Other

	Three months ended						Six months ended
June 30,	2011			2010			2011			2010
($ millions)
General and administrative (G&A) expense		108			81			206			158
Impairment		-			4			102			93
Dry hole expense		36			30			140			36
Exploration expense		136			69			248			162
Finance costs		60			68			136			137
Share-based payments (recovery)		(176	)		(61	)		(60	)		(131	)
(Gain) loss on held-for-trading financial instruments		(68	)		(64	)		251			(162	)
(Gain) on asset disposals		(122	)		(262	)		(214	)		(315	)
Other income		18			26			46			54
Other expenses, net		23			(6	)		81			15

G&A expense increased by $27 million relative to 2010 due principally to running costs associated with new office locations and initial costs associated with the outsourcing of certain information systems functions.

Dry hole expense includes the write-off of an exploration well in Papua New Guinea.

Exploration expense increased by $67 million relative to 2010 and includes seismic activities in Indonesia, Papua New Guinea, Colombia and in North America.

Finance costs includes interest on long-term debt and accretion expense relating to decommissioning liabilities.

The fair value of the Company’s share-based payments plans is established initially at the grant date and the obligation is revalued each reporting period until the awards are settled with any changes in the obligation recognized as share-based payments. The share-based payments recovery during the three month period ended June 30, 2011 of $176 million compared to a recovery of $61 million in the same period last year due principally to changes in the share price.

Talisman recorded a gain on held-for-trading financial instruments of $68 million principally related to a decrease in oil and liquids prices. See the ‘Risk Management’ section of this MD&A for further details concerning the Company’s financial instruments.

The gain on asset disposals arose largely from an additional sale of a 50% working interest in the Montney shale assets to Sasol. Refer to the ‘Asset Disposals’ section of this MD&A.

Other income of $18 million includes $16 million of pipeline and processing revenue.

TAXES

	Three months ended				Six months ended
June 30,	2011		2010		2011			2010
($ millions)
Income before taxes		1,151		819		1,281			1,480
Less: Petroleum Revenue Tax (PRT)
Current		26		23		85			59
Deferred		12		8		39			(9	)
Total PRT		38		31		124			50
		1,113		788		1,157			1,430
Income tax expense
Current income tax		410		158		794			386
Deferred income tax		5		58		(9	)		101
Total income tax expense		415		216		785			487
Effective income tax rate (%)		37		27		68			34

The $199 million increase in total income tax expense relative to the same period in 2010 arises mainly from increased revenues resulting from higher commodity prices, reduction in unlifted volumes and a legislative change in the UK.

The effective tax rate is expressed as a percentage of pre-tax income adjusted for PRT, which is deductible in determining taxable income. The Company’s effective tax rate is affected by the UK legislative change and the mix of income and losses between high and low rate tax jurisdictions.

In March 2011, the UK Government announced that, from March 24, 2011, the rate of supplementary charge levied on ring fence profits increased from 20% to 32%. Supplementary charge is levied on ring fence profits in addition to the ring fence corporation tax rate of 30%, which remains unchanged. Consequently, there is now a combined corporation tax and supplementary charge rate of 62% for oil and gas companies with fields not subject to PRT and 75% to 81% with fields subject to PRT. If the price of oil falls below a certain level (currently expected to be $75 per barrel) for a sustained period of time, the UK Government has indicated that it will reduce the supplementary charge rate back towards 20% on a “staged and affordable basis” while prices remain low. As a result of this change, the Company recorded additional current income tax expense of $41 million in the three month period ended June 30, 2011.

Additionally, the UK Government may restrict tax relief for decommissioning expenditures to the 20% supplementary charge rate. This measure could become substantively enacted in the first quarter of 2012, at which time deferred tax expense would be recorded, estimated by management to be approximately $220 million.

CAPITAL EXPENDITURES1

	Three months ended						Six months ended
June 30,	2011			2010			2011			2010
($ millions)
North America		433			375			867			614
North Sea		361			307			657			573
Southeast Asia		101			120			221			185
Other		70			43			114			96
Exploration and development1		965			845			1,859			1,468
Corporate, IS and Administrative		28			19			44			28
Acquisitions		564			350			1,357			570
Proceeds of dispositions		(290	)		(1,193	)		(539	)		(1,352	)
Total		1,267			21			2,721			714

1.	Excludes exploration expensed for the three month period ended June 30 of $136 million (2010 - $69 million) and for the six month period ended June 30 of $248 million (2010 - $162 million)

North America capital expenditures during the quarter totalled $433 million, of which $388 million related to shale activity with the majority spent on progressing development of the Pennsylvania Marcellus, Montney shale and Eagle Ford programs. The remaining capital was invested in conventional oil and gas properties.

Total North America shale wells drilled were 61 gross (38 net), including 39 gross (28 net) wells in the Pennsylvania Marcellus, 12 gross (6 net) wells in Montney and 10 gross (4 net) wells in Eagle Ford.

In the North Sea, capital expenditures of $361 million were comprised of $54 million on exploration, which included drilling of exploration wells in Norway, and $307 million on development, which included the Auk South, Auk North and Claymore developments in the UK, and the Yme project and developmental drilling in Norway. Yme offshore platform was on location at the end of the quarter.

In Southeast Asia, capital expenditures of $101 million included $79 million on exploration, the drilling of exploration wells in Papua New Guinea and Indonesia, and $22 million on development, which included developmental drilling in Corridor and on the Kitan development in Australia.

Capital expenditures in other areas of $70 million were comprised of $25 million on exploration in Colombia and in the Kurdistan region of northern Iraq. In addition, $43 million was spent on development in Algeria to progress the El Merk project and developmental drilling in Colombia.

ASSET DISPOSALS

Sale of Farrell Creek interests to Sasol

In March 2011, Talisman completed a transaction creating a strategic partnership with Sasol to develop the Farrell Creek assets in Talisman’s Montney shale play in British Columbia. Talisman sold a 50% working interest in the Farrell Creek assets for total consideration of C$1.1 billion, comprising $246 million in cash and approximately $800 million of certain future development costs. The transaction resulted in a pre-tax gain of $98 million.

Sale of Cypress A interests to Sasol

In June 2011, Talisman completed an additional transaction with Sasol to develop the Cypress A assets in Talisman's Montney shale play in British Columbia. Talisman sold a 50% working interest in the Cypress A assets for total consideration of C$1.1 billion, comprising $257 million in cash and approximately $800 million of certain future development costs. The transaction resulted in a pre-tax gain of $113 million, which is included in 'Gain on asset disposals' on the Consolidated Statement of Income.

ACQUISITIONS

In June 2011, Talisman acquired undeveloped land in the Alberta Duvernay shale play for $510 million.

On January 24, 2011, Talisman, together with its partner, Ecopetrol, completed the acquisition of Equión. Talisman acquired a 49% interest in Equión and is proportionately consolidating its interest. During the three month period ended June 30, 2011, working capital adjustments were recorded which adjusted the purchase price to $785 million.

On January 13, 2010, Talisman acquired 100% of the share capital of Hess (Indonesia-Jambi Merang) Limited, a company which owns a 25% interest in the Jambi Merang Production Sharing Contract, for cash consideration of $183 million.

LIQUIDITY AND CAPITAL RESOURCES

Talisman’s long-term debt at June 30, 2011 was $3.9 billion ($3.0 billion, net of cash and cash equivalents and bank indebtedness), down from $4.2 billion ($2.6 billion, net of cash and cash equivalents and bank indebtedness) at December 31, 2010.

During the quarter, the Company’s cash and cash equivalents reduced by $461 million. The Company generated $896 million of cash provided by operating activities compared to $860 million in 2010 reflecting higher sales revenue as a result of higher commodity prices.

On an ongoing basis, Talisman plans to fund its capital program and acquisitions with cash on hand, cash provided by operating activities, cash proceeds from its strategic partnership with Sasol and by drawing on the Company’s credit facilities.

The Company has an active hedging program that will partially protect 2011 cash flow from the effect of declining commodity prices. See the ‘Risk Management’ section of this MD&A for further information.

The majority of the Company’s debt matures subsequent to 2014, with $7 million maturing within one year.

The Company is in compliance with all of its debt covenants. The Company’s principal financial covenant under its primary facility is a debt-to-cash flow ratio of 3.5:1, calculated quarterly on a trailing twelve month basis.

Talisman manages its balance sheet with reference to its liquidity and a debt-to-cash flow ratio. The main factors in assessing the Company’s liquidity are cash flow (defined as cash provided by operating activities plus changes in non-cash working capital and exploration expenditure, less cash finance costs), cash provided by and used in investing activities and available bank credit facilities. The debt-to-cash flow ratio is calculated using gross debt divided by cash flow for the year. For the trailing twelve month period ended June 30, 2011, the debt-to-cash flow ratio was 1.26:1.

At June 30, 2011, the Company had available $4.1 billion of bank lines of credit, $4 billion of which are fully committed through 2014. Maturity dates may be extended from time to time by agreement between the Company and the respective lenders. Of the $4.1 billion of bank lines, $115 million was supporting letters of credit at June 30, 2011.

The Company utilizes letters of credit largely pursuant to committed and uncommitted letter of credit facilities. Letters of credit are issued by banks under these facilities and most are renewed annually. At June 30, 2011, letters of credit totalling $1.4 billion had been issued.

The Company routinely assesses the financial strength of its joint venture participants and customers, in accordance with the Company’s credit risk guidelines. At this time, Talisman expects that such counterparties will be able to meet their obligations when they become due.

A significant proportion of Talisman’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At June 30, 2011, approximately 83% of the Company’s trade accounts receivable were current. Talisman had no customers with individually significant balances outstanding at June 30, 2011. Concentration of credit risk is mitigated by having a broad domestic and international customer base. The maximum credit exposure associated with accounts receivable is the carrying value.

In December 2010, Talisman renewed its normal course issuer bid (NCIB), pursuant to which the Company may repurchase up to 51,068,705 of its common shares (representing 5% of the common shares outstanding at November 29, 2010) during the 12-month period commencing December 15, 2010 and ending December 14, 2011. Shareholders may obtain a copy of the Company’s notice of intention to make an NCIB, free of charge by emailing the Company at tlm@talisman-energy.com. During the six month period ended June 30, 2011, Talisman did not repurchase any common shares of the Company under its NCIB.

At June 30, 2011, there were 1,024,656,352 common shares outstanding. Subsequent to June 30, 2011, 31,778 shares were issued pursuant to the exercise of stock options, resulting in 1,024,688,130 common shares being outstanding at July 25, 2011.

At June 30, 2011, there were 60,466,773 stock options, 9,562,115 cash units and 11,018,068 long-term performance share units (PSUs) outstanding. Subsequent to June 30, 2011, no stock options were granted, 31,778 were exercised for shares, 20,210 were surrendered for cash and 24,110 were forfeited, with 60,390,675 outstanding at July 25, 2011. Subsequent to June 30, 2011, no cash units were granted, 22,650 were exercised and 20,777 were forfeited with 9,518,688 outstanding at July 25, 2011. Subsequent to June 30, 2011, no long-term PSUs were granted and 16,683 were forfeited, with 11,001,385 outstanding at July 25, 2011.

The Company may purchase shares on the open market to satisfy its obligation to deliver common shares to settle long-term PSUs. During the six month period ended June 30, 2011, the Company purchased 1,968,600 common shares on the open market for $42 million. Between July 1 and July 25, 2011, a further 250,000 common shares were purchased for $5 million to settle the PSU’s.

Talisman continually monitors its portfolio of assets and investigates business opportunities in the oil and gas sector. The Company may make acquisitions, investments or dispositions, some of which may be material. In connection with any acquisition or investment, Talisman may incur debt or issue equity.

For additional information regarding the Company’s liquidity and capital resources, refer to notes 10 and 13 to the 2010 audited Consolidated Financial Statements and notes 13 and 15 to the interim condensed Consolidated Financial Statements.

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 2011 (excluding the effect of derivative contracts) is summarized in the following table, based on a WTI oil price of approximately US$95/bbl, a NYMEX natural gas price of approximately US$4/mmbtu and exchange rates of US$1=C$1 and UK£1=US$1.60.

($ millions)	Net Income			Cash Provided by Operating Activities
Volume changes
Oil – 10,000 bbls/d		75			120
Natural gas – 60 mmcf/d		25			60
Price changes1
Oil – US$1.00/bbl		25			30
Natural gas (North America)2 – US$0.10/mcf		20			25
Exchange rate changes
US$/C$ decreased by US$0.01		(5	)		(10	)
US$/UK£ increased by US$0.02		5			-

1.	The impact of price changes excludes the effect of commodity derivatives. See specific commodity derivatives terms in the ‘Risk Management’ section of this MD&A, and note 16 to the interim condensed Consolidated Financial Statements.

Price sensitivity on natural gas relates to North American natural gas only. The Company’s exposure to changes in the natural gas prices in the UK, Norway Malaysia/Vietnam and Colombia 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.

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 can be found in note 10 to the 2010 audited Consolidated Financial Statements and note 13 to the interim condensed Consolidated Financial Statements. A discussion of the Company’s derivative financial instruments and commodity sales contracts can be found in the ‘Risk Management’ section of this MD&A.

There have been no significant changes in the Company’s expected future payment commitments, and the timing of those commitments, since December 31, 2010. Refer to note 16 to the 2010 audited Consolidated Financial Statements.

RISK MANAGEMENT

Talisman monitors the Company’s exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, Talisman periodically enters into physical delivery transactions for commodities of fixed or collared prices and into derivative financial instruments to reduce exposure to unfavourable movements in commodity prices, interest rates and foreign exchange rates. The terms of these contracts or instruments may limit the benefit of favourable changes in commodity prices, interest rates and currency values and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with contracts.

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 accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 3(o) to the interim condensed Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at June 30, 2011, including their respective fair values, are detailed in note 16 to the interim condensed Consolidated Financial Statements.

The Company has elected not to designate as hedges for accounting purposes any commodity price derivative contracts entered into. In 2008, the Company no longer designated its interest rate swap as a fair value hedge. These derivatives are classified as held-for-trading financial instruments and are measured at fair value with changes in fair value recognized in net income quarterly. This increases the volatility of net income.

Commodity Price Derivative Financial Instruments

The Company had the following commodity price derivative contracts outstanding at June 30, 2011, none of which were designated as a hedge:

Contract	Term	Average volume	Average price or floor/ceiling
Oil
Dated Brent oil collars	Jul-Dec 2011	21,000 bbls/d	US$80.00/91.27/bbl
Dated Brent oil collars	Jul-Dec 2011	20,000 bbls/d	US$84.00/97.57/bbl
WTI crude oil collars	Jul-Dec 2011	9,000 bbls/d	US$80.00/92.00/bbl
Dated Brent oil puts	Jul-Dec 2011	20,000 bbls/d	US$90.00/bbl
Dated Brent oil collars	Jan-Dec 2012	20,000 bbls/d	US$90.00/148.32/bbl
Natural gas
NYMEX natural gas collars	Jul-Dec 2011	71,200 mcf/d	US$6.14/6.59/mcf
NYMEX natural gas swaps	Jul-Dec 2011	23,734 mcf/d	US$6.12/mcf

Further details of contracts outstanding are presented in note 16 to the interim condensed Consolidated Financial Statements.

Physical Commodity Contracts

The Company enters into fixed price sales contracts for the physical delivery of commodities. These contracts are in the regular course of business and are intended to be settled by delivering the product. As such, the fair value of these contracts is not recognized in the Consolidated Financial Statements and future revenues are recognized in net income as earned over the term of the contract. The Company anticipates having sufficient future production to meet these fixed price sales contract commitments.

The Company had the following physical commodity contracts outstanding at June 30, 2011:

Contract	Term	mcf/d	US$/mcf
AECO natural gas swaps	Jul-Dec 2011	3,671	3.00

Interest Rate Swap

In order to swap a portion of the $375 million 5.125% notes due 2015 to floating interest rates, the Company entered into fixed to floating interest rate swap contracts with a total notional amount of $300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three-month US$ LIBOR plus 0.433% while receiving payments of 5.125% semi-annually.

In conjunction with the issuance of the 4.44% C$350 million medium term notes, the Company entered into a cross currency swap in order to hedge the foreign exchange exposure on this C$ denominated liability. As a result, the Company was effectively paying interest semi-annually in US$ at a rate of 5.05% on a notional amount of US$304 million. The cross currency swap was designated as a cash flow hedge. The notes were repaid in January 2011 and the hedge was settled.

SUMMARY OF QUARTERLY RESULTS

($ millions unless otherwise stated)

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

	Three months ended
	2011					2010									20091
	Jun 30		Mar 31			Dec 31			Sep 30		Jun 30		Mar 31		Dec 31			Sep 30
Total revenue and other income		2,234		2,000			1,863			1,683		1,600		1,836		1,631			1,303
Income (loss) from continuing operations		-		-			-			-		-		-		(172	)		23
Net income (loss)		698		(326	)		(350	)		352		572		371		(105	)		27
Per common share ($)
Income (loss) from continuing operations		-		-			-			-		-		-		(0.17	)		0.02
Diluted Income (loss) from continuing operations		-		-			-			-		-		-		(0.17	)		0.02
Net income (loss)		0.68		(0.32	)		(0.34	)		0.35		0.56		0.36		(0.10	)		0.03
Diluted net income (loss)2	0.50		(0.32		)	(0.34		)	0.33		0.50		0.30			(0.10	)		0.03

1.	2009 comparatives figures prepared in accordance with Canadian GAAP.

2.	Diluted net income per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options.

During the three month period ended June 30, 2011, total revenue and other income increased by $634 million over the same period in 2010 due principally to increased commodity prices and reduced inventory levels. Net income increased by $126 million due principally to increased revenue and stock based compensation recovery, partially offset by an increase in current income taxes and higher DD&A and operating expenses.

IFRS FIRST TIME ADOPTION

Talisman’s interim condensed Consolidated Financial Statements as at and for the three and six month periods ended June 30, 2011 have been prepared in accordance with IFRS as issued by the IASB. Previously, the Company prepared its annual and interim Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles then applicable to publically accountable enterprises (Canadian GAAP). Since this is the Company’s initial year in presenting its results and financial position under IFRS, these interim condensed Consolidated Financial Statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting and IFRS 1 First-time Adoption of IFRS.

These interim condensed Consolidated Financial Statements have been prepared in accordance with IFRS standards and interpretations of the IFRIC that are expected to be effective as at and for the year ending December 31, 2011, the date of the Company’s first annual reporting under IFRS. Accordingly, the accounting policies for the annual period that are relevant to the interim condensed Consolidated Financial Statements will be determined only when the first IFRS annual Consolidated Financial Statements are prepared for the year ending December 31, 2011.

The adoption of IFRS does not impact the underlying economics of Talisman’s operations or its cash flows. The most significant impacts of adoption are from the application of new accounting policies that reset the Company’s balance sheet, in particular, the election to use the IFRS 1 fair value as deemed cost exemption, and changes in the accounting for impairments, income taxes, decommissioning liabilities and share-based payments.

The Company’s significant accounting policies under IFRS are described in note 3 to the interim condensed Consolidated Financial Statements.

IFRS 1 Exemptions

The general principle to be applied on first-time adoption of IFRS is that standards in force at the first reporting date (December 31, 2011) should be applied as at the date of transition to IFRS (January 1, 2010) and throughout all periods presented in the first IFRS financial statements. However, IFRS 1 contains a number of exemptions that companies are permitted to apply. Talisman has elected to apply the following exemptions:

to measure certain properties at fair value at January 1, 2010 and use those fair values as deemed cost at that date;

to apply a modified approach in calculating the retrospective cost component of PP&E relating to the Company’s decommissioning liabilities. Under the modified approach, decommissioning liabilities are re-measured at the date of transition to IFRS under IAS 37 Provisions, Contingent Liabilities and Contingent Assets and amounts to be included in the related assets are estimated by discounting the liabilities to the date at which the liabilities first arose using the best estimates of the historical risk-adjusted discount rates. The related accumulated DD&A is then calculated based on the current estimates of the useful lives of the assets;

to apply IFRS 3 Business Combinations prospectively and not restate business combinations that occurred prior to January 1, 2010;

to not apply IFRS 2 Share-Based Payments to equity awards that vested and liability awards that settled prior to January 1, 2010;

to recognize cumulative unrecognized net actuarial losses on employee future benefits in opening retained earnings as at January 1, 2010. Also, to prospectively disclose required benefit plans amounts under IAS 19 Employee Benefits as the amounts are determined for each accounting period from January 1, 2010 instead of the current annual period and previous four annual periods; and

to apply IAS 23 Borrowing Costs prospectively from January 1, 2010 and derecognize the carrying value of capitalized borrowing costs recorded under Canadian GAAP as at January 1, 2010.

Reconciliation from Canadian GAAP to IFRS

In preparing the interim condensed Consolidated Financial Statements, the Company has adjusted amounts reported previously in its Consolidated Financial Statements prepared under Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s financial position, results of operations and cash flows, including the reconciliations required by IFRS 1, is presented in note 4 to the interim condensed Consolidated Financial Statements. Summaries of the impacts of IFRS adoption on the Company’s financial position at January 1, 2010 and its financial results for the three and six month periods ended June 30, 2010 follow.

In its 2010 MD&A, the Company indicated that it was modifying its accounting for stock options from the liability method to the equity method for Canadian based employees. After further consideration, management determined not to make this change.

Impact on Financial Position at January 1, 2010

The following table summarizes the adjustments made to report the Company’s financial position in US$ and to reset the opening balance sheet at January 1, 2010 on adoption of IFRS:

	CGAAP				IFRS adjustments & reclassifications			IFRS
(millions of $)		C$	US$		US$			US$
Current Assets		3,154		3,013		31			3,044
Long Term Assets		20,464		19,552		(2,608	)		16,944
Total Assets		23,618		22,565		(2,577	)		19,988

Current Liabilities		2,601		2,485		214			2,699
Long Term Liabilities		9,906		9,463		(1,021	)		8,442
Shareholders’ Equity		11,111		10,617		(1,770	)		8,847
Total Liabilities & Shareholders’ Equity		23,618		22,565		(2,577	)		19,988

Shareholders’ equity at the time of adoption of IFRS decreased by approximately $1.8 billion as a result of the after tax impact of adjustments to the opening balance sheet being recorded in retained earnings. These adjustments comprise approximately $1.2 billion for the fair value as deemed cost election, a significant portion of which related to assets sold during 2010, and impairment of exploration and evaluation assets, and approximately $0.6 billion relating to derecognition of capitalized borrowing costs, decommissioning liabilities, share-based payments, employee benefits and deferred taxes.

Total assets decreased by $2.6 billion as a result of electing to measure certain of the Company’s properties at fair value and, where permitted, deeming these fair values as cost ($1.7 billion), impairments of exploration and evaluation assets ($0.2 billion), changes to the cost component of PP&E relating to the Company’s decommissioning liabilities ($0.2 billion), derecognizing capitalized borrowing costs recorded under Canadian GAAP ($0.2 billion), as well as removing the tax adjustment from PP&E previously recorded for historical asset acquisitions under Canadian GAAP, which is not permitted under IFRS ($0.3 billion).

Current liabilities increased by approximately $0.2 billion due to the IFRS requirement to measure cash-settled share-based payments at fair values rather than the intrinsic method permitted under Canadian GAAP.

Long-term liabilities decreased by approximately $1 billion, largely as a result of the deferred tax effect of other IFRS adjustments, deferred income tax adjustments required for historical asset acquisitions and other changes in the accounting methodology for deferred tax and PRT.

Impact on Financial Results for the three month period ended June 30, 2010

The following table summarizes the adjustments made to Consolidated Statement of Income for the three month period ended June 30, 2010:

	CGAAP				IFRS adjustments & reclassifications			IFRS
(millions of $)		C$	US$		US$			US$
Total revenue		1,553		1,514		86			1,600
Total expenses		1,058		1,032		(251	)		781
Income before taxes		495		482		337			819
Taxes		84		83		164			247
Income from continuing operations		411		399		173			572
Income from discontinued operations		192		183		(183	)		-
Net income		603		582		(10	)		572

The resetting of the Company’s balance sheet under IFRS, which primarily impacted PP&E and the liabilities for decommissioning, share-based payments and deferred income tax, in conjunction with other changes in accounting policies under IFRS decreased the Company’s previously reported net income for the three months ended June 30, 2010 by $10 million. The changes in accounting policies under IFRS decreased DD&A and accretion expense ($54 million) and increased gain on asset disposals ($116 million), offset by tax expenses ($154 million). The remaining balance relates to other adjustments increasing net income by $6 million.

Impact on Financial Results for the six month period ended June 30, 2010

The following table summarizes the adjustments made to Consolidated Statement of Income for the six month period ended June 30, 2010:

	CGAAP				IFRS adjustments & reclassifications			IFRS
(millions of $)		C$	US$		US$			US$
Total revenue		3,327		3,217		219			3,436
Total expenses		2,339		2,263		(307	)		1,956
Income before taxes		988		954		526			1,480
Taxes		336		323		214			537
Income from continuing operations		652		631		312			943
Income from discontinued operations		179		171		(171	)		-
Net income		831		802		141			943

The resetting of the Company’s balance sheet under IFRS, which primarily impacted PP&E and the liabilities for decommissioning, share-based payments and deferred income tax, in conjunction with other changes in accounting policies under IFRS increased the Company’s previously reported net income for the six months ended June 30, 2010 by $141 million. The changes in accounting policies under IFRS decreased DD&A and accretion expense ($147 million) and increased gain on asset disposals ($228 million), offset by tax expenses ($262 million). The remaining balance relates to other adjustments increasing net income by $28 million.

IMPACT OF IFRS ADOPTION ON ACCOUNTING POLICIES AND 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 is presented in note 3 to the interim condensed Consolidated Financial Statements. The following critical accounting policies and significant estimates have been impacted by the adoption of IFRS:

Asset Impairments

Under IFRS, impairment assessments are based primarily on the recoverable amount of the asset, which has determined based on discounted cash flows. Previously under Canadian GAAP, only if an asset’s estimated undiscounted future cash flows are below its carrying value was a determination required of the amount of any impairment based on discounted cash flows.

As a result of these accounting changes, the Company recorded impairments of $209 million under IFRS at January 1, 2010 relating to exploration and evaluation assets. The Company recorded additional impairments of $186 million under IFRS for the year ended December 31, 2010. In the North America segment, $66 million was recorded in respect of natural gas assets primarily as a result of the decline in natural gas price assumptions. In the North Sea segment, $99 million was recorded as a result of a change in reserves estimates relating to PP&E, a change in the estimated timing of cash flows relating to oil and gas exploration and evaluation assets and changes in investment decisions. In the Southeast Asia segment, $21 million was recorded relating to oil assets due to an increase in estimated future costs. The carrying values of these assets were previously supported under Canadian GAAP on an undiscounted cash flow basis. The impairments are subject to future reversal if certain criteria are met.

In estimating the adjustments to PP&E and exploration and evaluation assets at the time of adoption of IFRS, management estimated fair value based on market information which consisted of offers to purchase the asset or comparable assets, independent market surveys and values derived from exchange quoted prices. Where reliable market information was not available, the recoverable amount was determined using cash flow projections that were based on a long-term view of commodity prices and a post-tax discount rate of 10% at January 1, 2010 and December 31, 2010.

Purchase Price Allocations

The principal impacts of the adoption of IFRS on Talisman’s accounting for business combinations and asset acquisitions arise from the accounting for contingent liabilities, contingent consideration and transactions costs.

a) Contingent Liabilities

Contingent liabilities are liabilities that may have to be recognized in the future, contingent upon the occurrence of certain events (e.g. a potential liability resulting from legal proceedings). Under IFRS, TLM must recognize a contingent liability based on fair value at acquisition date if a present obligation arises from a past event, regardless of how likely it is. Previously under Canadian GAAP, contingencies were not recognized on acquisition unless they could be reasonably estimated and were likely to be realized. The adoption of IFRS did not result in contingent liabilities being recorded in connection with the Jambi Merang acquisition that closed in January 2010.

b) Contingent Purchase Consideration

In some business combinations, part of the purchase consideration is contingent upon the occurrence of certain events or satisfaction of performance hurdles. Under IFRS, contingent purchase consideration made as part of a business combination must be fair valued and recognized at the acquisition date as a liability, regardless of whether uncertainties over the timing and amount of the contingencies are resolved. Previously under Canadian GAAP, contingent consideration was not recognized until the contingency was resolved and the consideration became payable. There was no contingent purchase consideration in connection with the Jambi Merang and Equión acquisitions.

c) Transaction Costs

Transaction costs include stamp duty, consulting fees (e.g. legal, accounting and valuation fees) and other integration costs. Under IFRS, all such costs must be expensed as incurred. Previously under Canadian GAAP, transaction costs were capitalized. The transaction costs incurred in connection with the Equión and Jambi Merang acquisitions were expensed when incurred under IFRS.

Decommissioning Liabilities

Decommissioning liabilities (formerly asset retirement obligations under Canadian GAAP) are measured based on the estimated cost of abandonment discounted to its net present value. Under Canadian GAAP, the current discount rate was applied only to new obligations and upward revisions, whereas the entire liability is recalculated using the current discount rate under IFRS. As a result, the Company recorded a decrease of $83 million, excluding the impact of discontinued operations, at January 1, 2010 (December 31, 2010 - $301 million increase) to decommissioning liabilities under IFRS. Under IFRS, the provision has been discounted using a weighted average credit-adjusted risk free rate of 6.7% at January 1, 2010 (Canadian GAAP – 6.6%) and 5.3% at December 31, 2010 (Canadian GAAP – 6.6%).

During the three month period ended June 30, 2011, there were no significant changes in the estimated cost of abandonment or the expected timing of abandonment obligations. The completion of the Equión acquisition resulted in the assumption of decommissioning liabilities having a net present value of $33 million.

As an indication of possible future changes in estimated decommissioning liabilities, if all of the Company’s abandonment obligations could be deferred by one year, the net present value of the liabilities would decrease by approximately $77 million.

Income Taxes

Under Canadian GAAP, when the cost of an acquired asset that was recorded as PP&E differed from its tax base, deferred tax was recorded on the difference. Under IFRS, deferred taxes are not recognized on asset acquisitions.

Under Canadian GAAP, deferred PRT was calculated using the life-of-field method. Under IFRS, a temporary differences basis is used. While PRT was presented separately on the Consolidated Statement of Income under Canadian GAAP, the Company has chosen to present the current and deferred portions of PRT as components of current and deferred income tax expense respectively under IFRS.

Under Canadian GAAP, deferred tax was not recognized for temporary differences between the functional currency of accounting for a foreign operation and the currency in which the taxes were filed. Under IFRS, such temporary tax differences in currencies are recognized.

As a result of all measurement differences impacting deferred taxes, including the three discussed above, but excluding the impact of discontinued operations and other reclassifications, the Company recorded a decrease of deferred tax liabilities of $1.1 billion at January 1, 2010 (December 31, 2010 - $1.6 billion) under IFRS. Additional income tax expense of $154 million for the three month period ended June 30, 2010, $263 million for the six month period ended June 30, 2010 and $232 million for the year ended December 31, 2010 was recorded arising from the reversal of temporary differences under IFRS.

OTHER CHANGE IN ACCOUNTING POLICIES

Foreign Exchange

Prior to January 1, 2011, the Company’s operations in the UK were translated from UK£ into US$ using the current rate method whereby assets and liabilities were translated at year-end exchange rates, while revenues and expenses were converted using average rates for the period. Gains and losses arising on translation from UK£ to US$ were deferred and included in a separate component of shareholders' equity described as accumulated other comprehensive loss. As a result of a reorganization of the Company’s operations, changes in the composition of revenue and costs and changes in intercompany loan arrangements, management has determined that the functional currency of the Company’s UK operation is more closely linked to the US$. Accordingly, effective January 1, 2011, this operation has been accounted for as a US$ functional currency entity. As a result, foreign currency translation adjustments remain in accumulated other comprehensive loss until Talisman reduces its net investment in its UK subsidiary. Following the change in the functional currency of the UK operation on January 1, 2011, the debt denominated in UK£ will no longer be designated as a hedge of Talisman’s net investment in the UK and, accordingly, future foreign exchange gains and losses will be recorded on the Consolidated Statement of Income.

Accounting Standards and Interpretations Issued but Not Yet Effective

The following pronouncements from the IASB are applicable to Talisman and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 Financial Instruments – as part of its project to replace IAS 39, the IASB issued the first phase of IFRS 9 implementation dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9 by incorporating requirements for the accounting for financial liabilities;

IFRS 10 Consolidated Financial Statements – establishes the accounting principles for consolidated financial statements when one entity controls other entities and replaces IAS 27 Consolidated and Separate Financial Statements and SIC-12 Consolidation – Special Purpose Entities. This standard establishes a new control model that applies to all entities;

IFRS 11 Joint Arrangements – establishes the accounting principles for parties to a joint arrangement and replaces IAS 31 Interest in Joint Ventures and SIC-13 Jointly Controlled Entites- Non-Monetary Contributions by Venturers. This standard requires a party to assess its rights and obligations from the arrangement in order to determine the type of joint arrangement. The choice of proportionate consolidation accounting is removed for joint ventures (formerly jointly controlled entities) as equity accounting is required;

IFRS 12 Disclosure of Interests in Other Entities – establishes comprehensive disclosure requirements for subsidiaries, joint arrangements, associates, and unconsolidated structured entities and replaces existing disclosures in related standards;

IFRS 13 Fair Value Measurement – establishes a single framework for fair value measurement and disclosures when fair value is required or permitted under IFRS;

IAS 1 Presentation of Financial Statements amendment –requires items within other comprehensive income to be grouped based whether they can be reclassified to the income statement and is applicable to annual periods beginning on or after July 1, 2012, with earlier adoption permitted;

IAS 19 Employee Benefits amendment – improves the accounting for employee benefits by eliminating the ‘corridor method’ to defer recognition of gains and losses, presentation changes for assets and liabilities arising from defined benefit plan, and enhanced disclosure requirements for defined benefit plans;

IAS 27 Separate Financial Statements – establishes the accounting and disclosure requirements for investments in subsidiaries, joint ventures, and associates when an entity prepares separate financial statements and replaces the current IAS 27 Consolidated and Separate Financial Statements as the consolidation guidance is included in IFRS 10 Consolidated Financial Statements;

IAS 28 Investments in Associates and Joint Ventures – establishes the accounting for investments in associates and defines how the equity method is applied when accounting for associates and joint ventures.

Except as noted above, all of the above pronouncements are effective for annual periods beginning on or after January 1, 2013 with earlier adoption permitted. With the exception of the IAS 19 amendment, part of which Talisman adopted on transition to IFRS, the Company is currently assessing the impact of adopting these pronouncements.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no significant changes in Talisman’s internal control over financial reporting during the three month period ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

LITIGATION

From time to time, Talisman is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation 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.

ADVISORIES

Forward-Looking Statements

This interim MD&A contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation. This forward-looking information includes, among others, statements regarding:

business strategy, plans and priorities;

expected counterparty risk;

expected sources of funding for the capital program;

expected production to meet fixed price sales contract commitments;

expected handling of the supplementary charge back by the UK government;

expected UK government restricted tax relief for decomissioning expenditures and timing;

the merits or anticipated outcome or timing of pending litigation; and

other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

With the exception of the ability of counterparties to meet their obligations, and the merits of pending litigation, the forward-looking information contained herein assumes production will be between 430,000 and 440,000 boe/d in 2011, a WTI oil price of approximately US$95/bbl, a NYMEX natural gas price of approximately US$4/mmbtu and 2011 cash exploration and development capital spending of $4 to $4.5 billion.

The completion of any contemplated disposition is contingent on various factors including market conditions, the ability of the company to negotiate acceptable terms of sale and receipt of any required approvals of such dispositions. Information regarding business plans generally assumes that the extraction of crude oil, natural gas and natural gas liquids remains economic.

Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by Talisman and described in the forward-looking information contained in this interim MD&A. The material risk factors include, but are not limited to:

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

risks and uncertainties involving geology of oil and gas deposits;

uncertainty related to securing sufficient egress and markets to meet shale gas production;

the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;

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

the impact of the economy on the ability of the counterparties to our commodity price derivative contracts to meet their obligations under the contracts;

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 any future acquisitions and dispositions;

health, safety and environmental risks;

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

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 possibility that government policies or laws may change or government approvals may be delayed or withheld including with respect to shale gas drilling; and

results of the Company’s risk mitigation strategies, including insurance and hedging activities.

The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results are included in the Company’s most recent Annual Information Form and Annual Report. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission.

Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law.

Advisory – Oil and Gas Information

Talisman makes reference to production volumes throughout this interim MD&A. 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 US, net production volumes are reported after the deduction of these amounts.

Talisman also discloses netbacks in this interim MD&A. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.

Use of ‘boe’

Throughout this interim MD&A, the calculation of barrels of oil equivalent (boe) is 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 may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf:1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Abbreviations

The following list of abbreviations is used in this document:

bbls/d

barrels per day

boe	barrels of oil equivalent

boe/d

barrels of oil equivalent per day

C$	Canadian dollar

GAAP	Generally Accepted Accounting Principles

gigajoule

IFRS	International Financial Reporting Standards

LIBOR

London Interbank Offered Rate

mbbls/d

thousand barrels per day

mboe/d

thousand barrels of oil equivalent per day

mcf	thousand cubic feet

mmbbls

million barrels

mmbtu

million British thermal units

mmcf/d

million cubic feet per day

NOK	Norwegian Kroner

NYMEX

New York Mercantile Exchange

PP&E	Property, plant and equipment

PRT	Petroleum Revenue Tax

UK	United Kingdom

UK£	Pound sterling

US	United States of America

US$	United States dollar

WTI	West Texas Intermediate