Continuing Operations Review

Results Summary

Gross sales of oil, liquids and natural gas in 2010 were $8.1 billion, an increase of 15% from 2009. Oil and liquids revenue increased $597 million and natural gas revenue increased $590 million due to higher prices and increased production. Reported amounts were impacted by the strengthening C$.

During 2010, North America pre-tax segmented income was $270 million, compared to a loss of $76 million in 2009. Gross sales in North America increased 18% to $1.7 billion due to higher commodity prices and increased shale activity.

In Scandinavia, pre-tax segmented income increased 159% to $409 million, up from $158 million in 2009. Scandinavia gross sales increased 41% to $1.4 billion as a result of higher oil prices and increased production.

Southeast Asia pre-tax segmented income increased 135% to $685 million, up from $291 million in 2009. Gross sales of $2.4 billion were 19% higher than 2009 due to the impact of higher commodity prices and increased gas production.

Daily Average Production, Before Royalties

Continuing operations	2010	2010 vs 2009 (%)	2009	2009 vs 2008 (%)	2008
Oil and liquids (mbbls/d)
North America	20	(5)	21	(5)	22
UK	74	(14)	86	(8)	93
Scandinavia	39	15	34	6	32
Southeast Asia	39	(5)	41	14	36
Other	14	–	14	(7)	15
	186	(5)	196	(1)	198
Natural gas (mmcf/d)
North America	636	19	536	(6)	573
UK	16	(16)	19	6	18
Scandinavia	88	52	58	205	19
Southeast Asia	485	20	403	21	334
	1,225	21	1,016	8	944
Continuing operations (mboe/d)	390	7	365	3	355
Discontinued operations
North America	27	(53)	58	(12)	66
UK	–	–	–	(100)	4
Scandinavia	–	–	–	(100)	1
Other	–	(100)	2	(67)	6
Discontinued operations (mboe/d)	27	(55)	60	(22)	77
Total (mboe/d)	417	(2)	425	(2)	432

For the full year 2010, production from continuing operations increased by 7% over 2009. Production from continuing operations in the fourth quarter of 2010 was 10% higher than the same quarter last year and 5% higher than the third quarter of 2010.

North American natural gas production increased by 19% due principally to successful development in the Pennsylvania Marcellus shale and Montney shale, partially offset by natural declines and plant turnarounds in conventional areas. Production from the Pennsylvania Marcellus shale play was 315 mmcf/d at the end of 2010.

Oil and liquids production in the UK was lower than 2009 as a result of maintenance and repair work, unplanned shutdowns and natural declines, partially offset by improved production efficiency at Claymore and first production at Auk North and Burghley.

In Scandinavia, production increased from 2009 due to the successful development drilling at Varg, as well as the ramp up of production and improved uptimes at Rev.

Southeast Asia natural gas production increased by 20% due to Indonesia, where natural gas production averaged 387 mmcf/d with higher contract takes at Corridor and better plant efficiency. Tangguh, which commenced production in mid 2009, produced 23 mmcf/d in 2010. In Malaysia, natural gas production was 34% higher than 2009, averaging 98 mmcf/d due to increased gas production from the Northern Fields.

Southeast Asia oil and liquids production decreased by 5% due to natural declines in Song Doc and Australia, partially offset by the increase in the Company’s working interest in a unitized field in PM305, which resulted in a one time increase of 1,600 boe/d in volumes for the year.

For details of production from discontinued operations, see the ‘Discontinued Operations’ section of this MD&A.

Volumes Produced Into (Sold Out of) Inventory ¹

	2010	2009	2008
UK	(327)	(1,661)	(2,001)
Scandinavia	153	(924)	674
Southeast Asia	108	(2,277)	2,851
Other	237	(4,694)	3,955
Total produced into (sold out of) inventory – bbls/d	171	(9,556)	5,479
Total produced into (sold out of) inventory – mmbbls	0.1	(3.5)	2.0
Inventory at December 31 – mmbbls	1.6	1.6	5.1

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, Before Royalties’ table represent production volumes in the year, which include oil volumes produced into inventory and exclude volumes sold out of inventory.

Company Netbacks^{1, 2}

December 31	2010	2009	2008
Oil and liquids ($/bbl)
Sale price	80.52	67.36	96.43
Hedging loss	–	–	(0.34)
Royalties	12.35	9.48	15.78
Transportation	1.18	1.15	1.09
Operating costs	20.70	19.24	20.21
	46.29	37.49	59.01
Natural gas ($/mcf)
Sale price	5.76	5.29	9.01
Royalties	0.96	0.87	1.89
Transportation	0.29	0.29	0.27
Operating costs	1.04	1.11	1.07
	3.47	3.02	5.78
Total ($/boe) (6 mcf = 1 boe)
Sale price	55.37	49.40	76.03
Hedging loss	–	–	(0.17)
Royalties	8.74	7.34	13.62
Transportation	1.50	1.43	1.34
Operating costs	12.80	12.91	13.57
	32.33	27.72	47.33

During 2010, the Company’s average netback was $32.33/boe, 17% higher than in 2009 due principally to higher commodity prices in 2010, partially offset by the strengthening of the C$ relative to the US$.

Commodity Prices and Exchange Rates¹

	2010	2010 vs 2009 (%)	2009	2009 vs 2008 (%)	2008
Oil and liquids ($/bbl)
North America	64.47	17	54.96	(36)	85.52
UK	81.71	20	68.36	(30)	98.35
Scandinavia	83.75	20	69.73	(30)	99.23
Southeast Asia	82.95	17	71.17	(27)	97.63
Other	85.17	15	74.03	(28)	102.51
	80.52	20	67.36	(30)	96.43
Natural gas ($/mcf)
North America	4.93	5	4.70	(46)	8.66
UK	4.72	–	4.73	(52)	9.78
Scandinavia	6.86	17	5.86	(18)	7.16
Southeast Asia	6.92	8	6.40	(36)	9.94
	5.76	9	5.29	(41)	9.01
Total ($/boe)	55.37	12	49.40	(35)	76.03
Hedging loss excluded from the above prices
Oil and liquids ($/bbl)	–		–		(0.34)
Natural gas ($/mcf)	–		–		–
Total $/boe	–		–		(0.17)
Benchmark prices
WTI (US$/bbl)	79.53	29	61.79	(38)	99.65
Dated Brent (US$/bbl)	79.47	29	61.51	(37)	96.99
Tapis (US$/bbl)	80.81	27	63.57	(36)	98.95
NYMEX (US$/mmbtu)	4.39	8	4.05	(55)	8.95
AECO ($/GJ)	3.82	2	3.75	(51)	7.71
US$/C$ exchange rate	0.97	10	0.88	(6)	0.94
C$/UK£ exchange rate	1.59	(11)	1.78	(9)	1.96

Talisman’s realized price of $55.37/boe was 12% higher than 2009. WTI averaged US$79.53/bbl, up 29% from 2009. North America natural gas prices also increased, with NYMEX and AECO up 8% and 2%, respectively.

The changes in the Company’s reported oil and liquids price is consistent with the relevant benchmark prices, however, the Company’s reported prices reflect the strengthening of the C$ relative to the US$ in 2010. Talisman’s average natural gas price in North America increased by 5%. Corridor gas prices averaged $7.80/mcf, where 60% of sales are referenced to Duri crude oil and High Sulphur Fuel Oil on an energy equivalent basis.

The physical and financial commodity price contracts outstanding at the balance sheet date are described in the ‘Risk Management’ section of this MD&A.

More than 96% of the Company’s revenues are either received in US$ or are closely referenced to US$. The Company converts these revenues into C$ for reporting purposes.

Royalties ¹

	2010		2009		2008
	Rates (%)	$ millions	Rates (%)	$ millions	Rates (%)	$ millions
North America	11	188	11	156	16	429
UK	–	7	–	5	–	13
Scandinavia	–	–	–	–	–	–
Southeast Asia	36	858	34	675	43	1,066
Other	53	221	51	229	57	291
Total	16	1,274	15	1,065	18	1,799

The Company’s royalty expense in 2010 was $1,274 million, an increase of $209 million (20%) from 2009, reflecting increased commodity prices.

Unit Operating Expenses¹

($/boe)	2010	2010 vs 2009 (%)	2009	2009 vs 2008 (%)	2008
North America	8.91	(5)	9.40	6	8.86
UK	29.15	10	26.47	(4)	27.66
Scandinavia	15.67	(12)	17.83	(17)	21.48
Southeast Asia	6.85	10	6.23	–	6.24
Other	5.53	(14)	6.45	10	5.84
	12.80	(1)	12.91	(5)	13.57

Total Operating Expenses

(millions of C$)	2010	2009	2008
North America	424	403	389
UK	824	878	942
Scandinavia	304	285	276
Southeast Asia	288	255	195
Other	27	40	20
Total	1,867	1,861	1,822

Total operating expenses for the Company during 2010 were $1.9 billion, relatively consistent with 2009. On a per unit basis, operating costs decreased by 1% to $12.80/boe, due to higher production.

In North America, total operating expenses increased by $21 million or 5% over 2009 due principally to higher gas production. Unit operating expenses benefited from increased shale production, which has lower unit rates.

In the UK, total operating expenses were lower due principally to the weakening of the UK£ relative to the C$, despite higher well intervention work.

In Scandinavia, total operating expenses increased due to higher production from the Rev field, increased well workover costs and Yme pre-operating costs.

In Southeast Asia, total operating expenses increased due to a full year of production in Northern Fields and higher maintenance and repair costs in Malaysia and Indonesia.

Unit Depreciation, Depletion and Amortization (DD&A) Expense¹

($/boe)	2010	2010 vs 2009 (%)	2009	2009 vs 2008 (%)	2008
North America	16.75	(10)	18.65	7	17.46
UK1	20.70	(13)	23.69	15	20.54
Scandinavia1	24.11	(4)	25.17	(3)	25.99
Southeast Asia	7.12	(24)	9.33	21	7.69
Other	5.83	(7)	6.28	10	5.71
	15.21	(12)	17.28	5	16.44

Total DD&A Expense

(millions of C$)	2010	2009	2008
North America	764	748	768
UK	582	781	1,144
Scandinavia	471	406	416
Southeast Asia	318	382	254
Other	29	43	24
	2,164	2,360	2,606

The Company’s 2010 DD&A expense decreased by $196 million, or 8%, to $2.2 billion due to higher reserves, the strengthening of the C$, and the impact of the timing of liftings.

In North America, DD&A expense increased from 2009 due principally to increased production in 2010. Unit DD&A decreased from the prior year due to increased shale gas production, which has a lower DD&A expense per unit.

In the UK, DD&A expense decreased from 2009 due to lower production and the weakening of the UK£ relative to the C$.

In Scandinavia, DD&A expense increased from 2009 due to an increase in production.

In Southeast Asia, DD&A expense decreased as a result of lower DD&A from Song Doc field.

For additional information relating to DD&A, refer to the ‘Application of Critical Accounting Policies and the Use of Estimates’ section of this MD&A.

Dry Hole Expense

(millions of C$)	2010	2009	2008
North America	(4)	134	219
UK	62	30	93
Scandinavia	11	69	90
Southeast Asia	31	253	13
Other	23	53	27
	123	539	442

During 2010, the Company incurred dry hole expense of $123 million, which includes the write-off of exploration wells in the UK, Peru, Indonesia and Australia.

Under the successful efforts method of accounting for oil and gas activities, the costs of unsuccessful and non-commercial exploration wells are written off to dry hole expense in the year a determination on success or commerciality is made. Until such determination is made, the costs are included in non-depleted capital. At December 31, 2010, $1 billion of costs relating to exploration wells were included in non-depleted capital and not subject to DD&A, pending final determination (2009 – $798 million).

Exploration Expense

(millions of C$)	2010	2009	2008
North America	40	84	165
UK	16	18	54
Scandinavia	32	22	50
Southeast Asia	118	75	84
Other	178	102	76
	384	301	429

Exploration expense consists of geological and geophysical costs, seismic, non-producing land lease rentals and indirect exploration expenses. These costs are expensed as incurred under the successful efforts method of accounting.

Corporate and Other

(millions of C$)	2010	2009	2008
General and administrative (G&A) expense	392	334	294
Interest on long-term debt	163	192	168
Stock‑based compensation expense (recovery)	201	290	(73)
(Gain) loss on held-for-trading financial instruments	(102)	412	(1,664)
Other revenue	110	115	112
Other expenses, net	194	47	(179)

G&A expense increased by $58 million relative to 2009 and includes costs associated with establishing offices in Pittsburgh and Houston, US and Brisbane, Australia to service the Pennsylvania Marcellus, Eagle Ford and Papua New Guinea operations respectively.

Interest expense on long-term debt decreased relative to 2009, capitalized interest having increased by $40 million as a result of increased capital expenditures on the Yme development. Total interest charges on long-term debt, including amounts expensed and capitalized, was $246 million, up marginally from 2009, due to the issuance of US$600 million of 3.75% notes due in 2021 in the US under its shelf prospectus.

The Company’s stock option plans provide employees and directors with the choice upon exercise to purchase a share of the Company at the stated exercise price or to receive cash. The cash payment is equal to the difference between the option’s exercise price and the share price at the time of surrender. See the ‘Income Taxes’ section of this MD&A for further details concerning the change to the taxation of stock options.

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. In 2010, stock-based compensation expense of $201 million (2009 – $290 million expense; 2008 – $73 million recovery) was incurred, due principally to the rising share price. The Company paid cash of $55 million (2009 – $52 million; 2008 – $211 million) to employees for options exercised.

The gain on held-for-trading financial instruments of $102 million related principally to commodity price derivatives that are not designated as hedges for accounting purposes. See the ‘Risk Management’ section of this MD&A for further details concerning the Company’s financial instruments.

Other revenue includes pipeline and custom treating tariffs of $77 million in 2010 (2009 – $85 million; 2008 – $90 million).

Other expense of $194 million includes property impairments of $118 million in North America, Scandinavia, and the rest of the world for $27 million, $66 million and $25 million, respectively, a net gain on minor asset disposals of $59 million, a foreign exchange loss of $92 million and miscellaneous interest of $24 million.

Income Taxes

(millions of C$)	2010	2009	2008
Income (loss) from continuing operations before taxes	1,299	(497)	4,502
Less PRT
Current	127	65	83
Future	4	43	93
	131	108	176
	1,168	(605)	4,326
Income tax expense (recovery)
Current	1,032	731	1,282
Future	(272)	(678)	165
	760	53	1,447
Effective income tax rate (%)	65	(9)	33

The Company’s effective income tax rate for 2010, after deducting PRT, was 65% (2009 – (9)%; 2008 – 33%). A number of events in the past three years have affected the Company’s effective tax rates, including the proportion of income in higher rate jurisdictions and losses in lower rate jurisdictions, tax rate reductions in Canada and the level of capital expenditure in the North Sea.

In March 2010, the federal budget included significant changes to the taxation of cash-settled stock-based compensation to prevent stock option deductions being claimed by both employer and employee in relation to the same employment benefit. The legislation took effect in the fourth quarter of 2010 and was applied retrospectively. As a result of this legislative change, Talisman will lose its tax benefit resulting from its stock option liability and, accordingly, recorded a future income tax expense of $83 million during the fourth quarter of 2010.

The UK government levies PRT on North Sea fields that received development approval before April 1993, based on gross profit after allowable deductions, including capital and operating expenditures. PRT, which is deductible for purposes of calculating corporate income tax, increased as a result of higher revenue on fields in the UK subject to PRT.

Capital Expenditures¹

(millions of C$)	2010	2010 vs 2009 (%)	2009	2009 vs 2008 (%)	2008
North America	1,794	21	1,479	(22)	1,903
UK	603	(11)	680	(7)	733
Scandinavia	590	(14)	685	(17)	825
Southeast Asia	566	(16)	677	(13)	777
Other2	382	45	263	68	157
Exploration and development	3,935	4	3,784	(14)	4,395
Corporate, Information Systems and Administrative	80	70	47	(27)	64
Acquisitions	1,562	257	438	(3)	452
Dispositions	(393)	22	(323)	223	(100)
Discontinued operations
Proceeds on disposition	(1,954)	(20)	(2,451)	617	(342)
Capital expenditures	18	(96)	461	(35)	711
	3,248	66	1,956	(62)	5,180

During 2010, shale properties were the focus of the Company’s capital investment activities in North America. Of the $1.8 billion of capital expenditures in North America, $1.6 billion related to shale activity with the majority spent on progressing development of the Pennsylvania Marcellus and Montney shale programs.

In North America, 200 gross (181 net) shale wells were drilled with 152 gross (145 net) in the Pennsylvania Marcellus shale play and 37 gross (30 net) wells in the Montney shale play.

Total capital expenditures in the UK decreased by $77 million to $603 million, with $96 million spent on exploration and $507 million on development. Major areas of development activity included the Auk South development project and the start-up of Auk North and Burghley fields in 2010. A total of three development wells, one exploration well, and one appraisal well were drilled in 2010. One exploration well was drilling over the year-end.

In Scandinavia, total expenditures decreased by $95 million to $590 million, with $89 million spent on exploration and $501 million on development. The majority of exploration spending related to the drilling of the Grevling appraisal well. Development spending included drilling in the Yme, Gyda, and Brage fields. A total of 11 development wells, three exploration wells and two appraisal wells were drilled during 2010. Two development wells and one exploration well were drilling over the year-end.

In Southeast Asia, capital expenditures of $566 million included $242 million for exploration and $324 million for development. The exploration expenditure related principally to the drilling of exploration wells in Papua New Guinea, Indonesia, and Block PM-3 CAA in Malaysia, and seismic programs in Papua New Guinea and Sabah (Malaysia). Development spending focused on Northern Fields development drilling, PM3 CAA Mercury Removal Unit and the Southern Fields Improved Oil Recovery program in Malaysia, on the Kitan development in Australia and on the Jambi Merang development in Indonesia. In 2010, Talisman participated in 46 oil and gas development wells, seven exploration wells, two appraisal wells, and two exploration wells were drilling over year end.

Capital expenditures in Algeria included $97 million for development, with Talisman participating in 15 development wells, with a further two wells drilling over the year-end. Talisman spent $285 million on exploration activities in the rest of the world, including $64 million in Colombia, $73 million in Peru and $100 million in the Kurdistan region of northern Iraq. The Company participated in three exploration and four stratigraphic wells in Colombia, one exploration and one appraisal well in Peru, and one exploration well in the Kurdistan region of northern Iraq.

Information related to details and funding of the planned 2011 capital expenditures program is included in the ‘Outlook for 2011’ section of this MD&A.