Exhibit 99.1

N E W S   R E L E A S E

TALISMAN ENERGY REPORTS STRATEGIC AND OPERATIONAL

 SUCCESS IN 2010

164% RESERVES REPLACEMENT

UNDERLYING PRODUCTION GROWTH OF 7%

CALGARY, Alberta, February 16, 2011 – Talisman Energy Inc. reported its operating and unaudited financial results for 2010. The company was successful in strategically repositioning its portfolio and achieving its 2010 operating targets.

· Cash flow1was $3.1 billion, down 23% from 2009, due to higher cash taxes in 2010 and lower cash proceeds from financial instruments.

· Net income was $648 million, a 48% increase from the previous year due to higher commodity prices, improved operating performance and non-cash gains on derivatives.

· Earnings from continuing operations1 were $347 million versus $631 million a year ago. Stronger operating performance was more than offset by the effect of cash proceeds from financial instruments the previous year and higher cash taxes in 2010.

· Talisman maintained capital discipline, reducing capital spending by 6% during 2010, to $4 billion.

· Production averaged 417,000 boe/d, significantly above initial guidance. Excluding asset sales, year on year production increased 7%, with fourth quarter volumes 10% higher than 2009.

· Talisman replaced 164% of production with proved reserves, excluding price revisions, achieving a 35% reduction in replacement costs compared to 2009 and a 63% reduction over the past two years. Proved developed producing replacement costs were 54% lower than 2009.

· Talisman sold over $2 billion of non-core assets in 2010, predominantly North American natural gas properties.

· Talisman entered into a strategic partnership with Sasol Limited, selling them a 50% interest in the company’s Farrell Creek shale play in British Columbia.

· The company acquired assets in two liquids areas, establishing a material position in the heart of the liquids rich window in the Eagle Ford shale play in Texas; and also acquired producing assets with significant upside in Colombia.

· Talisman made a number of exploration discoveries in Latin America, including an oil discovery and several successful stratigraphic tests in Colombia.

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1 The terms “cash flow” and “earnings from continuing operations” are non-GAAP measures. Please see the advisories and reconciliations elsewhere in this press release.

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“Talisman had a very successful year in 2010, in terms of operational delivery and strategic implementation,” said John A. Manzoni, President and CEO. “This was due to the hard work, focus and dedication of Talisman employees and contractors around the globe.

“Production averaged 417,000 boe/d both for the year and during the fourth quarter.  We increased production from continuing operations by 7% year over year and achieved 10% growth in the fourth quarter compared to a year ago. Part of this was due to rapidly growing shale volumes and we also set new production records in Southeast Asia again in 2010, with ongoing optimization at Corridor in Indonesia and infill drilling offshore Malaysia/Vietnam. We expect the underlying growth we delivered from the second half to translate into sustainable absolute production growth of 5-10% from 2011 into the medium term.

“Talisman replaced 164% of production with proved reserves, achieving a 35% reduction in replacement costs from 2009 and a 63% reduction over the past two years. We expect this trend to continue, albeit at a slower pace, which secures improving profitability into the future.

“We are now well positioned in three of the leading shale plays in North America, in different stages of development, and each with relatively low land retention commitments. This provides tremendous flexibility in being able to respond to dynamic external conditions.

“We have proved the low cost, high growth potential of the Marcellus shale, which was producing 315 mmcf/d at the end of the year.  The company secured a strategic partner in its Farrell Creek assets in the Montney shale, with Sasol paying approximately $1 billion for a 50% share, which includes funding the majority of future development capital. We are excited about the strategic options this partnership brings for the future. We also acquired a material position in the heart of the liquids rich window of the Eagle Ford shale play in Texas, forming a joint-venture with Statoil.

“As part of the move to reposition our portfolio, Talisman sold over $2 billion of mainly gas producing assets in North America in 2010, bringing total asset sales to over $5 billion during the past two years.

“Elsewhere, we are building a very exciting international exploration portfolio. We have added over 16 million net acres of prospective new exploration acreage over the past two years, and shot 1,700 square kilometers of 3D seismic and 2,900 kilometers of 2D seismic last year as we move to evaluate and prove up the potential of these plays.

“We underpinned our exploration program in Colombia with the acquisition of BP Colombia’s assets, conducted jointly with Ecopetrol.  Talisman also acquired interests in two exploration blocks in Norway.

“We made an oil discovery in Colombia in 2010 and early results from a stratigraphic drilling program are very exciting. Early indications from the Beta well in Norway and TR1 in the UK are encouraging, as are early drilling results in Papua New Guinea.

“Net income was $648 million, up 48% compared to a year ago, with higher commodity prices.  Earnings from continuing operations were down due to lower cash proceeds from financial instruments than the previous year and higher 2010 cash taxes, despite improved operating metrics. Cash flow was $3.1 billion in 2010 compared to $4 billion in 2009. The company recognized approximately $1 billion in cash from hedges in 2009 and higher cash taxes in 2010.

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“Looking forward, the portfolio is now positioned for sustainable and profitable growth. We have shifted the emphasis in 2011 in North America to liquids opportunities with a 35% reduction in spending on dry gas. We will ramp up activity in the Eagle Ford and in our conventional liquids areas, while scaling back our net spending in both the Marcellus and Montney. Colombia also adds 12,000-15,000 boe/d of production, half of which will be liquids.

“I fully expect another exciting year in 2011. We have a stable, oil leveraged production base from our North Sea assets and our conventional North American portfolio, and are not being held hostage by low North American natural gas prices. We are able to grow while maintaining a disciplined approach to capital spending, and continue to evaluate our large, and growing, international exploration portfolio. Our replacement costs will continue to decline, driving improved profitability into the future.”

Financial Results

All values in this press release are in Canadian dollars (C$) unless otherwise stated.  Commencing in the first quarter of 2011, Talisman will be reporting in US dollars (US$) to reflect the fact that the majority of the company’s transactions occur in US$ and this is the functional currency of the company.

The financial information contained in this release is unaudited. The company expects to file its audited Financial Statements for the year ended December 31, 2010, along with the related Management’s Discussion and Analysis, Annual Information Form and Annual Report on Form 40-F by February 28, 2011.

The company announced its capital spending plans for 2011 on January 11, 2011. For additional information, please visit Talisman’s website at www.talisman-energy.com.

	Three months ended						Year ended
December 31	2010			2009			2010		2009
Cash flow ($ million)		682			921			3,058		3,961
Cash flow per share 2		0.67			0.91			3.00		3.90
Net income (loss) ($ million)		(304	)		(111	)		648		437
Net income (loss) per share		(0.30	)		(0.11	)		0.64		0.43
Earnings from continuing operations ($ million)		84			68			347		631
Earnings from continuing operations per share 2		0.08			0.07			0.34		0.62
Average shares outstanding (million)		1,018			1,015			1,018		1,015

Net income was $648 million versus $437 million in 2009, reflecting higher average commodity prices, improved operating performance and gains on held for trading financial instruments, partially offset by higher taxes and lower gains on asset dispositions.  The company recorded a net loss of $304 million in the fourth quarter, compared to a net loss of $111 million in 2009, reflecting higher commodity prices and lower dry hole expenses, more than offset by higher stock based compensation and taxes.

Cash flow for 2010 was $3.1 billion versus $4 billion a year earlier, with higher revenue offset by higher royalties and cash taxes (as a result of higher prices and lower capital expenditures in the North Sea).  In addition, the company realized cash proceeds of approximately $1 billion from financial instruments in 2009.  Cash flow for the quarter was $682 million, broadly in line with the previous quarter, with higher commodity prices offset by higher stock based compensation and cash taxes in the fourth quarter.

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2 The terms “cash flow per share” and “earnings from continuing operations per share” are non-GAAP measures. Please see the advisories and reconciliations elsewhere in this press release.

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Earnings from continuing operations, which exclude non-operational items, were $347 million, compared to $631 million a year earlier, reflecting improved operating performance, lower dry hole expense and lower DD&A expense, more than offset by lower cash proceeds from derivatives and higher cash taxes.

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

Capital expenditures totaled $4 billion. Talisman spent $3.9 billion on exploration and development during 2010, a slight increase from $3.8 billion in 2009. North America accounted for 46% of spending, North Sea development 26%, Southeast Asia development 8% and international exploration 18%. Cash exploration and development spending in 2011 is expected to be approximately US$4 billion.

Production

	Three months ended				Year ended
December 31	2010		2009		2010		2009
Oil and liquids (bbls/d)		190,000		203,000		189,000		211,000
Natural gas (mmcf/d)		1,358		1,320		1,367		1,283
Total production (boe/d)		417,000		423,000		417,000		425,000
Discontinued operations (boe/d)		8,000		52,000		27,000		60,000
Continuing operations (boe/d)		409,000		371,000		390,000		365,000

Production from continuing operations averaged 390,000 boe/d, 7% above 2009 with higher North American shale gas volumes and record production in Southeast Asia. Production from continuing operations in the fourth quarter increased 10% compared to the same quarter in 2009.  Total production for the year was down 2% to 417,000 boe/d as a result of asset sales.

Production in North America from continuing operations was 126,000 boe/d, a 14% increase over 2009.  North American natural gas production increased 19%, due principally to successful development in the Pennsylvania Marcellus shale and Farrell Creek in the Montney shale play in northeastern BC.  Production from the Pennsylvania Marcellus shale play was 315 mmcf/d at the end of 2010, up from 65 mmcf/d at the end of 2009.

In the North Sea, total volumes were relatively unchanged.  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 the start-up of production at Auk North and Burghley.  In Scandinavia, production increased from 2009 due to successful development drilling at Varg, as well as improved uptime at Rev.

In Southeast Asia, volumes averaged 119,000 boe/d, an increase of 10% over 2009.  Natural gas production increased 20%, primarily due to Indonesia, where production averaged 387 mmcf/d with higher contract takes and better plant efficiency at Corridor and a full year of Tangguh production.   Natural gas production in Malaysia was also higher than 2009, averaging 98 mmcf/d due to increased gas production from the Northern Fields.

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Netbacks

	Three months ended				Year ended
December 31	2010		2009		2010		2009
($/boe)
Sales		58.32		55.51		55.37		49.40
Royalties		9.38		9.13		8.74		7.34
Transportation		1.44		1.64		1.50		1.43
Operating expenses		12.78		12.84		12.80		12.91
Netback		34.72		31.90		32.33		27.72
Oil and liquids netback ($/bbl)		53.24		44.68		46.29		37.49
Natural gas netback ($/mcf)		3.19		3.35		3.47		3.02

Talisman’s annual average realized price of $55.37/boe was 12% higher than 2009.  WTI averaged US$79.53/bbl, up 29% from 2009, reflecting the ongoing global economic recovery.  North American gas prices also increased, with NYMEX and AECO up 8% and 2%, respectively; however, natural gas prices did not keep pace with oil prices due to continuing over supply in North America.

The change in the company’s reported oil and liquids price is consistent with the relevant benchmark prices; however, the company’s reported prices also reflect the strengthening of the C$ relative to the US$ in 2010.

In 2010, the company’s average netback was $32.33/boe, 17% higher than 2009, due principally to higher commodity prices in 2010, partially offset by the strengthening C$ relative to the US$. Fourth quarter netbacks were up 9% from the same quarter in 2009, averaging $34.72/boe.

Royalty expense was $1.3 billion in 2010, a 20% increase from 2009, reflecting increased commodity prices.

Total operating costs for the company were $1.9 billion during 2010, relatively consistent with 2009. On a per unit basis, costs decreased 1% from the previous year to average $12.80/boe, helped by lower unit shale operating costs.

Gross Proved Reserves1

	Gross Proved Reserves Average 2010 Pricing
	mmboe
December 31, 2009	1,410.7
Discoveries, extensions and additions	225.5
Revisions and transfers	23.5
Price revisions	21.7
Net acquisitions and dispositions	(146.9)
Production	(152.0)
December 31, 2010	1,382.5

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1 The reserves data and other oil and gas information included herein are disclosed in accordance with US disclosure standards.  Please see the advisories elsewhere in this news release.

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Talisman spent approximately $4 billion to add 249 mmboe of proved reserves, excluding price revisions, in 2010, replacing 164% of production. Total proved reserves additions, including price revisions were 271 mmboe. The company’s reserves were reduced by 147 mmboe through acquisitions and dispositions, for a net addition of 124 mmboe of proved reserves. Proved undeveloped reserves accounted for 33% of the company total and 34% in North America at the end of 2010.

Excluding price revisions, replacement costs were down 35%. Proved, developed producing replacement costs were down 54%.

North America

In North America, production from continuing operations was 756 mmcfe/d (126,000 boe/d) in 2010, an increase of 14% over 2009, due to ongoing development programs in shale gas. Natural gas production from continuing operations averaged 636 mmcf/d.

Total production averaged 918 mmcfe/d (153,000 boe/d) for 2010, down 9% from a year ago, as a result of non-core asset sales.  Production from shale averaged 218 mmcfe/d during the year, up from 34 mmcf/d a year earlier. Shale accounted for 28% of Talisman’s North American natural gas production. Capital spending in North America was $1.8 billion, including $1.6 billion related to shale activities.

In the Pennsylvania Marcellus area, the company drilled 152 gross (145.4 net) wells during the year, 139 operated and 13 non-operated. Production averaged 181 mmcf/d in 2010, up from 29 mmcf/d the previous year, with an exit rate of 315 mmcf/d. Talisman ended the year with 12 operated rigs in the area.

Talisman continued to progress development of its Montney shale play in 2010. In Farrell Creek, Talisman drilled 21 gross (21 net) operated wells and, at the end of the year, had four operated rigs working. In Greater Cypress and Greater Groundbirch, Talisman continued its piloting program, drilling 16 gross (9.3 net) wells, nine of which were operated. Average production was 32 mmcf/d in the Montney play, with an exit rate of 84 mmcf/d.

In December 2010, Talisman reached an agreement to create a strategic partnership with Sasol Limited to develop the Farrell Creek assets in Talisman's Montney shale play. Pursuant to this agreement, Talisman will sell a 50% working interest in its Farrell Creek assets to Sasol for a total consideration of approximately $1 billion, including $250 million cash and a commitment to fund future capital in the amount of $800 million. Closing is expected to occur in the first half of 2011.

Talisman also established a strategic position in the heart of the liquids rich window of the Eagle Ford shale play through land acquisitions and the creation of a 50/50 joint venture with Statoil ASA. Talisman now holds approximately 78,000 net acres as a result of these transactions.  At the end of the year, Talisman had four rigs operating in the area. Average production in December 2010 was 14 mmcfe/d.

Talisman continued its pilot program in Quebec, drilling four gross (3.2 net) wells. The company also completed three wells, including a well drilled in 2009, and is planning to complete the remaining two wells in 2011.

Production from continuing operations from Talisman’s conventional areas was 421 mmcf/d natural gas and 20,000 bbls/d of liquids. The company drilled a total of 109 gross conventional wells (83 net) in the year. In the liquids rich window of the Cardium play in Alberta, Talisman started a pilot program in the fourth quarter of 2010.

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Talisman successfully completed the sale of conventional, non-core assets in North America, generating proceeds of approximately $2 billion. These properties were approximately 90% gas-weighted, with production of 45,000 boe/d (270 mmcfe/d) at the end of the 2009.

UK

Production in the UK averaged 77,000 boe/d, a 14% decrease from 2009. This was due to reductions from a number of fields due to planned and unplanned shutdowns and natural declines, partly offset by improved production efficiency at Claymore, the startup of Burghley in October and the Auk North field in November.

The company spent $507 million on development in the UK, with most of this capital directed at the Auk North and Auk South projects. As well as completing the Burghley project, the Montrose/Arbroath area redevelopment was progressed and an Auk North development well was completed during the year.

The Auk North development achieved first oil ahead of schedule and under budget, with production commencing November 2010. A fourth production well on Auk North is planned to be drilled during 2011. The Auk South redevelopment project was progressed during the year, with commencement of fabrication of the new facilities. First production from the Auk South redevelopment is expected in 2012.

Scandinavia

Production in Scandinavia averaged 54,000 boe/d, a 24% increase over 2009, mainly due to infill drilling at Varg and increased volumes from the Rev Field, due to improved uptime at the host facility. The company spent $501 million on development in Scandinavia during 2010, with approximately half directed at the Yme project.  A total of 11 development wells were drilled in Scandinavia in 2010, and two additional wells were drilling over year end.

The Yme field redevelopment was progressed during the year, with construction of the topsides finished and all pre-startup wells completed. The topsides were shipped from the construction yard in Abu Dhabi and are currently waiting in Stavanger for an adequate weather window to allow installation.

Southeast Asia

Production in Southeast Asia averaged 119,000 boe/d, an increase of 10% over 2009. The main production increases came from optimization of facilities in Corridor, from both liquefied natural gas (LNG) trains nearing their design capacity at Tangguh, and from higher gas sales in Malaysia.

Malaysia volumes were 37,400 boe/d, an increase of 18% over 2009, reflecting additional gas sales coming from Northern Fields. Talisman spent $128 million on development in Malaysia with one exploration and one appraisal well and 10 oil and gas development wells drilled and completed.  The Southern Fields Incremental Oil Recovery phase 1 program was completed in 2010 and contributed 6,300 boe/d gross (2,600 boe/d net TLM) in the year, offsetting natural declines.

Indonesia production was approximately 76,400 boe/d, an increase of 15% over last year.  Talisman spent $164 million, primarily on facilities upgrades, development at Jambi Merang and the drilling of three exploration and 28 development wells.

Production from the Corridor PSC was 61,300 boe/d, a new record, reflecting facilities optimization.

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Talisman acquired a 25% interest in the Jambi Merang Joint Operating Body (JOB) block in early 2010.  The first phase of development drilling is complete and facilities construction is underway.  Three new gas sales agreements were signed in November 2010.  The project is on schedule for mid-2011 startup.

In the Ogan Komering JOB block, the company commenced a 37-well infill drilling program, which will be completed over the next three years.  Drilling results from the nine wells drilled in 2010 are meeting expectations and are being brought onstream as they are completed.

Vietnam production averaged 2,200 bbls/d. Four infill wells in the Song Doc Field began drilling in the third quarter of 2010 and are expected to be completed in early 2011. Talisman continues to progress development options for the Hai Su Trang and Hai Su Den discoveries and has entered into a Heads of Agreement for an oil tie-back to facilities south of Block 15-2/01.

Production in Australia averaged 3,500 bbls/d from the Laminaria and Corallina fields, and development of the Kitan field in the Joint Petroleum Development Area between Timor Leste and Australia is expected to be onstream around year end. To date, a total of three development wells have been drilled in Kitan and the fourth well spudded in early 2011.

International Exploration

The company continued to build its international exploration portfolio, focused on providing long-term growth in South East Asia and Latin America, sustaining the North Sea and testing material growth opportunities in the Kurdistan region of northern Iraq and Poland.

Total international exploration spending during the year was $712 million, invested in continuing to build the portfolio; extensive seismic programs, which have increased the prospect inventory; as well as exploration and appraisal drilling, which resulted in a number of significant discoveries.

In Southeast Asia, Talisman was successful in drilling two exploration and one appraisal wells in Malaysia on Block PM3-CAA, and continued to acquire seismic offshore Sabah.  In Papua New Guinea Talisman increased its land holdings and the company now holds interests in 12 blocks covering in excess of 9 million net acres.  Two onshore exploration wells were spudded in late 2010; both found gas with associated condensate.  Five additional wells are planned for 2011.  In Vietnam, government approval for two new blocks (133 and 134) was received in March and a PSC for Block 5-2/10 was signed in early 2011.  In Indonesia, Talisman participated in the unsuccessful Bravo well in the Pasangkayu PSC in the North Makassar Straits.  Another exploration well, Romeo, will be drilled in Pasangkayu this year, in addition to the first well in the Talisman-operated South Makassar Sageri PSC.

In the Norwegian North Sea, successful appraisal wells were drilled on the 2009 Grevling discovery and on the recently acquired 2009 Beta discovery. In the UK Sector, Talisman has drilled the TR1 well in the Fulmar area with encouraging results and the well is being prepared for testing.

Talisman had a successful year in Latin America.  The Akacias-1 well in Colombia CPO-9 made a significant oil discovery adjacent to Ecopetrol’s Chichimene field in the Llanos Basin.  Five stratigraphic wells on CPE-6 have indicated the potential for a considerable hydrocarbon resource, which will be appraised in 2011.  Further appraisal drilling around the Huron discovery is planned for 2011.  In Peru, the Situche Central-3X well proved up additional resources and the company farmed into Blocks 123 /129 to expand its land position in the Marañon Basin.

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In August 2010, Talisman entered into an agreement to purchase a 49% non-operated interest in BP Exploration Company (Colombia) Limited.  The transaction closed on January 24, 2011 and builds on Talisman’s large acreage position in Colombia, in close proximity to its Niscota Block, where it has announced a significant discovery with the Huron well.  The acquisition provides an additional 330,000 net acres in Colombia, along with 12,000 boe/d of net production and provides Talisman with a strategic holding in the Ocensa export pipeline.

In the Kurdistan region of northern Iraq, the Kurdamir-1 well in Block 44 was suspended after finding significant gas resources and encouraging indications of liquids.  Challenging drilling conditions prevented evaluation of deeper levels of the structure and the well will be re-drilled in 2011.   The conversion of Block K39 to a Production Sharing Contract was underway at the end of 2010 and the company will drill its first well on this block in 2011, Topkhana-1.

In February 2010, Talisman entered into a farm-in arrangement with San Leon Energy PLC for interests in three Baltic gas licenses in Poland. The company will be leveraging its North American shale gas expertise in 2011 when drilling commences on the first two of three shale gas wells following completion of its seismic acquisition program.

Talisman Energy Inc. is a global, diversified, upstream oil and gas company, headquartered in Canada. Talisman’s three main operating areas are North America, the North Sea and Southeast Asia. The company also has a portfolio of international exploration opportunities. Talisman is committed to conducting business safely, in a socially and environmentally responsible manner, and is included in the Dow Jones Sustainability (North America) Index. Talisman is listed on the Toronto and New York Stock Exchanges under the symbol TLM. Please visit our website at www.talisman-energy.com.

For further information, please contact:

Media and General Inquiries:		Shareholder and Investor Inquiries:
David Mann		Christopher J. LeGallais
Vice President, Corporate		Vice President, Investor Relations
& Investor Communications		Phone:	403-237-1957 Fax: 403-237-1210
Phone:	403-237-1196 Fax:  403-237-1210	E-mail:	tlm@talisman-energy.com
E-mail:	tlm@talisman-energy.com

03-11

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Forward-Looking Information

This news releasecontains 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:

· expected  growth and asset quality arising from increasing amounts of capital in North American shale plays;

· expected onstream dates of North Sea developments;

· potential gas-to-liquids project;

· expected reduction in replacement costs;

· planned exploration and development spending;

· expected medium term growth, and longer-term production growth from shale;

· anticipated filing dates of financial statements, management discussion & analysis, the annual information form, and the annual report;

· planned drilling in Quebec;

· planned drilling in the North Sea;

· expected timing of first production at Jambi Merang and Kitan;

· planned drilling in the Corridor Block, Ogan Komering JOB block and Song Doc Field; and

· planned drilling in Papua New Guinea, Colombia, the Kurdistan region of northern Iraq and Poland.

The forward-looking information listed above is based on Talisman's 2011 capital program as announced on January 11, 2011. Talisman set its 2011 capital expenditure plans assuming: (1) Talisman’s production in 2011 will be approximately 5-10% greater than 2010, excluding the BP Colombia acquisition; (2) a WTI oil price of US$75/bbl; and (3) a NYMEX natural gas price of US$4/mmbtu. Information regarding business plans generally assumes that the extraction of crude oil, natural gas and natural gas liquids remains economic. Closing of any transactions will be subject to receipt of all necessary regulatory approvals and completion of definitive agreements.

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 news release. 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 prices and 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 the Company's 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;

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· health, safety and environmental risks, including risks related to the possibility of major accidents;

· uncertainties as to the availability and cost of credit and other 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 governmental 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 any 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. 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 (SEC). 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.

Reserves Information

National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. Talisman has obtained an exemption from Canadian securities regulatory authorities to permit it to provide certain disclosures in accordance with the US disclosure standards, in order to provide for comparability of oil and gas disclosure with that provided by US and other international issuers. Accordingly, the reserves information included in this news release is disclosed in accordance with US disclosure standards.

A separate exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data contained in this news release reflects Talisman’s estimates of its reserves and resources. While Talisman annually obtains an independent audit of a portion of its proved and probable reserves, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this news release.

Replacement Ratio

The replacement ratios before net acquisitions and dispositions were calculated by dividing the sum of changes (revisions of estimates and discoveries) to estimated gross proved oil and gas reserves during 2010 by the Company’s 2010 gross production. The Company’s management uses reserves replacement ratios as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that a reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely, based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not include cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.

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Replacement Costs

In this news release, Talisman discloses a reduction in replacement costs.  Replacement costs are used by the Company to determine the cost of reserves additions in a period.  Talisman’s reported replacement costs may not be comparable to similarity titled measures used by other companies. Replacement costs may not reflect full cycle replacement costs.  Replacement costs’ predictive and comparative value is limited for the aforementioned reasons. Replacement costs are calculated by dividing exploration and development capital spending of $4 billion (including discontinued operations, but excluding midstream) by gross proved reserve additions of 249 mmboe.

Netbacks

Talisman also discloses its Company netbacks in this news release. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.

Gross Production

Throughout this news release, Talisman makes reference to production volumes. 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.

Boe Conversion

Throughout this news release, barrels of oil equivalent (boe) are calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil (bbl).  Oil is converted to natural gas equivalent (mcfe) at the ratio of one bbl to six mcf of natural gas.  Boes and mcfes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl and an mcfe conversion ratio of 1 bbl: 6 mcf are based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Canadian Dollars and GAAP

Dollar amounts are presented in Canadian dollars, except where otherwise indicated. Unless otherwise indicated, the financial information is set out in accordance with Canadian GAAP which may differ from U.S. GAAP. See the notes to Talisman’s Annual Consolidated Financial Statements for the significant differences between Canadian and U.S. GAAP.

Non-GAAP Financial Measures

Included in this news release are references to financial measures used in the oil and gas industry such as cash flow, earnings from continuing operations and net debt. These terms are not defined by GAAP in either Canada or the U.S. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of cash flow, earnings from continuing operations and net debt may not be comparable to similarly titled measures reported by other companies.

Cash flow represents net income before exploration costs, DD&A, future taxes and other non-cash expenses. Cash flow is used by the Company to assess operating results between years and between peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with Canadian GAAP as an indicator of the Company’s performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. A reconciliation of cash provided by operating activities to cash flow follows:

12

Cash Flow

December 31, 2010

$ million, except per share amounts

	Three Months ended						Year ended
December 31	2010			2009			2010			2009
Cash provided by operating activities		607			624			3,460			3,599
Changes in non-cash working capital		75			297			(402	)		362
Cash flow		682			921			3,058			3,961
Cash provided by discontinued operations 1		(6	)		(62	)		(190	)		(385	)
Cash flow from continuing operations		676			859			2,868			3,576
Cash flow per share		0.67			0.91			3.00			3.90
Cash flow from continuing operations per share		0.66			0.85			2.82			3.52

1. Comparatives restated for operations classified as discontinued during 2010.

Earnings from continuing operations are calculated by adjusting the Company’s net income per the financial statements, for certain items of a non-operational nature, on an after tax basis. The Company uses this information to evaluate performance of core operational activities on a comparable basis between periods. Earnings from continuing operations per share are earnings from continuing operations divided by the average number of common shares outstanding during the period. A reconciliation of net income to earnings from continuing operations follows:

Earnings from Continuing Operations

December 31, 2010

$ million, except per share amounts

	Three Months ended					Year ended
December 31,	2010			2009	4		2010		2009	4
Income (loss) from continuing operations		(313	)	(181	)		408		(658	)
Unrealized (gain) loss  on financial instruments 1 (tax adjusted)		66		173			(265	)	1,056
Stock-based compensation2 (tax adjusted)		222		20			187		198
Foreign exchange on net debt and future income taxes		57		(17	)		48		(59	)
Restructuring charges (tax adjusted)		-		14			-		14
Future tax rate changes		-		21					21
Future tax (recovery) of unrealized foreign exchange (losses) on net foreign denominated debt and other tax adjustments 3		52		38			(31	)	59
Earnings from continuing operations		84		68			347		631
Per share		0.08		0.07			0.34		0.62

1. Unrealized losses on financial instruments relate to the change in the period of the mark-to-market value of the company’s held-for-trading financial instruments.

2. Stock-based compensation expense relates to the mark-to-market value of the company’s outstanding stock options and cash units at December 31. The company’s stock-based compensation expense is based on the difference between the company’s share price and its stock options or cash units exercise price. The three months and year ended December 31, 2010 amounts reflect the legislative change occurring in the fourth quarter of 2010 whereby the company is unable to obtain a tax benefit.

3. Tax adjustment includes future taxes relating to unrealized foreign exchange gains and losses associated with the impact of fluctuations in the Canadian dollar on net foreign denominated debt.

4. Comparatives restated for operations classified as discontinued during 2010, and for foreign exchange on net debt and future income taxes in order to be presented on the same basis as in 2010.

13

Net debt is calculated by adjusting the Company’s long-term debt per the financial statements for bank indebtedness, cash and cash equivalents. The Company uses this information to assess its true debt position and eliminate the impact of timing differences.

Net Debt

December 31, 2010

$ million

December 31,	2010			2009
Long-term debt (including current portion)		4,181			3,780
Bank indebtedness		2			36
Cash and cash equivalents		(1,646	)		(1,690	)
Net debt		2,537			2,126

14

Talisman Energy Inc.

Highlights

(unaudited)

	Three months ended						Year ended
	December 31						December 31
	2010			2009			2010		2009
Financial
(millions of C$ unless otherwise stated)
Cash flow (1)		682			921			3,058		3,961
Net income (loss)		(304	)		(111	)		648		437
Capital expenditures		1,253			1,446			4,052		4,189
Per common share (C$)
Cash flow (1)		0.67			0.91			3.00		3.90
Net income (loss)		(0.30	)		(0.11	)		0.64		0.43
Production
(daily average)
Oil and liquids (bbls/d)
North America		20,773			29,117			23,133		34,477
UK		82,739			78,515			74,074		85,504
Scandinavia		38,201			38,490			38,973		33,649
Southeast Asia		33,681			42,336			38,481		40,755
Other		14,972			14,588			13,983		16,068
Total oil and liquids		190,366			203,046			188,644		210,453
Natural gas (mmcf/d)
North America		780			787			778		803
UK		11			13			16		19
Scandinavia		98			100			88		58
Southeast Asia		469			420			485		403
Total natural gas		1,358			1,320			1,367		1,283
Total mboe/d (2)		417			423			417		425
Prices (3)
Oil and liquids (C$/bbl)
North America		63.73			64.24			64.47		54.96
UK		86.75			78.78			81.71		68.36
Scandinavia		91.25			77.61			83.75		69.73
Southeast Asia		94.09			84.26			82.95		71.17
Other		98.67			100.59			85.17		74.03
Total oil and liquids		87.38			79.18			80.52		67.36
Natural gas (C$/mcf)
North America		4.42			4.86			4.93		4.70
UK		5.42			4.41			4.72		4.73
Scandinavia		7.93			4.99			6.86		5.86
Southeast Asia		7.22			7.19			6.92		6.40
Total natural gas		5.65			5.61			5.76		5.29
Total (C$/boe) (2)		58.32			55.51			55.37		49.40

(1) Cash flow and cash flow per share are non-GAAP measures.

(2) 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.

(3) Prices are before hedging.

Includes the results from continuing and discontinued operations.

15

Talisman Energy Inc.

Consolidated Balance Sheets

(unaudited)

December 31 (millions of C$)	2010			2009
				(restated)
Assets
Current
Cash and cash equivalents		1,646			1,690
Accounts receivable		1,399			1,253
Inventories		143			144
Prepaid expenses		20			9
Assets of discontinued operations		-			58
		3,208			3,154
Other assets		861			170
Future income taxes		170			120
Goodwill		1,150			1,176
Property, plant and equipment		18,804			16,431
Assets of discontinued operations		-			2,567
		20,985			20,464
Total assets		24,193			23,618
Liabilities
Current
Bank indebtedness		2			36
Accounts payable and accrued liabilities		2,532			2,121
Income and other taxes payable		510			357
Current portion of long-term debt		357			10
Future income taxes		-			68
Liabilities of discontinued operations		-			9
		3,401			2,601
Deferred credits		51			59
Asset retirement obligations		2,252			2,116
Other long-term obligations		212			168
Long-term debt		3,824			3,770
Future income taxes		3,974			3,599
Liabilities of discontinued operations		-			194
		10,313			9,906
Shareholders' equity
Common shares, no par value
Authorized: unlimited
Issued and outstanding:
2010 - 1,019,290,939 (2009 - 1,014,876,564)		2,457			2,374
Contributed surplus		132			153
Retained earnings		9,568			9,174
Accumulated other comprehensive loss		(1,678	)		(590	)
		10,479			11,111
Total liabilities and shareholders' equity		24,193			23,618

Prior period balances have been restated to reflect the financial position of discontinued operations.

16

Talisman Energy Inc.

Consolidated Statements of Income

(unaudited)

	Three months ended						Year ended
	December 31						December 31
(millions of C$)	2010			2009			2010			2009
				(restated)						(restated)
Revenue
Gross sales		2,194			2,056			8,076			7,011
Less royalties		348			359			1,274			1,065
Net sales		1,846			1,697			6,802			5,946
Other		28			26			110			115
Total revenue		1,874			1,723			6,912			6,061
Expenses
Operating		474			465			1,867			1,861
Transportation		55			64			227			222
General and administrative		106			88			392			334
Depreciation, depletion and amortization		546			598			2,164			2,360
Dry hole		45			204			123			539
Exploration		143			99			384			301
Interest on long-term debt		44			49			163			192
Stock-based compensation		224			42			201			290
(Gain) loss on held-for-trading financial instruments		125			142			(102	)		412
Other, net		59			22			194			47
Total expenses		1,821			1,773			5,613			6,558
Income (loss) from continuing operations before taxes		53			(50	)		1,299			(497	)
Taxes
Current income tax		401			254			1,032			731
Future income tax recovery		(86	)		(173	)		(272	)		(678	)
Petroleum revenue tax		51			50			131			108
		366			131			891			161
Income (loss) from continuing operations		(313	)		(181	)		408			(658	)
Income from discontinued operations		9			70			240			1,095
Net income (loss)		(304	)		(111	)		648			437
Per common share (C$):
Income (loss) from continuing operations		(0.31	)		(0.18	)		0.40			(0.65	)
Diluted income (loss) from continuing operations		(0.31	)		(0.18	)		0.39			(0.65	)
Income from discontinued operations		0.01			0.07			0.24			1.08
Diluted income from discontinued operations		0.01			0.07			0.23			1.08
Net income (loss)		(0.30	)		(0.11	)		0.64			0.43
Diluted net income (loss)		(0.30	)		(0.11	)		0.62			0.43
Average number of common shares outstanding (millions)		1,018			1,015			1,018			1,015
Diluted number of common shares outstanding (millions)		1,018			1,015			1,037			1,015

Prior period balances have been restated to reflect the results of discontinued operations.

17

Talisman Energy Inc.

Consolidated Statements of Cash Flows

(unaudited)

	Three months ended						Year ended
	December 31						December 31
(millions of C$)	2010			2009			2010			2009
				(restated)						(restated)
Operating
Income (loss) from continuing operations		(313	)		(181	)		408			(658	)
Items not involving cash		846			941			2,076			3,933
Exploration		143			99			384			301
		676			859			2,868			3,576
Changes in non-cash working capital		(75	)		(297	)		402			(362	)
Cash provided by continuing operations		601			562			3,270			3,214
Cash provided by discontinued operations		6			62			190			385
Cash provided by operating activities		607			624			3,460			3,599
Investing
Capital expenditures
Exploration, development and other		(1,250	)		(1,393	)		(4,034	)		(3,729	)
Corporate acquisitions		-			-			(189	)		-
Property acquisitions		(913	)		(32	)		(1,364	)		(310	)
Proceeds of resource property dispositions		188			96			308			200
Acquisition deposit		(18	)		-			(656	)		-
Changes in non-cash working capital		167			139			265			(18	)
Discontinued operations, net of capital expenditures		350			449			1,936			1,990
Cash used in investing activities		(1,476	)		(741	)		(3,734	)		(1,867	)
Financing
Long-term debt repaid		-			-			(11	)		(970	)
Long-term debt issued		600			12			600			1,261
Common shares issued		48			1			57			2
Common shares purchased		(32	)		-			(78	)		(1	)
Common share dividends		(127	)		(114	)		(254	)		(229	)
Deferred credits and other		9			(24	)		(3	)		(10	)
Changes in non-cash working capital		-			3			(2	)		4
Cash provided by (used in) financing activities		498			(122	)		309			57
Effect of translation on foreign currency cash and cash equivalents		(57	)		(41	)		(59	)		(133	)
Net increase (decrease) in cash and cash equivalents		(428	)		(280	)		(24	)		1,656
Cash and cash equivalents net of bank indebtedness, beginning of year		2,072			1,948			1,668			12
Cash and cash equivalents net of bank indebtedness, end of year		1,644			1,668			1,644			1,668
Cash and cash equivalents		1,646			1,690			1,646			1,690
Cash and cash equivalents reclassified to discontinued operations		-			14			-			14
Bank indebtedness		(2	)		(36	)		(2	)		(36	)
Cash and cash equivalents net of bank indebtedness, end of year		1,644			1,668			1,644			1,668

Prior period balances have been restated to reflect the cash flows of discontinued operations.

18

Supplemental financial information

The following supplemental financial information has been prepared to assist readers of the unaudited consolidated financial information as at and for the three month period and year ended December 31, 2010.  This financial information does not constitute interim financial statements as defined by Generally Accepted Accounting Principles in that certain statements and disclosures normally required to be included in interim financial statements and the notes thereto have not been provided.  This unaudited consolidated financial information should be read in conjunction with the audited annual Consolidated Financial Statements as at and for the year ended December 31, 2009 and the most recently completed unaudited interim Consolidated Financial Statements as at and for the three and nine month periods ended September 30, 2010.

Commodity derivatives

The Company had the following commodity price derivative contracts outstanding at December 31, 2010:

Fixed price swaps	Term	mcf/d		C$/mcf		Fair value (millions of C$)
ICE index	Jan-Mar 2011		17,824		6.45		(6	)
ICE index	Apr-Jun 2011		16,886		5.89		(5	)
							(11	)
Fixed price swaps	Term	mcf/d		US$/mcf		Fair value (millions of C$)
NYMEX index	Jan-Dec 2011		23,734		6.12		11
Two-way collars	Term	bbls/d		Floor/ceiling US$/bbl		Fair value (millions of C$)
Dated Brent oil index	Jan-Jun 2011		20,000		80.00/92.41		(18	)
Dated Brent oil index	Jan-Dec 2011		21,000		80.00/91.27		(49	)
Dated Brent oil index	Jan-Dec 2011		20,000		84.00/97.57		(20	)
WTI	Jan-Dec 2011		9,000		80.00/92.00		(18	)
							(105	)
Two-way collars	Term	mcf/d		Floor/ceiling C$/mcf		Fair value (millions of C$)
NYMEX index	Jan-Jun 2011		95,000		5.27/6.66		12
NYMEX index	Jan-Dec 2011		71,200		6.14/6.59		36
							48

The Company had the following physical commodity contracts outstanding at December 31, 2010:

	Term	mcf/d		C$/mcf
AECO natural gas swaps	Jan-Dec 2011		3,671		2.98

19

Supplemental cash flow information

Items not involving cash are as follows:

	Three months ended December 31						Year ended December 31
(millions of C$)	2010			2009			2010			2009
Depreciation, depletion & amortization		546			598			2,164			2,360
Dry hole		45			204			123			539
Net gain on asset disposals		(6	)		(22	)		(59	)		(37	)
Stock-based compensation expense		195			30			146			238
Future taxes and deferred PRT (recovery)		(76	)		(156	)		(268	)		(635	)
Unrealized (gains) losses on held for trading financial instruments		73			218			(278	)		1,401
Other		69			69			248			67
		846			941			2,076			3,933

20

Talisman Energy Inc.

Segmented Information

(unaudited)

	North America (1)											UK										Scandinavia
	Three months ended December 31					Year ended December 31						Three months ended December 31					Year ended December 31					Three months ended December 31					Year ended December 31
(millions of C$)	2010		2009			2010			2009			2010			2009		2010			2009		2010		2009			2010		2009
Revenue
Gross sales		427		378			1,650			1,394			649			582		2,239			2,188		379		308			1,393		986
Royalties		48		41			188			156			2			1		7			5		-		-			-		-
Net sales		379		337			1,462			1,238			647			581		2,232			2,183		379		308			1,393		986
Other		22		24			88			93			3			2		18			19		3		1			3		3
Total revenue		401		361			1,550			1,331			650			583		2,250			2,202		382		309			1,396		989
Segmented expenses
Operating		115		91			424			403			186			223		824			878		77		70			304		285
Transportation		15		15			61			59			9			13		34			46		15		18			64		54
DD&A		202		184			764			748			162			163		582			781		96		140			471		406
Dry hole		10		14			(4	)		134			(1	)		-		62			30		6		8			11		69
Exploration		5		19			40			84			3			5		16			18		11		6			32		22
Other		-		8			(5	)		(21	)		(15	)		66		(14	)		72		37		(10	)		105		(5	)
Total segmented expenses		347		331			1,280			1,407			344			470		1,504			1,825		242		232			987		831
Segmented income (loss) before taxes		54		30			270			(76	)		306			113		746			377		140		77			409		158
Non-segmented expenses
General and administrative
Interest on long-term debt
Stock-based compensation
Currency translation
(Gain) loss on held-for-trading financial instruments
Total non-segmented expenses
Income (loss) from continuing operations before taxes
Capital expenditures
Exploration		64		750			285			1,189			22			19		96			149		13		18			89		157
Development		547		125			1,506			264			110			106		507			531		93		144			501		528
Midstream		2		(2	)		3			26			-			-		-			-		-		-			-		-
Exploration and development		613		873			1,794			1,479			132			125		603			680		106		162			590		685
Property acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment							7,721			6,155								4,347			4,549							2,668		2,040
Goodwill							140			149								265			289							597		628
Other							1,546			594								540			386							376		226
Discontinued operations							-			2,585								-			-							-		-
Segmented assets							9,407			9,483								5,152			5,224							3,641		2,894
Non-segmented assets
Total assets

(1) North America	2010		2009		2010		2009
Canada		306		328		1,231		1,210
US		95		33		319		121
Total revenue		401		361		1,550		1,331
Canada						4,991		4,993
US						2,730		1,162
Property, plant and equipment						7,721		6,155

21

Talisman Energy Inc.

Segmented Information

(unaudited)

	Southeast Asia (2)									Other (3)												Total
	Three months ended December 31					Year ended December 31				Three months ended December 31						Year ended December 31						Three months ended December 31						Year ended December 31
(millions of C$)	2010			2009		2010		2009		2010			2009			2010			2009			2010			2009			2010			2009
Revenue
Gross sales		606			620		2,379		1,995		133			168			415			448			2,194			2,056			8,076			7,011
Royalties		226			209		858		675		72			108			221			229			348			359			1,274			1,065
Net sales		380			411		1,521		1,320		61			60			194			219			1,846			1,697			6,802			5,946
Other		-			-		1		-		-			(1	)		-			-			28			26			110			115
Total revenue		380			411		1,522		1,320		61			59			194			219			1,874			1,723			6,912			6,061
Segmented expenses
Operating		89			70		288		255		7			11			27			40			474			465			1,867			1,861
Transportation		15			16		61		55		1			2			7			8			55			64			227			222
DD&A		78			97		318		382		8			14			29			43			546			598			2,164			2,360
Dry hole		27			163		31		253		3			19			23			53			45			204			123			539
Exploration		53			31		118		75		71			38			178			102			143			99			384			301
Other		(8	)		6		21		9		(6	)		(3	)		(5	)		7			8			67			102			62
Total segmented expenses		254			383		837		1,029		84			81			259			253			1,271			1,497			4,867			5,345
Segmented income (loss) before taxes		126			28		685		291		(23	)		(22	)		(65	)		(34	)		603			226			2,045			716
Non-segmented expenses
General and administrative																							106			88			392			334
Interest on long-term debt																							44			49			163			192
Stock-based compensation																							224			42			201			290
Currency translation																							51			(45	)		92			(15	)
(Gain) loss on held-for-trading financial instruments																							125			142			(102	)		412
Total non-segmented expenses																							550			276			746			1,213
Income (loss) from continuing operations before taxes																							53			(50	)		1,299			(497	)
Capital expenditures
Exploration		107			54		242		233		129			61			285			217			335			902			997			1,945
Development		102			80		324		444		21			22			97			46			873			477			2,935			1,813
Midstream		-			-		-		-		-			-			-			-			2			(2	)		3			26
Exploration and development		209			134		566		677		150			83			382			263			1,210			1,377			3,935			3,784
Property acquisitions																							907			116			1,562			438
Proceeds on dispositions																							(192	)		(177	)		(393	)		(323	)
Other non-segmented																							32			14			80			47
Net capital expenditures																							1,957			1,330			5,184			3,946
Property, plant and equipment							3,076		2,864								992			823									18,804			16,431
Goodwill							148		110								-			-									1,150			1,176
Other							622		427								163			156									3,247			1,789
Discontinued operations							-		-								-			40									-			2,625
Segmented assets							3,846		3,401								1,155			1,019									23,201			22,021
Non-segmented assets																													992			1,597
Total assets																													24,193			23,618

(2) Southeast Asia	2010		2009		2010		2009
Indonesia		204		202		865		693
Malaysia		125		134		496		400
Vietnam		11		23		53		101
Australia		40		52		108		126
Total revenue		380		411		1,522		1,320
Indonesia						1,081		906
Malaysia						1,067		1,171
Vietnam						278		241
Papua New Guinea						426		337
Australia						224		209
Property, plant and equipment						3,076		2,864

(3) Other	2010		2009		2010		2009
Algeria		61		59		194		219
Total revenue		61		59		194		219
Algeria						249		193
Kurdistan						595		512
Other						148		118
Property, plant and equipment						992		823

22

Continuity of Gross Proved Reserves

	Canada			US			UK			Scandinavia			Indonesia			Other Southeast Asia			Other			Total
Oil and Liquids (mmbbls)
Total Proved
Proved reserves at December 31, 2007		152.8			-			387.2			67.3			35.7			53.5			52.8			749.3
Discoveries, additions and extensions		13.7			-			15.0			8.3			0.4			0.2			(0.7	)		36.9
Purchase of reserves		0.3			-			-			-			-			-			-			0.3
Sale of reserves		(0.3	)		-			(17.5	)		(1.7	)		-			-			-			(19.5	)
Net revisions and transfers		2.6			-			(133.7	)		(5.3	)		0.6			(5.6	)		0.6			(140.8	)
2008 Production		(14.8	)		-			(34.3	)		(12.0	)		(4.3	)		(8.7	)		(7.6	)		(81.7	)
																	-			-
Proved reserves at December 31, 2008		154.3			-			216.7			56.6			32.4			39.4			45.1			544.5
Proved reserves at December 31, 2008		154.3			-			216.7			56.6			32.4			39.4			45.1			544.5
Discoveries, additions and extensions		4.8			-			5.2			1.1			(1.7	)		7.4			12.2			29.0
Purchase of reserves		0.2			-			-			-			1.0			-			-			1.2
Sale of reserves		(45.7	)		-			(0.2	)		(4.0	)		-			-			(3.8	)		(53.7	)
Net revisions and transfers		-			-			77.0			14.5			1.1			3.8			(8.6	)		87.8
2009 Production		(12.6	)		-			(31.2	)		(12.3	)		(4.2	)		(10.7	)		(5.9	)		(76.9	)
Proved reserves at December 31, 2009		101.0			-			267.5			55.9			28.6			39.9			39.0			531.9
Proved reserves at December 31, 2009		101.0			-			267.5			55.9			28.6			39.9			39.0			531.9
Discoveries, additions and extensions		5.0			3.4			6.8			9.7			3.4			3.0			2.2			33.5
Purchase of reserves		-			1.2			-			-			3.5			-			-			4.7
Sale of reserves		(18.5	)		(0.2	)		-			-			-			-			(0.7	)		(19.4	)
Net revisions and transfers		0.2			-			18.0			1.8			0.9			6.7			0.2			27.8
2010 Production		(8.4	)		(0.1	)		(27.0	)		(14.2	)		(4.3	)		(9.7	)		(5.1	)		(68.8	)
Proved reserves at December 31, 2010		79.3			4.3			265.3			53.2			32.1			39.9			35.6			509.7
Proved developed
December 31, 2007		146.2			-			344.5			25.6			28.2			31.3			48.2			624.0
December 31, 2008		143.4			-			173.3			24.8			26.0			24.9			35.2			427.6
December 31, 2009		92.6			-			197.1			26.1			23.2			31.2			23.7			393.9
December 31, 2010		74.6			0.9			211.9			21.6			21.4			30.8			19.6			380.8

	Canada			US			UK			Scandinavia			Indonesia			Other Southeast Asia			Other			Total
Natural Gas (bcf)
Total Proved
Proved reserves at December 31, 2007		2,565.7			126.5			100.2			78.9			1,981.9			387.0			224.0			5,464.2
Discoveries, additions and extensions		308.2			33.9			12.4			12.1			1.3			27.0			0.4			395.3
Purchase of reserves		15.3			2.8			-			-			-			-			-			18.1
Sale of reserves		(65.3	)		-			-			-			-			-			-			(65.3	)
Net revisions and transfers		(30.3	)		1.4			(3.2	)		17.8			-			(2.5	)		(0.8	)		(17.6	)
2008 Production		(286.6	)		(26.7	)		(13.8	)		(6.9	)		(97.2	)		(24.9	)		(0.2	)		(456.3	)
Proved reserves at December 31, 2008		2,507.0			137.9			95.6			101.9			1,886.0			386.6			223.4			5,338.4
Proved reserves at December 31, 2008		2,507.0			137.9			95.6			101.9			1,886.0			386.6			223.4			5,338.4
Discoveries, additions and extensions		201.2			544.5			-			(0.5	)		88.6			27.9			-			861.7
Purchase of reserves		15.9			-			-			-			8.7			-			-			24.6
Sale of reserves		(137.6	)		(1.5	)		(67.0	)		-			-			-			(220.5	)		(426.6	)
Net revisions and transfers		(75.3	)		0.1			2.9			12.7			14.8			(11.1	)		(1.0	)		(56.9	)
2009 Production		(262.7	)		(30.3	)		(7.0	)		(21.1	)		(120.6	)		(26.7	)		(0.1	)		(468.5	)
Proved reserves at December 31, 2009		2,248.5			650.7			24.5			93.0			1,877.5			376.7			1.8			5,272.7
Proved reserves at December 31, 2009		2,248.5			650.7			24.5			93.0			1,877.5			376.7			1.8			5,272.7
Discoveries, additions and extensions		286.4			874.7			0.1			6.7			21.2			(37.4	)		-			1,151.7
Purchase of reserves		-			23.0			-			-			60.7			-			-			83.7
Sale of reserves		(867.3	)		(7.3	)		-			-			-			-			(1.8	)		(876.4	)
Net revisions and transfers		33.2			12.5			4.9			12.1			(3.0	)		44.6			-			104.3
2010 Production		(203.6	)		(80.5	)		(5.7	)		(32.2	)		(141.2	)		(35.9	)		-			(499.1	)
Proved reserves at December 31, 2010		1,497.2			1,473.1			23.8			79.6			1,815.2			348.0			-			5,236.9
Proved developed
December 31, 2007		2,125.6			111.4			86.7			7.0			1,197.6			58.2			1.1			3,587.6
December 31, 2008		2,066.8			117.9			65.5			99.0			1,348.9			199.0			1.2			3,898.3
December 31, 2009		1,840.9			197.9			22.4			91.2			1,231.6			320.8			0.8			3,705.6
December 31, 2010		1,134.7			687.5			22.0			73.3			1,083.1			281.3			-			3,281.9

23

Continuity of Net Proved Reserves

	Canada			US			UK			Scandinavia			Indonesia			Other Southeast Asia			Other			Total
Oil and Liquids (mmbbls)
Total Proved
Proved reserves at December 31, 2007		123.9			-			385.3			67.2			13.6			30.1			27.6			647.7
Discoveries, additions and extensions		12.1			-			15.0			8.3			-			(0.3	)		(0.3	)		34.8
Purchase of reserves		0.3			-			-			-			-			-			-			0.3
Sale of reserves		(0.3	)		-			(17.5	)		(1.6	)		-			-			-			(19.4	)
Net revisions and transfers		7.4			-			(133.2	)		(5.3	)		4.2			2.0			3.1			(121.8	)
2008 Production		(11.9	)		-			(34.2	)		(12.0	)		(1.7	)		(4.7	)		(4.1	)		(68.6	)
Proved reserves at December 31, 2008		131.5			-			215.4			56.6			16.1			27.1			26.3			473.0
Proved reserves at December 31, 2008		131.5			-			215.4			56.6			16.1			27.1			26.3			473.0
Discoveries, additions and extensions		4.0			-			5.2			1.1			(0.5	)		5.3			6.5			21.6
Purchase of reserves		0.1			-			-			-			0.7			-			-			0.8
Sale of reserves		(39.0	)		-			(0.2	)		(4.0	)		-			-			(3.7	)		(46.9	)
Net revisions and transfers		2.7			-			76.8			14.5			(1.8	)		3.8			(4.7	)		91.3
2009 Production		(9.9	)		-			(31.1	)		(12.3	)		(1.8	)		(7.6	)		(3.4	)		(66.1	)
Proved reserves at December 31, 2009		89.4			-			266.1			55.9			12.7			28.6			21.0			473.7
Proved reserves at December 31, 2009		89.4			-			266.1			55.9			12.7			28.6			21.0			473.7
Discoveries, additions and extensions		4.7			2.5			6.8			9.7			1.4			2.5			1.0			28.6
Purchase of reserves		-			0.9			-			-			1.5			-			-			2.4
Sale of reserves		(15.1	)		(0.2	)		-			-			-			-			(0.5	)		(15.8	)
Net revisions and transfers		(2.4	)		0.1			18.0			1.8			(0.8	)		0.6			(0.2	)		17.1
2010 Production		(6.6	)		(0.1	)		(27.0	)		(14.2	)		(2.0	)		(6.1	)		(2.4	)		(58.4	)
Proved reserves at December 31, 2010		70.0			3.2			263.9			53.2			12.8			25.6			18.9			447.6
Proved developed
December 31, 2007		118.9			-			342.6			25.6			10.7			18.9			25.4			542.1
December 31, 2008		122.0			-			172.0			24.8			13.5			17.7			20.2			370.2
December 31, 2009		82.1			-			196.0			26.1			11.0			21.2			13.0			349.4
December 31, 2010		65.6			0.7			210.6			21.6			8.6			18.6			9.8			335.5

	Canada			US			UK			Scandinavia			Indonesia			Other Southeast Asia			Other			Total
Natural Gas (bcf)
Total Proved
Proved reserves at December 31, 2007		2,087.1			109.0			100.2			78.9			1,359.0			245.5			223.3			4,203.0
Discoveries, additions and extensions		249.7			29.4			12.4			12.1			(30.3	)		20.2			0.4			293.9
Purchase of reserves		11.9			2.4			-			-			-			-			-			14.3
Sale of reserves		(55.2	)		-			-			-			-			-			-			(55.2	)
Net revisions and transfers		113.3			1.3			(3.2	)		17.8			143.0			42.8			(0.7	)		314.3
2008 Production		(237.6	)		(22.9	)		(13.8	)		(6.9	)		(64.0	)		(18.8	)		(0.2	)		(364.2	)
Proved reserves at December 31, 2008		2,169.2			119.2			95.6			101.9			1,407.7			289.7			222.8			4,406.1
Proved reserves at December 31, 2008		2,169.2			119.2			95.6			101.9			1,407.7			289.7			222.8			4,406.1
Discoveries, additions and extensions		185.6			474.6			-			(0.5	)		62.8			25.3			-			747.8
Purchase of reserves		14.2			-			-			-			7.5			-			-			21.7
Sale of reserves		(115.8	)		(1.4	)		(67.0	)		-			-			-			(220.0	)		(404.2	)
Net revisions and transfers		28.2			-			2.9			12.7			(19.5	)		(33.3	)		(1.0	)		(10.0	)
2009 Production		(238.4	)		(26.2	)		(7.0	)		(21.1	)		(84.4	)		(20.3	)		(0.1	)		(397.5	)
Proved reserves at December 31, 2009		2,043.0			566.2			24.5			93.0			1,374.1			261.4			1.7			4,363.9
Proved reserves at December 31, 2009		2,043.0			566.2			24.5			93.0			1,374.1			261.4			1.7			4,363.9
Discoveries, additions and extensions		263.7			738.6			0.1			6.7			8.1			(22.6	)		-			994.6
Purchase of reserves		-			17.5			-			-			42.4			-			-			59.9
Sale of reserves		(772.5	)		(5.8	)		-			-			-			-			(1.6	)		(779.9	)
Net revisions and transfers		11.2			10.3			4.9			12.1			(57.2	)		14.3			(0.1	)		(4.5	)
2010 Production		(190.9	)		(68.9	)		(5.7	)		(32.2	)		(98.2	)		(27.3	)		-			(423.2	)
Proved reserves at December 31, 2010		1,354.5			1,257.9			23.8			79.6			1,269.2			225.8			-			4,210.8
Proved developed
December 31, 2007		1,725.0			95.7			86.7			7.0			811.1			44.4			1.0			2,770.9
December 31, 2008		1,785.8			101.8			65.5			99.0			1,022.2			149.0			1.2			3,224.5
December 31, 2009		1,663.5			171.1			22.4			91.2			915.2			225.5			0.8			3,089.7
December 31, 2010		1,011.4			584.9			22.0			73.3			763.7			187.2			-			2,642.5

24

RESERVES ESTIMATES

Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices

The following table sets forth Talisman's estimates of its proved developed, proved undeveloped, total proved, probable developed, probable undeveloped and total probable reserves as at December 31, 2010. The reserves estimates included in this table were prepared using the standards of the US Securities and Exchange Commission ("SEC"), which requires that proved reserves be estimated using existing economic conditions.  The price used for calculating reserves is an unweighted arithmetic average of the first-day-of-the-month price for each month within the period unless the prices are defined by contractual obligations (excluding escalations based on future conditions).

	Proved Developed 1 ,2				Proved Undeveloped 1,3				Total Proved 1				Probable Developed 4,5				Probable Undeveloped 4,6				Total Probable 4
	Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8
Oil and Liquids (mmbbls)
North America
Canada		74.6		65.6		4.7		4.4		79.3		70.0		15.8		13.2		3.3		3.0		19.1		16.2
United States		0.9		0.7		3.4		2.5		4.3		3.2		0.2		0.1		0.6		0.5		0.8		0.6
UK
United Kingdom		211.9		210.6		53.4		53.3		265.3		263.9		59.9		59.8		90.4		89.8		150.3		149.6
Scandinavia
Norway		21.6		21.6		31.6		31.6		53.2		53.2		13.2		13.2		34.6		34.6		47.8		47.8
Southeast Asia
Indonesia 9		21.4		8.6		10.7		4.2		32.1		12.8		1.1		0.4		10.1		4.9		11.2		5.3
Malaysia		25.1		13.2		3.4		1.6		28.5		14.8		18.1		9.6		13.8		5.7		31.9		15.3
Australia		4.5		4.4		5.5		5.2		10.0		9.6		2.3		2.2		4.0		2.8		6.3		5.0
Vietnam		1.2		1.0		0.2		0.2		1.4		1.2		0.4		0.3		21.6		17.8		22.0		18.1
Other
Algeria		19.6		9.8		16.0		9.1		35.6		18.9		7.7		3.5		4.7		1.6		12.4		5.1
Peru		-		-		-		-		-		-		-		-		17.5		16.5		17.5		16.5
Total		380.8		335.5		128.9		112.1		509.7		447.6		118.7		102.3		200.6		177.2		319.3		279.5

25

	Proved Developed 1,2				Proved Undeveloped 1,3				Total Proved 1				Probable Developed 4,5				Probable Undeveloped 4,6				Total Probable 4
	Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8		Gross 7		Net 8
Natural Gas (bcf)
North America
Canada		1,134.7		1,011.4		362.5		343.1		1,497.2		1,354.5		349.4		310.8		201.0		187.2		550.4		498.0
United States		687.5		584.9		785.6		673.0		1,473.1		1,257.9		154.5		131.6		751.8		645.8		906.3		777.4
UK
United Kingdom		22.0		22.0		1.8		1.8		23.8		23.8		6.8		6.8		167.3		167.3		174.1		174.1
Scandinavia
Norway		73.3		73.3		6.3		6.3		79.6		79.6		28.1		28.1		45.8		45.8		73.9		73.9
Southeast Asia
Indonesia 9		1,083.1		763.7		732.1		505.5		1,815.2		1,269.2		5.3		3.4		626.6		422.8		631.9		426.2
Malaysia		281.3		187.2		66.7		38.6		348.0		225.8		104.8		68.5		171.7		97.0		276.5		165.5
Australia		-		-		-		-		-		-		-		-		-		-		-		-
Vietnam		-		-		-		-		-		-		-		-		12.0		12.0		12.0		12.0
Other
Algeria		-		-		-		-		-		-		-		-		-		-		-		-
Peru		-		-		-		-		-		-		-		-		-		-		-		-
Total		3,281.9		2,642.5		1,955.0		1,568.3		5,236.9		4,210.8		648.9		549.2		1,976.2		1,577.9		2,625.1		2,127.1

Notes:

1. "Proved" reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

2. "Proved Developed" reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional oil and gas expected to be obtained through installed extraction equipment and infrastructure operational at the time of the reserves estimate are included as proved developed reserves.

3. "Proved Undeveloped" reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

4. "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Probable reserves can be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Includes reserves assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.

5. "Probable Developed" reserves are those reserves that are less certain to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional oil and gas expected to be obtained through installed extraction equipment and infrastructure operational at the time of the reserves estimate are included as probable developed reserves.

6. "Probable Undeveloped" reserves are those reserves that are less certain to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion.

7. "Gross" reserves refer to the sum of (i) working interest reserves before deduction of royalty burdens payable, and (ii) royalty interest reserves. The Canadian Oil and Gas Evaluation Handbook ("COGEH") refers to this sum of reserves as "Company interest reserves". Royalty interest reserves for Canada were approximately 0.7 mmboe (proved) and 0.2 mmboe (probable) as at December 31, 2010. The inclusion of royalty interest volumes in gross reserves does not conform to COGEH standards applicable under NI 51-101.

8. "Net" reserves are the remaining reserves of Talisman, after deduction of estimated royalty burdens and including royalty interests in the amount set out in note 7 above.

9. Interests of various governments, other than working interests or income taxes, are accounted for as royalties. Royalties are reflected in "net" reserves using effective rates over the life of the contract.

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