EX-99.1 2 a2207664zex-99_1.htm EX-99.1
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Exhibit 99.1

SAFE PROFITABLE GROWTH TALISMAN ENERGY 2011 ANNUAL REPORT

B TALISMAN ENERGY ANNUAL REPORT 2011 03 President’s Message 07 Our Strategy Explained 08 Growth 10 Renewal 11 Base 13 Management’s Discussion and Analysis 61 Consolidated Financial Statements and Notes 127 Supplementary Oil and Gas Information 135 Additional Information 142 Detailed Property Reviews 145 Corporate Governance 146 Investor Information 147 Corporate Information 150 Market Information 151 Advisories ) ABOUT OUR COMPANY 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.

01 TALISMAN ENERGY ANNUAL REPORT 2011 The objective of Talisman’s business strategy is to deliver safe profitable growth. The strategy is designed to deliver 5–10% production growth through the medium term and to lead to the long-term renewal of the company. $3.4 billion CASH FLOW 1 up 16% year over year. $776million NET INCOME down 18% due to higher DD&A, lower gains on asset sales, and higher operating expenses and taxes 426 thousand boe/d PRODUCTION an increase in underlying production of 9% over the previous year 47 percent PERSONAL SAFETY IMPROVEMENT 72% lower than our 2008 lost-time injury frequency number • Earnings from operations1 increased 9% year over year, to $604 million. • Proved reserves replacement was 157%, at a cost of less than $20/boe. The company’s three-year replacement cost trend continues to improve. • Shale volumes in North America more than doubled year over year, to 500 mmcfe/d. • The company commenced drilling in the Duvernay shale play in Alberta. • The non-operated Kitan project in Australia was commissioned and started producing oil in October. • The company drilled a successful well in Papua New Guinea at year-end as part of its gas aggregation strategy and continues its active drilling program in Colombia. 1 Non-GAAP measures. See advisories on page 151. 2011 HIGHLIGHTS

(millions of US$ unless otherwise stated) 2011 2010 Cash flow 1 3,434 2,954 Net income 776 945 Earnings from operations 1 604 552 Per common share Cash flow ($) 1 3.36 2.90 Net income ($) 0.76 0.93 Earnings from operations ($) 1 0.59 0.54 Oil and liquids production (mbbls/d) 2 178 189 Gas production (mmcf/d) 2 1,491 1,367 Total production (mboe/d) 2,3 426 417 Production from assets sold (mboe/d) – 27 Production from ongoing operations (mboe/d) 2,3 426 390 2011 FINANCIAL AND OPERATING HIGHLIGHTS This annual report is dated March 5, 2012. Talisman encourages stakeholders to read the company’s Corporate Responsibility report, which can be obtained from the company or viewed online at www.talisman-energy.com. Readers are referred to the advisories, definitions and abbreviations at the back of this annual report. Our business strategy has proven resilient to changes in the external environment. For 2012, the diversity of our portfolio gives us the ability to redirect capital towards higher-value liquids opportunities. 1 Non-GAAP measures. See advisories on page 151. 2 Production numbers are before royalties unless otherwise stated. 3 Six mcf of natural gas equals one boe. 426,000 boe/d Talisman’s aggregate production for the year ended December 31, 2011

OUR PORTFOLIO 2011 PRODUCTION 426 MBOE/D Our portfolio includes three categories of assets: GROWTH NORTH AMERICAN SHALE AND SOUTHEAST ASIA Medium-term growth RENEWAL SOUTHEAST ASIA AND LATIN AMERICA Long-term renewal through exploration BASE NORTH AMERICAN CONVENTIONAL AND NORTH SEA Steady production to generate cash 45% and 45% is natural gas 55% Approximately 55% of the company’s production is liquids and oil-linked gas 42% LIQUIDS 26% GAS 19% SHALE GAS 13% OIL LINKED GAS

02 TALISMAN ENERGY ANNUAL REPORT 2011 We are well positioned for the future as a result of the talent and efforts of our people. )

03 TALISMAN ENERGY ANNUAL REPORT 2011 The company has sold over $5 billion in higher-cost conventional assets, and has created a platform for growth in both Southeast Asia and the shale business in North America. Our exploration portfolio continues to evolve, with early signs of success in Colombia and Papua New Guinea offering substantial opportunities for resource renewal. Oil prices remained strong, but the UK government imposed a significant tax hike early in the year and North American gas prices fell by a third over the course of 2011, reaching levels not seen in a decade. We continue to optimize our portfolio in light of changing external circumstances, and benefit from the diversity of the portfolio providing options as gas and oil prices move. Despite some operational disappointments in the North Sea during 2011, we made significant progress in a number of areas. Our first priority is safe operations, and we continue to make substantial progress. We improved our performance by 47% last year and 72% over the past three years, as measured by the frequency of lost-time incidents. One injury is still too many, and we will continue our efforts in this area, but I am pleased with this ongoing improvement. We delivered 9% underlying production growth in 2011 on top of 7% growth in 2010. Cash flow increased 16% year over year and 25% compared to the fourth quarter of 2010, due to higher oil prices. We replaced 157% of proved reserves at a cost of less than $20/boe, and our three-year replacement cost trend continues to improve. Talisman doubled its shale production in North America to 500 mmcfe/d in 2011. We have also ramped up our activity in the liquids-rich Eagle Ford play in Texas and acquired a material land position in the Duvernay shale in Alberta. We will test the potential of the Duvernay this year. We also set a new gas production record in Southeast Asia, averaging over 500 mmcf/d for the year. The majority of our natural gas sales here are tied to liquids, with prices averaging $9.30/mcf in 2011. Growth in the region is expected to average 8% per year over the next few years. Our acquisition in Colombia is proving to be very successful. We drilled two development wells in the Piedemonte region, and expect to sanction a development program for that area this year to build on existing production from the block. We are encouraged by our exploration program, with stratigraphic wells in Block 6 and the long-term flow test of a well in Block 9. We have also drilled a number of successful wells in Papua New Guinea and brought in Mitsubishi Corporation (MC) as a strategic partner, which provides ongoing confidence in our gas aggregation strategy for the country. And finally, in the Kurdistan Region of northern Iraq, a recent well has confirmed a significant gas condensate discovery. PRESIDENT’S MESSAGE In 2011 Talisman continued on the journey we started in 2008, when we set out a new strategic direction. Over a relatively short period of time, we have made substantial progress and major changes to the portfolio. John A. Manzoni President and CEO “Safety is our top priority. It is paramount to our business that we create a work environment that is incident-free, where we do no harm and workers are not exposed to hazards.”

04 TALISMAN ENERGY ANNUAL REPORT 2011 As we move into 2012, our expectation is that North American natural gas prices will remain low for most of this year, but that oil will be underpinned at $85/bbl or higher. Our portfolio offers flexibility to adjust to external conditions, which are likely to be volatile. Our plan for the year has three main elements: reduced exploration and development spending, reallocating capital to liquids and continuing to focus the portfolio. We will spend approximately $4 billion during the year on exploration and development activities. Within this program, 80% will be directed at liquids, including liquids-linked gas, or liquids rich opportunities. We will direct significant new amounts of funding to the liquids-rich Eagle Ford and Duvernay shale plays and to exploration and appraisal drilling in Colombia. We will continue to focus the portfolio, looking to reduce our exposure in the North Sea and to sell additional non-core assets in North America. Talisman is reducing exploration spending this year and will focus on Southeast Asia and Colombia. We will also look to exit or monetize a number of exploration areas as we review the results of our drilling activity over the course of the next 12 months. While we continue to upgrade the portfolio to support our strategy of safe profitable growth, our focus in 2012 will be profitability over headline growth. We will not continue to invest in unprofitable dry gas, and will vary our investment patterns depending on the dynamics of the gas prices through the year. Over the medium term, our portfolio can deliver 5 – 10% annual production growth sustainably. I would like to thank our Board of Directors for their continued guidance, especially our Chairman, Chuck Williamson. Most of all, I would like to thank our employees for their hard work, dedication and contributions during the year. Their commitment and talent are what make Talisman a great place to work, and I am grateful for their loyalty and support. John A. Manzoni President and Chief Executive Officer Talisman Energy Inc. Our priorities for 2012 are profitability versus headline production growth, and preserving our balance sheet. WE CONTINUE TO UPGRADE THE PORTFOLIO SAFETY Our goal is to create working conditions where we cause no harm to people PASSION We inspire others by the passion we demonstrate for our work RESULTS We have a bias for results and take initiative to get things done efficiently, creating value for our shareholders RESPECT We take time to consider and appreciate other people’s points of view, and treat the environment with respect EXCELLENCE We strive for excellence in what we do and how we do it TEAMWORK By working effectively together, we can deliver results far beyond our individual capabilities HONEST COMMUNICATION We show courage to speak honestly and support others to do the same OUR VALUES

CORPORATE RESPONSIBILITY Working in underexplored parts of the world can present challenges as we enter into markets not accustomed to oil and gas development. We recognize our activities impact local communities and the environment surrounding our operations. We respect local customs and traditions and are committed to minimizing disruption and impact to the environment. We understand that how we conduct our business is crucial to maintaining our licence to operate. Talisman is committed to conducting business in a socially and environmentally responsible fashion, and we report on the impact of our operations annually. Our 2011 Corporate Responsibility Report will be available in June. Previous reports are available at www.talisman-energy.com. OUR PEOPLE To meet our business needs today and in the future, Talisman’s guiding principle for resourcing is to find the best possible candidate and employment relationship for each position. We believe career development is important to attract and retain talent. It’s a shared accountability between the employee and the organization – an investment with expected returns in improved individual and organizational knowledge, ability and performance. We also want to ensure that Talisman is a great company to work for. That’s why our values are such an important part of our culture. Talisman was built on a foundation of strong values that are fundamental to the relationships that exist between our 3,700 global employees and in the communities where we operate. Living these values across all our operations will support Talisman’s continued success, both as a company and as an employer. SAFETY Our goal is to create a working environment where we cause no harm to people and minimize our impact on the environment. To achieve this we will: • Operate our business to ensure proactive risk mitigation and continuous improvement; • Set goals and targets, and measure performance against them; • Hold ourselves and our contractors accountable to meet Talisman standards; and • Communicate openly with those who may be affected by our activities. Safe operations is a core value. If operational results and safety ever come into conflict, we all have a responsibility to choose safety over operational results. Talisman will support that choice. 05 TALISMAN ENERGY ANNUAL REPORT 2011

50% We have reduced replacement costs by 50% over the last three years, improving our long-term profitability. In 2011, our reserves replacement cost was less than $20/boe, with costs in North America less than $10/boe. We replaced 157% of production with proved reserves last year. In 2011, oil prices remained high and helped drive annual cash flow up by 16%. The company grew underlying production by 9% with record shale volumes, two new projects in Southeast Asia and production from Colombia. Our three-year replacement cost trend continued to improve, and we made significant progress in our safety statistics. However, our own delivery, particularly in the North Sea, fell short of expectations. We saw a significant tax increase in the UK. And in North America, natural gas prices fell by a third, ending the year below $3. As a result, we have shifted our capital spending focus for the year ahead. In 2012, we will reduce exploration and development spending and redirect capital to more profitable liquids-rich opportunities. We expect to see liquids volumes grow at more than double the rate of natural gas volumes over the next few years. We are also looking to focus our portfolio by divesting some non-core assets in North America, reducing our exposure in the North Sea, and exiting some exploration areas over the course of the next 12 months. We will adapt our plans to accommodate changes in the external environment. The diversity of our portfolio enables us to deliver 5 – 10 % growth per year over the medium term. 06 TALISMAN ENERGY ANNUAL REPORT 2011

07 TALISMAN ENERGY ANNUAL REPORT 2011 The opportunity for Talisman and the energy industry as a whole is to find economic new sources of oil and natural gas and to develop them safely and responsibly. To this end, Talisman continues to optimize production from existing conventional reservoirs, use new technology to exploit unconventional reservoirs, drill in underexplored basins (including deepwater), and evaluate business opportunities further along the value chain, such as GTL or LNG. Talisman’s balanced portfolio allows us options to adjust our focus as external conditions change. In 2012, given the natural gas price environment, we are redirecting capital to higher value liquids-rich opportunities. Our business strategy of safe profitable growth remains unchanged. The following pages explain how our three categories of assets will help us deliver that growth. GROWTH will come from both Southeast Asia and shale plays in North America, with a near-term focus on liquids-rich opportunities. The company has substantial running room in the shale business, and Southeast Asia is expected to deliver growth of approximately 8% per year over the medium term. To ensure long-term RENEWAL of the company, Talisman’s international exploration program is focusing on identifying and developing new core areas to provide future engines of growth. In Colombia, for example, we are in the process of moving two oilfields from the evaluation phase into commerciality. In Papua New Guinea, we will continue with our strategy of proving up material natural gas volumes. The BASE is comprised of conventional assets in North America and the North Sea. The primary purpose of our investment in these assets is to maintain the integrity of the assets and sustain steady production that will generate cash for reinvestment elsewhere in the business. OUR PORTFOLIO INCLUDES THREE CATEGORIES OF ASSETS: RENEWAL GROWTH BASE OUR STRATEGY EXPLAINED Predictions are for global energy demand to increase more than 50% over the next two decades. Demand for natural gas is expected to grow faster than oil and liquids, although petroleum and other liquid fuels will remain the largest energy source worldwide.* Talisman is in business to help provide some of this energy – and, in doing so, to create value for our shareholders. * International Energy Outlook 2011, US Energy Information Administration.

08 TALISMAN ENERGY ANNUAL REPORT 2011 2011 ACCOMPLISHMENTS 2012 PLANS GROWTH MARCELLUS More than doubled production over 2010 MONTNEY Completed two strategic transactions with Sasol Limited EAGLE FORD Production averaged 31 mmcfe/d, up from 5 mmcfe/d in 2010 DUVERNAY Acquired additional acreage in the Duvernay, bringing our land position to approximately 360,000 net acres Shale spending expected to be between $1.3 billion and $1.5 billion Shale portfolio will produce 105,000 – 110,000 boe/d (630 – 660 mmcfe/d) MARCELLUS Hold production relatively flat, depending on gas prices MONTNEY Moving to a four-rig program in Farrell Creek EAGLE FORD Budget of ~$500 million; expect to double production DUvERNAY Continue the pilot program 80 percent of our investment in 2012 will be directed towards liquids-rich opportunities NORTH AMERICAN SHALE Talisman has material positions in a number of top-tier shale plays in North America. We are one of the largest players in the Pennsylvania Marcellus – a low-cost, dry-gas play with significant potential. We are also continuing to evaluate and drill the thick and prolific British Columbia Montney shale. And we are investing significant capital into the liquids-rich Eagle Ford in Texas and piloting Alberta’s Duvernay shale play. With almost 2 million net acres of shale acreage, we have plenty of running room for the future. Shale now accounts for the majority of Talisman’s North American gas production and helps underpin long-term sustainability for the company. SOUTHEAST ASIA NORTH AMERICAN SHALE

09 TALISMAN ENERGY ANNUAL REPORT 2011 SOUTHEAST ASIA Our Southeast Asia portfolio continues to deliver according to plan and remains a self-funded growth area. Talisman expects production to grow at an average of approximately 8% per year through the medium term. Regional demand for electricity generation makes Southeast Asia one of the world’s fastest growing natural gas markets, with gas prices expected to remain relatively high compared to North America for the foreseeable future. The majority of our gas production here is linked to liquids prices. In 2011, the region achieved record levels of gas sales combined with an average realized price above $9/mcf. These factors, together with high average netbacks, provide strong growth opportunities for the company. 60,000boe/d 2011 production from Corridor in Indonesia, the highest level since the asset has been in operation 2011 ACCOMPLISHMENTS 2012 PLANS Overall production was 119,000 boe/d MALAYSIA Optimization initiatives at PM-3 CAA, along with infill drilling, resulted in an increase of 15% in gas sales volumes year over year VIETNAM The Hai Su Trang/Hai Su Den (HST/HSD) project was sanctioned INDONESIA Ongoing facilities development success at Corridor continues to secure gas volumes for long-term supply contracts JAMBI MERANG (Indonesia) and KITAN (Timor-Leste/Australia) Successfully commissioned on time and on budget Southeast Asia production expected to be over 120,000 boe/d, with a full year of Jambi Merang and Kitan production Capital spending expected to be between $600 million and $700 million, including exploration MALAYSIA Ongoing infill drilling program in PM-3 CAA VIETNAM Focus on the HST/HSD development project; first oil expected in the second half of 2013 INDONESIA Corridor field will see additional facilities projects for capacity expansions and additional compression

10 TALISMAN ENERGY ANNUAL REPORT 2011 RENEWAL The goal of the renewal component of our strategy is to add 600 million to 700 million boe of contingent resources on a five-year basis at a cost of $5 a barrel or less. Over the past several years, we have increased our position in areas that have significant resource potential and low finding costs. We will continue to high grade the exploration portfolio by seeking new organic options and rationalizing others at an earlier stage in the cycle. We expect 2012 will be an important year for exploration results. $9.30/mcf 2011 natural gas price average in Southeast Asia 2011 ACCOMPLISHMENTS 2012 PLANS PNG Drilled several successful wells in support of our gas aggregation strategy COLOMBIA Completed acquisition of 49% of BP Colombia, now renamed Equion Energia, which added 13,400 boe/d of production in 2011 Niscota Started drilling an appraisal well on the Huron discovery in the foothills Block 9 The Akacias discovery well was placed on a long-term test and has produced over 325,000 boe Block 6 Finished the initial six-well stratigraphic program, which confirmed the existence of hydrocarbons VIETNAM Production sharing contract was signed in Nam Con Son Basin KURDISTAN Drilled a significant gas/gas condensate discovery (Topkhana-1 well) Drilling a number of wells over year-end, including the Situche Norte-4X well in Peru, the Kurdamir-2 well in Kurdistan Region of northern Iraq, and the second well of a three-well exploration program in Poland Capital spending expected to be ~$600 million Exploration and appraisal wells in Peru, Kurdistan, Poland, Vietnam, Malaysia and the North Sea PNG As part of the gas aggregation strategy, Talisman has brought in a strategic partner • Drill two appraisal wells, in addition to a successful exploration gas well already drilled over year-end • Complete drilling of the exploration well (Weimang-1) • Continue seismic acquisition across various blocks with a view to identifying suitable drilling prospects for subsequent years COLOMBIA A principal focus is Colombia, where production is expected to be 15,000 – 16,000 boe/d and where we are progressing two fields to commercial development (Block 9 and Block 6) Piedemonte Piedemonte area expansion project underway Niscota Finish drilling the Huron 2 appraisal well and spud the Huron 3 appraisal well Block 9 Continue to appraise the Akacias discovery Block 6 Complete the second six-well stratigraphic appraisal drilling program LATIN AMERICA SOUTHEAST ASIA

11 TALISMAN ENERGY ANNUAL REPORT 2011 NORTH AMERICAN CONVENTIONAL We continue to review our North American conventional portfolio as some assets are non-core to Talisman and can be sold. In other areas, we will seek to use third-party expertise or resources to accelerate activity and optimize value. We are also looking at ways to extract maximum value from existing assets. The result will be a stronger, more sustainable base with a higher percentage of profitable liquids opportunities. NORTH SEA Most of our production in the region is liquids. We will continue to invest in this business to maintain the integrity of a mature set of assets and to improve operational efficiency in order to sustain steady production. But we will also seek to reduce our exposure to this mature and relatively volatile business over time. BASE 2011 ACCOMPLISHMENTS 2011 ACCOMPLISHMENTS 2012 PLANS 2012 PLANS Production averaged 90,000 boe/d (23% liquids), with exploration and development spending of $400 million Drilled 124 net wells Production averaged 106,000 boe/d, with $1.2 billion of spending focused on developments at Auk South and Auk North and the Claymore replacement compressor in the UK, and on Yme in Norway Spending expected to range between $300 million and $350 million Production expected to be 80,000 boe/d, of which 25% will be liquids Roughly one-third of spending targeted towards liquids-rich Wild River play Cash capital spending expected to be $1.2 billion $600million cash generated by North Sea for reinvestment elsewhere in the business NORTH AMERICAN CONVENTIONAL NORTH SEA

FINANCIAL PERFORMANCE Management’s Discussion and Analysis 13 Company Overview 14 Strategy 14 2011 Performance Highlights 15 Financial and Operating Highlights 15 2011 Net Income Variances 16 Operations Review 17 Asset Disposals 25 Acquisitions 26 Reserves Replacement 26 Liquidity and Capital Resources 27 Sensitivities 29 Commitments and Off-Balance Sheet Arrangements 30 Transactions with Related Parties 31 Risk Management 31 Summary of Quarterly Results 33 Outlook for 2012 34 Internal Control over Financial Reporting and Disclosure Controls and Procedures 35 Litigation 36 Application of Critical Accounting Policies and Use of Estimates 37 IFRS First-Time Adoption 41 Impact of IFRS Adoption on Accounting Policies and Estimates 43 Other Accounting Changes 45 Regulatory Developments 46 Risk Factors 46 Advisories 57 Abbreviations and Definitions 59 Report of Management 61 Management Report on Internal Control over Financial Reporting 61 Independent Auditors’ Report on Internal Controls Under Standards of the Public Company Accounting Oversight Board (United States) 62 Independent Auditors’ Report of Registered Public Accounting Firm 63 Consolidated Balance Sheets 64 Consolidated Statements of Income 65 Consolidated Statements of Comprehensive Income 66 Consolidated Statements of Changes in Shareholders’ Equity 67 Consolidated Statements of Cash Flows 68 Notes to the Consolidated Financial Statements 69 Supplementary Oil and Gas Information 127 Results of Operations from Oil and Gas Producing Activities 127 Capitalized Costs Relating to Oil and Gas Activities 128 Costs Incurred in Oil and Gas Activities 129 Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves 130 Discounted Future Net Cash Flows from Proved Reserves 132 Principal Sources of Changes in Discounted Cash Flows 133 Continuity of Net Proved Reserves 133 Additional Information 135 Consolidated Financial Ratios 135 Ratios and Key Indicators 135 Historical Operations Summary 136 Net Production – After Royalties 136 Product Netbacks – After Royalties 137 Historical Gross Proved Reserves 139 Continuity of Gross Proved Reserves 140 Detailed Property Reviews 142 2011 Acreage 142 2011 Drilling 143 Five Year Drilling Results 144 Corporate Governance 145 Investor Information 146 Corporate Information 147 Market Information 150 Advisories 151 12 TALISMAN ENERGY ANNUAL REPORT 2011

Management's Discussion and Analysis (MD&A)

(March 5, 2012)

General

This Management's Discussion and Analysis (MD&A) should be read in conjunction with the Consolidated Financial Statements of Talisman Energy Inc. (Talisman or the Company) for the year ended December 31, 2011. The Company's Consolidated Financial Statements and the financial data included in this MD&A have been prepared in accordance with International Financial Reporting Standards (IFRS), unless otherwise noted.

Unless otherwise stated, references to production and reserves represent Talisman's working interest share (including Talisman's share of volumes of royalty interest) before deduction of royalties. Throughout this MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas to one barrel (bbl) of oil. The boe measure may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalence at the wellhead.

All comparisons are between the years ended December 31, 2011 and 2010, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this MD&A are listed in the section 'Abbreviations and Definitions'.

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

Adoption of International Financial Reporting Standards (IFRS)

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

Note 4 to the Consolidated Financial Statements contains a detailed description of the Company's adoption of IFRS, including a reconciliation of the Consolidated Financial Statements previously prepared under Canadian generally accepted accounting principles (GAAP) to those under IFRS for the following:

•: Consolidated Balance Sheets at January 1, 2010 and at December 31, 2010;
•: Consolidated Statements of Income, Comprehensive Income (Loss) and Cash Flows for the year ended December 31, 2010; and
•: Consolidated Statements of Shareholders' Equity at January 1, 2010 and December 31, 2010.

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

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

Change in Reporting Conventions

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

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

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TALISMAN ENERGY ANNUAL REPORT 2011

COMPANY OVERVIEW

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's common shares are listed on the Toronto and New York stock exchanges under the symbol TLM.

Unless the context indicates otherwise, references in this MD&A to 'Talisman' or 'the Company' include, for reporting purposes only, the direct or indirect subsidiaries of Talisman Energy Inc. and partnership interests held by Talisman Energy Inc. and its subsidiaries. Such use of 'Talisman' or 'the Company' to refer to these other legal entities and partnership interests does not constitute a waiver by Talisman Energy Inc. or such entities or partnerships of their separate legal status, for any purpose.

Talisman's financial statements are prepared on a consolidated basis and include the accounts of Talisman and its subsidiaries. Substantially all of Talisman's activities are conducted jointly with others, and the Consolidated Financial Statements reflect only the Company's proportionate interest in such activities.

Note 31 to the Consolidated Financial Statements provides segmented financial information that forms the basis for much of the following discussion and analysis. In 2011, Talisman's activities were conducted in four geographic segments for the purposes of financial reporting: North America, North Sea, Southeast Asia and Other. The North America segment includes operations in Canada and the US. The North Sea segment includes operations and exploration activities in the UK and Norway. The Southeast Asia segment includes operations and exploration activities in Indonesia, Malaysia, Vietnam and Papua New Guinea and operations in Australia/Timor-Leste. The Company also conducts operations in Algeria, operations and exploration activities in Colombia, and exploration activities in Peru, Poland, Sierra Leone and the Kurdistan region of northern Iraq. For ease of reference, the activities in Algeria, Colombia, Peru, Poland, Sierra Leone and the Kurdistan region of northern Iraq are referred to collectively as the Other geographic segment.

STRATEGY

Safe, profitable growth is at the heart of Talisman's business strategy, which is designed to deliver 5-10% production growth through the medium term and to lead to the long-term renewal of the Company.

The portfolio includes three categories of assets:

•: Growth will come from both Southeast Asia and shale plays in North America, with a near term focus on liquids-rich opportunities. The Company has substantial growth prospects in the shale business, and Southeast Asia is expected to deliver growth of approximately 8% per year over the medium term;
•: To ensure long-term renewal of the Company, Talisman's international exploration program is focusing on identifying and developing new core areas to provide future growth. In Colombia, for example, the Company is in the process of moving two oil fields from the evaluation phase into commerciality. In Papua New Guinea, the Company will continue with its strategy of proving up material natural gas volumes; and
•: The base is comprised of conventional assets in North America and the North Sea. The primary purpose of the investment in these assets is to maintain the integrity of the assets and sustain steady production that will generate cash for reinvestment elsewhere in the business.

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TALISMAN ENERGY ANNUAL REPORT 2011

2011 PERFORMANCE HIGHLIGHTS

•: Net income was $776 million, down 18% due to higher DD&A, lower gains on asset sales, and higher operating expenses and taxes;
•: Production averaged 426,000 boe/d, an increase in underlying production of 9% over the previous year;
•: Proved reserves replacement was 157%. The Company's three-year replacement cost trend continues to improve;
•: Shale volumes in North America more than doubled year over year, to 500 mmcfe/d;
•: The Company commenced drilling in the Duvernay shale play;
•: The non-operated Kitan project was commissioned and started producing oil in October; and
•: The Company drilled a successful well in Papua New Guinea at year-end as part of its gas aggregation strategy and continues its active drilling program in Colombia.

FINANCIAL AND OPERATING HIGHLIGHTS

(millions of $, unless otherwise stated)			2011		2010		2009¹

			US$		US$		C$

Cash provided by operating activities			2,812		3,144		3,599

Cash provided by continuing operations			2,812		3,144		3,214

Net income			776		945		437

	Income (loss) from continuing operations		776		945		(658	)

	Income from discontinued operations		–		–		1,095

Common share dividends			277		249		229

Per share ($)

	Net income		0.76		0.93		0.43

	Diluted net income²		0.38		0.93		0.43

	Income (loss) from continuing operations		0.76		0.93		(0.65	)

	Income from discontinued operations		–		–		1.08

	Common share dividends	US$	0.27	C$	0.25	C$	0.23

Production (mboe/d)			426		417		425

Production from ongoing operations (mboe/d)			426		390		365

Average sales price ($/boe)			65.35		53.80		49.40

Total revenue and other income			8,272		6,982		6,061

Operating costs ($/boe)			14.17		12.44		12.91

Depreciation, depletion and amortization (DD&A) expense, exploration and dry hole expense			2,617		2,275		3,200

Total exploration and development spending			4,142		3,473		3,784

Total assets			24,226		22,094		23,618

Total long-term debt (including current portion)			4,895		4,204		3,780

Cash and cash equivalents, net of bank indebtedness			414		1,653		1,654

Total long-term liabilities			10,745		9,186		9,906

Gross proved reserves additions, net of revisions (before acquisitions and dispositions) – including price revisions (mmboe)³			251		271		251

Reserves replacement ratio (before acquisitions and dispositions) – including price revisions³			162%		178%		162%

Gross proved reserves (mmboe)³			1,488		1,383		1,411

Gross proved reserves additions, net of revisions (before acquisitions and dispositions) – excluding price revisions (mmboe)³			243		249		174

Reserves replacement ratio (before acquisitions and dispositions) – excluding price revisions³			157%		164%		112%

1: 2009 comparative figures prepared in accordance with Canadian GAAP and in Canadian dollars.
2: Diluted net income per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options.
3: Calculated pursuant to methodology prescribed by the SEC. See the 'Reserves Replacement' section of this MD&A for method of calculation.

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TALISMAN ENERGY ANNUAL REPORT 2011

2011 NET INCOME VARIANCES

(millions of $)

2010 net income	945

Favourable (unfavourable) variances¹:

Commodity prices²	2,121

Production volumes²	(157	)

Royalties²	(645	)

Operating expenses	(300	)

General and administrative (G&A) expense	(60	)

DD&A expense	(161	)

Impairment	75

Dry hole expense	(128	)

Exploration expense	(53	)

Interest on long-term debt	(2	)

Share-based payments expense/recovery	522

Gain on disposal of assets	(328	)

Gain/loss on held-for-trading financial instruments	(297	)

Current taxes (including Petroleum Revenue Tax (PRT))	(305	)

Deferred taxes (including PRT)	(338	)

Other	(113	)

Total variances	(169	)

2011 net income	776

1: Variances are before tax except for current and deferred taxes.
2: In the commentary that follows, the term 'sales' refers to the net impact of commodity prices, production volumes and royalties.

The significant variances from 2010 as summarized in the net income variances table are:

•: Higher oil and gas revenue reflecting higher commodity prices;
•: Higher volumes due principally to shale drilling in North America, the startup of new fields in Southeast Asia and the acquisition of Equión Energía Limited (Equión), offset by reduced oil and liquids production in the North Sea due to remediation work and natural decline;
•: Higher royalties primarily resulting from increased commodity prices;
•: Higher operating expenses due principally to higher maintenance costs in the North Sea and Southeast Asia, as well as the startup of new fields and the acquisition of Equión;
•: Higher DD&A expense due to higher production, the startup of new fields in Southeast Asia and the addition of DD&A expense for Colombia;
•: Higher dry hole expense, exploration wells in the North Sea and Southeast Asia being written off during 2011;
•: A share-based payments recovery, relative to an expense in 2010, as a result of changes in Talisman's share price;
•: A decrease in gain on disposal of assets, 2010 having seen an extensive disposition program of North American non-core conventional oil and gas assets;
•: A loss on commodity price derivatives driven by rising oil and liquids prices in 2011, compared to a gain in 2010;
•: Increased current taxes due principally to higher commodity prices and the UK legislative change described in the 'Income Taxes' section of this MD&A; and
•: Increased deferred taxes due principally to the UK legislative change described in the 'Income Taxes' section of this MD&A, which increased deferred taxes by $225 million.

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TALISMAN ENERGY ANNUAL REPORT 2011

OPERATIONS REVIEW

Results Summary

Sales of oil, liquids and natural gas in 2011 were $8.2 billion, an increase of 19% from 2010. Oil and liquids revenue increased by $1.1 billion due to higher prices. Natural gas revenue increased by $222 million as increased production was partially offset by lower prices.

In North America, production growth of 13% was offset by lower gas prices resulting in relatively flat sales. While sales were relatively constant, DD&A was higher due to production increases and operating costs declined year-over-year as a result of the transition to shale production.

In the North Sea, sales increased by 16%, the benefit of higher oil and liquids prices being partially offset by lower production. Operating expenses increased as a result of higher maintenance costs.

In Southeast Asia, sales of $1.9 billion were 28% higher than 2010 due principally to higher pricing for both liquids and natural gas. Operating expenses, DD&A and exploration expense increased year-over-year.

Activity in the rest of the world increased following the completion of the acquisition of a 49% interest in Equión in January 2011.

Daily Average Production


		Gross before royalties		Net of royalties
		2011	2010	2011	2010

Oil and liquids (mbbls/d)

	North America	23	23	19	18

	North Sea	98	113	97	113

	Southeast Asia	34	39	17	22

	Other	23	14	13	7

		178	189	146	160

Natural gas (mmcf/d)

	North America	899	778	803	718

	North Sea	52	104	52	104

	Southeast Asia	506	485	351	339

	Other	34	–	27	–

		1,491	1,367	1,233	1,161

Total Daily Production (mboe/d)

	North America	173	153	153	137

	North Sea	106	131	106	131

	Southeast Asia	119	119	75	78

	Other	28	14	17	7

Total (mboe/d)		426	417	351	353

Assets sold

	North America	–	27	–	24

From ongoing operations (mboe/d)		426	390	351	329

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

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TALISMAN ENERGY ANNUAL REPORT 2011

Production from ongoing operations increased by 9% over the previous year due principally to increased gas volumes in North America and Southeast Asia, and additional liquids volumes from Colombia as a result of the Equión acquisition in January 2011, partially offset by lower North Sea production. Total production increased by 2% in 2011.

In North America, production from ongoing operations increased by 37%. Natural gas production increased by 41% due principally to successful shale development in the Pennsylvania Marcellus and Montney, where production during the year averaged 413 mmcf/d and 55 mmcf/d, respectively. In the Eagle Ford, production averaged 31 mmcfe/d, of which 2 mboe/d was from liquids.

Production in the North Sea decreased 19% versus a year ago. Reduced natural gas and liquids production in Norway accounts for the majority of the decrease. Although Rev completed its annual turnaround successfully, mechanical issues associated with the maintenance of the gas export line from the host platform delayed the restart of production until the end of the third quarter. In the UK, a full year of production from Auk North and increased operational efficiency at Auk South were offset by natural decline and extended shutdowns for safety-related upgrades. Production from the Tartan platform, which was shut down during the fourth quarter of 2011, is expected to restart in the first quarter of 2012.

In Southeast Asia, natural gas production increased by 4% due principally to better production efficiency at PM-3 CAA and the startup of Jambi Merang in April 2011. Oil and liquids production decreased due principally to natural declines, partially offset by the startup of Kitan in October 2011.

In December 2011, the Suban field within the Corridor Production Sharing Contract (PSC) was unitized with the adjacent Suban Barat PSC in which the Company has no interest, reducing Talisman's interest from 36% to 32.4%. The impact of this unitization is that production is expected to be reduced by approximately 4,500 boe/d until the end of the PSC in 2023.

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

Volumes Produced Into (Sold Out of) Inventory¹

	2011		2010

North Sea – bbls/d	(687	)	(174	)

Southeast Asia – bbls/d	960		108

Other – bbls/d	400		237

Total produced into inventory – bbls/d	673		171

Total produced into inventory – mmbbls	0.2		0.1

Inventory at December 31 – mmbbls	1.9		1.6

1: Gross before royalties.

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

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TALISMAN ENERGY ANNUAL REPORT 2011

Company Netbacks¹

		Gross before royalties		Net of royalties
		2011	2010	2011	2010

Oil and liquids ($/bbl)

	Sales price	107.04	78.19	107.04	78.19

	Royalties	19.69	12.00	–	–

	Transportation	1.29	1.15	1.58	1.35

	Operating costs	25.72	20.10	31.49	23.74

		60.34	44.94	73.97	53.10

Natural gas ($/mcf)

	Sales price	5.92	5.59	5.92	5.59

	Royalties	1.24	0.93	–	–

	Transportation	0.24	0.28	0.31	0.34

	Operating costs	0.98	1.02	1.24	1.22

		3.46	3.36	4.37	4.03

Total $/boe (6mcf=1boe)

	Sales price	65.35	53.80	65.35	53.80

	Royalties	12.54	8.49	–	–

	Transportation	1.39	1.45	1.72	1.73

	Operating costs	14.17	12.44	17.68	14.81

		37.25	31.42	45.95	37.26

1: Netbacks do not include pipeline operations.

During 2011, the Company's average gross netback was $37.25/boe, 19% higher than in 2010. Talisman's realized net price of $65.35/boe was 21% higher than 2010, due principally to higher global oil and liquids prices and Southeast Asia gas prices, the majority of which is linked to liquids prices.

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

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TALISMAN ENERGY ANNUAL REPORT 2011

Commodity Prices and Exchange Rates

		2011	2010

Oil and liquids ($/bbl)

	North America	75.19	62.59

	North Sea	110.75	80.13

	Southeast Asia	115.82	80.54

	Other	110.32	82.69

		107.04	78.19

Natural gas ($/mcf)

	North America	3.93	4.79

	North Sea	8.62	6.35

	Southeast Asia	9.30	6.72

	Other	4.22	–

		5.92	5.59

Company $/boe (6mcf=1boe)		65.35	53.80

Benchmark prices and foreign exchange rates

	WTI ($/bbl)	95.13	79.53

	Dated Brent ($/bbl)	111.27	79.47

	Tapis ($/bbl)	117.11	80.81

	NYMEX ($/mmbtu)	4.07	4.39

	AECO (C$/gj)	3.48	3.82

C$/US$ exchange rate		0.99	1.03

UK£/US$ exchange rate		0.62	0.65

Talisman's realized oil and liquids prices increased by 37%, consistent with the movement in the benchmark price in the Company's primary oil and gas-producing regions. North America natural gas prices decreased by 18%, due to lower benchmark prices and the expiry of the physical commodity contracts which increased the North American reported price by $0.68/mcf in 2010. Most of the contracts expired at the end of 2010. Corridor gas prices averaged $10.06/mcf, where 60% of sales are referenced to Duri crude oil and High Sulphur Fuel Oil on an energy equivalent basis.

Royalties¹

	2011		2010
	Rate (%)	$ million	Rate (%)	$ million

North America	13	255	11	217

North Sea	1	25	–	7

Southeast Asia	40	1,236	36	834

Other	43	402	53	215

	19	1,918	16	1,273

1: Includes impact of royalties related to sales volumes.

The corporate royalty rate was 19%, up from 16% in 2010 due to higher commodity prices. In the rest of the world, the acquisition of Equión reduced the royalty rate to 43% in 2011, while the North America rate reflects higher Eagle Ford production.

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TALISMAN ENERGY ANNUAL REPORT 2011

Unit Operating Expenses¹

	Gross before royalties		Net of royalties
($/boe)	2011	2010	2011	2010

North America	7.11	8.65	8.04	9.59

North Sea	33.60	22.91	33.79	22.95

Southeast Asia	8.78	6.67	13.82	10.14

Other	7.07	5.37	11.65	11.39

	14.17	12.44	17.68	14.81

1: Includes impact of production volumes.

Total Operating Expenses

(millions of $)	2011	2010

North America	454	487

North Sea	1,292	1,096

Southeast Asia	372	280

Other	72	27

	2,190	1,890

Total operating expenses increased by $300 million due to higher maintenance costs, the startup of new fields and the acquisition of Equión.

In North America, operating expenses decreased due to the sale of high cost conventional assets in 2010. In the North Sea, operating expenses were higher due to increased maintenance and the weakening of the US$. In Southeast Asia, operating expenses increased due to the startup of the Jambi Merang and Kitan fields and higher well intervention and maintenance costs at PM-3 CAA. The increase in the rest of the world was due to the acquisition of Equión in Colombia.

Unit operating expenses for the Company increased to $14.17/boe due to the reasons noted above.

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

	Gross before royalties		Net of royalties
($/boe)	2011	2010	2011	2010

North America	13.50	12.85	15.26	14.24

North Sea	17.21	16.08	17.31	16.11

Southeast Asia	7.10	6.37	11.22	9.69

Other	11.82	5.53	20.92	11.97

	12.55	11.76	15.28	13.88

Total DD&A Expense

(millions of $)	2011	2010

North America	852	717

North Sea	671	766

Southeast Asia	305	277

Other	121	28

	1,949	1,788

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TALISMAN ENERGY ANNUAL REPORT 2011

Total DD&A expense was $2 billion, up 9% from 2010 as a result of higher production volumes in North America, the acquisition of Equión and the startup of a number of fields, partially offset by lower North Sea production.

The DD&A expense in North America increased due to higher shale gas volumes. The DD&A expense in the North Sea decreased due principally to lower production volumes, partially offset by the startup of the Auk North field in November 2010 and higher rates at various fields due to reserve revisions at the end of 2010. In Southeast Asia, the increase was due principally to the startup of Jambi Merang and Kitan. The DD&A expense in the rest of the world increased due to the additional production from Equión.

Unit DD&A expense was impacted by the same factors as noted above with the overall unit DD&A increasing 7% to $12.55/boe.

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

Impairment

(millions of $)		2011	2010

Impairment losses

	North America	129	116

	North Sea	231	164

	Southeast Asia	–	21

	Other	–	–

		360	301

Impairment reversals

	North America	–	–

	North Sea	118	–

	Southeast Asia	16	–

	Other	–	–

		134	–

Net impairment		226	301

During 2011, the Company recorded an impairment expense of $129 million in North America due principally to reduced third party tariffs in the Company's midstream operations and lower conventional natural gas reserves.

Of the $231 million of impairments recorded in the North Sea, $102 million was a result of the change in legislation announced by the UK government in March 2011 described in the 'Income Taxes' section of this MD&A, and $129 million arose due to a reduction in year-end reserves in a field in Norway. An impairment reversal of $118 million was recorded as a result of an increase in year-end reserves in a field in the UK.

An impairment reversal of $16 million in Southeast Asia resulted from an increase in year-end reserves and higher oil prices.

The Yme project in Norway has experienced significant delays and cost overruns. The project is subject to arbitration with the contractor. Management has assessed the project's recoverability based on a range of possible startup dates, arbitration outcomes and completion costs. No impairment writedown of the Yme project was recorded during the year ended December 31, 2011. Management will continue to assess the project's recoverability as new information becomes available. The net carrying value of Yme is approximately $800 million. The net after tax exposure is significantly less than the net carrying value of the project.

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TALISMAN ENERGY ANNUAL REPORT 2011

Dry Hole Expense

(millions of $)	2011	2010

North America	6	(11	)

North Sea	106	70

Southeast Asia	127	31

Other	2	23

	241	113

Dry hole expense includes the write off of unsuccessful exploration wells in the UK, Norway, Indonesia and Papua New Guinea.

Exploration Expense

(millions of $)	2011	2010

North America	70	52

North Sea	40	47

Southeast Asia	208	116

Other	109	159

	427	374

Exploration expense consists of geological and geophysical costs, seismic, non-producing land lease rentals and indirect exploration expense. These costs are expensed as incurred consistent with the successful efforts method of accounting. Exploration expense increased by $53 million relative to 2010 due principally to seismic activity in Papua New Guinea.

Corporate and Other

(millions of $)	2011		2010

G&A expense	431		371

Finance costs	278		276

Share-based payments expense (recovery)	(310	)	212

(Gain) loss on held-for-trading financial instruments	210		(87	)

Gain on asset disposals	(192	)	(520	)

Other income	78		107

Other expenses, net	161		72

G&A expense was higher due in part to the running and transition costs associated with new offices in the US and Southeast Asia and the initial costs associated with the outsourcing of certain information system functions.

Finance costs include interest on debt, other finance charges and accretion expense relating to decommissioning liabilities. The total interest expense did not increase significantly from 2010 as the increase in interest relating to the issuance of $600 million 3.75% notes in November 2010 and additional borrowings in the second half of 2011 was offset by the repayment of C$350 million 4.44% medium-term notes in January 2011.

The share-based payments recovery for the year ended December 31, 2011 was $310 million, compared to an expense of $212 million in 2010 due principally to changes in Talisman's share price.

Talisman recorded a loss on held-for-trading financial instruments of $210 million principally related to an increase in the Dated Brent price. See the 'Risk Management' section of this MD&A for further details concerning the Company's financial instruments.

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TALISMAN ENERGY ANNUAL REPORT 2011

The 2011 gain on asset disposals arose largely from the sale of a 50% working interest in the Farrell Creek and Cypress A assets to Sasol Limited (Sasol). Refer to the 'Asset Disposals' section of this MD&A. The gain in 2010 arose largely from the disposition of non-core North American conventional gas assets.

Other income includes $53 million of pipeline and processing revenue.

Other expenses includes PP&E derecognition expense, foreign exchange gains and losses, other miscellaneous expenses and a $65 million allowance for a doubtful account, which contributed to the increase in other expenses over 2010.

Income Taxes


(millions of $)		2011	2010

Income before taxes		2,445	1,971

Less: PRT

	Current	121	124

	Deferred	52	(20	)

Total PRT		173	104

		2,272	1,867

Income tax expense

	Current income tax	1,320	1,012

	Deferred income tax	176	(90	)

Income tax expense (excluding PRT)		1,496	922

Effective income tax rate (%)		66%	49%

The $574 million increase in income tax expense (excluding PRT) arises mainly from higher commodity prices, a legislative change in the UK and the revaluation of Norwegian tax pools as a result of the weakening of the NOK relative to the US$.

The effective tax rate is expressed as a percentage of income before taxes adjusted for PRT, which is deductible in determining taxable income. The Company's effective tax rate is impacted by the mix of income before taxes between high and low rate tax jurisdictions, the revaluation of tax pools denominated in foreign currencies and other non-taxable gains and losses.

Additionally, the UK government intends to restrict tax relief for decommissioning expenditures to the 20% supplementary charge rate effective from March 21, 2012. This measure could become substantively enacted in the second or third quarter of 2012, at which time deferred income tax expense would be recorded, estimated by management to be approximately $140 million.

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TALISMAN ENERGY ANNUAL REPORT 2011

Capital Expenditures


(millions of $)	2011		2010

North America	2,155		1,700

North Sea	1,205		1,117

Southeast Asia	487		442

Other	295		214

Exploration and development	4,142		3,473

Corporate, IS and Administrative	159		78

Acquisitions	1,319		1,530

Proceeds of dispositions	(569	)	(2,273	)

	5,051		2,808

North America capital expenditures for the year were $2.2 billion, of which $1.8 billion related to shale activity with the majority spent on progressing development of the Pennsylvania Marcellus, Montney and Eagle Ford programs. The remaining capital was invested in conventional oil and gas properties.

In the North Sea, capital expenditures of $1.2 billion included $1 billion spent on development projects including Auk South and Auk North in the UK, Yme in Norway and the Claymore replacement compression project in the UK. In addition, $128 million was spent on exploration activity, the majority of which occurred in Norway. A total of seven development wells, three exploration wells and three appraisal wells were drilled during 2011.

In Southeast Asia, capital expenditures of $487 million included $257 million for exploration, with the majority spent on the drilling of exploration wells in Papua New Guinea and Indonesia, and $230 million on development, with the majority spent on development drilling in Corridor and the Jambi Merang and Kitan fields. In 2011, Talisman participated in 33 successful development wells, 14 exploration wells and two appraisal wells.

Capital expenditures in other areas were $295 million, including $138 million on exploration activity in Colombia, Peru, Poland and the Kurdistan region of northern Iraq. Talisman also spent $157 million on development in Colombia and Algeria. During the year, the Company participated in one exploration well, one appraisal well and nine stratigraphic wells in Colombia, one exploration well in Peru, two exploration wells in the Kurdistan region of northern Iraq, two exploration wells in Poland and six development wells in Algeria.

Information related to details and funding of the planned 2012 capital expenditures program is included in the 'Outlook for 2012' section of this MD&A.

ASSET DISPOSALS

Sale of Farrell Creek Interests to Sasol

In March 2011, Talisman completed a transaction creating a strategic partnership with Sasol to develop the Farrell Creek assets in Talisman's Montney shale play in British Columbia. Talisman sold 50% of its working interests in the Farrell Creek assets for approximately $1 billion, comprising $238 million in cash and approximately $800 million of certain future development costs. The transaction resulted in a pre-tax gain of $89 million, which is included in 'Gain on asset disposals' on the Consolidated Statement of Income.

Sale of Cypress A Interests to Sasol

In June 2011, Talisman completed an additional transaction with Sasol to develop the Cypress A assets in Talisman's Montney shale play in British Columbia. Talisman sold 50% of its working interests in the Cypress A assets for approximately $1.1 billion, comprising $257 million in cash and approximately $800 million of certain future development costs. The

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TALISMAN ENERGY ANNUAL REPORT 2011

transaction resulted in a pre-tax gain of $113 million, which is included in 'Gain on asset disposals' on the Consolidated Statement of Income.

Asset sales completed in 2010

During 2010, Talisman completed the sale of oil and gas producing properties in North America with a carrying value of approximately $2 billion for aggregate proceeds of approximately $2.2 billion. The net investment in the Company's Canadian operations was reduced as a result of the transactions occurring in 2010 and, accordingly, $367 million of exchange gains previously accumulated in other comprehensive income were included in the gains of $520 million, which are included in 'Gain on asset disposals' on the Consolidated Statement of Income. Tax of $38 million was recorded in respect of these transactions.

ACQUISITIONS

During 2011, Talisman completed the acquisition of a 49% interest in Equión for cash consideration of $785 million, of which $613 million was paid as a deposit in 2010. Since Equión is a jointly controlled entity, the Company is proportionately consolidating its interest, which is reported in the Other segment.

Also in 2011, the Company acquired undeveloped land in the Alberta Duvernay shale play for approximately $510 million and acquired undeveloped land in the Eagle Ford shale play for approximately $145 million. This is in addition to the Eagle Ford acreage acquired in 2010 for cash consideration of $910 million.

During 2010, Talisman acquired a 25% interest in the Jambi Merang PSC for cash consideration of $183 million. The Company also acquired a 35% working interest in the PL378 Grosbeak discovery and a 20% interest in the PL375 Beta discovery in Norway for $192 million in cash, with a further cash payment of $15 million occurring in 2011.

RESERVES REPLACEMENT

Disclosure Requirements

As a Canadian public company, Talisman is subject to the oil and gas disclosure requirements of National Instrument 51-101 (NI 51-101) of the Canadian Securities Administrators. In order to provide disclosure comparable to US and international peers, Talisman also provides disclosure in accordance with the disclosure standards of the US Securities and Exchange Commission (SEC).

SEC Reserves

Talisman's gross proved reserves, compiled in accordance with the SEC disclosure requirements using average annual prices, are estimated as follows:

Gross proved reserves	Oil and liquids (mmbbls)		Natural gas (bcf)		Total (mmboe)

At December 31, 2010	509.7		5,236.9		1,382.5

Discoveries, extensions and additions	34.8		1,235.5		240.7

Acquisitions and dispositions	19.2		(58.6	)	9.5

Price revisions	12.0		(26.3	)	7.6

Other revisions	7.1		(26.2	)	2.7

Production	(64.8	)	(543.6	)	(155.4	)

At December 31, 2011	518.0		5,817.7		1,487.6

Talisman added 243.4 mmboe of gross proved reserves compared to production of 155.4 mmboe for a replacement of 157% of 2011 production (see calculation below). North America accounts for the largest increase in reserves as a result of the successful drilling programs in the Pennsylvania Marcellus, Montney and Eagle Ford shale plays. Price-related revisions

26
TALISMAN ENERGY ANNUAL REPORT 2011

increased gross proved reserves by 7.6 mmboe, principally related to the Company's North Sea operations. At December 31, 2011, North America, Southeast Asia and the North Sea accounted for 48%, 26% and 21%, respectively, of the Company's total gross proved reserves. Proved undeveloped reserves accounted for 37% of the Company total and 43% in North America at the end of 2011.

The Company uses reserves replacement ratios as an indicator of its 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, property acquisitions and average prices. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not take into account the cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.

The proved reserves replacement ratios noted above and in the 'Financial and Operating Highlights' section of this MD&A were calculated as follows:

•: 157% was calculated by dividing the sum of changes (discoveries, extensions and additions, and other revisions, before acquisitions and dispositions and excluding price revisions) to gross proved reserves during 2011 by the Company's 2011 gross production; and
•: 162% was calculated by dividing the sum of changes (discoveries, extensions and additions, price revisions and other revisions, before acquisitions and dispositions) to gross proved reserves during 2011 by the Company's 2011 gross production.

NI 51-101 Reserves

Talisman's gross proved and probable reserves at December 31, 2011, compiled in accordance with the NI 51-101 disclosure requirements using forecast prices, are estimated as follows:

Total gross	Light Oil (mmbbls)	Heavy Oil (mmbbls)	Shale Oil (mmbbls)	Shale Gas (bcf)	Non-Shale Natural Gas (bcf)	NGL (mmbbls)	Total (mmboe)

Proved Developed Producing	260.6	45.5	0.9	946.3	2,154.8	42.5	866.4

Proved Developed Non-Producing	10.0	0.1	–	90.8	195.1	3.4	61.2

Proved Undeveloped	106.9	0.1	5.5	1,639.8	901.3	23.7	559.7

Proved	377.5	45.7	6.4	2,676.9	3,251.2	69.6	1,487.3

Probable	323.6	7.4	1.0	874.8	1,385.4	26.3	735.0

Total Proved Plus Probable	701.1	53.1	7.4	3,551.7	4,636.6	95.9	2,222.3

Information regarding the pricing assumptions used in the preparation of the estimates of NI 51-101 reserves is set forth in Schedule A of Talisman's AIF dated March 5, 2012.

LIQUIDITY AND CAPITAL RESOURCES

Talisman's debt at December 31, 2011 was $4.9 billion ($4.5 billion, net of cash and cash equivalents and bank indebtedness), up from $4.2 billion ($2.6 billion, net of cash and cash equivalents and bank indebtedness) at December 31, 2010.

During 2011, the Company generated $2.8 billion of cash provided by operating activities, incurred capital expenditures of $4.3 billion and acquisition expenditures of $893 million, and received proceeds of $527 million from the disposition of assets.

On an ongoing basis, Talisman plans to fund its capital program and acquisitions with cash on hand, cash provided by operating activities, cash proceeds from the disposition of non-core assets (estimated to be $1 billion to $2 billion in 2012), by drawing on the Company's credit facilities and issuing commercial paper.

27
TALISMAN ENERGY ANNUAL REPORT 2011

On December 5, 2011, Talisman issued 8,000,000 Cumulative Redeemable Rate Reset First Preferred Shares, Series 1 ("Series 1 preferred shares") at a price of C$25 per share for aggregate gross proceeds of C$200 million. Net proceeds, after deducting underwriting fees, were C$194 million ($191 million). Holders of Series 1 preferred shares are entitled to receive cumulative quarterly fixed dividends of 4.2% per annum for the initial period ending December 31, 2016, as and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 2.77%. The first dividend to preferred shareholders of C$0.3136 per share was declared in February 2012 to be paid in April 2012.

The Company has an active hedging program that will partially protect 2012 cash flow from the effect of declining oil prices. See the 'Risk Management' section of this MD&A for further information.

With the exception of the $402 million of debt presented as a current liability relating to the Company's US commercial paper program discussed below, Talisman has no significant debt maturities until 2014.

Talisman manages its balance sheet with reference to its liquidity and a debt-to-cash flow ratio. The main factors in assessing the Company's liquidity are cash flow (defined in accordance with the Company's debt covenant as cash provided by operating activities before adjusting for changes in non-cash working capital, exploration expenditure and amounts attributable to assets subject to non-recourse debt), cash provided by and used in investing activities and available bank credit facilities. The debt-to-cash flow ratio is calculated using debt (calculated by adding the gross debt and bank indebtedness, production payments and finance lease less non-recourse debt) divided by cash flow for the year.

The Company is in compliance with all of its debt covenants. The Company's principal financial covenant under its primary bank credit facility is a debt-to-cash flow ratio of less than 3.5:1, calculated quarterly on a trailing 12-month basis as of the last day of each fiscal quarter. Talisman's debt-to-cash flow was 1.39:1 at December 31, 2011 compared to 1.35:1 at December 31, 2010.

Talisman has unsecured bank credit facilities of $4 billion that are fully committed through November 2014. The maturity date of these facilities may be extended from time to time upon agreement between the Company and the respective lenders.

The Company established a US commercial paper program in November 2011. The authorized amount under this program is $1 billion. The amount available under the commercial paper program is limited to the availability of backup funds under the Company's bank credit facilities. At December 31, 2011, the amount of commercial paper outstanding was $402 million and the average interest rate on outstanding commercial paper was 0.6%. In addition, $648 million in the form of bankers' acceptances (C$410 million and US$245 million) was drawn on the bank credit facilities at December 31, 2011.

Available borrowing capacity was $3 billion at December 31, 2011.

The Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. Letters of credit are issued by banks under these uncommitted facilities and most are renewed annually. At January 1, 2012, letters of credit totaling $1.6 billion had been issued under these facilities, of which $1.1 billion were provided as security for the costs of decommissioning obligations in the UK. The remaining outstanding letters of credit relate primarily to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations in other areas.

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

A significant proportion of Talisman's accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At December 31, 2011, approximately 96% of the Company's trade accounts receivable were current and the largest single counterparty exposure, accounting for 17% of the total, was with a very highly rated counterparty. Concentration of credit risk is mitigated by having a broad domestic and international customer base. The maximum credit exposure associated with accounts receivable is the carrying value. A $65 million allowance for a doubtful account ($22 million, net of tax) has been made in respect of a 2011 oil sale, which is included in 'Other expense' on the Consolidated Statement of Income.

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TALISMAN ENERGY ANNUAL REPORT 2011

Talisman's normal course issuer bid expired on December 14, 2011. During the years ended December 31, 2011 and 2010, Talisman did not repurchase any common shares under its normal course issuer bid.

At December 31, 2011, there were 1,031,273,751 common shares outstanding, of which 9,851,281 were held in trust by the Company (see below) resulting in 1,021,422,470 common shares outstanding for accounting purposes. Subsequent to December 31, 2011, 296,153 shares were issued pursuant to the exercise of stock options, with 1,031,569,904 common shares being outstanding at February 28, 2012, of which 9,931,281 were held in trust by the Company resulting in 1,021,638,623 common shares outstanding for accounting purposes.

At December 31, 2011, there were 59,092,044 stock options, 9,461,164 cash units and 11,219,027 long-term performance share units (PSUs) outstanding. Subsequent to December 31, 2011, 61,520 stock options were granted, 296,153 were exercised for shares, 3,033 were surrendered for cash and 943,909 were forfeited, with 57,910,469 outstanding at February 28, 2012. Subsequent to December 31, 2011, 92,240 cash units were granted, 6,531 were exercised and 70,913 were forfeited with 9,475,960 outstanding at February 28, 2012. Subsequent to December 31, 2011, 64,453 long-term PSUs were granted and 137,326 were forfeited, with 11,146,154 outstanding at February 28, 2012.

The Company may purchase shares on the open market to satisfy its obligation to deliver common shares to settle long-term PSUs, which are held in trust. During the year ended December 31, 2011, 5,368,600 common shares were purchased on the open market for $94 million (2010 – 4,482,681 common shares purchased for $81 million). Between January 1 and February 28, 2012, a further 80,000 common shares were purchased on the open market for $1 million.

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

For additional information regarding the Company's liquidity and capital resources, refer to notes 17 and 20 to the 2011 audited Consolidated Financial Statements.

SENSITIVITIES

Talisman's financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated annualized impact of these factors for 2012 (excluding the effect of derivative contracts) is summarized in the following table, based on a WTI oil price of approximately $80/bbl, a NYMEX natural gas price of approximately $4.50/mmbtu and exchange rates of US$1=C$1 and UK£1=US$1.63.

(millions of $)		Net Income		Cash Provided by Operating Activities

Volume changes

	Oil – 10,000 bbls/d	60		130

	Natural gas – 60 mmcf/d	15		60

Price changes¹

	Oil – $1.00/bbl	20		35

	Natural gas (North America)² – $0.10/mcf	20		25

Exchange rate changes

	US$/C$ decreased by US$0.01	(5	)	(5	)

	US$/UK£ increased by US$0.02	5		–

1: The impact of price changes excludes the effect of commodity derivatives. See specific commodity derivative terms in the 'Risk Management' section of this MD&A, and note 22 to the Consolidated Financial Statements.
2: Price sensitivity on natural gas relates to North American natural gas only. The Company's exposure to changes in the natural gas prices in the UK, Norway and Malaysia/Vietnam and Colombia is not material. Most of the natural gas price in Indonesia is based on the price of crude oil and, accordingly, has been included in the price sensitivity for oil except for a small portion which is sold at a fixed price.

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TALISMAN ENERGY ANNUAL REPORT 2011

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

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

Additional disclosure of the Company's decommissioning liabilities, debt repayment obligations and significant commitments can be found in notes 15, 17, 18 and 23 to the 2011 audited Consolidated Financial Statements. A discussion of the Company's derivative financial instruments and commodity sales contracts can be found in the 'Risk Management' section of this MD&A.

The following table includes the Company's gross long-term debt, decommissioning obligations, share-based payments, operating and finance leases, property, plant and equipment (PP&E) and exploration and evaluation (E&E) assets commitments and other expected future payment commitments as at December 31, 2011 and estimated timing of such payments:

			Payments due by period^1,² (millions of $)

Commitments	Recognized in balance sheet	Total	Less than 1 year	1-3 years	4-5 years	After 5 years

Gross long-term debt	Yes – Liability	4,895	410	715	545	3,225

Decommissioning liabilities³	Yes – Partially accrued	5,035	53	153	339	4,490

Office leases	No	257	52	92	34	79

Vessel leases	No	667	243	216	159	49

Finance lease obligations	Yes – Partially accrued	114	18	36	32	28

Transportation and processing commitments⁴	No	1,564	260	299	278	727

PP&E and E&E assets⁵	No	1,475	991	428	56	–

Other service contracts	No	520	204	190	84	42

Share-based payments⁶	Yes – Liability	244	230	14	–	–

Total		14,771	2,461	2,143	1,527	8,640

1: Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivative contracts.
2: Payments denominated in foreign currencies have been translated at the December 31, 2011 exchange rate.
3: The decommissioning liabilities represent management's probability weighted, undiscounted best estimate of the cost and timing of decommissioning obligations based on engineering estimates and in accordance with existing legislation and industry practice.
4: Certain of the Company's transportation commitments are tied to firm gas sales contracts.
5: PP&E and E&E assets includes drilling rig commitments to meet a portion of the Company's future drilling requirements, as well as minimum work commitments.
6: The liability for share-based payments recognized on the balance sheet is based on the Company's year-end stock price or valued at the time of issuance based on the number of stock options, performance share units and cash units outstanding, adjusted for vesting terms. The amount included in this table includes the full value of unvested stock options and cash units. Timing of payments is based on vesting and expiry. Actual payments are dependent on the Company's stock price at the time of exercise.

There have been no significant changes in the Company's expected future payment commitments, and the timing of those payments, since December 31, 2011. A finance lease relating to the Yme project will be recorded upon first oil production.

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TALISMAN ENERGY ANNUAL REPORT 2011

TRANSACTIONS WITH RELATED PARTIES

The compensation of key management personnel, consisting of the Company's directors and executive officers, is as follows:


(millions of $)	2011	2010

Short-term benefits	15	14

Pension and other post-employment benefits	5	4

Termination benefits	4	–

Share-based payments¹	11	15

	35	33

1: The amount reported represents the cost to the Company of key management's participation in share-based payment plans, as measured by the fair value that the individual received based on the value of the shares exercised in the current period.

There were no other transactions with related parties.

RISK MANAGEMENT

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

The Company has established a system of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties.

The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 3(p) to the Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at December 31, 2011, including their respective fair values, are detailed in note 22 to the Consolidated Financial Statements.

The Company has elected not to designate as hedges for accounting purposes any commodity price derivative contracts entered into. These derivatives are classified as held-for-trading financial instruments and are measured at fair value with changes in fair value recognized in net income quarterly. This can potentially increase the volatility of net income.

Commodity Price Derivative Financial Instruments

The Company had the following commodity price derivative contracts outstanding at December 31, 2011, none of which are designated as a hedge:

Two-way collars	Term	bbls/d	Floor/ceiling $/bbl

Dated Brent oil index	Jan-Dec 2012	20,000	90.00/148.36

Dated Brent oil index	Jan-Jun 2012	9,000	90.00/126.93

Dated Brent oil index	Jan-Jun 2012	11,000	90.00/155.16

Dated Brent oil index	Jan-Jun 2012	10,000	90.00/123.08

Dated Brent oil index	Jul-Dec 2012	7,000	90.00/119.26

Subsequent to December 31, 2011, the Company entered into a Dated Brent two-way collar of 3,000 bbls/d for the second half of 2012 with a floor of $90/bbl and a ceiling of $121.35/bbl.

Further details of contracts outstanding are presented in note 22 to the Consolidated Financial Statements.

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TALISMAN ENERGY ANNUAL REPORT 2011

Long-Term Sales Contracts

In order to support the Company's investments in natural gas projects outside of North America and the North Sea, Talisman has entered into a number of long-term sales contracts.

The majority of Talisman's Corridor natural gas production in Indonesia is currently sold under long-term sales agreements with PT Chevron Pacific Indonesia (Chevron), Singapore Power and PGN (West Java). Under two sales agreements with Chevron, natural gas sales are at a price equal to 76% of the equivalent value of the Indonesia Crude Price for Duri crude oil. The minimum volume commitment under this contract is approximately 346 bcf over the remaining 10-year life of the contract. Under the agreement with Singapore Power, sales to Singapore from Corridor are referenced to the spot price of high sulphur fuel oil in Singapore. The minimum volume commitment is approximately 190 bcf over the remaining 12-year life of the contract. Sales from Corridor to PGN for their market in West Java are under long-term contract at a price of approximately $1.91/mcf, with no associated transportation costs. The minimum volume commitment is approximately 650 bcf over the remaining 12-year life of the contract.

The Company is subject to volume delivery requirements for approximately 100 mmcf/d at prices referenced to the Singapore high sulphur fuel oil spot market in relation to a long-term sales contract in Malaysia, currently scheduled to end in 2018. In the event these delivery requirements are not met in a contract year, volumes delivered in the subsequent contract year are subject to a 25% price discount for the equivalent volume of unexcused shortage that was not delivered in the prior year.

Currently, the Company anticipates having sufficient production to meet future delivery requirements.

Interest Rate Swap

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

In conjunction with the issuance of the C$350 million 4.44% medium-term notes in January 2006, the Company entered into a cross currency swap in order to hedge the foreign exchange exposure on this C$ denominated liability. As a result, the Company was effectively paying interest semi-annually in US$ at a rate of 5.05% on a notional amount of $304 million. The cross currency swap was designated as a cash flow hedge. The notes were repaid in January 2011 and the hedge was settled.

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TALISMAN ENERGY ANNUAL REPORT 2011

SUMMARY OF QUARTERLY RESULTS

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


			Three months ended

(millions of $, unless otherwise stated)		Annual	Dec. 31		Sep. 30	Jun. 30	Mar. 31

2011

Total revenue and other income		8,272	2,082		1,956	2,234	2,000

Net income (loss)		776	(117	)	521	698	(326	)

Per common share ($)

	Net income (loss)	0.76	(0.11	)	0.51	0.68	(0.32	)

	Diluted net income (loss)¹	0.38	(0.11	)	0.24	0.50	(0.32	)

Daily average production

	Oil and liquids from ongoing operations (mbbls/d)²	178	180		161	175	197

	Natural gas from ongoing operations (mmcf/d)	1,491	1,572		1,435	1,470	1,484

	From ongoing operations (mboe/d)	426	442		400	420	444

	Total (mboe/d)	426	442		400	420	444

2010

Total revenue and other income		6,982	1,863		1,683	1,600	1,836

Net income (loss)		945	(350	)	352	572	371

Per common share ($)

	Net income (loss)	0.93	(0.34	)	0.35	0.56	0.36

	Diluted net income (loss)¹	0.93	(0.34	)	0.35	0.50	0.30

Daily average production

	Oil and liquids from ongoing operations (mbbls/d)²	186	190		175	177	201

	Natural gas from ongoing operations (mmcf/d)	1,225	1,313		1,282	1,172	1,130

	From ongoing operations (mboe/d)	390	409		389	372	389

	Assets sold (mboe/d)	27	8		15	39	46

	Total (mboe/d)	417	417		404	411	435

1: Diluted net income (loss) per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options.
2: Includes oil volumes produced into inventory, and excludes oil volumes sold out of inventory, for the years ended December 31, 2011 and 2010 of 673 bbls/d and 171 bbls/d, respectively.

During the three-month period ended December 31, 2011, total revenue and other income increased by $219 million over the same period in 2010 due principally to increased commodity prices. The net loss decreased by $233 million due principally to the revenue variance, as well as a decrease in taxes and a decrease in share-based payments expense partially offset by an increase in operating expenses and DD&A.

Also, during the three-month period ended December 31, 2011, the Company:

•: Recorded total production of 442,000 boe/d, up 6% from 2010. Production from ongoing operations was up 8%;
•: Commenced production from Kitan in Australia, which is currently producing 11,000 boe/d;
•: Recommenced production from Claymore in the UK, which had been shut down throughout the third quarter, and shut down the Tartan platform for safety-related upgrades;
•: Issued 8,000,000 preferred shares at C$25 per share for aggregate gross proceeds of C$200 million. Net proceeds after underwriting fees were C$194 million ($191 million); and

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TALISMAN ENERGY ANNUAL REPORT 2011

•: Established a US commercial paper program in November 2011. The authorized amount under this program is $1 billion. At December 31, 2011, the amount of commercial paper outstanding was $402 million.

OUTLOOK FOR 2012

Talisman expects exploration and development capital spending to be approximately $4 billion in 2012, a decrease of approximately $500 million from 2011. This reflects a reduction in dry gas expenditure of between $500 million and $600 million and increased spending of $350 million on identified liquids projects. Talisman also expects a reduction in exploration spending in 2012, with greater emphasis on oil and oil-linked opportunities, with shorter term monetization options. In 2012, Talisman will be looking to sell between $1 billion to $2 billion of non-core assets.

The Company expects production growth of up to 5% in 2012 relative to 426,000 boe/d produced in 2011.

North America

Talisman is shifting focus to the liquids-rich opportunities within its portfolio. Talisman expects to grow the Company's liquids production in North America from approximately 25,000 bbls/d in 2012 to over 60,000 bbls/d by 2015.

Capital spending in North America is expected to be approximately $1.8 billion in 2012, which is approximately $400 million lower than 2011, primarily as a result of reducing expenditures on dry gas plays. Over 40% of the program will focus on liquids-rich opportunities. Production from the shale portfolio is expected to range between 630-660 mmcfe/d (105,000-110,000 boe/d).

Spending in the liquids-rich Eagle Ford play in Texas is expected to increase from $350 million in 2011 to approximately $500 million in 2012. The Company plans to ramp up the development of the liquids-rich areas and expects to exit 2012 with 14 rigs, up from 10 at the end of 2011.

In the Pennsylvania Marcellus play, in light of current gas prices, Talisman may reduce activity from 10 operating rigs at year-end to as few as three rigs over the course of 2012. Production is expected to remain relatively flat going forward as Talisman expects to reduce activity in light of natural gas prices. Spending in the Pennsylvania Marcellus is expected to be upwards of $600 million, with significant investment in infrastructure in new parts of the play.

With a four-rig program planned this year, Talisman plans to reduce activity in the Montney play in British Columbia in order to allocate more capital to liquids-rich opportunities. Talisman plans to drill at least six wells as it continues to pilot the liquids-rich Duvernay shale play in Alberta.

Spending in the conventional portfolio is expected to range between $300 million and $350 million, with production relatively flat at 80,000 boe/d, of which 25% is expected to be liquids. Approximately one-third of spending is planned for the liquids-rich Wild River play in Alberta.

Talisman will continue to actively focus its North American conventional portfolio, which could result in the disposition of certain non-core assets. In other areas, Talisman may seek to use third party expertise or resources to accelerate activity and optimize value.

North Sea

Talisman will focus on making improvements in overall operating efficiency in the North Sea. Most of Talisman's production in the North Sea is liquids and the region provided over $600 million of cash to the business in 2011.

Cash capital spending in the North Sea is expected to be $1.2 billion in 2012, roughly the same as 2011. Talisman expects to spend $800 million in the UK, where the major projects are the Monarb and Auk South field redevelopments. Talisman will also continue upgrades to the Claymore platform to increase operating efficiency and drill development wells at Tweedsmuir and Clyde. In Norway, there are a number of infill wells planned at Brage, Veslefrikk, Gyda and Rev.

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TALISMAN ENERGY ANNUAL REPORT 2011

Talisman expects to continue to invest in its North Sea portfolio to ensure the integrity of installations and to secure the cash flow it generates, but will also seek to reduce exposure somewhat to this mature and relatively volatile business over time, through possible asset sales or farm-out arrangements.

Southeast Asia

Southeast Asia is a self-funding growth area with the majority of Talisman's gas contracts linked to oil price benchmarks.

Spending in Southeast Asia is expected to range between $600 million and $700 million in 2012, including exploration, with over two-thirds of this directed towards development activities. Production averaged approximately 119,000 boe/d in 2011 and is expected to increase slightly in 2012, with a full year of contribution from the Kitan and Jambi Merang fields. The region is expected to deliver, on average, 8% compound annual production growth over the next few years through currently identified projects.

In Vietnam, Talisman sanctioned the offshore HST/HSD development late in 2011, with first oil expected in the second half of 2013.

Elsewhere in the region, there are a number of projects planned at the Corridor field in Indonesia, and Talisman plans to continue its infill drilling program at PM-3 CAA, offshore Malaysia/Vietnam.

International Exploration

A principal focus of the exploration program in 2012 is expected to be Colombia, where production is expected to be 15,000 – 16,000 boe/d, and where Talisman is in the process of moving two fields from the evaluation phase into commerciality.

The exploration budget for 2012 is $600 million, of which one-quarter is planned to be spent in Latin America. The plan is to drill over 10 exploration, appraisal and stratigraphic wells in Colombia this year for $150 million. Talisman has a well in the Akacias field on long-term test producing at 1,500-1,600 bbls/d and one additional well that is encouraging, but which has not yet been tested. An additional $150 million is to be spent on development, for a total capital expenditure of $300 million in Colombia.

In Block CPE-6, Talisman completed a six-well stratigraphic program in 2011 and has commenced a second six-well stratigraphic/appraisal well program in 2012. Talisman has two active rigs in the Piedemonte Block and expects to sanction the Piedemonte expansion by mid-year. In the Foothills region, Talisman expects to complete the drilling of the Huron-2 appraisal well and spud the Huron-3 appraisal well.

There are 10 wells planned for Southeast Asia in 2012, which includes one well drilling over year-end 2011. These wells support ongoing gas aggregation in Papua New Guinea and new opportunities in Vietnam and Malaysia. In February 2012, the Company secured Mitsubishi Corporation as a partner in its strategy to aggregate 2 – 4 tcf of gas in Papua New Guinea, with a view to potential LNG exports of up to three million tonnes per year.

Exploration and appraisal wells are also planned in the North Sea, Peru, Poland and the Kurdistan region of northern Iraq.

INTERNAL CONTROL OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS AND PROCEDURES

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in rules 13a-15(f) and 15d-15(f) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act).

Management, including the Company's Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the Company's internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on management's assessment as at December 31, 2011, management has concluded that the Company's internal control over financial reporting is effective.

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TALISMAN ENERGY ANNUAL REPORT 2011

The results of management's assessment were reviewed with the Audit Committee of the Company's Board of Directors. Ernst & Young LLP, the independent registered public accounting firm that audited the Company's Consolidated Financial Statements, independently assessed the effectiveness of the Company's internal control over financial reporting. Ernst & Young LLP's attestation is located in the Independent Auditors' Report on Internal Controls Under Standards of the Public Company Accounting Oversight Board (United States), which is an exhibit to the Company's Annual Report on Form 40-F.

Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company's financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

The adoption of IFRS impacts Talisman's presentation of financial results and accompanying disclosures. The Company has evaluated the impact of the adoption of IFRS on its processes, controls and financial reporting systems and has made modifications to its control environment accordingly. There have been no significant changes in Talisman's internal control over financial reporting during the year ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Effective January 1, 2012, Talisman implemented a new integrated finance and supply chain application in its North American business and corporate function. The implementation of this new application was not in response to any deficiency in the Company's internal controls, but is the first phase of a project to standardize applications globally.

Disclosure Controls and Procedures

At the end of the period covered by this MD&A, an evaluation was carried out under the supervision of, and with the participation of, the Company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by the Company in reports that it files with or submits to the Canadian Securities Administrators and the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods required.

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

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

LITIGATION

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not expected to have a material impact on the Company's financial position.

The New York Attorney General has commenced an investigation, pursuant to the Martin Act, into the disclosure practices of companies engaged in hydraulic fracturing in the New York state area. The Martin Act provides broad authority to commence and conduct investigations, whether upon receipt of a complaint, or on the Attorney General's own initiative. Subpoenas have been issued to a number of companies, including Talisman. The Company has been cooperating with the New York Attorney

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TALISMAN ENERGY ANNUAL REPORT 2011

General in the investigation. No enforcement action has been taken against Talisman, nor has the Company been advised that any enforcement action is imminent.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates and judgment. Actual results could differ materially from those estimates. A summary of significant accounting policies adopted by Talisman can be found in note 3 to the Consolidated Financial Statements. In assisting the Company's Audit Committee to fulfil its financial statement oversight role, management regularly meets with the Committee to review the Company's significant accounting policies, estimates and any significant changes thereto, including those discussed below.

Management believes the most critical accounting policies, including judgments in their application, which may have an impact on the Company's financial results, relate to the accounting for PP&E, E&E assets, decommissioning liabilities, the recognition of assets acquired and liabilities assumed upon a business combination and goodwill. The rate at which the Company's assets are depleted, depreciated or otherwise written off and the decommissioning liabilities provided for, with the associated accretion expensed to the income statement, are subject to a number of estimates about future events, many of which are beyond management's control. Reserves recognition is central to much of an oil and gas company's accounting, as described below.

Reserves Recognition

Underpinning Talisman's estimates and judgments regarding oil and gas assets and goodwill are its oil and gas reserves. Detailed rules and industry practice, to which Talisman adheres, have been developed to provide uniform reserves recognition criteria. However, the process of estimating oil and gas reserves is inherently judgmental. There are two principal sources of uncertainty: technical and commercial. Technical reserves estimates are made using available geological and reservoir data as well as production performance data. As new data becomes available, including actual reservoir performance, reserves estimates may change. Reserves can also be classified as proved or probable with decreasing levels of certainty as to the likelihood that the reserves will be ultimately produced.

Reserves recognition is also impacted by economic considerations. In order for reserves to be recognized, they must be reasonably certain of being produced under existing economic and operating conditions, which is viewed as being annual average commodity prices determined by the prices in effect on the first day of each month with a cost profile based on current operations (SEC requirements) or forecast prices and cost assumptions (NI 51-101 requirements). Any anticipated changes in conditions must have reasonable certainty of occurrence. In particular, in international operations, consideration includes the status of field development planning and gas sales contracts. As economic conditions change, primarily as a result of changes in commodity prices and, to a lesser extent, operating and capital costs, marginally profitable production, typically experienced in the later years of a field's life cycle, may be added to reserves or, conversely, may no longer qualify for reserves recognition.

The Company's reserves and revisions to those reserves, although not separately reported on the Company's balance sheet or income statement, impact the Company's reported assets, liabilities and net income through the DD&A of the Company's PP&E, impairments and the provision for decommissioning liabilities.

The Reserves Committee of Talisman's Board of Directors reviews the Company's reserves booking process and related public disclosures and the report of the internal qualified reserves evaluator (IQRE). The primary responsibilities of the Reserves Committee include, among other things, reviewing the Company's reserves booking process and recommending to the Board of Directors the Company's annual disclosure of reserves data and other oil and gas information contained in the Company's AIF. The IQRE reports the Company's annual reserves data to the Reserves Committee and delivers a regulatory certificate regarding proved and probable reserves and their related future net revenue, disclosed pursuant to NI 51-101 requirements.

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Depreciation, Depletion and Amortization Expense (DD&A)

A significant portion of the Company's PP&E is amortized based on the unit of production method with other assets being depreciated on a straight-line basis over their expected useful lives. The unit of production method attempts to amortize the asset's cost over its proved oil and gas reserves base. Accordingly, revisions to reserves or changes to management's view as to the operational lifespan of an asset will impact the Company's future DD&A expense. Depletion and depreciation rates are updated in each reporting period that a significant change in circumstances, including reserves revisions, occurs.

Exploration and Evaluation (E&E) Assets

Exploration well costs are initially capitalized and, if subsequently determined to have not found sufficient reserves to justify commercial production, are charged to dry hole expense. Exploration well costs that have found sufficient reserves to justify commercial production, but those reserves cannot be classified as proved, continue to be capitalized as long as sufficient progress is being made to assess the reserves and economic viability of the well and/or related project. All such carried costs are subject to technical, commercial and management review at each reporting date to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is tested for potential impairment and then transferred to PP&E.

Undeveloped land costs are classified initially as E&E assets and transferred to PP&E as proved reserves are assigned.

E&E assets are not subject to DD&A.

Impairment of Assets

The Company tests PP&E and E&E assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable; for example, changes in assumptions relating to future prices, future costs and reserves. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets, known as a cash-generating unit (CGU). If any such indication of impairment exists, an estimate of the CGU's recoverable amount is made. A CGU's recoverable amount is the higher of its fair value less costs to sell and its value in use. These assessments require the use of estimates and assumptions regarding long-term commodity prices, discount rates, future capital expenditures requirements, reserves determination and life-of-field. E&E assets are also tested for possible impairment when transferred to PP&E.

A previously recognized impairment loss is reversed only if there has been a change in the estimates or assumptions used to determine the CGU's recoverable amount since the impairment loss was recognized. If that is the case, the carrying amount of the CGU is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the CGU in prior periods. Such a reversal is recognized in net income, following which the depreciation charge is adjusted in future periods to allocate the CGU's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

In estimating the possible impairment to PP&E, management estimates fair value based on market information, which consists of offers to purchase the asset or comparable assets, independent market surveys and values derived from exchange-quoted prices. Where reliable market information is not available, the recoverable amount was determined using cash flow projections that were based on a long-term view of commodity prices and a post-tax discount rate of 10%.

During the year, the Company recorded a net impairment of oil and gas assets of $226 million (2010 – $301 million).

Goodwill Impairments

Goodwill represents the excess of the consideration transferred over the fair value of the identifiable assets acquired and liabilities assumed in a business combination. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. The impairment test requires that goodwill be allocated to CGUs, which Talisman has determined by aggregating locations having similar economic characteristics and/or which are in similar geographic locations, and which correspond with the operating segments, except for locations within the 'Other' segment, which are allocated to the

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TALISMAN ENERGY ANNUAL REPORT 2011

relevant countries. Impairment is determined for goodwill by assessing the recoverable amount (based on fair value less costs to sell) of each segment to which the goodwill relates. Where the recoverable amount of the segment is less than the carrying amount, an impairment loss is recognized. Goodwill impairment losses cannot be reversed. No impairment of goodwill was recorded during the year.

Business Combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred at acquisition date fair value. When the Company acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. The Company allocates the purchase price to identifiable assets and liabilities based on their fair value. In many cases, the determination of fair value requires management to make certain assumptions and estimates regarding future events. Typically in determining fair value, management develops a number of possible future cash flow scenarios to which probabilities are judgmentally assigned. The acquired assets and liabilities may span multiple geographical segments and may be amortized at different rates, or not at all as in the case of goodwill or, initially, for acquired probable reserves.

Transaction costs include stamp duty, consulting fees (e.g. legal, accounting and valuation fees) and other integration costs and are expensed as incurred.

Decommissioning Liabilities

Decommissioning liabilities are measured based on the estimated cost of abandonment discounted to its net present value using a weighted average credit-adjusted risk free rate. At December 31, 2011, the net present value of the Company's decommissioning liability was $3.0 billion (2010 – $2.6 billion) and is recorded as a liability on the Company's balance sheet. In determining the net present value of the Company's decommissioning liability, management developed a number of possible remediation scenarios to which probabilities were assigned based on management's reasonable judgment. The undiscounted decommissioning obligations were estimated at $5.0 billion at December 31, 2011 (2010 – $4.5 billion), which is based on management's probability weighted estimate of costs and is in accordance with existing legislation and industry practice. The majority of the payments to settle this provision will occur over a period of 35 years and will be funded from the general resources of the Company as they arise. The provision for the costs of decommissioning production facilities and pipelines at the end of their economic lives has been estimated using existing technology, at current prices or long-term assumptions and based upon the expected timing of the activity. The provision has been discounted using a current weighted average credit-adjusted risk free rate of 5.1% (2010 – 5.3%).

The completion of the Equión acquisition resulted in the assumption of decommissioning liabilities having a net present value of $25 million.

While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs. As an indication of possible future changes in estimated decommissioning liabilities, if all of the Company's decommissioning obligations could be deferred by one year, the net present value of the liabilities would decrease by approximately $85 million.

Income Taxes

Current tax is based on estimated taxable income and tax rates, which are determined pursuant to the tax laws that are enacted or substantively enacted at the balance sheet date.

Deferred tax is determined using the liability method. Under the liability method, deferred tax is calculated based on the differences between assets and liabilities reported for financial accounting purposes and those reported for income tax purposes. Deferred tax assets and liabilities are measured using substantively enacted tax rates. The impact of a change in tax rate is recognized in net income in the period in which the tax rate is substantively enacted. The Company recognizes in its financial statements the best estimate of the impact of a tax position by determining if the available evidence indicates whether

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it is more likely than not, based solely on technical merits, that the position will be sustained on audit. The Company estimates the amount to be recorded by weighting all possible outcomes by their associated probabilities.

Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction and relate to the same taxable entity. Based on expectations for the future and available tax-planning strategies, management expects remaining deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income.

The determination of the income tax provision is an inherently complex process, requiring management to interpret continually changing regulations and to make certain judgments. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the jurisdictions in which the Company operates around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible that such changes could be significant when compared with the Company's total unrecognized tax benefits. However, the amount of change cannot be quantified.

Foreign Exchange Accounting

Talisman's worldwide operations expose the Company to transactions denominated in a number of different currencies, which are required to be translated into one currency for financial statement reporting purposes. Talisman's foreign currency translation policy, as detailed in note 3(n) to the Consolidated Financial Statements, is designed to reflect the economic exposure of the Company's operations to the various currencies. The Company's functional currency is US$, a reflection of Talisman's overall exposure to US$ denominated transactions, assets and liabilities; oil prices are largely denominated in US$ as is much of the Company's corporate debt and international capital spending and operating costs.

Prior to January 1, 2011 in the UK and prior to January 1, 2010 in Canada and Norway, the Company's operations were translated from UK£, C$ and NOK, respectively, into US$ using the current rate method whereby assets and liabilities were translated at year-end exchange rates, while revenues and expenses were converted using average rates for the period. Gains and losses arising on translation from UK£, C$ and NOK to US$ were deferred and included in a separate component of shareholders' equity described as accumulated other comprehensive income.

As a result of changes in the composition of revenue and costs and changes in intercompany loan arrangements, management has determined that the functional currency of the Company's UK operation is more closely linked to the US$. Accordingly, effective January 1, 2011, this operation has been accounted for as a US$ functional currency entity. As a result, foreign currency translation adjustments remain in accumulated other comprehensive income until Talisman reduces its net investment in its UK subsidiary. Following the change in the functional currency of the UK operation on January 1, 2011, the debt denominated in UK£ was no longer designated as a hedge of Talisman's net investment in the UK and, accordingly, foreign exchange gains and losses are recorded on the Consolidated Statement of Income.

The Company's operations in Canada and Norway are accounted for as US$ functional currency entities. As a result, foreign currency translation adjustments remain in accumulated other comprehensive income until Talisman reduces its net investment in its Canadian or Norwegian subsidiaries. The reduction of the net investment in the Canadian subsidiary that occurred during 2010 is described in note 4.9 to the Consolidated Financial Statements.

The remaining foreign operations are translated as follows: monetary assets and liabilities at exchange rates in effect at the balance sheet date, non-monetary assets and liabilities at rates in effect on the dates the assets were acquired or liabilities were assumed, and revenues and expenses at rates of exchange prevailing on the transaction dates. Gains and losses on translation are reflected in income when incurred.

Effective from the first quarter of 2011, the Company is reporting its financial position and results of operations in US$. The impact of changing the reporting currency from C$ to US$ is presented in note 4 to the Consolidated Financial Statements.

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TALISMAN ENERGY ANNUAL REPORT 2011

Production Sharing Contract (PSC) Arrangements

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

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

Risk Management

The Company enters into derivative financial instruments in order to manage risks associated with fluctuations in commodity prices, interest rates and foreign currency exchange rates. As detailed in Talisman's financial instruments accounting policy described in note 3(p) to the Consolidated Financial Statements, derivative instruments are recorded at fair value on the Consolidated Balance Sheets. Gains or losses on financial instruments are recognized as hedging gains or losses or held-for-trading gains or losses in net income. Fair values are determined based on third party market information and are subject to a degree of uncertainty. Estimates of fair value are subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance risk. Cash settlement of derivative financial instruments may vary from fair value estimates, depending on the underlying market prices at the date of settlement.

IFRS FIRST-TIME ADOPTION

Talisman's Consolidated Financial Statements as at and for the years ended December 31, 2011 and 2010 represent the first annual financial statements of Talisman prepared in accordance with IFRS, as issued by the IASB and interpretations of the IFRIC effective at December 31, 2011. Previously, Talisman prepared its annual Consolidated Financial Statements in accordance with Canadian GAAP then applicable to publicly accountable enterprises (CGAAP).

Since this is Talisman's initial year presenting its results and financial position under IFRS, the Consolidated Financial Statements have been prepared in accordance with IFRS 1 First-Time Adoption of IFRS.

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

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

IFRS 1 Exemptions

The general principle to be applied on first-time adoption of IFRS is that standards in force at the first reporting date (December 31, 2011) should be applied as at the date of transition to IFRS (January 1, 2010) and throughout all periods

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TALISMAN ENERGY ANNUAL REPORT 2011

presented in the first IFRS financial statements. However, IFRS 1 contains a number of exemptions that companies are permitted to apply. Talisman elected to apply the following exemptions:

•: To measure certain properties at fair value at January 1, 2010 and use those fair values as deemed cost at that date;
•: To apply a modified approach in calculating the retrospective cost component of PP&E relating to the Company's decommissioning liabilities. Under the modified approach, decommissioning liabilities are re-measured at the date of transition to IFRS under IAS 37 Provisions, Contingent Liabilities and Contingent Assets and amounts to be included in the related assets are estimated by discounting the liabilities to the date at which the liabilities first arose using the best estimates of the historical credit risk-adjusted discount rates. The related accumulated DD&A is then calculated based on the current estimates of the useful lives of the assets;
•: To apply IFRS 3 Business Combinations prospectively and not restate business combinations that occurred prior to January 1, 2010;
•: To not apply IFRS 2 Share-Based Payments to equity awards that vested and liability awards that settled prior to January 1, 2010;
•: To recognize cumulative unrecognized net actuarial losses on employee future benefits in opening retained earnings as at January 1, 2010. Also, to prospectively disclose required benefit plans amounts under IAS 19 Employee Benefits as the amounts are determined for each accounting period from January 1, 2010 instead of the current annual period and previous four annual periods; and
•: To apply IAS 23 Borrowing Costs prospectively from January 1, 2010 and derecognize the carrying value of capitalized borrowing costs recorded under Canadian GAAP as at January 1, 2010.

Reconciliation from Canadian GAAP to IFRS

In preparing the Consolidated Financial Statements, the Company adjusted amounts reported previously in its Consolidated Financial Statements prepared under Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS affected the Company's financial position, results of operations and cash flows, including the reconciliations required by IFRS 1, is presented in note 4 to the Consolidated Financial Statements. Summaries of the impacts of IFRS adoption on the Company's financial position at January 1, 2010 and its financial results for the year ended December 31, 2010 follow.

Impact on Financial Position at January 1, 2010

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

	CGAAP		IFRS adjustments & reclassifications		IFRS
(millions of $)	C$	US$	US$		US$

Current assets	3,154	3,013	31		3,044

Long-term assets	20,464	19,552	(2,608	)	16,944

Total assets	23,618	22,565	(2,577	)	19,988

Current liabilities	2,601	2,485	214		2,699

Long-term liabilities	9,906	9,463	(1,021	)	8,442

Shareholders' equity	11,111	10,617	(1,770	)	8,847

Total liabilities & shareholders' equity	23,618	22,565	(2,577	)	19,988

Shareholders' equity at the time of adoption of IFRS decreased by approximately $1.8 billion as a result of the after tax impact of adjustments to the opening balance sheet being recorded in retained earnings. These adjustments comprise approximately $1.2 billion for the fair value as deemed cost election, a significant portion of which related to assets sold during 2010, and

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impairment of E&E assets, and approximately $0.6 billion relating to derecognition of capitalized borrowing costs, decommissioning, share-based payments, employee benefits and deferred taxes.

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

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

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

Impact on Financial Results for the Year Ended December 31, 2010

The following table summarizes the adjustments made to Consolidated Statement of Income for the year ended December 31, 2010:

	CGAAP		IFRS adjustments & reclassifications		IFRS
(millions of $)	C$	US$	US$		US$

Total revenue	6,912	6,715	267		6,982

Total expenses	5,613	5,465	(454	)	5,011

Income before taxes	1,299	1,250	721		1,971

Taxes	891	868	158		1,026

Income from continuing operations	408	382	563		945

Income from discontinued operations	240	231	(231	)	–

Net income	648	613	332		945

The resetting of the Company's balance sheet under IFRS, which primarily impacted PP&E and the liabilities for decommissioning, share-based payments and deferred income tax, in conjunction with other changes in accounting policies under IFRS increased the Company's previously reported net income for the year ended December 31, 2010 by $332 million. The changes in accounting policies under IFRS decreased DD&A and accretion expense ($266 million) and increased gain on asset disposals ($395 million), offset by increased impairments ($186 million) and increased tax expenses ($158 million). The remaining balance relates to other adjustments increasing net income by $15 million.

IMPACT OF IFRS ADOPTION ON ACCOUNTING POLICIES AND ESTIMATES

The following critical accounting policies and significant estimates have been impacted by the adoption of IFRS:

Asset Impairments

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

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decline in natural gas price assumptions. In the North Sea, $99 million was recorded as a result of a change in reserves estimates relating to PP&E, a change in the estimated timing of cash flows relating to oil and gas E&E assets and changes in investment decisions. In Southeast Asia, $21 million was recorded relating to oil assets due to an increase in estimated future costs. The carrying values of these assets were previously supported under Canadian GAAP on an undiscounted cash flow basis. The impairments are subject to future reversal if certain criteria are met.

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

Business Combinations and Asset Acquisitions

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

a) Contingent Liabilities

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

b) Contingent Purchase Consideration

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

c) Transaction Costs

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

Decommissioning Liabilities

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

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Income Taxes

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

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

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

As a result of all measurement differences impacting deferred taxes, including the three discussed above, the Company recorded a decrease of deferred tax liabilities of $1.1 billion at January 1, 2010 (December 31, 2010 – $1.6 billion) under IFRS. Additional income tax expense of $232 million for the year ended December 31, 2010 was recorded arising from the reversal of temporary differences under IFRS.

OTHER ACCOUNTING CHANGES

Foreign Exchange

Management has determined that the functional currency of the Company's UK operation is more closely linked to the US$ due to the composition of revenue, costs and intercompany arrangements, and this operation has been accounted for as a US$ functional currency entity, effective January 1, 2011. Information of this change is further described in the 'Application of Critical Accounting Policies and Use of Estimates' section of this MD&A.

Accounting Standards and Interpretations Issued but Not Yet Effective

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

•: IFRS 9 Financial Instruments – as part of its project to replace IAS 39, the IASB issued the first phase of IFRS 9 implementation dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9 by incorporating requirements for the accounting for financial liabilities;
•: IFRS 10 Consolidated Financial Statements – establishes the accounting principles for consolidated financial statements when one entity controls other entities and replaces IAS 27 Consolidated and Separate Financial Statements and the related provisions of SIC-12 Consolidation – Special Purpose Entities. This standard establishes a new control model that applies to all entities;
•: IFRS 11 Joint Arrangements – establishes the accounting principles for parties to a joint arrangement and replaces IAS 31 Interest in Joint Ventures and SIC-13 Jointly Controlled Entities: Non-Monetary Contributions by Venturers. This standard requires a party to assess its rights and obligations from the arrangement in order to determine the type of joint arrangement. The choice of proportionate consolidation accounting is removed for joint ventures (currently jointly controlled entities under IAS 31) as equity accounting is required;
•: IFRS 12 Disclosure of Interests in Other Entities – establishes comprehensive disclosure requirements for subsidiaries, joint arrangements, associates, and unconsolidated structured entities and replaces existing disclosures in related standards;
•: IFRS 13 Fair Value Measurement – establishes a single framework for fair value measurement and disclosures when fair value is required or permitted under IFRS;
•: IAS 1 Presentation of Financial Statements – amendment requires items within other comprehensive loss to be grouped based on whether they can be reclassified to the income statement and is applicable to annual periods beginning on or after July 1, 2012, with earlier adoption permitted;

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TALISMAN ENERGY ANNUAL REPORT 2011

•: IAS 19 Employee Benefits amendment – improves the accounting for employee benefits by eliminating the 'corridor method' to defer recognition of actuarial gains and losses, introducing presentation changes for the financial statements effect arising from defined benefit plans, and introducing enhanced disclosure requirements for defined benefit plans;
•: IAS 27 Separate Financial Statements – establishes the accounting and disclosure requirements for investments in subsidiaries, joint ventures, and associates when an entity prepares separate financial statements and replaces the current IAS 27 Consolidated and Separate Financial Statements as the consolidation guidance is included in IFRS 10 Consolidated Financial Statements; and
•: IAS 28 Investments in Associates and Joint Ventures – establishes the accounting for investments in associates and defines how the equity method is applied when accounting for associates and joint ventures.

Except as noted above, all of the above pronouncements are effective for annual periods beginning on or after January 1, 2013 with earlier adoption permitted, except for IFRS 9, which is effective January 1, 2015. The Company is currently assessing the impact of adopting these pronouncements.

REGULATORY DEVELOPMENTS

Dodd-Frank Act

In 2010, the US Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act or the Act) was signed into law. The Dodd-Frank Act provides for numerous new substantive requirements in areas such as the disclosure of payments made to foreign governments, rules regarding the use of credit ratings, and corporate governance and executive compensation reforms, among others, some of which apply to Talisman as a foreign private issuer. Talisman will continue to assess the effect on the Company of the Dodd-Frank Act and related rules. The SEC estimates that the rules relating to pay-for-performance, pay parity, hedging and executive compensation clawbacks will be adopted by the second half of 2012.

With respect to the disclosure of payments to governments, the Act requires resource extraction issuers to disclose payments made to the US federal government or a foreign government (including a department, agent or instrumentality of a foreign government or a company owned by a foreign government) in their annual reports. A payment would be an amount that is not de minimus and that is paid to further the commercial development of oil, natural gas or minerals, including taxes, royalties, fees (including licence fees), bonuses, production entitlements or any other material benefits the SEC determines is part of commonly recognized revenue streams for resource extraction. The Dodd-Frank Act requires disclosure of the type and total amount of such payments made for each project and to each government. The SEC's final rule is expected to be adopted in the second half of 2012.

RISK FACTORS

Talisman is exposed to a number of risks inherent in exploring for, developing and producing crude oil and natural gas. This section describes the important risks and other matters that could cause actual results of Talisman to differ materially from those presented and that could affect the trading price of the Company's outstanding shares. The risks described below may not be the only risks Talisman faces, as Talisman's business and operations may also be subject to risks that Talisman does not yet know of, or that Talisman currently believes are immaterial. If any of the events or circumstances described below actually occurs, Talisman's business, financial condition, results of operations or cash flow could be materially and adversely affected and the trading price of Talisman's securities could decline. The following risk factors should be read in conjunction with the other information contained herein and in the Consolidated Financial Statements and the related notes.

Volatility of Oil and Natural Gas Prices

Talisman's financial performance is highly sensitive to the prevailing prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have a material adverse effect on the Company's operations and financial condition, the value of its oil and natural gas reserves and its level of expenditure for oil and gas exploration and development. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are largely beyond the Company's control. Oil prices are determined by

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international supply and demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries (OPEC), world economic conditions, government regulation, political stability throughout the world, the availability of alternative fuel sources, technological advances affecting energy production and consumption, and weather conditions. About 60% of the natural gas prices realized by Talisman are affected primarily by North American supply and demand, weather conditions and prices of alternative sources of energy. The remaining 40% of natural gas prices realized by Talisman are from markets outside of North America, primarily in Southeast Asia. These other prices are typically determined by long-term contracts that are linked to international oil and/or oil prevalent prices. The development of oil and natural gas discoveries in offshore areas and the development of shale gas plays are particularly dependent on the outlook for oil and natural gas prices because of the large amount of capital expenditure required for development prior to commencing production.

A substantial and extended decline in the prices of crude oil or natural gas could result in delay or cancellation of drilling, development or construction programs, curtailment in production or unutilized long-term transportation commitments, all of which could have a material adverse impact on the Company. The amount of cost oil required to recover Talisman's investment and costs in various PSCs is dependent on commodity prices, with higher commodity prices resulting in the booking of lower oil and gas reserves net of royalties.

Moreover, changes in commodity prices may result in the Company making downward adjustments to the Company's estimated reserves. If this occurs, or if the Company's estimates of production or economic factors change, accounting rules may require the Company to impair, as a non-cash charge to earnings, the carrying value of the Company's oil and gas properties. The Company is required to perform impairment tests on oil and gas properties whenever events or changes in circumstances indicate that the carrying value of properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and, therefore, an impairment charge will be required to reduce the carrying value of the proved properties to their estimated fair value. The Company may incur impairment charges in the future, which could materially affect the Company's results of operations in the period incurred.

Exchange Rate Fluctuations

Results of operations are affected primarily by the exchange rates between the US$, C$, UK£ and NOK. These exchange rates may vary substantially. Most of the Company's revenue is received in or is referenced to US$ denominated prices (including the Company's Consolidated Financial Statements, which are presented in US$), while Talisman's expenditures are denominated in US$, C$, UK£ and NOK. A change in the relative value of the US$ against the UK£ would also result in an increase or decrease in Talisman's UK£ denominated debt, as expressed in US$, and the related interest expense. Talisman is also exposed to fluctuations in other foreign currencies.

Capital Allocation and Project Decisions

Talisman's long-term financial performance is sensitive to the capital allocation decisions taken and the underlying performance of the projects undertaken. In 2012, Talisman plans to spend approximately $4 billion in exploration and development cash capital expenditures, the majority of which is to be allocated among Talisman's North America, Southeast Asia, North Sea and exploration portfolios. Capital allocation and project decisions are undertaken after assessing reserves and production projections, capital and operating cost estimates and applicable fiscal regimes that govern the respective government take from any project. All of these factors are evaluated against common commodity pricing assumptions and the relative risks of projects. These factors are used to establish a relative ranking of projects and capital allocation, which is then calibrated to ensure the debt and liquidity of the Company is not compromised.

Material changes to project outcomes, in any of production volumes and rates, realized commodity price, cost or tax and/or royalties could have a material impact on the Company's cash flow and financial performance.

The Company cannot be certain that funding, if needed, will be available to the extent required or on acceptable terms. To the extent that asset sales are necessary to fund capital requirements, Talisman's ability to sell assets is subject to market availability. If Talisman is unable to access funding when needed on acceptable terms, the Company may not be able to fully

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implement its business plans, take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on Talisman's business, financial condition, cash flows, and results of operations. See also 'Risk Factors – Credit and Liquidity' and 'Risk Factors – Interest Rates'.

Operational Risks

Major Incident, Major Spill / Loss of Well Control

Oil and gas drilling and producing operations are subject to many risks, including the risk of fire, explosions, mechanical failure, pipe or well cement failure, well casing collapse, pressure or irregularities in formations, chemical and other spills, unauthorized access to hydrocarbons, accidental flows of oil, natural gas or well fluids, sour gas releases, contamination of oil and gas, vessel collision, structural failure, loss of buoyancy, storms or other adverse weather conditions and other occurrences. If any of these should occur, Talisman could incur legal defence costs and remedial costs and could suffer substantial losses due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, unplanned production outage, cleanup responsibilities, regulatory investigation and penalties, increased public interest in Talisman's operational performance and suspension of operations. The Company's horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

Talisman maintains insurance that contemplates both first and third party exposures for Talisman's onshore and offshore operations globally. There is no assurance that this insurance will be adequate to cover all losses or exposures to liability. The Company believes that its coverage is aligned with customary industry practices and in amounts and at costs that Talisman believes to be prudent and commercially practicable. While Talisman believes these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, the Company's insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on the Company's financial position, results of operations and cash flows. The insurance coverage that the Company maintains may not be sufficient to cover every claim made against Talisman in the future. In addition, a major incident could impact Talisman's reputation in such a way that it could have a material adverse effect on the Company's business.

Talisman operates and drills wells in both mature producing areas such as the UK, Norway and North America and in several remote areas in multiple countries. In 2011, Talisman initiated drilling operations in the Kurdistan region of northern Iraq, Papua New Guinea, Poland and offshore deepwater Indonesia. The Company plans to continue to seek new leases and drill in similar environments.

Health Hazards and Personal Safety Incidents

The employee and contractor personnel involved in activities and operations of the Company, including but not limited to well fracturing, are subject to many health and safety risks and hazards, which could result in occupational illness or health issues, personal injury and loss of life, facility quarantine and/or facility and personnel evacuation. In particular, employees working in well fracturing operations are subject to the possibility of loss of containment. This could lead to the release of high pressure materials as well as collateral shrapnel from piping and vessels, which could result in personal injury and loss of life.

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Security Incident

Talisman's operations may be adversely affected by security-related incidents which are not within the control of the Company, such as war (external and internal conflicts) and remnants of war, sectarian violence, civil unrest or criminal acts in locations where Talisman operates. In particular, the Company faces increased security risks in the Kurdistan region of northern Iraq and Colombia within Talisman's current portfolio. A significant security incident could result in the deferral of or termination of Company activity within the impacted areas of operations, thus adversely impacting execution of the Company's business strategy (e.g. delaying exploration, causing a halt to production or forcing exit strategy processes), which could adversely affect Talisman's financial position, results of operations and cash flows.

Regulatory Approvals and Changes to Laws and Regulations

Talisman's exploration and production operations are subject to extensive regulation at many levels of government, including municipal, state, provincial and federal governments, in the countries where Talisman operates and are subject to interruption or termination by governmental and regulatory authorities based on environmental or other considerations. Moreover, Talisman has incurred and will continue to incur costs in the Company's efforts to comply with the requirements of environmental, safety and other regulations. Further, the regulatory environment in the oil and gas industry could change in ways that Talisman cannot predict and that might substantially increase the Company's costs of compliance and, in turn, materially and adversely affect the Company's business, results of operations and financial condition.

Failure to comply with the applicable laws or regulations may result in significant increases in costs, fines or penalties and even shutdowns or losses of operating licences or criminal sanctions. If regulatory approvals or permits required for operations are delayed or not obtained, Talisman could experience delays or abandonment of projects, decreases in production and increases in costs. This could result in an inability of the Company to fully execute its strategy and adverse impacts on its financial condition. See also 'Risk Factors – Fiscal Stability' and 'Risk Factors – Socio-Political Risks'.

Changes to existing laws and regulations or new laws and regulations such as those described below could, if adopted, have an adverse effect on Talisman's business by increasing costs, reducing revenue and cash flow from natural gas and oil sales, reducing liquidity or otherwise altering the way Talisman conducts business. The Company cannot predict what additional laws or regulations (or amendments to existing laws or regulations) may be proposed or when such proposals, if enacted, might become effective. For example, the state of New York's updating of its Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program will likely cause delays in shale gas development in that state. In Pennsylvania, delays could also be experienced as Pennsylvania continues to update the Pennsylvania Oil & Gas Act and other state laws. In Quebec, delays in shale gas development are expected to continue as the province implements the various recommendations made by the BAPE, including the main recommendation that a strategic environmental assessment on shale gas development be performed. See also 'Risk Factors – Operational Risks – Hydraulic Fracturing'.

There have also been various proposals to enact new, or amend existing, laws and regulations relating to greenhouse gas (GHG) emissions, hydraulic fracturing (including associated additives, water use and disposal) and shale gas development generally. Such additional laws or regulations could also impact the Company's development schedule or costs of development and significantly affect the Company's operations and financial condition. See also 'Risk Factors – Environmental Risks'.

Talisman may also face regulatory delays in other areas. In particular, in Colombia, the high level of oil and gas activity in the country has resulted in significant delays in the granting of the required environmental permits to the oil and gas industry. While these delays are likely to be reduced as the respective governing bodies increase staff levels to match the increased demand, there is a risk of delays beyond current plans. These delays may result in reduced near-term production.

Talisman continues to monitor and assess any new policies, legislation, regulations and treaties in the areas where the Company operates to determine the impact on Talisman's operations. Governmental organizations unilaterally control the timing, scope and effect of any currently proposed or future laws, regulations or treaties and such enactments are subject to a myriad of factors, including political, monetary and social pressures. Talisman acknowledges that the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect the Company's business, results of operations and financial condition.

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Environmental Risks

General

All phases of Talisman's oil and natural gas business are subject to environmental regulation pursuant to a variety of laws and regulations in the countries where Talisman does business. These regulatory regimes consist of laws of general application that apply to the Company's business in the same manner as they apply to other companies or enterprises in the energy industry. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with the Company's drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from the Company's operations. Talisman's business is subject to the trend toward increased rigour in regulatory compliance and civil or criminal liability for environmental matters in certain regions (e.g. Canada, US and the European Union). Compliance with environmental legislation can require significant expenditures, and failure to comply with environmental legislation may result in the assessment of administrative, civil and criminal penalties, the cancellation or suspension of regulatory permits, the imposition of investigatory or remedial obligations or the issuance of injunctions restricting or prohibiting certain activities. Under existing environmental laws and regulations, Talisman could be held strictly liable for the removal or remediation of previously released materials or property contamination resulting from its operations, regardless of whether those operations were in compliance with all applicable laws at the time they were performed. Regulatory delays, legal proceedings and reputational impacts from an environmental incident could result in a material adverse effect on the Company's business. Increased stakeholder concerns and regulatory actions regarding shale gas development could lead to third-party or governmental claims, and could adversely affect the Company's business and financial condition. Although Talisman currently believes that the costs of complying with environmental legislation and dealing with environmental civil liabilities will not have a material adverse effect on the Company's financial condition or results of operations, there can be no assurance that such costs will not have such an effect in the future.

Hydraulic Fracturing

Concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including water aquifer contamination and other qualitative and quantitative effects on water resources as large quantities of water are used and injected fluids either remain underground or flow back to the surface to be collected, treated and disposed. As discussed below, regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns. Federal, provincial, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays,and adversely affect Talisman's production. Public perception of environmental risks associated with hydraulic fracturing can further increase pressure to adopt new laws, regulation or permitting requirements or lead to regulatory delays, legal proceedings and/or reputational impacts. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delay, increased operating costs, and third-party or governmental claims. They could also increase the Company's costs of compliance and doing business as well as delay the development of hydrocarbon (natural gas and oil) resources from shale formations, which may not be commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

In the event state, local, or municipal legal restrictions are adopted in areas where Talisman is currently conducting, or in the future plans to conduct operations, Talisman may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. In addition, if hydraulic fracturing becomes more regulated, the Company's fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

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Greenhouse Gas Emissions (GHG)

Talisman is subject to various GHG emissions-related legislation. Current GHG emissions legislation does not result in material compliance costs, but compliance costs may increase in the future and may impact the Company's operations and financial results. Talisman operates in jurisdictions with existing GHG legislation (e.g. UK, Norway, US and Canada, notably Alberta and British Columbia) as well as in regions which currently do not have GHG emissions legislation and jurisdictions where GHG emissions legislation is emerging or is subject to change. Talisman monitors GHG legislative developments in all areas that the Company operates. If the Company becomes subject to additional GHG legislation, there can be no assurances that the compliance costs will not have a material impact on the Company.

In the UK, Phase II of the European Union Emissions Trading Scheme (EU ETS) began in 2008 and will run until the end of 2012. The EU ETS requires that member states set emissions limits for installations in their country covered by the scheme and assigns such installations an emissions cap. Installations may meet their cap by reducing emissions or by buying allowances from other participants. Phase II impacts to the Company are minimal. Phase III of the EU ETS will potentially have a material impact on Talisman's business in the UK. The proposed Phase III legislation, which is to begin in 2013 and run until 2020, will significantly reduce emissions caps. In addition, free allowances for electrical power generation will no longer be issued. Approximately 50% of total Talisman UK emissions are associated with electrical power generation. Compliance costs associated with Phase III of the EU ETS may have a material impact on Talisman's business in the UK.

The Norwegian national GHG emissions trading system is linked to the EU ETS. Talisman is required to purchase emissions credits corresponding to its total annual CO₂ emissions, and to pay the CO₂ emissions tax. Starting January 2011, the Company was required to purchase emissions credits for mobile rigs in addition to payment for the mobile rig CO₂ emissions tax that began in 2010. Phase II ends in 2012 and compliance costs are not expected to be material to Talisman because the Norwegian government will adjust the CO₂ emissions tax so that total costs of the CO₂ emissions tax and emissions credit purchases are similar to the pre-2008 costs that were not material to Talisman. The proposed Phase III legislation, which is to begin in 2013 and run until 2020, will further reduce emissions caps for the Company's Norwegian operations, but the Company does not anticipate that the costs of compliance will be material considering its current compliance requirements.

Environmental and Decommissioning Liabilities

Talisman is involved in the operation and maintenance of facilities and infrastructure in difficult and challenging areas, including offshore, deepwater, jungle and desert environments. Despite Talisman's implementation of health, safety and environmental standards, there is a risk that accidents or regulatory misalignments can occur, the outcomes of which, including remedial work or regulatory intervention, cannot be foreseen or planned for. Talisman expects to incur site restoration costs over a prolonged period as existing fields are depleted. The Company provides for decommissioning liabilities in its annual Consolidated Financial Statements in accordance with IFRS. Additional information regarding decommissioning liabilities is set forth in the notes to the annual Consolidated Financial Statements. The process of estimating decommissioning liabilities is complex and involves significant uncertainties concerning the timing of the decommissioning activity; legislative changes; technological advancement; regulatory, environmental and political changes; and the appropriate discount rate used in estimating the liability. Any change to these assumptions could result in a change to the decommissioning liabilities to which Talisman is subject. In Talisman's North Sea operations, changes in these assumptions would potentially have a significant impact on the Company's decommissioning liabilities because of the size of these liabilities. There can be no assurances that the cost estimates and decommissioning liabilities are materially correct and that the liabilities will occur when predicted. In addition, Talisman is often jointly and severally liable for the decommissioning costs associated with Talisman's various operations, and could therefore be required to pay more than its net share.

Fiscal Stability

Governments may amend or create new legislation that could impact the Company's operations, which could result in increased capital, operating and compliance costs. For example, the British Columbia government could revoke its royalty holiday due to increasing shale gas development. Further examples include the potential increase in ring fence taxes due to

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the change in the supplementary charge in the UK as well as the potential for an aggregate change to environmental regulations in the US.

Moreover, Talisman's operations are subject to various levels of taxation in the countries where the Company operates. Income tax rates or incentive programs relating to the oil and gas industry and, in particular the UK, the US and Canadian foreign affiliate rules, may in the future be changed or interpreted in a manner that could materially affect the economic value of the respective assets, as was the case in 2011 when the UK unexpectedly significantly increased its supplementary charge on oil and gas production. Specifically, the US Congress has been considering a revision of the immediate deduction currently available for drilling costs.

Socio-Political Risks

The Company's operations may be adversely affected by political or economic developments or social instability in the jurisdictions in which it operates, which are not within the control of Talisman, including, among other things, a change in crude oil or natural gas pricing policy and/or related regulatory delays, the risks of war, terrorism, abduction, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, a change in taxation policies, economic sanctions, the imposition of specific drilling obligations, the imposition of rules relating to development and abandonment of fields and currency controls. As a result of continuing evolution of an international framework for corporate responsibility and accountability for international crimes, the Company could also be exposed to potential claims for alleged breaches of international law and other human rights-based litigation risk. Various countries in which the Company is active, including, but not limited to, the Kurdistan region of northern Iraq, Colombia, Vietnam, Papua New Guinea and Peru, have been subject to recent economic or political instability, disputes and social unrest, and military or rebel hostilities. The potential deterioration of socio-political security situations (i.e. political instability and/or disputes) poses increased risk which may result in the cessation of operations as well as the delay in payment or exports: for example in the Kurdistan region of northern Iraq (with the negotiation of Iraq Federal Oil and Gas Law), Peru (where the new government could change economic/fiscal policy direction and contractual terms), Vietnam (with respect to the escalation of China's claim over disputed waters in the South China Sea) as well as in Papua New Guinea (where national elections and the overall socio-political situation may cause slow or uncertain government approval and extension process, or result in a failure to obtain a strategic partner or partner misalignment or cause lack of licence commitment flexibility in drilling programs).

Stakeholder Opposition

Talisman's planned activities may be adversely affected if there is strong community opposition to its operations. For example, there are concerns regarding gas migration, impact on water resources, and general anti-hydraulic fracturing sentiments in North America and Europe. In some circumstances, this risk may be increased in areas occupied by indigenous communities that are not accustomed to developments of this nature and have concerns regarding land access and/or damage and claim compensation. In addition, Talisman regularly evaluates opportunities worldwide, and may in the future engage in projects or acquire properties in other nations that are experiencing economic or political instability, social unrest, military hostilities or United Nations, US or other international sanctions. Some of the foregoing government actions may lead to political or reputational pressures on the Company from non-governmental organizations, home governments and investors.

Ability to Find, Develop or Acquire Additional Reserves

The Company's future success depends largely on its ability to find and develop, or acquire, additional oil and gas reserves that are economically recoverable. Hydrocarbons are a limited resource, and Talisman is subject to increasing competition from other companies, including national oil companies. Exploration and development drilling may not result in commercially productive reserves and, if production begins, reservoir performance may be less than projected. Successful acquisitions require an assessment of a number of factors, many of which are uncertain. These factors include recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. If a high impact prospect identified by the Company fails to materialize in a given year, the Company's multi-year exploration and/or development portfolio may be compromised. See also 'Risk Factors – Volatility of Oil and Natural Gas Prices'.

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Uncertainty of Reserves Estimates

The process of estimating oil and gas reserves is complex and involves a significant number of assumptions in evaluating available geological, geophysical, engineering and economic data. In addition, the process requires future projections of reservoir performance and economic conditions; therefore, reserves estimates are inherently uncertain. Since all reserves estimates are, to some degree, uncertain, reserves classification attempts to qualify the degree of uncertainty involved.

Since the evaluation of reserves involves the evaluator's interpretation of available data and projections of price and other economic factors, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on estimated uncertainty, and the estimates of future net revenue or future net cash flows prepared by different evaluators or by the same evaluators at different times may vary substantially.

Each year, Talisman prepares evaluations of all of its reserves internally. Initial estimates of reserves are often based upon volumetric calculations and analogy to similar types of reservoirs, rather than actual well data and performance history. Estimates based on these methods generally are less certain than those based on actual performance. The Company may adjust its estimates and classification of reserves and future net revenues or cash flows based on results of exploration and development drilling and testing, additional performance history, prevailing oil and gas prices, and other factors, many of which are beyond the Company's control. As new information becomes available, subsequent evaluations of the same reserves may continue to have variations in the estimated reserves, some of which may be material. In addition, Talisman's actual production, taxes and development and operating expenditures with respect to its reserves will likely vary from such estimates and such variances could be material.

Project Timing

Talisman manages a variety of projects, including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may impact expected revenues and project cost overruns could make projects uneconomic. Talisman's ability to complete projects depends upon numerous factors, many of which are beyond the Company's control. These factors include the level of direct control by Talisman since many of the projects in which Talisman is involved are not operated by Talisman and timing and project management control are the responsibility of the operator. See also 'Risk Factors – Non-Operatorship'. In particular, the majority of the Company's operations in Colombia are non-operated. Additionally, for Talisman operated projects, the global demand for project resources can impact the access to appropriately competent contractors and construction yards as well as to raw products, such as steel. Typical execution risks include the availability of processing capacity, the availability and proximity of pipeline capacity, the availability of drilling and other equipment, the ability to access lands, weather, unexpected cost increases, accidents, the availability of skilled labour, including engineering and project planning personnel, the need for government approvals and permits, and regulatory matters. Subsurface challenges can also result in additional risk of cost and schedule overrun if conditions are not typical of historical experiences, such as in up-scaling shale operations from pilot to full field developments. Talisman utilizes materials and services which are subject to general industry-wide conditions. Cost escalation for materials and services may be unrelated to commodity price changes and may continue to have a significant impact on project planning and economics. Talisman operates in challenging, environmentally hostile climates, such as Papua New Guinea, where logistical costs can be materially impacted by seasonal and occasionally unanticipated weather patterns. Contracts where work has been placed under a lump sum arrangement, for example with the Company's Yme project, are subject to additional scheduling challenges as the contractor is wholly responsible for delivery of the facility.

Egress and Gas Buyers

As rapidly increasing volumes of natural gas and liquids are brought onstream by Talisman and others, transportation infrastructure capacity may at times be exceeded before capacity additions become available. In such event, there is a risk that some production may be affected waiting on pipeline connection or infrastructure additions. In particular, Colombia's oil export infrastructure is currently producing at or near capacity, pending capacity additions which are at various stages of approval and construction. While Equión has access to the key Ocensa and Oleoducto de Colombia (ODC) pipelines, pipeline egress from the Llanos Basin to the main export terminal at Covenas presents a risk. Although additional pipeline projects are underway

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and oil can be trucked to Covenas, capacity restrictions may result in a portion of Talisman's production being reduced or delayed as pipeline connection and infrastructure additions are implemented and/or netbacks reduced on a portion of Talisman's production due to the materially higher costs of trucking. There are similar egress risks in the liquids-rich Eagle Ford. Currently, there is limited existing transportation and associated midstream infrastructure. Talisman has and is in the process of obtaining access to infrastructure for both liquids and gas within the Eagle Ford. However, additional capacity and infrastructure will be required. As a result, there are multiple pipeline and processing projects underway aimed at meeting the growing production needs in the area. Another associated risk will be the availability and diversity of buyers depending upon the pipeline and infrastructure project with which Talisman obtains capacity. Should Talisman be unable to secure access to infrastructure and buyers, a result could be reduced production and/or materially lower prices on some portion of production, which in turn could adversely affect the Company's operating results.

Non-operatorship

Some of Talisman's projects are conducted in joint venture environments where Talisman has a limited ability to influence or control operations or future development, safety and environmental standards and amount of capital expenditures. Companies which operate these properties may not necessarily share Talisman's health, safety and environmental standards or strategic or operational goals, which may result in accidents, regulatory misalignments, project delays or unexpected future costs, all of which may affect the viability of these projects.

Talisman is also dependent on other working interest co-participants of these projects to fund their contractual share of the capital expenditures. If these co-participants are unable to fund their contractual share of, or do not approve, the capital expenditures, the co-participants may seek to defer programs, resulting in strategic misalignments and a delay of a portion of development of Talisman's programs, or the co-participants may default such that projects may be delayed and/or Talisman may be partially or totally liable for their share.

Industry Cost Inflation

The industry costs to find and develop reserves have generally risen over time. An upward rise in industry activity could increase key input demand and prices, at least in the short run, and possibly delay sourcing of key labour, materials or facilities construction. Rising industry costs broadly correspond with higher oil and gas prices but, in a competitive market among competing fuels, it is possible that not all costs may be recovered through higher prices. Although the Company strives for continuous improvement in its planning, operations and procurement, material or unexpected changes can affect the Company's financial performance.

Attraction, Retention, and Development of Personnel

Successful execution of the Company's plans is dependent on Talisman's ability to attract and retain talented personnel who have the skills necessary to deliver on the Company's strategy and maintain safe operations. This includes not only key talent at a senior level, but also individuals with the professional and technical skill sets critical for Talisman's business, particularly drilling and completions and geosciences. As labour demand remains high and a greater percentage of the population reaches retirement age, retention concerns are also heightened. In particular, growth in Talisman's Eagle Ford shale business requires additional people resources to match the Company's desired activity level; if unmet, this could adversely impact Talisman's ability to deliver. Additionally, in the North Sea, high project activity has compounded competition for labour, posing an increased retention risk. Various national regimes, partnerships and joint venture activities may also impose requirements to develop their talent, increase secondee assignments, and employ local nationals.

Competitive Risk

The global oil and gas industry is highly competitive. Talisman faces significant competition and many of the Company's competitors have resources in excess of Talisman's available resources. The Company actively competes for the acquisition of properties, the exploration for and development of new sources of supply, the contractual services for oil and gas drilling and production equipment and services, the transportation and marketing of current production, and industry personnel, including, but not limited to, geologists, geophysicists, engineers and other specialists that enable the business. Many of Talisman's

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competitors have the ability to pay more for seismic and lease rights in crude oil and natural gas properties and exploratory prospects. They can define, evaluate, bid for and purchase a greater number of properties and prospects than Talisman's financial or human resources permit. If the Company is not successful in the competition for oil and gas reserves or in the marketing of production, Talisman's financial condition and results of operations may be adversely affected. Many of the Company's competitors have resources substantially greater than Talisman's and have established positions in countries in which Talisman may seek new entry and, as a consequence, the Company may be at a competitive disadvantage. Typically during times of high commodity prices or increased industry activity, drilling and operating costs will also increase. These competitive forces may also lead to an overall increase in costs, which could have a negative impact on the Company's financial results.

Litigation

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Specific disclosure of current legal proceedings, and the risks associated with current proceedings and litigation generally, are disclosed under the heading 'Litigation' in this MD&A.

Credit and Liquidity

From time to time, the Company may finance capital expenditures in whole or in part with debt. While the Company may have access to various financing options, including draws on existing facilities and the issuance of debt or equity, the terms of such financing options may not be acceptable to the Company. A reduction in any of the Company's current investment-grade credit ratings to below investment grade would likely adversely affect the cost of borrowing and/or access to sources of liquidity and capital, and reduce the financing options available to the Company. Additionally, the Company relies on access to letters of credit in the normal course of business in order to support some of its operations. There can be no assurance that the Company will be able to obtain the necessary letters of credit. See also 'Risk Factors – Capital Allocation and Project Decisions'.

During the last few years, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, and the health of the US and European economies have contributed to increased economic uncertainty and diminished expectations for the global economy. If an economic recovery in the US or European Union is slow or prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which Talisman can sell oil, natural gas and NGLs, affect the ability of vendors, suppliers and customers to continue operations, and ultimately adversely impact the Company's results of operations, liquidity and financial condition. Additionally, a portion of the Company's long-term debt is syndicated among European, including French, banks, and Talisman has exposure to these financial institutions via derivative transactions. In light of recent instability and weakness in the European markets, if any lender under Talisman's credit facility is unable to fund its commitment, the Company's liquidity will be reduced by an amount up to the aggregate amount of such lender's commitment. See also 'Risk Factors – Counterparty Credit Risk'.

Interest Rates

The Company is exposed to interest rate risk principally by virtue of its borrowings. Borrowing in floating rates exposes Talisman to short-term movements in interest rates. Borrowing in fixed rates exposes Talisman to reset risk associated with debt maturity. Most of the Company's debt is issued at fixed interest rates; therefore, the Company's main exposure to changes in interest rates would occur in respect of short-term investments or borrowings in the event that substantial cash balances are invested by or owed to the Company.

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Hedging Activities

Talisman uses derivative instruments (primarily financial collars and puts) to hedge a portion of the Company's expected production so as to manage the impact of fluctuations in crude oil and natural gas prices on the Company's results of operations and cash flow. Fluctuations in crude prices could have a material effect on the volatility of the Company's earnings. To the extent that Talisman engages in hedging activities to protect itself against commodity price declines, Talisman may be prevented from fully realizing the benefits of increases in crude oil and natural gas prices above the prices established by the Company's hedging contracts. The Company also uses currency swaps to manage fluctuations in exchange rates and interest rate swaps to manage Talisman's exposure to interest rate changes through the Company's borrowings. See also 'Risk Factors – Exchange Rate Fluctuations' and 'Risk Factors – Interest Rates'.

Additionally, Talisman's hedging portfolio may expose it to financial losses in certain circumstances, such as the recognition of certain mark-to-market gains and losses on derivative instruments. The fair value of the Company's natural gas and oil, exchange rate or interest rate derivative instruments can fluctuate significantly between periods.

Counterparty Credit Risk

In the normal course of business, Talisman enters into contractual relationships with counterparties in the energy industry and other industries, including suppliers and coventurers, counterparties to interest rate hedging, foreign exchange hedging and commodity derivative arrangements. If such counterparties do not fulfil their contractual obligations or settle their liabilities to the Company, the Company may suffer losses, may have to proceed on a sole risk basis, may have to forgo opportunities or may have to relinquish leases or blocks. The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions. While the Company maintains a risk management system that limits exposures to any one counterparty, losses due to the failure by counterparties to fulfil their contractual obligations may adversely affect Talisman's financial condition.

Corruption

Talisman's operations are governed by the laws of many jurisdictions, which generally prohibit bribery and other forms of corruption. It is possible that Talisman, or some of its employees or contractors, could be charged with bribery or corruption. Talisman requires all employees to participate in ethics awareness training, which includes Talisman's policies against giving or accepting money or gifts in certain circumstances. However, if Talisman is found guilty of such a violation, which could include a failure to take effective steps to prevent or address corruption by its employees or contractors, Talisman could be subject to onerous penalties. A mere investigation itself could lead to significant corporate disruption, high legal costs and forced settlements (such as the imposition of an internal monitor). In addition, bribery allegations or bribery or corruption convictions could impair Talisman's ability to work with governments or non-governmental organizations. Such convictions or allegations could result in the formal exclusion of Talisman from a country or area, national or international lawsuits, government sanctions or fines, project suspension or delays, reduced market capitalization and increased investor concern.

Information Systems

Many of Talisman's business processes depend on the availability, capacity, reliability and security of the Company's information technology infrastructure (IT) and Talisman's ability to expand and continually update this infrastructure in response to the Company's changing needs. The Company's IT systems are increasingly concentrated in terms of geography, number of systems, and key contractors supporting the delivery of IT systems. The performance of Talisman's key suppliers is critical to ensure appropriate delivery of key services. Any failure to manage, expand and update the Company's information technology infrastructure, any failure in the extension or operation of this infrastructure, or any failure by the Company's key contractors in the performance of their services could materially and adversely harm Talisman's business. Additionally, the increasing risk of information security breaches, including more sophisticated attempts often referred to as advanced persistent threats, requires Talisman to increase its ability to detect and prevent such occurrences. Disruption of critical IT services, or breaches of information security, could have a negative effect on Talisman's operational performance and earnings, as well as on the Company's reputation.

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TALISMAN ENERGY ANNUAL REPORT 2011

ADVISORIES

Forward-Looking Statements

This MD&A contains information that constitutes "forward-looking information" or "forward-looking statements" (collectively "forward-looking information") within the meaning of applicable securities legislation. Forward-looking information is included throughout this MD&A, including, among other places, under the headings 'Outlook for 2012' and 'Risk Factors'. This forward-looking information includes, but is not limited to, statements regarding:

•: Expected outcomes and events of the elements of the business strategy;
•: The estimated impact on Talisman's financial performance from changes in production volume, commodity prices and exchange rates;
•: The effects of the hedging program;
•: Anticipated funding of decommissioning obligations;
•: Expected future payment commitments and receipts, including share-based payments expenses in future periods;
•: Expected capital spending and spending focus, company-wide and regionally;
•: Expected production and production growth, company-wide and regionally;
•: Planned dispositions and/or farmouts and related proceeds;
•: Planned rigs and drilling in North America;
•: Planned upgrades, projects and drilling in the North Sea;
•: Expected first oil at the HST/HSD development;
•: Timing of Yme first production and related impacts on production;
•: Planned drilling and seismic in Southeast Asia; and
•: Planned exploration, appraisal and stratigraphic drilling in Colombia, and planned sanctioning of the Piedemonte expansion.

Statements concerning oil and gas reserves contained in this MD&A may be deemed to be forward-looking information as they involve the implied assessment that the resources described can be profitably produced in the future.

The factors or assumptions on which the forward-looking information is based include: assumptions inherent in current guidance; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; ability to obtain regulatory and partner approval; commodity price and cost assumptions; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 2012 assumes escalating commodity prices.

Closing of any transactions will be subject to receipt of all necessary regulatory approvals and completion of definitive agreements. The disposition metrics disclosed assume closing of all dispositions announced. The completion of any contemplated disposition is contingent on various factors, including favourable market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approval for such disposition.

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

57
TALISMAN ENERGY ANNUAL REPORT 2011

instances to differ materially from those anticipated by Talisman and described in the forward-looking information contained in this MD&A. The material risk factors include, but are not limited to:

•: The risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas, market 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, including decommissioning liabilities;
•: Risks related to capital allocation decisions, including 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, interest rates and tax or royalty rates;
•: The outcome and effects of any future acquisitions and dispositions;
•: Health, safety, security and environmental risks, including risks related to the possibility of major accidents;
•: Environmental regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing;
•: Uncertainties as to the availability and cost of credit and other financing and changes in capital markets;
•: Risks in conducting foreign operations (for example, civil, political and fiscal instability and corruption);
•: Risks related to the attraction, retention and development of personnel;
•: Changes in general economic and business conditions;
•: The possibility that government policies, regulations 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 AIF and Annual Report. In addition, information is available in the Company's other reports on file with Canadian securities regulatory authorities and the 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 Data and Other Oil and Gas Information

Talisman's disclosure of reserves data and other oil and gas information in accordance with US disclosure standards is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities, which permits Talisman to provide such disclosure in order to allow comparison of oil and gas disclosure with that provided by US and other peers. The primary differences between the US disclosure standards and the Canadian disclosure mandated under NI 51-101 are that:

a): NI 51-101 requires disclosure of gross and net reserves using forecast prices, whereas the SEC rules require the disclosure of net reserves estimated using a historical 12-month average price;
b): NI 51-101 requires the disclosure of the net present value of future net revenue attributable to all of the disclosed reserve categories, estimated using forecast prices and costs, before and after deducting income tax expenses, calculated without discount and using discount rates of 5%, 10%, 15% and 20%, whereas the SEC rules require disclosure of the present

58
TALISMAN ENERGY ANNUAL REPORT 2011

value of future net cash flows attributable to proved reserves only, estimated using a constant price (the historical 12-month average price) and a 10% discount rate;

c): NI 51-101 requires a one-year reconciliation of gross proved reserves, gross probable reserves and gross proved plus probable reserves, based on forecast prices and costs, for various product types, whereas the SEC rules require three-year reconciliation of net proved reserves, based on constant prices and costs, for less specific product types;
d): NI 51-101 requires reserves to show a hurdle rate of return, whereas the SEC rules require reserves to be only cash flow positive on an undiscounted basis.

Further information on the differences between the US standards and NI 51-101 requirements is set forth under the heading 'Note Regarding Reserves Data and Other Oil and Gas Information' in Talisman's most recent AIF.

The information provided by Talisman in this MD&A may differ from the corresponding information prepared in accordance with NI 51-101 standards. Talisman's proved and probable reserves, using SEC annual average pricing methodology, have been estimated using the standards contained in Regulation S-X of the SEC, which requires that proved and probable reserves be estimated using existing economic and operating conditions.

An exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data contained in this MD&A reflects Talisman's internally-generated estimates of its reserves.

Gross Production

Throughout this MD&A, 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. US readers may refer to the table headed 'Net Production After Royalties' in Talisman's most recent AIF for a statement of Talisman's net production volumes by reporting segment that are comparable to those made by US companies subject to SEC reporting and disclosure requirements.

Netbacks

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

Financial Outlook

Included in this MD&A is the Company's financial outlook. Its purpose is to enrich management's discussion and analysis. This information may not be appropriate for other purposes.

ABBREVIATIONS AND DEFINITIONS

The following abbreviations and definitions are used in this document:

AIF		Annual Information Form
bbl		barrel
bbls		barrels
bbls/d		barrels per day
bcf		billion cubic feet
boe		barrels of oil equivalent
boe/d		barrels of oil equivalent per day
C$		Canadian dollar
CO₂		Carbon dioxide
E&E		Exploration and evaluation
EU		European Union
G&A		General and administrative

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TALISMAN ENERGY ANNUAL REPORT 2011

GAAP		Generally Accepted Accounting Principles
gj		Gigajoule
IFRS		International Financial Reporting Standards
LIBOR		London Interbank Offered Rate
LNG		Liquefied Natural Gas
mbbls/d		thousand barrels per day
mboe/d		thousand barrels of oil equivalent per day
mcf		thousand cubic feet
mmbbls		million barrels
mmboe		million barrels of oil equivalent
mmbtu		million British thermal units
mmcf/d		million cubic feet per day
mmcfe/d		million cubic feet equivalent per day
NGL		Natural Gas Liquids
NI		National Instrument
NOK		Norwegian Kroner
NYMEX		New York Mercantile Exchange
OPEC		Organization of Petroleum Exporting Countries
PGN		PT Perusahaan Gas Negara (Persero) Tbk
PP&E		Property, plant and equipment
PRT		Petroleum Revenue Tax
PSC		Production Sharing Contract
PSU		Performance share unit
SEC		US Securities and Exchange Commission
tcf		trillion cubic feet
UK		United Kingdom
UK£		Pound sterling
US		United States of America
US$ or $		United States dollar
WTI		West Texas Intermediate

Gross acres means the total number of acres in which Talisman has a working interest. Net acres means the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Gross production means Talisman's interest in production volumes (through working interests and royalty interests) before the deduction of royalties. Net production means Talisman's interest in production volumes after deduction of royalties payable by Talisman.

Gross wells means the total number of wells in which the Company has a working interest. Net wells means the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Conversion and equivalency factors

Imperial		Metric
1 ton		= 0.907 tonnes
1 acre		= 0.40 hectares
1 barrel		= 0.159 cubic metres
1 cubic foot		= 0.0282 cubic metres

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TALISMAN ENERGY ANNUAL REPORT 2011

Report of Management

Management is responsible for the Consolidated Financial Statements.

Management has prepared the Consolidated Financial Statements in accordance with International Financial Reporting Standards. If alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has ensured that the Consolidated Financial Statements are presented fairly in all material respects.

The Board of Directors is responsible for reviewing and approving the Consolidated Financial Statements and Management's Discussion and Analysis and, primarily through its Audit Committee, ensures that management fulfils its responsibilities for financial reporting.

The Audit Committee is appointed by the Board of Directors and is composed entirely of unrelated, independent directors. The Audit Committee meets regularly with management, and with the internal and external auditors, to discuss internal controls and reporting issues and to satisfy itself that each party is properly discharging its responsibilities. It reviews the Consolidated Financial Statements and the external auditors' report. The Audit Committee also considers, for review by the Board of Directors and approval by the shareholders, the engagement or reappointment of the external auditors.

Ernst & Young LLP, the external auditors, have audited the Consolidated Financial Statements in accordance with auditing standards generally accepted in Canada and the standards of the Public Company Accounting Oversight Board (United States) on behalf of the shareholders. Ernst & Young LLP have full and free access to the Audit Committee.

Management Report on Internal Control over Financial Reporting

Management has conducted an evaluation of the Company's internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on management's assessment as at December 31, 2011, the end of the Company's fiscal year, management has concluded that the Company's internal control over financial reporting is effective.

The results of management's assessment were reviewed with the Audit Committee of the Company's Board of Directors. Ernst & Young LLP, the independent registered public accounting firm that audited the Company's Consolidated Financial Statements included herewith, independently assessed the effectiveness of the Company's internal control over financial reporting. Ernst & Young LLP's attestation is located in the Independent Auditors' Report on Internal Controls under Standards of the Public Company Accounting Oversight Board (United States), which is an exhibit to the Company's Annual Report on Form 40-F.



John A. Manzoni		L. Scott Thomson
President and Chief Executive Officer		Executive Vice-President, Finance and Chief Financial Officer
March 1, 2012

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TALISMAN ENERGY ANNUAL REPORT 2011

Independent Auditors' Report on Internal Controls Under
Standards of the Public Company Accounting Oversight
Board (United States)

To the Shareholders of Talisman Energy Inc.

We have audited Talisman Energy Inc.'s internal control over financial reporting as at December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Talisman Energy Inc.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Talisman Energy Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the Consolidated Balance Sheets of Talisman Energy Inc. as at December 31, 2011 and 2010 and January 1, 2010 and the Consolidated Statements of Income, Comprehensive Income, Changes in Shareholders' Equity and Cash Flows for the years ended December 31, 2011 and 2010, and our report dated March 1, 2012 expressed an unqualified opinion thereon.

Chartered Accountants

Calgary, Canada
March 1, 2012

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TALISMAN ENERGY ANNUAL REPORT 2011

Independent Auditors' Report of Registered Public Accounting Firm

To the Shareholders of Talisman Energy Inc.

We have audited the accompanying Consolidated Financial Statements of Talisman Energy Inc., which comprise the Consolidated Balance Sheets as at December 31, 2011 and 2010, and January 1, 2010, and the Consolidated Statements of Income, Comprehensive Income, Changes in Shareholders' Equity and Cash Flows for the years ended December 31, 2011 and 2010, and a summary of significant accounting policies and other explanatory information.

MANAGEMENT'S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

AUDITORS' RESPONSIBILITY

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OPINION

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of Talisman Energy Inc. as at December 31, 2011 and 2010, and January 1, 2010, and its financial performance and cash flows for the years ended December 31, 2011 and 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

OTHER MATTER

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Talisman Energy Inc.'s internal control over financial reporting as at December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2012 expressed an unqualified opinion on Talisman Energy Inc.'s internal control over financial reporting.

Chartered Accountants

Calgary, Canada
March 1, 2012

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TALISMAN ENERGY ANNUAL REPORT 2011

Consolidated Balance Sheets


		December 31,	December 31,	January 1,
(millions of US$)		2011	2010	2010

			(note 4)	(note 4)
Assets
Current

	Cash and cash equivalents (note 28)	474	1,655	1,628

	Accounts receivable (note 9)	1,550	1,287	1,216

	Risk management (note 22)	42	119	29

	Inventories (note 10)	164	144	141

	Prepaid expenses	24	20	8

	Assets held for sale (note 5)	–	–	22

		2,254	3,225	3,044

Other assets (note 11)		101	667	74

Investments (note 12)		395	121	34

Risk management (note 22)		24	25	40

Goodwill (note 8)		1,317	1,164	1,183

Property, plant and equipment (note 13)		15,909	13,266	13,254

Exploration and evaluation assets (note 13)		3,954	3,442	2,212

Deferred tax assets (note 26)		272	184	147

		21,972	18,869	16,944

Total assets		24,226	22,094	19,988

Liabilities
Current

	Bank indebtedness	60	2	35

	Accounts payable and accrued liabilities	2,622	2,722	2,040

	Risk management (note 22)	–	117	266

	Income and other taxes payable	371	513	341

	Current portion of long-term debt (note 17)	410	359	10

	Liabilities associated with assets held for sale (note 5)	–	–	7

		3,463	3,713	2,699

Decommissioning liabilities (note 15)		2,982	2,580	2,003

Other long-term obligations (note 18)		346	326	316

Risk management (note 22)		–	–	6

Long-term debt (note 17)		4,485	3,845	3,601

Deferred tax liabilities (note 26)		2,932	2,435	2,516

		10,745	9,186	8,442

Contingencies and commitments (note 23)
Shareholders' equity

Common shares (note 20)		1,561	1,480	1,401

Preferred shares (note 20)		191	–	–

Contributed surplus		186	108	117

Retained earnings		7,292	6,819	6,135

Accumulated other comprehensive income (note 21)		788	788	1,194

		10,018	9,195	8,847

Total liabilities and shareholders' equity		24,226	22,094	19,988

See accompanying notes.

On behalf of the Board:


Charles R. Williamson		William R. P. Dalton
Chairman of the Board		Director

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TALISMAN ENERGY ANNUAL REPORT 2011

Consolidated Statements of Income


Years ended December 31 (millions of US$)		2011		2010

				(note 4)
Revenue

	Sales	8,194		6,875

	Other income (note 24)	78		107

Total revenue and other income		8,272		6,982

Expenses

	Operating	2,190		1,890

	Transportation	216		221

	General and administrative	431		371

	Depreciation, depletion and amortization	1,949		1,788

	Impairment (note 14)	226		301

	Dry hole	241		113

	Exploration	427		374

	Finance costs (note 16)	278		276

	Share-based payments expense (recovery) (note 20)	(310	)	212

	(Gain) loss on held-for-trading financial instruments (note 22)	210		(87	)

	Gain on asset disposals (note 5)	(192	)	(520	)

	Other, net (note 25)	161		72

Total expenses		5,827		5,011

Income before taxes		2,445		1,971

Income taxes (note 26)

	Current income tax	1,441		1,136

	Deferred income tax (recovery)	228		(110	)

		1,669		1,026

Net income		776		945

Per common share (US$):

	Net income	0.76		0.93

	Diluted net income	0.38		0.93

Weighted average number of common shares outstanding (millions)

	Basic (note 29)	1,023		1,018

	Diluted (note 29)	1,038		1,018

See accompanying notes.

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TALISMAN ENERGY ANNUAL REPORT 2011

Consolidated Statements of Comprehensive Income


Years ended December 31 (millions of US$)		2011		2010

				(note 4)
Net income		776		945

Foreign currency translation¹		–		(408	)

Actuarial losses relating to pension and other post-employment benefits²		(26	)	(12	)

Gains on derivatives designated as cash flow hedges

	Gains arising during the year³	–		13

	Gains recognized in net income⁴	–		(11	)

		–		2

Other comprehensive loss		(26	)	(418	)

Comprehensive income		750		527

1: Includes net investment hedging gain of $nil (2010 – $22 million)
2: Net of tax of $29 million (2010 – $1 million)
3: Net of tax of $nil (2010 – $5 million)
4: Net of tax of $nil (2010 – $4 million)

See accompanying notes.

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TALISMAN ENERGY ANNUAL REPORT 2011

Consolidated Statements of Changes in Shareholders' Equity


Years ended December 31 (millions of US$)	2011		2010

			(note 4)
Common shares

Balance at beginning of year	1,480		1,401

Issued on exercise of stock options	175		95

Shares purchased and held in trust for long-term PSU plan (note 20)	(94	)	(81	)

Shares released from trust for 2008 PSU plan (note 20)	–		65

Balance at end of year	1,561		1,480

Preferred shares

Balance at beginning of year	–		–

Issued (note 20)	191		–

Balance at end of year	191		–

Contributed surplus

Balance at beginning of year	108		117

Share-based payments (note 20)	78		(9	)

Balance at end of year	186		108

Retained earnings

Balance at beginning of year	6,819		6,135

Net income	776		945

Actuarial losses transferred to retained earnings	(26	)	(12	)

Common share dividends (note 20)	(277	)	(249	)

Balance at end of year	7,292		6,819

Accumulated other comprehensive income

Balance at beginning of year	788		1,194

Other comprehensive loss	(26	)	(418	)

Actuarial losses transferred to retained earnings	26		12

Balance at end of year	788		788

See accompanying notes.

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TALISMAN ENERGY ANNUAL REPORT 2011

Consolidated Statements of Cash Flows


Years ended December 31 (millions of US$)		2011		2010

				(note 4)
Operating activities

Net income		776		945

Add: Finance costs (cash and non-cash) (note 16)		278		276

Dividends from equity investments		9		–

Items not involving cash (note 27)		2,124		1,556

		3,187		2,777

Changes in non-cash working capital (note 27)		(375	)	367

Cash provided by operating activities		2,812		3,144

Investing activities
Capital expenditures

	Exploration, development and other	(4,303	)	(3,566	)

	Corporate acquisitions, net of cash acquired (note 7)	(156	)	(183	)

	Property acquisitions (note 6)	(737	)	(1,340	)

Proceeds of resource property dispositions (note 5)		527		2,194

Repayment of note receivable (note 22)		40		–

Acquisition deposit		18		(630	)

Investments		54		–

Changes in non-cash working capital		18		274

Cash used in investing activities		(4,539	)	(3,251	)

Financing activities

Long-term debt repaid (note 17)		(313	)	(10	)

Long-term debt issued (note 17)		1,044		595

Common shares issued (note 20)		114		55

Common shares purchased (note 20)		(94	)	(75	)

Preferred shares issued (note 20)		191		–

Finance costs (cash)		(202	)	(197	)

Common share dividends (note 20)		(277	)	(249	)

Deferred credits and other		(9	)	(2	)

Changes in non-cash working capital		11		(1	)

Cash provided by financing activities		465		116

Effect of translation on foreign currency cash and cash equivalents		23		51

Net increase (decrease) in cash and cash equivalents		(1,239	)	60

Cash and cash equivalents net of bank indebtedness, beginning of year		1,653		1,593

Cash and cash equivalents net of bank indebtedness, end of year		414		1,653

Cash and cash equivalents (note 28)		474		1,655

Bank indebtedness		(60	)	(2	)

Cash and cash equivalents net of bank indebtedness, end of year		414		1,653

See accompanying notes.

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TALISMAN ENERGY ANNUAL REPORT 2011

Notes to the Consolidated Financial Statements

(tabular amounts in millions of US$, except as noted)

1. CORPORATE INFORMATION

Talisman Energy Inc. ('Talisman' or 'the Company') is a public company incorporated pursuant to the laws of Canada and domiciled in Alberta, Canada, with common shares listed on the Toronto and New York stock exchanges under the symbol TLM. The registered office is located at Suite 2000, 888 – 3^rd Street SW, Calgary, Alberta, Canada, T2P 5C5.

The Company is in the business of exploration, development, production and marketing of crude oil, natural gas and natural gas liquids (NGLs).

The Consolidated Financial Statements as at and for the year ended December 31, 2011 were authorized for issuance by the Board of Directors on March 1, 2012.

2. BASIS OF PREPARATION

The Consolidated Financial Statements of Talisman Energy Inc. represent the first annual financial statements of the Company and its subsidiaries prepared in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC). Previously, the Company prepared its annual Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles then applicable to publically accountable enterprises (Canadian GAAP or CGAAP).

Since this is the Company's initial year presenting its financial position, results of operations and cash flows under IFRS, these Consolidated Financial Statements have been prepared in accordance with IFRS 1 First-Time Adoption of IFRS.

The preparation of these Consolidated Financial Statements resulted in changes to accounting policies as compared with the most recent annual Consolidated Financial Statements prepared in accordance with Canadian GAAP. The accounting policies set out below have been applied consistently to all periods presented in these Consolidated Financial Statements and in preparing an opening IFRS balance sheet as at January 1, 2010, as required by IFRS 1. The impact of the transition from Canadian GAAP to IFRS is presented in note 4.

These Consolidated Financial Statements were prepared on a going concern basis, under the historical cost convention, except for certain financial assets and financial liabilities measured at fair value through the Consolidated Statement of Income.

The preparation of Consolidated Financial Statements in accordance with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise judgment in applying the Company's accounting policies. The areas of accounting that require a high degree of judgment or which are based upon significant estimates are disclosed in note 3(y).

3. SIGNIFICANT ACCOUNTING POLICIES

a) Consolidation

The Consolidated Financial Statements include the accounts of Talisman and its subsidiaries, being those companies over which the Company, either directly or indirectly, has control through a majority of the voting rights or the right to exercise control or to obtain the majority of the benefits and be exposed to the majority of the risks. Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases, using consistent accounting policies. All intercompany balances and transactions, including unrealized profits arising from such transactions, are eliminated upon consolidation. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

b) Joint Ventures and Investments

A jointly controlled asset offers joint ownership by the venturers of the assets contributed to the joint venture, without the formation of a corporation, partnership or other entity.

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A jointly controlled entity is a company, partnership or other entity in which each venturer has an interest and jointly controls the assets of the entity, earning its own income and incurring its own liabilities and expenses. Interests in jointly controlled entities are accounted for using proportionate consolidation.

Substantially all of Talisman's activities are conducted jointly with others, and the Consolidated Financial Statements reflect only the Company's proportionate interest in such activities.

Interests in entities over which Talisman has significant influence, but not control or joint control, are accounted for using the equity method. Talisman's share of the income of equity investments is recorded in the Consolidated Statement of Income. Dividends from equity investments are included in cash provided by operating activities. Interests in entities over which Talisman does not have significant influence are recorded at cost. Both equity and cost investments are tested for possible impairment whenever events or changes in circumstances indicate that the carrying value of the investment may not be recoverable.

c) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method. The cost of an acquisition is the aggregate of the consideration transferred, measured at acquisition date fair value. Acquisition costs incurred are expensed. When the Company acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts acquired.

Contingent consideration to be transferred by the Company is recognized at fair value at the acquisition date. Subsequent changes to the fair value of contingent consideration recorded as a financial asset or liability are recognized in net income in accordance with IAS 39 Financial Instruments: Recognition and Measurement.

Goodwill represents the excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed in business combinations. Goodwill is not amortized but is subject to impairment reviews annually, or more frequently as economic events dictate, as described in note 3(i).

Where goodwill forms part of an operating segment and part of the operation within that segment is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the segment retained.

d) Accounts Receivable

Accounts receivable are recorded based on the Company's revenue recognition policy. The allowance for doubtful accounts is management's best estimate of accounts receivable balances that may not be collectible, and is reviewed quarterly.

e) Inventories

Inventories are valued at the lower of cost and net realizable value. Cost comprises direct purchase costs, cost of production and taxes, and is determined using the first-in first-out method for product inventories and by the average cost method for materials and supplies. Net realizable value is determined by reference to prices existing at the balance sheet date less any costs expected to be incurred to completion and disposal.

f) Property, Plant and Equipment (PP&E)

PP&E, comprising oil and gas development and production properties and corporate assets, is stated at cost less accumulated depreciation, depletion and amortization and accumulated impairment losses.

Oil and gas development and production expenditure is generally accounted for using the principles of the successful efforts method of accounting. Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells is capitalized within PP&E.

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The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning liability and capitalized borrowing costs for qualifying assets. The capitalized value of a finance lease is also included within PP&E.

Expenditure on turnarounds comprises the cost of replacement assets or parts of assets and inspection and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits will flow to the Company from the replacement, the expenditure is capitalized and the replaced part is derecognized. Inspection and overhaul costs relating to turnarounds, which generally occur annually, and all other repairs and maintenance costs are expensed when incurred.

Well injection costs incurred to stimulate depleted wells are charged as an expense when incurred. Certain stimulation costs which increase production and reserves, extending beyond one year, are deferred in PP&E and depleted using the unit of production method.

Exchanges of development and production assets are measured at fair value unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset exchanged is reliably measurable. The cost of the acquired asset is measured at the fair value of the asset exchanged, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset exchanged. The gain or loss arising is recognized in net income.

The Company assesses at each reporting date whether there is an indication that its PP&E may be impaired or subject to impairment reversals. If any indication exists, the Company estimates the asset's recoverable amount using the methodology described in note 3(h).

g) Exploration and Evaluation (E&E) Assets

Undeveloped land costs are classified initially as E&E assets and transferred to PP&E as proved reserves are assigned.

All other exploration costs, including geological and geophysical costs and annual lease rentals, are charged to exploration expense when incurred.

For exchanges or parts of exchanges that involve principally E&E assets, the exchange is accounted for at the carrying amount of the asset exchanged.

h) Impairment of Assets

The Company tests PP&E and E&E assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, for example, changes in assumptions relating to future prices, future costs and reserves. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets, known as a cash-generating unit (CGU). If any such indication of impairment exists, an estimate of the CGU's recoverable amount is made. A CGU's recoverable amount is the higher of its fair value less costs to sell and its value in use. These assessments require the use of estimates and assumptions regarding long-term commodity prices, discount rates, future capital expenditures requirements, reserves determination and life of field. E&E assets are also tested for possible impairment when transferred to PP&E.

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been determined, net of depletion, had no impairment loss been recognized for the CGU in prior periods. Such a reversal is recognized in net income, following which the depletion charge is adjusted in future periods to allocate the CGU's revised carrying amount on a systematic basis over its remaining useful life.

i) Goodwill

Goodwill is tested for impairment annually and when circumstances indicate that the carrying amount may be impaired. The impairment test requires that goodwill be allocated to CGUs, which Talisman has determined by aggregating locations having similar economic characteristics and/or which are in similar geographic locations, and which correspond with the operating segments described in note 31, except for locations within the Other segment, which are generally grouped by country. Impairment is determined for goodwill by assessing the recoverable amount (based on fair value less costs to sell) of each segment or country, as appropriate, to which the goodwill relates. Where the recoverable amount of the segment is less than the carrying amount, an impairment loss is recognized. Goodwill impairment losses cannot be reversed.

j) Depreciation, Depletion and Amortization (DD&A)

Capitalized costs of proved oil and gas properties are depleted using the unit of production method. For purposes of these calculations, production and reserves of natural gas are converted to barrels (bbls) on an energy equivalent basis at a ratio of six thousand cubic feet (mcf) of natural gas for one barrel (bbl) of oil. Depletion and depreciation rates are updated in each reporting period that a significant change in circumstances, including reserves revisions, occurs.

Successful exploratory wells and development costs are depleted over proved developed reserves. Significant development costs incurred in connection with proved undeveloped reserves are excluded from depletion until the reserves are developed. In the case of unconventional natural gas developments, land and development costs are depleted over total proved reserves and include future development costs.

Acquired resource properties with proved reserves, including offshore platform costs, are depleted over total proved reserves. Acquisition costs of probable reserves are not depleted or amortized while under active evaluation for commercial reserves. Costs are transferred to depletable costs as proved reserves are recognized.

Costs associated with significant development projects are not depleted until the asset is substantially complete and ready for its intended use. Unproved land acquisition costs that are individually material are not amortized, but are assessed for impairment and transferred to depletable costs as proved reserves are recognized. Unproved land acquisition costs that are individually immaterial are amortized on a straight-line basis over the average lease term. Gas plants are depreciated on a straight-line basis over their estimated remaining useful lives, not to exceed the estimated remaining productive lives of related fields. Pipelines and corporate assets are depreciated using the straight-line method at annual rates of 4% and 5 - 33%, respectively. Gas plants and pipelines in the North Sea are depleted using the unit of production method based on the related fields.

k) Non-Current Assets Held for Sale

Non-current assets classified as held for sale and associated liabilities are measured at the lower of carrying amount and fair value less costs to sell, and are presented as current on the Consolidated Balance Sheet.

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

PP&E is not depreciated once classified as held for sale.

l) Decommissioning and Environmental Liabilities

Decommissioning liabilities are recognized when the Company has a legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate of the amount of the

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obligation can be made. A corresponding amount equivalent to the liability is recognized as part of the cost of the related PP&E or E&E asset.

Decommissioning liabilities are carried on the Consolidated Balance Sheet at their discounted present value, which is remeasured each reporting period in order to reflect the period end discount rate. The liabilities are calculated using a weighted average credit adjusted risk free rate, and are accreted over time for the change in their present value, with this accretion expense included in finance costs on the Consolidated Statement of Income. Actual expenditures incurred are charged against the accumulated obligation. Any difference between the recorded decommissioning liability and the actual retirement costs incurred is recorded as a gain or loss.

The increase in capitalized costs is amortized to income on a basis consistent with DD&A of the underlying assets. Subsequent changes in the estimated decommissioning liabilities are capitalized and amortized over the remaining useful life of the underlying asset.

Liabilities for environmental costs are recognized when an obligation exists and the associated costs can be reliably estimated. Generally, the timing of recognition of these liabilities coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. These estimates are included in decommissioning liabilities.

Initially, the Company recognizes neither the deferred tax asset relating to the temporary difference on the decommissioning liability nor the corresponding deferred tax liability relating to the temporary difference on the decommissioning asset.

m) Finance Costs and Long-Term Debt

Finance costs include interest and other costs that Talisman incurs in connection with the borrowing of funds, as well as accretion expense relating to the Company's decommissioning liabilities.

Finance costs associated with major development projects are capitalized and included in the carrying amounts of the related assets until they are completed and ready for use. These costs are subsequently amortized to income with the related assets. The amount of borrowing costs capitalized for the period is determined by applying the weighted average interest rate applicable to appropriate borrowings outstanding during the period to the average amount of capitalized expenditure for the qualifying assets.

All other finance costs are recognized on the Consolidated Statement of Income in the period in which they are incurred.

The classification of debt instruments in the Consolidated Balance Sheet reflects management's intent in respect of the refinancing of those instruments. In particular, the classification of bankers' acceptances reflects management's intent to refinance a short-term obligation with a committed long-term facility with the same lender.

n) Foreign Currency Translation

Talisman's functional currency is the US$.

Prior to January 1, 2011 in the UK and prior to January 1, 2010 in Canada and Norway, the Company's operations were translated from UK£, C$ and NOK respectively into US$ using the current rate method whereby assets and liabilities were translated at year-end exchange rates, while revenues and expenses were converted using average rates for the period. Gains and losses arising on translation from UK£, C$ and NOK to US$ were deferred and included in a separate component of shareholders' equity described as accumulated other comprehensive income.

As a result of changes in the composition of revenue and costs and changes in intercompany loan arrangements, management has determined that the functional currency of the Company's UK operation is more closely linked to the US$. Accordingly, effective January 1, 2011, this operation has been accounted for as a US$ functional currency entity. As a result, foreign currency translation adjustments remain in accumulated other comprehensive income until Talisman reduces its ownership interest in its UK subsidiary. Following the change in the functional currency of the UK operation on January 1, 2011, the debt denominated in UK£ was no longer designated as a hedge of Talisman's net investment in the UK and, accordingly, foreign exchange gains and losses are recorded on the Consolidated Statement of Income.

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The Company's operations in Canada and Norway are accounted for as US$ functional currency entities. As a result, foreign currency translation adjustments remain in accumulated other comprehensive income until Talisman reduces its net investment in its Canadian or Norwegian subsidiaries. The reduction of the net investment in a Canadian subsidiary that occurred during 2010 is described in note 5.

Effective 2011, the Company reports its financial position and results of operations in US$. The impact of changing the reporting currency from C$ to US$ is presented in note 4.

o) Employee Benefit Plans

The cost of providing benefits under the Company's defined benefit pension plans and non-pension post-employment benefit plans is determined using the projected benefit method pro-rated on service and management's best estimate of expected plan investment performance, salary escalation and employee retirement ages. There is uncertainty relating to the assumptions used to calculate the net benefit expense and accrued benefit obligation, due to their long-term nature.

The discount rate used to determine the accrued benefit obligation is determined by reference to market interest rates at the measurement date on high quality debt instruments with cash flows that match the timing and amount of expected benefit payments. The Company recognizes all actuarial gains and losses immediately in other comprehensive loss and transfers them to retained earnings in the year recorded.

Payments to defined contribution plans are expensed as incurred, which is as the related service is rendered.

The pension benefits of key management personnel represent the attributable amount of the net benefit expense of the plans in which they participate.

p) Financial Instruments

The Company classifies its financial instruments into one of the following categories: held-for-trading assets and liabilities, assets available-for-sale, loans and receivables, assets held-to-maturity and other financial liabilities. All financial assets and liabilities are recognized on the Consolidated Balance Sheet when the Company becomes a party to the contractual requirements of the instrument. All financial instruments are measured at fair value on initial recognition. Transaction costs are included in the initial carrying amount of financial instruments except for held-for-trading items, in which case they are expensed as incurred. Measurement in subsequent periods depends on the classification of the financial instrument.

In conducting its business, the Company may use derivative financial instruments in order to manage risks associated with fluctuations in commodity prices, interest rates and foreign currency exchange rates.

Non-Hedge Financial Instruments

Held-for-trading financial assets and liabilities are subsequently measured at fair value with changes in fair value recognized in net income. Financial assets available-for-sale are subsequently measured at fair value with changes in fair value recognized in other comprehensive loss, net of tax. Financial assets held-to-maturity, loans and receivables and other financial liabilities are subsequently measured at amortized cost using the effective interest rate method.

Cash equivalents are classified as held-for-trading and are measured at carrying value, which approximates fair value, due to the short-term nature of these instruments. Accounts receivable and certain other assets that are financial instruments are classified as loans and receivables. Accounts payable and accrued liabilities, certain other long-term obligations and current and long-term debt are classified as other financial liabilities. Financial liabilities are derecognized when the obligation under the liability is discharged, cancelled or expires.

Financial instruments that are derivative contracts are considered held-for-trading unless they are designated as a hedge. The financial derivative contracts outstanding at December 31, 2011 are disclosed in note 22.

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Derivatives embedded in other financial instruments and non-financial host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contract. Contracts are assessed for embedded derivatives when the Company becomes a party to them, including at the date of a business combination. Embedded derivatives requiring separation are measured at fair value at each balance sheet date and any gains or losses arising from changes in fair value are recognized in net income.

Hedges

The Company may designate financial instruments as a hedging instrument for accounting purposes. Hedge accounting requires the designation of a hedging relationship, including a hedged and a hedging item, identification of the risk exposure being hedged and an expectation that the hedging relationship will be highly effective throughout its term. In addition, in the case of anticipated transactions, it must also be highly probable that the transaction designated as being hedged will occur. The Company assesses, both at the hedge's inception and on an ongoing basis, whether the derivative financial instruments designated as hedges are highly effective in offsetting changes in fair value or cash flows of the hedged items. If the derivative financial instrument that has been designated as a hedge is terminated or is no longer designated as part of the hedging relationship, the gain or loss on the hedge at that date is deferred in other comprehensive loss and recognized in net income concurrently with the anticipated transaction. If the forecast transaction is no longer expected to occur, the gain or loss on the hedge at that date is recognized immediately in net income. The Company had the following hedges during the periods covered by these Consolidated Financial Statements:

Cash flow hedges – Until January 2011, when the cross-currency hedge and related debt were settled, the effective portion of changes in the fair value of financial instruments designated as cash flow hedges was recognized in other comprehensive loss, net of tax, with any ineffective portion being recognized immediately in net income. Gains and losses were recovered from other comprehensive loss and recognized in net income in the same period as the hedged item was realized.

Net investment hedges – Until December 31, 2010, foreign exchange gains and losses on UK£ debt designated as a net investment hedge would have been recognized in other comprehensive loss. These gains and losses would have been recovered from other comprehensive loss and recognized in net income if the net investment was reduced below the value of the debt. Since January 1, 2011, following the change in functional currency described in note 3(n), the debt denominated in UK£ is no longer designated as a hedge of the Company's net investment.

Own Use Exemption

Contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Company's expected purchase, sale or usage requirements fall within the exemption from IAS 32 and IAS 39, which is known as the 'own use' exemption. The Company enters into physical commodity contracts in the normal course of business, including contracts with fixed terms. The Company's production is expected to be sufficient to deliver all required volumes under these contracts. No amounts are recognized in the Consolidated Financial Statements related to these contracts until such time as the associated volumes are delivered.

q) Comprehensive Income and Equity

The Consolidated Statement of Comprehensive Income reflects net income and items of other comprehensive loss which comprise changes in the fair value of financial instruments designated as cash flow hedges, to the extent they are effective, gains and losses recovered from other comprehensive loss and recognized in net income and actuarial gains and losses arising in relation to the Company's employee benefit plans. Until December 31, 2010, foreign currency translation gains or losses arising from the translation of the Company's foreign operations or reductions in the net investments therein and translation from the Company's functional currency to its presentation currency also gave rise to other comprehensive loss. See note 3(n) for more details.

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r) Income Taxes

Income taxes comprise current tax, deferred tax and Petroleum Revenue Tax (PRT) and are recognized on the Consolidated Statement of Income except to the extent they relate to items recognized in other comprehensive loss or directly in equity. PRT is treated as an income tax and deferred PRT is accounted for on a temporary difference basis.

Interest and penalties assessed by taxing authorities on any underpayment of income tax are accrued and classified as a component of income taxes on the Consolidated Statement of Income.

Certain of the Company's contractual arrangements in foreign jurisdictions stipulate that income taxes be paid by the respective national oil company out of its entitlement share of production. Such amounts are included in income taxes at the statutory tax rate in effect at the time of production.

Current Tax

Current tax is based on estimated taxable income and tax rates which are determined pursuant to the tax laws that are enacted or substantively enacted at the balance sheet date.

Deferred Tax

s) Revenue Recognition

Revenues associated with the sale of crude oil, natural gas and NGLs are recognized at the fair value of the consideration received or receivable when the significant risks and rewards of ownership have been transferred, which is when title passes from the Company to the customer. For the Company's international operations, generally, customers take title when the crude oil is loaded onto a tanker. The Company employs the entitlement method in accounting for crude oil and natural gas sales and records a receivable from a joint interest participant if a participant sells more than its proportionate share of crude oil or natural gas production. Crude oil and natural gas produced and sold, below or above the Company's working interest share in the related resource properties, results in production underliftings, or overliftings. Underliftings are recorded as inventory at the cost to produce and transport the product to storage tanks, and overliftings are recorded in accounts payable and accrued at the sales value. Underliftings are reversed from inventory when the crude oil is lifted and sold, with the sales proceeds recorded as revenue and the cost of the inventory expensed. Overliftings are reversed from accounts payable and accrued liabilities when sufficient volumes are produced to make up the overlifted volume. Amounts received under take-or-pay gas sales contracts in respect of undelivered volumes are accounted for as deferred income in accounts payable and accrued liabilities and recognized as revenue when volumes are delivered. Transportation expenses are reported as a separate expense and are not netted against revenue.

A significant portion of the Company's operations outside North America and the North Sea are governed by Production Sharing Contracts (PSCs). Under PSCs, revenues are derived from cost recovery oil and gas and profit oil and gas. Generally, cost recovery oil and gas allows the Company to recover its capital and production costs and, as appropriate, the costs carried by the Company on behalf of state oil companies from production. Profit oil is allocated to the host government and contract parties in accordance with their respective equity interests.

All taxes collected from customers that are remitted to governments are excluded from revenues.

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Certain of the Company's foreign operations are conducted jointly with the respective national oil companies. These operations are reflected in the Consolidated Financial Statements based on Talisman's working interest in such activities. All other government takes, other than income taxes, are considered to be royalty interests. Royalties on production from these joint foreign operations represent the entitlement of the respective governments to a portion of Talisman's share of crude oil, natural gas and NGLs production and are recorded using rates in effect under the terms of contracts at the time of production.

Sales as reported represents the Company's share of revenues from the sale of crude oil, natural gas and NGLs and is presented after deduction of royalty payments to governments and other mineral interest owners.

t) Leases

Leases that transfer substantially all of the benefits and risks of ownership to Talisman are accounted for at the commencement of the lease term as finance leases and recorded as PP&E at the fair value of the leased asset, or, if lower, at the present value of the minimum lease payments, together with an offsetting liability. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and are recognized in net income. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.

All other leases are accounted for as operating leases and the lease costs are expensed as incurred.

u) Share-Based Payments

Talisman has stock option plans, cash unit plans, performance share unit (PSU) plans, a deferred share unit plan and a restricted share unit plan, under which it receives services from employees and directors as consideration for cash payments or equity instruments of the Company. The long-term PSU plan must be settled in shares. The cash unit, deferred share unit and restricted share unit plans must be settled in cash. The stock option plans may be settled in cash at the option of the holder. The 2008 PSU plan was settled in 2010 – see note 20.

Equity-Settled Awards

The Company uses the Black-Scholes pricing model to estimate the fair value of equity-settled awards.

For the PSU plans, the Company determines the fair value of the units on the date of grant and recognizes the fair value over the vesting period as share-based payments expense and contributed surplus.

Cash-Settled Awards

The Company uses the Black-Scholes pricing model to estimate the fair value of cash-settled awards. Fair value is established initially at the grant date and the obligation is revalued each reporting period until the awards are settled with any changes in the obligation recognized as share-based payments expense (recovery) on the Consolidated Statement of Income, except for the changes related to deferred share units, which are included in general and administrative expenses.

The stock option plans are classified as liability instruments and re-measured at their fair value at the end of each reporting period.

For plans having vesting conditions, the total expense is recognized over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied. At the end of each reporting period, the Company revises its estimates of the number of options and units that are expected to vest based on the vesting conditions and recognizes the impact of the revision to original estimates, if any, in net income.

v) Net Income and Diluted Net Income Per Share

Net income per share is calculated by dividing net income by the weighted average number of common shares outstanding. Diluted net income per share is calculated giving effect to the potential dilution that could occur if stock options were exercised in exchange for common shares.

The method the Company uses to determine the dilutive impact of stock options assumes that any proceeds from the exercise of in-the-money stock options would be used to purchase common shares at the average market price during the period. In

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periods when a share-based payments recovery is reported, net income used in the dilution calculation is reduced by the amount of the recovery.

For stock options that may be settled in cash or shares at the employees' option, the more dilutive impact of cash settlement and equity settlement is used in calculating diluted net income per share regardless of how the stock option plan is accounted for. Stock options that are reported as cash-settled for accounting purposes may require an adjustment to the numerator in the diluted net income per share calculation for any changes in net income that would result if the stock options had been reported as equity instruments.

w) Cash and Cash Equivalents

Cash and cash equivalents include cash on deposit with banks and interest-bearing short-term investments with an original maturity of three months or less. Cash and cash equivalents are stated at cost, which approximates market value.

For the purpose of the Consolidated Statements of Cash Flows, cash and cash equivalents consist of cash and cash equivalents as defined above, net of bank indebtedness.

x) Segmented Information

The Company's reporting segments are established on the basis of having similar economic characteristics and/or which are in similar geographic locations and those components of the Company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance.

Effective January 1, 2011, the composition of the Company's segments changed such that the activities in the UK and Norway are reported as a single North Sea segment since, in management's judgment, the assets in those locations now share similar economic characteristics. Comparative period balances have been restated accordingly. See note 31 for disclosure of segmented information.

y) Significant Accounting Judgments, Estimates and Assumptions

To facilitate the timely preparation of the Consolidated Financial Statements, management has made estimates and assumptions regarding certain assets and liabilities and contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods noted. Such estimates relate primarily to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts.

DD&A, the fair value of PP&E and E&E assets, amounts recognized for impairment charges and reversals and the recognition of assets acquired and liabilities assumed upon a business combination are impacted by estimates of oil and natural gas reserves, commodity prices and capital and operating costs required to develop and produce those reserves. By their nature, estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the Consolidated Financial Statements of future periods could be material. The measurement of impairment charges and reversals is also dependent upon management's judgment in determining CGUs.

Inherent in the calculation of decommissioning liabilities are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to assumptions impact the amount of decommissioning liabilities, a corresponding adjustment is made to the PP&E and/or E&E assets balance.

The values of pension assets and obligations and the amount of the net benefit expense charged to net income depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty.

The measurement of income tax expense, and the related provisions on the Consolidated Balance Sheet, is subject to uncertainty associated with future recoverability of oil and natural gas reserves, commodity prices, the timing of future events and changes in legislation, tax rates and interpretations by tax authorities.

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The fair values of financial instruments are estimated based upon market and third party inputs. These estimates are subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance risk.

The fair values of equity-settled and cash-settled share-based payment awards are estimated using the Black-Scholes pricing model. These estimates depend on certain assumptions including share price volatility, risk free interest rate, the term of the awards, the forfeiture rate and the annual dividend yield which, by their nature, are subject to measurement uncertainty.

The designation of the Company's functional currency is a management judgment based on the composition of revenue and costs in the locations in which it operates.

Provisions are recorded when the Company has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.

Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the Company. Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote. The evaluation of the likelihood of the contingent events requires management judgment as to the probability of exposure to potential loss.

z) Accounting Standards and Interpretations Issued but Not Yet Effective

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

•: IFRS 9 Financial Instruments – as part of its project to replace IAS 39, the IASB issued the first phase of IFRS 9 implementation dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9 by incorporating requirements for the accounting for financial liabilities;
•: IFRS 10 Consolidated Financial Statements – establishes the accounting principles for consolidated financial statements when one entity controls other entities and replaces IAS 27 Consolidated and Separate Financial Statements and the related provisions of SIC-12 Consolidation – Special Purpose Entities. This standard establishes a new control model that applies to all entities;
•: IFRS 11 Joint Arrangements – establishes the accounting principles for parties to a joint arrangement and replaces IAS 31 Interest in Joint Ventures and SIC-13 Jointly Controlled Entities: Non-Monetary Contributions by Venturers. This standard requires a party to assess its rights and obligations from the arrangement in order to determine the type of joint arrangement. The choice of proportionate consolidation accounting is removed for joint ventures (currently jointly controlled entities under IAS 31) as equity accounting is required;
•: IFRS 12 Disclosure of Interests in Other Entities – establishes comprehensive disclosure requirements for subsidiaries, joint arrangements, associates, and unconsolidated structured entities and replaces existing disclosures in related standards;
•: IFRS 13 Fair Value Measurement – establishes a single framework for fair value measurement and disclosures when fair value is required or permitted under IFRS;
•: IAS 1 Presentation of Financial Statements – amendment requires items within other comprehensive loss to be grouped based on whether they can be reclassified to the income statement and is applicable to annual periods beginning on or after July 1, 2012, with earlier adoption permitted;
•: IAS 19 Employee Benefits amendment – improves the accounting for employee benefits by eliminating the corridor method to defer recognition of actuarial gains and losses, introducing presentation changes for the financial statements effect arising from defined benefit plans, and introducing enhanced disclosure requirements for defined benefit plans;
•: IAS 27 Separate Financial Statements – establishes the accounting and disclosure requirements for investments in subsidiaries, joint ventures, and associates when an entity prepares separate financial statements and replaces the current

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IAS 27 Consolidated and Separate Financial Statements as the consolidation guidance is included in IFRS 10 Consolidated Financial Statements; and

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

4. IFRS FIRST-TIME ADOPTION

The accounting policies described in note 3 have been applied in preparing the Consolidated Financial Statements as at and for the year ended December 31, 2011, the comparative information as at and for the year ended December 31, 2010 and the opening IFRS balance sheet as at January 1, 2010, the Company's date of transition to IFRS.

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

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

IFRS 1 Exemptions

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

•: To measure certain properties at fair value as at January 1, 2010 and use those fair values as deemed cost at that date;
•: To apply a modified approach in calculating the retrospective cost component of PP&E relating to the Company's decommissioning liabilities. Under the modified approach, decommissioning liabilities are re-measured at the date of transition to IFRS under IAS 37 Provisions, Contingent Liabilities and Contingent Assets and amounts to be included in the related assets are estimated by discounting the liabilities to the date at which they first arose using the best estimates of the historical risk-adjusted discount rates. The related accumulated DD&A is then calculated based on the current estimates of the useful lives of the assets;
•: To apply IFRS 3 Business Combinations prospectively and not restate business combinations that occurred prior to January 1, 2010;
•: To not apply IFRS 2 Share-Based Payments to equity awards that vested and liability awards that settled prior to January 1, 2010;
•: To recognize cumulative unrecognized net actuarial losses on employee future benefits in opening retained earnings as at January 1, 2010. Also, to prospectively disclose required benefit plans amounts under IAS 19 Employee Benefits as the amounts are determined for each accounting period from January 1, 2010 instead of the current annual period and previous four annual periods; and
•: To apply IAS 23 Borrowing Costs prospectively from January 1, 2010 and derecognize the carrying value of capitalized borrowing costs recorded under Canadian GAAP as at January 1, 2010.

Reconciliations from Canadian GAAP to IFRS

In preparing the Consolidated Financial Statements, the Company adjusted amounts reported previously in its Consolidated Financial Statements prepared under Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS affected the Company's financial position, results of operations and cash flows is presented in the following reconciliations (as required by IFRS 1) and explanatory notes, together with the impact of the Company changing its reporting currency from C$ to US$.

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Reconciliation of Consolidated Balance Sheet at January 1, 2010

			CGAAP		IFRS adjustments & reclassifications		IFRS
January 1, 2010 (millions of $)		Notes	C$¹	US$	US$		US$

Assets
Current

	Cash and cash equivalents		1,690	1,615	13		1,628

	Accounts receivable		1,223	1,168	48		1,216

	Risk management		30	29	–		29

	Inventories		144	137	4		141

	Prepaid expenses		9	8	–		8

	Assets of discontinued operations/Assets held for sale	4.8	58	56	(34	)	22

			3,154	3,013	31		3,044

Other assets		4.7	128	122	(14	)	108

Risk management			42	40	–		40

Goodwill			1,176	1,124	59		1,183

Property, plant and equipment		4.1-4.4, 4.11-12	16,431	15,698	(2,444	)	13,254

Exploration and evaluation assets		4.1, 4.12	–	–	2,212		2,212

Future income taxes/Deferred tax assets			120	115	32		147

Assets of discontinued operations		4.8	2,567	2,453	(2,453	)	–

			20,464	19,552	(2,608	)	16,944

Total assets			23,618	22,565	(2,577	)	19,988

Liabilities
Current

	Bank indebtedness		36	35	–		35

	Accounts payable and accrued liabilities	4.6	1,845	1,759	281		2,040

	Risk management		276	266	–		266

	Income and other taxes payable		357	341	–		341

	Current portion of long-term debt		10	10	–		10

	Future income taxes/Deferred tax liabilities	4.12	68	65	(65	)	–

	Liabilities of discontinued operations/liabilities associated with assets held for sale	4.8	9	9	(2	)	7

			2,601	2,485	214		2,699

Deferred credits			59	56	(9	)	47

Asset retirement obligations/Decommissioning liabilities		4.4	2,116	2,023	(20	)	2,003

Other long-term obligations		4.6, 4.7	161	155	114		269

Risk management			7	6	–		6

Long-term debt			3,770	3,601	–		3,601

Future income taxes/Deferred tax liabilities		4.3, 4.12	3,599	3,437	(921	)	2,516

Liabilities of discontinued operations		4.8	194	185	(185	)	–

			9,906	9,463	(1,021	)	8,442

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TALISMAN ENERGY ANNUAL REPORT 2011

		CGAAP			IFRS adjustments & reclassifications		IFRS
January 1, 2010 (millions of $)	Notes	C$¹		US$	US$		US$

Shareholders' equity

Common shares		2,374		1,401	–		1,401

Contributed surplus		153		117	–		117

Retained earnings		9,174		7,905	(1,770	)	6,135

Accumulated other comprehensive income (loss)	4.10	(590	)	1,194	–		1,194

		11,111		10,617	(1,770	)	8,847

Total liabilities and shareholders' equity		23,618		22,565	(2,577	)	19,988

1: Canadian GAAP Consolidated Balance Sheet as at December 31, 2009 restated for operations classified as discontinued during 2010.

Reconciliation of Shareholders' Equity at January 1, 2010

(millions of US$)		January 1, 2010

Shareholders' equity under Canadian GAAP		10,617

Adjustments:

	Opening balance sheet	(1,770	)

Shareholders' equity under IFRS		8,847

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Reconciliation of Consolidated Balance Sheet at December 31, 2010

			CGAAP			IFRS adjustments & reclassifications		IFRS
December 31, 2010 (millions of $)		Notes	C$		US$	US$		US$

Assets
Current

	Cash and cash equivalents		1,646		1,655	–		1,655

	Accounts receivable		1,281		1,287	–		1,287

	Risk management		118		119	–		119

	Inventories		143		144	–		144

	Prepaid expenses		20		20	–		20

			3,208		3,225	–		3,225

Other assets		4.7	837		841	(53	)	788

Risk management			24		25	–		25

Goodwill			1,150		1,157	7		1,164

Property, plant and equipment		4.1-4.4, 4.11-12	18,804		18,906	(5,640	)	13,266

Exploration and evaluation assets		4.1, 4.12	–		–	3,442		3,442

Future income taxes/Deferred tax assets			170		171	13		184

			20,985		21,100	(2,231	)	18,869

Total assets			24,193		24,325	(2,231	)	22,094

Liabilities
Current

	Bank indebtedness		2		2	–		2

	Accounts payable and accrued liabilities	4.6	2,416		2,433	289		2,722

	Risk management		116		117	–		117

	Income and other taxes payable		510		513	–		513

	Current portion of long-term debt		357		359	–		359

			3,401		3,424	289		3,713

Deferred credits			51		51	(5	)	46

Asset retirement obligations/Decommissioning liabilities		4.4	2,252		2,264	316		2,580

Other long-term obligations		4.6, 4.7	212		213	67		280

Long-term debt			3,824		3,845	–		3,845

Future income taxes/Deferred tax liabilities		4.12	3,974		3,995	(1,560	)	2,435

			10,313		10,368	(1,182	)	9,186

Shareholders' equity

Common shares			2,457		1,480	–		1,480

Contributed surplus			132		98	10		108

Retained earnings			9,568		8,269	(1,450	)	6,819

Accumulated other comprehensive income (loss)		4.10	(1,678	)	686	102		788

			10,479		10,533	(1,338	)	9,195

Total liabilities and shareholders' equity			24,193		24,325	(2,231	)	22,094

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TALISMAN ENERGY ANNUAL REPORT 2011

Reconciliation of Shareholders' Equity at December 31, 2010

(millions of US$)		December 31, 2010

Shareholders' equity under Canadian GAAP		10,533

Adjustments:

	Opening balance sheet	(1,770	)

	Consolidated Statement of Comprehensive Income for the year ended December 31, 2010	422

	Share-based payments impact on contributed surplus	10

Shareholders' equity under IFRS		9,195

Reconciliation of Consolidated Statement of Income for the Year Ended December 31, 2010

			CGAAP				IFRS adjustments & reclassifications		IFRS
Year ended December 31, 2010 (millions of $)		Notes	C$		US$		US$		US$

Revenue

	Sales	4.12	8,076		7,846		(971	)	6,875

	less: Royalties	4.12	(1,274	)	(1,238	)	1,238		–

	Other income		110		107		–		107

Total revenue and other income			6,912		6,715		267		6,982

Expenses

	Operating		1,867		1,813		77		1,890

	Transportation		227		221		–		221

	General and administrative	4.7	392		381		(10	)	371

	Depreciation, depletion and amortization	4.5, 4.12	2,164		2,099		(311	)	1,788

	Impairment	4.1	118		115		186		301

	Dry hole		123		121		(8	)	113

	Exploration		384		374		–		374

	Interest on long-term debt	4.12	163		158		(158	)	–

	Finance costs	4.4, 4.12	–		–		276		276

	Stock-based compensation/share-based payments	4.6	201		198		14		212

	(Gain) loss on held-for-trading financial instruments		(102	)	(92	)	5		(87	)

	Gain on asset disposals	4.8, 4.9	(59	)	(57	)	(463	)	(520	)

	Other, net	4.7, 4.11-12	135		134		(62	)	72

Total expenses			5,613		5,465		(454	)	5,011

Income before taxes			1,299		1,250		721		1,971

Taxes

	Current income tax		1,032		1,006		130		1,136

	Deferred income tax (recovery)		(272	)	(266	)	156		(110	)

	Petroleum revenue tax		131		128		(128	)	–

		4.3	891		868		158		1,026

Income from continuing operations			408		382		563		945

Income from discontinued operations		4.8	240		231		(231	)	–

Net income			648		613		332		945

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TALISMAN ENERGY ANNUAL REPORT 2011

Reconciliation of Consolidated Statement of Comprehensive Income (Loss) for the Year Ended December 31, 2010

			CGAAP				IFRS adjustments & reclassifications		IFRS
Year ended December 31, 2010 (millions of $)		Notes	C$		US$		US$		US$

Net income			648		613		332		945

Foreign currency translation			(625	)	(46	)	5		(41	)

Transfer of accumulated foreign currency gain to net income		4.9	(465	)	(464	)	97		(367	)

Actuarial losses relating to pension and other post-employment benefits¹		4.7	–		–		(12	)	(12	)

Gains and losses on derivatives designated as cash flow hedges

	Gains arising during the year		14		13		–		13

	Gains recognized in net income		(12	)	(11	)	–		(11	)

			2		2		–		2

Other comprehensive loss			(1,088	)	(508	)	90		(418	)

Comprehensive income (loss)			(440	)	105		422		527

1: Actuarial gains and losses are transferred to retained earnings each year.

Reconciliation of Consolidated Statement of Cash Flows for the Year Ended December 31, 2010

		CGAAP				IFRS adjustments & reclassifications		IFRS
Year ended December 31, 2010 (millions of $)	Notes	C$		US$		US$		US$

Cash provided by operating activities	4.12	3,460		3,331		(187	)	3,144

Cash used in investing activities	4.12	(3,734	)	(3,635	)	384		(3,251	)

Cash provided by financing activities	4.12	309		313		(197	)	116

Effect of translation on foreign currency cash and cash equivalents		(59	)	51		–		51

Net increase (decrease) in cash and cash equivalents		(24	)	60		–		60

Cash and cash equivalents net of bank indebtedness, beginning of year		1,668		1,593		–		1,593

Cash and cash equivalents net of bank indebtedness, end of year		1,644		1,653		–		1,653

Notes for Reconciliation from Canadian GAAP to IFRS

4.1) Fair Value as Deemed Cost and Impairments

a) Fair Value as Deemed Cost

The Company elected to use the fair value as deemed cost exemption under IFRS 1 to record certain assets at fair value as at January 1, 2010 as their deemed cost under IFRS while these assets were measured on a historical cost basis under Canadian GAAP. As a result of the change in accounting, the Company recorded a $1.7 billion reduction in PP&E at January 1, 2010, of which $463 million related to assets sold during 2010. The aggregate fair value of properties at January 1, 2010 for which the Company used this exemption was $2.3 billion.

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b) Impairments

Under Canadian GAAP, only if an asset's estimated undiscounted future cash flows was below its carrying value was a determination required of the amount of any impairment based on discounted cash flows. Under IFRS, impairment assessments are based on the recoverable amount of the asset, which the Company has determined to be fair value calculated using discounted cash flows.

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

c) Assumptions

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

	December 31, 2010	January 1, 2010

WTI ($/bbl)	80.00	70.00

Dated Brent ($/bbl)	78.53	68.75

Henry Hub natural gas ($/mmbtu)	5.50	6.00

AECO (C$/gj)	4.92	5.60

US$/C$	0.95	0.90

US$/UK£	1.60	1.69

Post-tax discount rate	10%	10%

4.2) Capitalized Borrowing Costs

The Company elected to use the exemption under IFRS 1 to derecognize borrowing costs that had been capitalized under Canadian GAAP, which reduced PP&E by $218 million at January 1, 2010.

4.3) Income Taxes

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

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

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As a result of all measurement differences impacting deferred tax, including the three discussed above, but excluding the impact of discontinued operations and other reclassifications, the Company recorded a decrease of deferred tax liabilities of $1.1 billion at January 1, 2010 (December 31, 2010 – $1.6 billion) under IFRS. Additional income tax expense of $232 million for the year ended December 31, 2010 was recorded under IFRS.

4.4) Decommissioning

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

The Company elected to apply a modified approach under IFRS 1 in calculating the retrospective cost component of PP&E relating to the Company's decommissioning liabilities, described above in the 'IFRS Exemptions' section of note 4. As a result, the Company recorded a decrease of $221 million to PP&E at January 1, 2010 under IFRS.

The measurement difference described above resulted in a lower decommissioning liability under IFRS at January 1, 2010. The Company recorded a reduction in finance costs under IFRS of $46 million for the year ended December 31, 2010 as a result of lower accretion expense.

4.5) DD&A

The Company recorded a decrease to DD&A of $260 million, excluding the impact of discontinued operations and other reclassifications, for the year ended December 31, 2010 as a result of the Canadian GAAP and IFRS differences described in these reconciliation notes that reduced PP&E, namely electing to use the fair value as deemed cost exemption under IFRS 1, impairments, income taxes and decommissioning.

4.6) Share-Based Payments

Under Canadian GAAP, the intrinsic value method was used to measure share-based payments plans having a cash settlement feature. Under IFRS, this method is not permitted and all share-based payments plans must be measured at fair value using an accepted option pricing model. As a result, the Company recorded an increase of $321 million at January 1, 2010 and $304 million at December 31, 2010 to the share-based payments liability under IFRS. In addition, the Company elected to not apply IFRS 2 Share-Based Payments to equity awards that vested and liability awards that settled prior to January 1, 2010 in determining the adjustment at January 1, 2010.

The following assumptions are used in the Black-Scholes option pricing model to estimate the fair value of share-based payments plans:

	December 31, 2010	January 1, 2010

Expected volatility	42%	47%

Risk-free interest rate	2.6%	2.8%

Expected term (years)	5	5

Expected forfeiture rate	3.4%	4.2%

Expected annual dividend yield	1.1%	1.0%

The Company recorded an additional share-based payments expense of $14 million for the year ended December 31, 2010 under IFRS arising from the measurement differences described above.

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4.7) Employee Benefits

Under Canadian GAAP, actuarial gains and losses were deferred on the balance sheet and amortized to net income over the average remaining service life of active employees. The Company elected to recognize cumulative unrecognized net actuarial losses of $49 million in retained earnings at January 1, 2010, which reduced the accrued pension asset by $22 million and increased the accrued pension liability by $57 million. As a result of this measurement difference, the Company reversed the Canadian GAAP amortization of actuarial gains and losses of $7 million for the year ended December 31, 2010, and recorded net actuarial losses of $12 million for the year ended December 31, 2010 in other comprehensive loss under IFRS.

4.8) Discontinued Operations

Under IFRS, only disposals of significant operations such as a separate major line of business or geographical area are presented as discontinued operations. Under Canadian GAAP, this definition was broader and included a component of an entity. Under both Canadian GAAP and IFRS, assets classified as held for sale and associated liabilities are presented separately on the balance sheet. However, they are reported as current under IFRS and comparative information is not restated.

Income from discontinued operations was reported separately in the Consolidated Statement of Income under Canadian GAAP, but is not presented separately under IFRS since the asset disposals occurring during 2010 did not meet the definition of a discontinued operation under IFRS. The gains and losses arising on such disposals are reported in 'Gain on asset disposals' on the Consolidated Statements of Income.

4.9) Asset Disposals

Due to Canadian GAAP and IFRS differences described above that reduced PP&E, namely electing to use the fair value as deemed cost exemption under IFRS 1, income taxes and decommissioning, the gains and losses recorded on asset disposals under IFRS differ from Canadian GAAP. In particular, the transfer of non-taxable foreign exchange gains previously accumulated in other comprehensive income to net income resulting from the disposal of North American assets was deferred within 2010 under IFRS to coincide with the closing of the transactions.

4.10) Cumulative Translation Differences

Cumulative translation differences arising from translation of foreign operations have been recalculated under IFRS to reflect the impact of other adjustments to the opening IFRS balance sheet as at January 1, 2010.

4.11) Other Adjustments

Other reconciling items include differences between Canadian GAAP and IFRS related to asset transactions and risk sharing arrangements, embedded derivatives, and derecognition of replacement parts, none of which are significant.

4.12) Reclassifications

a) Deferred Taxes

Deferred taxes are classified as non-current under IFRS, but were classified as both current and non-current under Canadian GAAP based on the classification of the underlying assets and liabilities that gave rise to the differences. As a result, the Company reclassified $65 million of current deferred tax liabilities at January 1, 2010 (December 31, 2010 – $nil) to non-current liabilities under IFRS.

b) E&E Assets

E&E assets are presented as a separate line item under IFRS but were reported as part of PP&E under Canadian GAAP. As a result, the Company reclassified PP&E with a net book value of $2.2 billion at January 1, 2010 (December 31, 2010 – $3.4 billion) to E&E assets under IFRS.

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c) Royalties

Under Canadian GAAP, royalties were presented separately from revenue, while revenue is presented net of royalties under IFRS. As a result, the Company reclassified royalties as a reduction of sales under IFRS of $1.3 billion, excluding the impact of discontinued operations, for the year ended December 31, 2010.

d) Finance Costs

Under Canadian GAAP, interest on long-term debt was presented as a separate item in the Consolidated Statement of Income and accretion expense was included as part of DD&A. These items are presented as finance costs under IFRS. The Company reclassified interest on long-term debt of $158 million for the year ended December 31, 2010 and accretion expense of $79 million for the year ended December 31, 2010 to finance costs under IFRS. The remaining reclassification related to other interest.

e) Statement of Cash Flows

The underlying cash flows of the Company do not change under IFRS. However, the Company reclassified exploration costs of $384 million for the year ended December 31, 2010 from an investing activity under Canadian GAAP to an operating activity under IFRS, and reclassified finance costs of $197 million for the year ended December 31, 2010 from an operating activity under Canadian GAAP to a financing activity under IFRS.

5. ASSETS SOLD AND HELD FOR SALE

Sale of Farrell Creek Interests to Sasol Limited (Sasol)

Sale of Cypress A Interests to Sasol

Asset Sales Completed in 2010

During the year ended December 31, 2010, Talisman completed the sale of oil and gas producing properties in North America with a carrying value of approximately $2 billion for aggregate proceeds of approximately $2.2 billion. The net investment in the Company's Canadian operations was reduced as a result of the transactions occurring in 2010 and, accordingly, $367 million of exchange gains previously accumulated in other comprehensive income were included in the gains of $520 million, which are included in 'Gain on asset disposals' on the Consolidated Statement of Income. Tax of $38 million was recorded in respect of these transactions.

Assets Held for Sale

During 2010, Talisman completed the sale of oil and gas producing assets in Tunisia (included in the Other segment) for proceeds of $23 million, resulting in a loss of $5 million, net of tax of $nil. The assets held for sale and liabilities associated with assets held for sale included in the Consolidated Balance Sheet as at January 1, 2010 were $22 million and $7 million, respectively. The operating results related to these assets held for sale were included in net income for the year ended December 31, 2010 and the loss was included in 'Gain on asset disposals' on the Consolidated Statement of Income.

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6. PROPERTY ACQUISITIONS

During the year ended December 31, 2010, Talisman acquired undeveloped land in the Eagle Ford shale play for approximately $910 million and a 35% working interest in the PL378 Grosbeak discovery and a 20% interest in the PL375 Beta discovery in Norway for $192 million. During the year ended December 31, 2011, Talisman acquired additional undeveloped land in the Eagle Ford shale play for approximately $145 million and undeveloped land in the Alberta Duvernay shale play for approximately $510 million.

7. BUSINESS COMBINATIONS

Equión Energía Limited

On January 24, 2011, Talisman, together with Ecopetrol, completed the acquisition of BP Exploration Company (Colombia) Limited, renamed Equión Energía Limited (Equión). Talisman acquired a 49% interest in Equión for cash consideration of $785 million. Since Equión is a jointly controlled entity, the Company is proportionately consolidating its interest, which is reported in the Other segment.

The recognition of assets acquired and liabilities assumed has been updated as a result of the completion of the Company's process to evaluate the acquired reserves, and reflects additional market-based information for certain acquired assets.

The assets acquired through this transaction include interests in producing properties and investments in companies having interests in oil and gas pipelines in Colombia.

This acquisition, which builds on the Company's acreage position in Colombia, was accounted for using the acquisition method. The fair values of the identifiable assets acquired and liabilities assumed by Talisman, after working capital and other adjustments, were as follows:

Fair value of share of net assets acquired

Property, plant and equipment		559

Cash		16

Accounts receivable		81

Inventories		16

Investments		350

Indemnification asset		52

Accounts payable		(113	)

Other current liabilities		(52	)

Decommissioning liability		(25	)

Provisions		(52	)

Deferred tax liability		(209	)

Total identifiable net assets at fair value		623

Goodwill arising on acquisition (note 8)		162

Total cost of acquisition		785

Satisfied by:

	Cash deposit paid in 2010	613

	Cash paid in 2011	172

Total cash paid		785

The fair value of the acquired accounts receivable approximates the carrying value due to their short-term nature. None of the accounts receivable were impaired and the full contractual amount was collected.

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TALISMAN ENERGY ANNUAL REPORT 2011

The goodwill arising on acquisition is attributable to the difference between the accounting fair value and the tax basis of the net assets acquired, and is not expected to be deductible for income tax purposes.

From the date of acquisition, Equión contributed revenue of $287 million and net income of $110 million to the Company's Consolidated Statement of Income during the year ended December 31, 2011. Had the transaction closed on January 1, 2011, the incremental revenue and net income reported by Talisman would have been immaterial.

Transaction costs of $11 million were expensed in 2010 and included in other expenses on the Consolidated Statement of Income and shown as a component of cash provided by operating activities in the Consolidated Statement of Cash Flows.

As part of the purchase transaction, Talisman assumed provisions of $52 million for which the vendor has indemnified the Company. Accordingly, a non-current asset was recorded in the same amount.

No contingent consideration arose from this transaction.

Jambi Merang

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

This acquisition, which facilitates Talisman's strategy to increase its presence in Indonesia and is being reported in the Southeast Asia segment, was accounted for using the acquisition method. The fair values of the identifiable assets acquired and liabilities assumed by Talisman were as follows:

Fair value of net assets acquired

Property, plant and equipment		181

Accounts receivable		26

Other assets		13

Accounts payable		(20	)

Other current liabilities		(17	)

Deferred tax liability		(43	)

Total identifiable net assets at fair value		140

Goodwill arising on acquisition (note 8)		43

Total cost of acquisition		183

Satisfied by:

	Cash paid	183

The fair value of the acquired accounts receivable approximates the carrying value due to their short-term nature. None of the accounts receivable acquired were impaired and the full contractual amount was collected.

The goodwill recognized above is attributable to the difference between the accounting fair value and the tax basis of the net assets acquired and is not expected to be deductible for income tax purposes.

Revenue and net income from Jambi Merang did not have a material impact on the Company during 2010, since first production was achieved in April 2011.

Transaction costs of $1 million were expensed in 2010 and included in other expenses in the Consolidated Statement of Income and shown as a component of cash provided by operating activities in the Consolidated Statement of Cash Flows.

No contingent consideration or contingent liabilities arose from this transaction.

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TALISMAN ENERGY ANNUAL REPORT 2011

8. GOODWILL


Continuity of goodwill	2011		2010

Balance, beginning of year	1,164		1,183

Acquisitions (note 7)	162		43

Disposals	(9	)	(57	)

Foreign currency translation	–		(5	)

Balance, end of year	1,317		1,164

Goodwill has no tax basis. See note 14 for details of the impairment testing of goodwill.

9. ACCOUNTS RECEIVABLE


	December 31, 2011		December 31, 2010		January 1, 2010

Trade receivables	1,617		1,289		1,218

Allowance for doubtful accounts (note 25)	(67	)	(2	)	(2	)

	1,550		1,287		1,216

The fair value of accounts receivable approximates the carrying amount due to their short term to maturity.

Trade receivables are non-interest bearing and are generally on 30-90 day terms.

At December 31, the analysis of trade receivables that were due or past due, but not impaired, was as follows:


			Past due but not impaired
	Total	Neither past due nor impaired	91-120 days	> 120 days

2011	1,550	1,483	12	55

2010	1,287	1,221	14	52

10. INVENTORIES


	December 31, 2011	December 31, 2010	January 1, 2010

Materials and supplies	56	69	75

Product	108	75	66

	164	144	141

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TALISMAN ENERGY ANNUAL REPORT 2011

11. OTHER ASSETS


	December 31, 2011	December 31, 2010	January 1, 2010

Accrued pension asset (note 30)	1	5	4

Note receivable (note 22)	–	–	40

Decommissioning sinking fund (note 15)	38	30	22

Acquisition deposits	–	630	–

Indemnification asset (note 7)	52	–	–

Other	10	2	8

	101	667	74

12. INVESTMENTS


	December 31, 2011	December 31, 2010	January 1, 2010

Investment in Oleoducto Central S.A (Ocensa) (note 7)	325	–	–

Other investments acquired pursuant to the Equión business combination (note 7)	25	–	–

Investment acquired pursuant to a property disposition	–	54	–

Investment in Transasia Pipeline Company Pvt. Ltd.	34	34	34

Other	11	33	–

	395	121	34

Investments comprise Talisman's interests accounted for using the equity method and the cost method.

The investment in Ocensa was acquired as part of the Equión business combination described in note 7 and is accounted for using the equity method. Ocensa has an interest in a pipeline in Colombia. The equity income recorded by Talisman in respect of this investment during the year ended December 31, 2011 was not material.

Three other investments were acquired pursuant to the Equión business combination, one of which is accounted for using the equity method and two using the cost method.

In 2010, Talisman acquired shares in a Canadian private company as part of the consideration for one of the North American property dispositions described in note 5. This private company completed an initial public offering later in 2010. These shares were subsequently sold on the open market in January 2011 for cash proceeds of $54 million.

The investment in Transasia Pipeline Company Pvt. Ltd. is accounted for using the cost method.

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TALISMAN ENERGY ANNUAL REPORT 2011

13. OIL AND GAS ASSETS

Cost and Accumulated DD&A

The cost and accumulated DD&A of the Company's PP&E (including corporate assets) and E&E assets are as follows:


	PP&E		E&E assets		Total

Cost

At January 1, 2010	25,726		2,212		27,938

Acquisitions through business combinations (note 7)	181		–		181

Other additions	3,044		1,856		4,900

Disposals and derecognition	(3,982	)	(229	)	(4,211	)

Transfers from E&E assets to PP&E	168		(168	)	–

Change in decommissioning liabilities	596		–		596

Expensed to dry hole	–		(113	)	(113	)

Foreign exchange	(273	)	(4	)	(277	)

At December 31, 2010	25,460		3,554		29,014

Acquisitions through business combinations (note 7)	559		–		559

Other additions	3,491		1,527		5,018

Disposals and derecognition	(384	)	(73	)	(457	)

Transfers from E&E assets to PP&E	654		(654	)	–

Change in decommissioning liabilities	363		–		363

Expensed to dry hole	–		(241	)	(241	)

At December 31, 2011	30,143		4,113		34,256

Accumulated DD&A

At January 1, 2010	12,472		–		12,472

Charge for the year	1,788		–		1,788

Disposals and derecognition	(2,119	)	–		(2,119	)

Impairment losses	189		112		301

Foreign exchange	(136	)	–		(136	)

At December 31, 2010	12,194		112		12,306

Charge for the year	1,949		–		1,949

Disposals and derecognition	(88	)	–		(88	)

Impairment losses	313		47		360

Impairment reversals	(134	)	–		(134	)

At December 31, 2011	14,234		159		14,393

Net book value

At December 31, 2011	15,909		3,954		19,863

At December 31, 2010	13,266		3,442		16,708

At January 1, 2010	13,254		2,212		15,466

Included in PP&E are capitalized interest costs of $161 million (December 31, 2010 – $81 million; January 1, 2010 – $nil) relating to projects under construction and development. During the year ended December 31, 2011, interest costs of $85 million (2010 – $81 million) were capitalized.

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TALISMAN ENERGY ANNUAL REPORT 2011

An incremental DD&A expense of $24 million was booked in the fourth quarter of 2011 to reflect an adjustment to reserves. For 2010, the impact of adjusting the DD&A expense in the fourth quarter for reserves revisions was a reduction of $47 million.

Non-Depleted Capital

PP&E and E&E assets include the following costs that were not subject to DD&A:


December 31		2011	2010

Undeveloped land

	North America	2,240	1,763

	Southeast Asia	304	287

	Other	219	201

Acquired unproved reserve costs not associated with producing fields¹

	North Sea	224	235

	Other	9	9

Exploration costs²

	North America	130	123

	North Sea	314	305

	Southeast Asia	194	340

	Other	320	179

E&E assets		3,954	3,442

Development projects³

	North America	–	58

	North Sea	1,714	1,144

	Southeast Asia	486	482

	Other	362	117

		6,516	5,243

1: Acquisition costs of unproved reserves are not depleted while under active evaluation for commercial reserves.
2: Exploration costs consist of drilling in progress and wells awaiting determination of proved reserves and are not depleted pending approval of development plans.
3: Development projects are not depleted until the asset is substantially complete and ready for its intended use.

Costs relating to wells drilled prior to 2011 continue to be capitalized, since management's ongoing assessment includes further planned activity. The number of wells drilled prior to 2011 and related costs are as follows:

	Years	Number of wells	Cost

North America	2008-2010	12	103

North Sea	2007-2010	10	513

Southeast Asia	2007-2010	8	26

Other	2008-2010	11	202

		41	844

North America wells drilled prior to 2011 are in the process of being evaluated or are awaiting completion of the construction of infrastructure. The remaining wells relate to fields where either further appraisal drilling is ongoing or development options are being assessed.

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TALISMAN ENERGY ANNUAL REPORT 2011

North Sea and other international wells relate to projects that are in the process of being evaluated, including the drilling of additional appraisal wells and the completion of additional seismic analysis. Some of these projects are in the final stages of project sanction.

14. IMPAIRMENT

Impairment of Assets


Years ended December 31		2011	2010

Impairment losses

	E&E assets	47	112

	PP&E	313	189

		360	301

Impairment reversals

	E&E assets	–	–

	PP&E	134	–

		134	–

Net impairment		226	301

At December 31, 2011, the Company assessed the carrying amount of its oil and gas assets for indicators of impairment such as changes in future prices, futures costs and reserves. The Company generally calculates the recoverable amount as the fair value less costs to sell using a discounted cash flow model. The discount rate is derived from the Company's post-tax weighted average cost of capital. Any country-specific risks are adjusted for within the cash flows. The rate to be applied is reassessed each year. The calculation is sensitive to the following assumptions which have been based on a long-term view of global oil and gas supply and demand as well as extensive industry experience:

•: Production volumes;
•: Discount rates;
•: Commodity prices;
•: Operating costs;
•: Future capital cost estimates;
•: Foreign exchange rates; and
•: Income taxes.

The following assumptions were used in developing the cash flow model for each cash-generating unit:

	2012	2013 and beyond

WTI ($/bbl)	90.00	86.69

Dated Brent ($/bbl)	95.00	85.77

Henry Hub natural gas ($/mmbtu)	5.00	5.50

AECO (C$/gj)	4.17	4.54

US$/C$	1.00	1.00

US$/UK£	1.63	1.63

Post-tax discount rate	10%	10%

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TALISMAN ENERGY ANNUAL REPORT 2011

During the year ended December 31, 2011, the Company recorded impairment of $129 million in North America due principally to reduced third party tariffs in the Company's midstream operations and lower conventional natural gas reserves. Impairments of $231 million in the North Sea were recorded in respect of oil and gas PP&E ($184 million) and E&E assets ($47 million). Of the $231 million, $102 million was as a result of a change in legislation announced by the UK government in March 2011 that raises the combined corporation tax and supplementary charge rate from 50% to 62% for oil and gas companies with fields not subject to PRT, and 75% to 81% with fields subject to PRT. See note 26 for further details. Additional impairment expense of $129 million in the North Sea arose due to a reduction in year-end reserves in a field in Norway.

Also during 2011, an impairment reversal of $134 million (2010 – $nil) resulted from price increases and an increase in estimated reserves for oil and gas assets that were previously impaired in the North Sea and Southeast Asia.

During the year ended December 31, 2010, the Company recorded $301 million of impairments, of which $189 million related to PP&E and $112 million to E&E assets. In North America, natural gas assets of $92 million were written down due to the decline in natural gas price assumptions and $24 million of exploration acreage was relinquished. In the North Sea, oil and gas assets of $76 million and E&E assets of $23 million were written down due to a change in reserves estimates, a change in the estimated timing of cash flows and changes in investment decisions. In addition, $65 million of exploration acreage was relinquished. In Southeast Asia, $21 million was recorded relating to oil assets due to an increase in estimated future costs.

The Yme project in Norway has experienced significant delays and cost overruns. The project is subject to arbitration with the contractor. Management has assessed the project's recoverability based on the above assumptions and a range of possible start up dates, arbitration outcomes and completion costs. No impairment writedown of the Yme project was recorded during the year ended December 31, 2011. Management will continue to assess the project's recoverability as new information becomes available. The net carrying value of Yme is approximately $800 million. The net after tax exposure is significantly less than the net carrying value of the project.

Impairment of Goodwill

No impairment of goodwill was recorded during the year ended December 31, 2011 (2010 – $nil), and there were no accumulated impairment losses at January 1, 2010. No reasonably possible change in assumptions would cause goodwill to become impaired.

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TALISMAN ENERGY ANNUAL REPORT 2011

15. DECOMMISSIONING LIABILITIES


Continuity of decommissioning liabilities	2011		2010

Balance, beginning of year	2,610		2,031

Liabilities incurred during the year	115		50

Liabilities settled during the year	(44	)	(76	)

Accretion expense (note 16)	76		79

Revisions in estimated cash flows	204		89

Change in discount rate	74		437

Balance, end of year	3,035		2,610

Expected to be settled within one year	53		30

Expected to be settled in more than one year	2,982		2,580

	3,035		2,610

Revisions in estimated cash flows occurring in 2011 related to cost increases in the North Sea as well as cost increases and a revision of the expected timing of settlement of liabilities in North America. The liabilities incurred during the year related principally to new wells and facilities in North America and Southeast Asia, as well as the addition of the decommissioning liabilities of Equión.

The Company provides for the future cost of decommissioning oil and natural gas properties and facilities on a discounted basis. At December 31, 2011, the estimated undiscounted decommissioning liabilities associated with oil and gas properties and facilities were $5.0 billion (December 31, 2010 – $4.5 billion; January 1, 2010 – $4.6 billion). The majority of the payments to settle this provision will occur over a period of 35 years and will be funded from the general resources of the Company as they arise. The provision for the costs of decommissioning production facilities and pipelines at the end of their economic lives has been estimated using existing technology, at current prices or long-term assumptions and based upon the expected timing of the activity. The provision has been discounted using a weighted average credit-adjusted risk free rate of 5.1% (2010 – 5.3%). Total accretion expense for the year ended December 31, 2011 of $76 million (2010 – $79 million) has been included in finance costs on the Consolidated Statements of Income.

The Company provided letters of credit at January 1, 2012 in an amount of $1.1 billion as security for the costs of decommissioning obligations in the UK.

The Company has established a decommissioning sinking fund of $38 million at December 31, 2011 (December 31, 2010 – $30 million; January 1, 2010 – $22 million) that represents secured funding for its decommissioning obligations in Southeast Asia.

16. FINANCE COSTS


Years ended December 31	2011		2010

Interest on long-term debt	240		235

Miscellaneous interest expense and other fees	47		43

Accretion expense (note 15)	76		79

Less: interest capitalized	(85	)	(81	)

	278		276

The interest rate applied in determining the amount of interest capitalized in 2011 was approximately 6.1% (2010 – 6.4%).

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TALISMAN ENERGY ANNUAL REPORT 2011

17. LONG-TERM DEBT


		December 31, 2011		December 31, 2010		January 1, 2010

Bank Credit Facilities		648		–		–

Commercial Paper		402		–		–

Tangguh Project Financing		97		105		101

Debentures and Notes (Unsecured)¹

	6.89% notes (US$10 million), Series B, due 2010	–		–		10

	4.44% medium term notes (C$350 million), due 2011²	–		352		334

	8.25% notes (US$50 million), due 2014	50		50		50

	5.125% notes (US$375 million), due 2015³	374		374		373

	8.50% notes (US$150 million), due 2016	150		150		150

	6.625% notes (UK£250 million), due 2017	385		386		399

	7.75% notes (US$700 million), due 2019	694		693		692

	3.75% notes (US$600 million), due 2021	592		592		–

	7.25% debentures (US$300 million), due 2027	300		300		300

	5.75% notes (US$125 million), due 2035	123		123		123

	5.85% notes (US$500 million), due 2037	493		493		493

	6.25% notes (US$600 million), due 2038	587		586		586

Gross debt⁴		4,895		4,204		3,611

Less: current portion		(410	)	(359	)	(10	)

Long-term debt		4,485		3,845		3,601

1: Interest on debentures and notes is payable semi-annually except for interest on the 6.625% notes, which is payable annually, and interest on the 6.89%, 8.25% and 8.50% notes, which is payable quarterly.
2: The currency and interest rate on these notes was swapped to $304 million bearing interest at 5.054%. See note 22 for details.
3: The interest rate on $300 million of these notes has been swapped to a floating rate obligation bearing interest at three-month LIBOR plus 0.43% (0.89% at December 31, 2011). See note 22 for details.
4: Financing costs of $41 million, $44 million and $38 million have been netted against the individual debt facilities as at December 31, 2011, December 31, 2010 and January 1, 2010, respectively.

During the year ended December 31, 2011, Talisman repaid $313 million of debt from cash on hand, and settled the cross-currency swap which was designated as a cash flow hedge.

Bank Credit Facilities and Commercial Paper

At December 31, 2011, Talisman had unsecured credit facilities totaling $4 billion, consisting of facilities of $3.8 billion (Facility No. 1) and $200 million (Facility No. 2). These facilities mature in November 2014, although the maturity date may be extended from time to time upon agreement between the Company and the respective lenders. Prior to the maturity date, the Company may borrow, repay and reborrow at its discretion. All facilities must be repaid on the maturity date.

Borrowings under Facility No. 1 are available in the form of prime loans, C$ or US$ bankers' acceptances, US$ base rate loans or LIBOR-based loans. In addition, drawings to a total of $1 billion are available in the form of letters of credit. Borrowings under Facility No. 2 are available in the form of prime loans, C$ or US$ guaranteed notes, US$ base rate loans and LIBOR-based loans. At December 31, 2011, $648 million in the form of bankers' acceptances (C$410 million and US$245 million) was drawn on the Company's facilities and $30 million was supporting letters of credit. The average rate on the outstanding bankers' acceptances was 2.88%, which reflects the weighted average interest rate of instruments outstanding at December 31, 2011. The rate is floating rate-based and varies with changes in short-term market interest rates.

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TALISMAN ENERGY ANNUAL REPORT 2011

At December 31, 2011, available borrowing capacity under the bank credit facilities was $3 billion.

Tangguh Project Financing

In connection with the acquisition of its interest in the Tangguh LNG Project, Talisman became a participant in a series of project financing facilities, the Company's share of which is up to $105 million. Approximately $97 million was outstanding under these facilities at December 31, 2011 (December 31, 2010 – $105 million; January 1, 2010 – $101 million), of which $8 million is due for repayment in 2012. The amount outstanding is secured by Talisman's interest in the Tangguh LNG Project, having a net book value of $223 million. Draws under these facilities bear interest at LIBOR plus 0.19% through to LIBOR plus 0.33% per annum and will mature in 2021.

Debentures and Notes

In 2010, Talisman completed a $600 million offering of 3.75% notes due February 2021. Interest on the notes is payable semi-annually.

Other

The Company has a financing structure whereby subsidiaries have $1.3 billion drawn on bank facilities that have been offset against equal amounts of cash deposited by another subsidiary with the same bank under a right of offset agreement. The Company intends to offset these amounts at maturity.

Repayment Schedule

The Company's contractual minimum repayments of gross long-term debt are as follows:

Year

2012¹		410

2013		8

2014		707

2015		384

2016		161

Subsequent to 2016		3,225

Gross debt		4,895

1: Includes $402 million of commercial paper to be refinanced in 2012.

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TALISMAN ENERGY ANNUAL REPORT 2011

18. OTHER LONG-TERM OBLIGATIONS


	December 31, 2011	December 31, 2010	January 1, 2010

Accrued pension and other post-employment benefits liability (note 30)	163	107	92

Deferred credits	25	46	47

Long-term portion of discounted obligations under finance leases	66	76	90

Long-term portion of share-based payments liability (note 20)	14	66	75

Acquired provisions (note 7)	52	–	–

Other	26	31	12

	346	326	316

The fair value of financial liabilities included above approximates the carrying amount.

Finance Leases

The Company has entered into two leasing arrangements for the modification, refitting and use of Floating Storage Offloading (FSO) vessels for use in its operations. Elements of the leasing arrangements have been defined by the Company as finance leases. The imputed rates of interest on these leases, which expire in 2016 and 2019, are 6% and 10%, respectively. Of the total discounted liability of $84 million (December 31, 2010 – $94 million; January 1, 2010 – $108 million), $18 million (December 31, 2010 – $18 million; January 1, 2010 – $18 million) is included in accounts payable and accrued liabilities.

The future minimum lease payments for finance leases and the present value of minimum finance lease payments by payment date are as follows:


	December 31, 2011			December 31, 2010			January 1, 2010

	Minimum payments		Present value of payments	Minimum payments		Present value of payments	Minimum payments		Present value of payments

Within one year	18		18	18		18	18		18

After one year but not more than five years	68		51	71		53	76		55

More than five years	28		15	43		23	66		35

Total minimum lease payments	114		84	132		94	160		108

Less amounts representing accretion	(30	)	–	(38	)	–	(52	)	–

Present value of minimum lease payments	84		84	94		94	108		108

19. CAPITAL DISCLOSURES

Talisman's objective in managing capital is to retain access to capital markets, ensure its ability to meet all financial obligations and meet its operational and strategic objectives.

Talisman's capital structure consists of shareholders' equity and debt. The Company makes adjustments to its capital structure based on changes in economic conditions and its planned requirements. Talisman has the ability to adjust its capital structure by issuing new equity or debt, selling assets to reduce debt, controlling the amount it returns to shareholders and making adjustments to its capital expenditure program.

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TALISMAN ENERGY ANNUAL REPORT 2011

Talisman manages its balance sheet with reference to its liquidity and a debt-to-cash flow ratio. The main factors in assessing the Company's liquidity are cash flow (defined below), cash provided by and used in investing activities and available bank credit facilities. The debt-to-cash flow ratio at December 31, 2011 and 2010 was as follows:


	2011	2010

Debt	4,967	4,226

Cash flow	3,572	3,140

Debt-to-cash flow	1.39:1	1.35:1

The calculation of debt is as follows:


	2011		2010

Gross debt and bank indebtedness	4,955		4,206

Add: Production payments and finance leases	109		125

Less: Non-recourse debt	(97	)	(105	)

Debt	4,967		4,226

The calculation of cash flow is as follows:


	2011		2010

Cash provided by operating activities	2,812		3,144

Changes in non-cash operating working capital	375		(367	)

Add: Exploration expenditure	427		374

Less: Amounts attributable to assets subject to non-recourse debt	(42	)	(11	)

Cash flow	3,572		3,140

Talisman is in compliance with all of its debt covenants. The Company's principal financial covenant under its primary bank credit facility is a debt-to-cash flow ratio of less than 3.5:1, calculated quarterly on a trailing 12-month basis as of the last day of each fiscal quarter.

1: 1 Dollar amounts in share-based payments tables are provided in C$.

20. SHARE CAPITAL AND SHARE-BASED PAYMENTS¹

Authorized

Talisman's authorized share capital consists of an unlimited number of common shares without nominal or par value and an unlimited number of first and second preferred shares.

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TALISMAN ENERGY ANNUAL REPORT 2011

Common Shares Issued


Continuity of common shares	2011				2010

	Shares		Amount		Shares		Amount

Balance, beginning of year	1,019,290,939		1,480		1,014,876,564		1,401

Issued on exercise of stock options	7,500,131		175		4,835,056		95

Shares purchased and held in trust for long-term PSU plan (see below)	(5,368,600	)	(94	)	(4,482,681	)	(81	)

Shares released from trust for 2008 PSU plan (see below)	–		–		4,062,000		65

Balance, end of year	1,021,422,470		1,561		1,019,290,939		1,480

During 2011, Talisman declared dividends of $0.27 per share (2010 – C$0.25 per share) for an aggregate dividend of $277 million (2010 – $249 million).

Subsequent to December 31, 2011, 296,153 stock options were exercised for shares and a further 80,000 common shares were purchased and held in trust for the long-term PSU plan. There were 1,021,638,623 common shares outstanding at February 28, 2012.

Holders of common shares are entitled to receive notice of and to attend all meetings of shareholders. Each common share carries with it the right to one vote. Subject to the rights of holders of other classes of shares who are entitled to receive dividends in priority to or rateably with the common shares, the Board of Directors may declare dividends on the common shares to the exclusion of any other class of shares of the Company. In the event of liquidation, dissolution or winding up of the Company or any other distribution of assets of the Company among its shareholders for the purpose of winding up its affairs, and subject to the rights of other classes of shares on a priority basis, the holders of common shares are entitled to participate rateably in any distribution of any assets of the Company.

Normal Course Issuer Bid

Talisman's normal course issuer bid expired on December 14, 2011. During the years ended December 31, 2011 and 2010, Talisman did not repurchase any common shares of the Company under its normal course issuer bid.

Preferred Shares Issued


Continuity of preferred shares		2011		2010

		Shares	Amount	Shares	Amount

Cumulative Redeemable Rate Reset First Preferred Shares,

	4.2% Series 1:

Balance, beginning of year		–	–	–	–

Issued		8,000,000	191	–	–

Balance, end of year		8,000,000	191	–	–

Holders of Series 1 preferred shares are entitled to receive a cumulative quarterly fixed dividend of 4.2% annually for the initial period ending December 31, 2016, as and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 2.77%.

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The Company may redeem all or a portion of the outstanding Series 1 preferred shares for C$25 per share plus accrued and unpaid dividends, on December 31, 2016 and on December 31 every five years thereafter. Holders of Series 1 preferred shares will have the right to convert their shares into Cumulative Rate Reset First Preferred Shares, Series 2 ("Series 2 preferred shares"), subject to certain conditions, on December 31, 2016 and on December 31 every five years thereafter. Holders of Series 2 preferred shares will be entitled to receive cumulative quarterly floating rate dividends at a rate equal to the three-month Government of Canada Treasury Bill yield plus 2.77%.

In the event of the liquidation, dissolution or winding up of the Company, the holders of Series 1 preferred shares will be entitled to receive C$25 per share together with all dividends accrued and unpaid to the date of payment before any amount will be paid or any assets of the Company distributed to the holders of any shares ranking junior to the Series 1 preferred shares. The holders of Series 1 preferred shares will not be entitled to share in any further distribution of the assets of the Company.

Holders of Series 1 preferred shares are not entitled to voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series 1 preferred shares are in arrears to the extent of eight quarterly dividends, whether or not consecutive.

Stock Option Plans

Talisman has stock option plans that govern the granting of options to employees and directors. All options issued by the Company permit the holder to purchase one common share of the Company at the stated exercise price per share or to receive a cash payment equal to the appreciated value of the shares underlying the stock option. Options granted under the plans are generally exercisable after three years and expire 10 years after the grant date. Commencing in 2006, options granted to new employees vest evenly on an annual basis over a three-year period. Option exercise prices approximate the market price for the common shares on the date the options are granted.

Continuity of stock options	2011			2010

	Number of shares underlying options		Weighted average exercise price (C$)	Number of shares underlying options		Weighted average exercise price (C$)

Outstanding, beginning of year	62,959,223		15.89	69,489,526		15.22

Granted	6,686,170		23.29	7,743,117		17.42

Exercised for common shares	(7,500,131	)	14.54	(4,835,056	)	11.75

Surrendered for cash	(642,889	)	15.62	(6,254,804	)	12.59

Forfeited	(2,410,329	)	17.40	(3,183,560	)	17.81

Outstanding, end of year	59,092,044		16.82	62,959,223		15.89

Exercisable, end of year	39,242,566		16.33	35,790,358		15.59

Options available for future grants pursuant to Stock Option Plans	39,523,835			42,653,842

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The range of exercise prices of the Company's outstanding stock options is as follows:

December 31, 2011			Outstanding options	Exercisable options

Range of exercise prices (C$)	Number of shares underlying options	Weighted average exercise price (C$)	Weighted average years to expiry	Number of shares underlying options	Weighted average exercise price (C$)

6.34 - 9.99	4,813,660	7.42	1	4,813,660	7.42

10.00 - 12.99	1,697,995	11.69	7	1,332,554	11.70

13.00 - 15.99	15,050,150	13.64	5	7,963,961	13.89

16.00 - 18.99	18,812,911	17.76	7	12,506,360	17.97

19.00 - 21.99	12,485,108	20.04	5	12,247,551	20.05

22.00 - 23.92	6,232,220	23.84	9	378,480	22.99

6.34 - 23.92	59,092,044	16.82	6	39,242,566	16.33

The fair value of the liability for the stock option plans at December 31, 2011 was $209 million (December 31, 2010 – $596 million; January 1, 2010 – $529 million), of which $196 million (December 31, 2010 – $540 million; January 1, 2010 – $462 million) is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets.

Subsequent to December 31, 2011, 3,033 stock options were surrendered for cash, 296,153 were exercised for shares, 61,520 were granted and 943,909 were forfeited, with 57,910,469 stock options outstanding at February 28, 2012.

Cash Unit Plan

In addition to the Company's stock option plans, Talisman's subsidiaries issue stock appreciation rights under the cash unit plan. Cash units are similar to stock options except that the holder does not have a right to purchase the underlying shares of the Company. Units granted under the cash unit plan are generally exercisable after three years and expire 10 years after the grant date.

Continuity of cash units	2011			2010

	Number of units		Weighted average exercise price (C$)	Number of units		Weighted average exercise price (C$)

Outstanding, beginning of year	10,112,792		16.64	10,078,102		16.42

Granted	1,547,670		22.34	1,170,920		17.38

Exercised	(1,636,458	)	17.42	(826,175	)	14.39

Forfeited	(562,840	)	18.33	(310,055	)	17.49

Outstanding, end of year	9,461,164		17.35	10,112,792		16.64

Exercisable, end of year	6,234,650		16.90	6,180,730		16.83

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The range of exercise prices of the Company's cash units is as follows:

December 31, 2011			Outstanding units	Exercisable units

Range of exercise prices (C$)	Number of units	Weighted average exercise price (C$)	Weighted average years to expiry	Number of units	Weighted average exercise price (C$)

6.60 - 9.99	754,840	7.64	2	754,840	7.64

10.00 - 12.99	101,427	10.96	7	35,144	11.12

13.00 - 15.99	2,209,111	13.70	6	1,090,826	13.94

16.00 - 18.99	2,467,694	17.67	7	1,570,903	17.94

19.00 - 21.99	2,790,482	20.02	5	2,739,077	20.03

22.00 - 25.19	1,137,610	24.21	9	43,860	23.93

6.60 - 25.19	9,461,164	17.35	6	6,234,650	16.90

The fair value of the liability for the cash unit plan at December 31, 2011 was $28 million (December 31, 2010 – $95 million; January 1, 2010 – $74 million), of which $27 million (December 31, 2010 – $85 million; January 1, 2010 – $66 million) is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets.

Subsequent to December 31, 2011, 6,531 cash units were exercised, 92,240 were granted and 70,913 were forfeited, with 9,475,960 cash units outstanding at February 28, 2012.

Long-Term Performance Share Unit (PSU) Plan

In 2009, the Company implemented a long-term PSU plan that allows for the granting of PSUs to employees, vesting after three years to varying degrees (0-150%) subject to predetermined performance measures being achieved. Each PSU represents the right, subject to performance, to receive one common share of the Company. Participants in the PSU plan are credited with additional PSUs corresponding to any associated dividend payments (referred to as 'dividend equivalent PSUs').


Continuity of long-term PSU plan	2011		2010

	Number of units		Number of units

Outstanding, beginning of year	8,173,762		5,520,158

Granted	3,450,930		3,768,840

Forfeited	(605,949	)	(1,221,258	)

Dividend equivalent PSUs	200,284		106,022

Outstanding, end of year	11,219,027		8,173,762

To satisfy the Company's obligations to deliver common shares to settle the PSUs, Talisman has arranged for a third party trustee to hold common shares which were purchased on the open market. During 2011, the Company purchased 5,368,600 common shares on the open market for $94 million. For accounting purposes, the cost of the purchase of the common shares held in trust has been accounted for as a reduction in outstanding common shares and the trust has been consolidated since it is a special purpose entity controlled by the Company. The Company is not exposed to fluctuations in the stock price in respect of the shares held in trust. Additional purchases of common shares to satisfy the Company's obligations are contemplated.

The 2009 long-term PSU grant vested on December 31, 2011 and settlement is expected to occur during the first quarter of 2012. Based on the Company's performance relative to the predetermined performance measures, the Board of Directors approved the vesting of 104% of the PSUs granted.

Subsequent to December 31, 2011, 64,453 PSUs were granted and 137,326 were forfeited with 11,146,154 outstanding at February 28, 2012. Between January 1 and February 28, 2012, a further 80,000 common shares were purchased on the open market for $1 million.

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2008 PSU Plan

In 2008, Talisman implemented a PSU plan pursuant to which 4,158,860 PSUs were granted. These PSUs vested on January 31, 2010 subject to predetermined performance measures being achieved. Based on the Company's performance relative to these predetermined performance measures, the Board of Directors approved the vesting of 90% of the PSUs granted.

To satisfy the Company's obligation to deliver common shares to settle the PSUs, the Company established a trust that purchased 4,062,000 common shares on the open market for $65 million. These shares were released from trust when the PSUs vested.

Deferred Share Unit (DSU) Plan

Talisman issues DSUs to directors in lieu of cash compensation. Each DSU represents the right to receive a cash payment on retirement equal to the market value of the Company's shares at the time of surrender. Dividends are credited as additional DSUs when paid. At December 31, 2011, there were 394,655 (December 31, 2010 – 330,448; January 1, 2010 – 396,550) units outstanding and the fair value of the liability was $5 million (December 31, 2010 – $7 million; January 1, 2010 – $7 million), which is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets. Recovery of $1 million (2010 – $3 million expense) related to the DSUs is recognized in general and administrative expenses on the Consolidated Statements of Income.

Restricted Share Unit (RSU) Plan

Talisman has a RSU plan that grants RSUs to eligible employees. All RSUs issued by the Company permit the holder to receive a cash payment equal to the market value of the stock. Participants are also credited with additional RSUs corresponding to any associated notional dividend payments (referred to as 'dividend equivalent RSUs'). Typically, RSUs granted under the plan are paid three years after the grant date. At December 31, 2011, there were 404,863 (December 31, 2010 – 462,133; January 1, 2010 – 342,730) units outstanding (including dividend equivalent RSUs) and the fair value of the liability was $2 million (December 31, 2010 – $5 million; January 1, 2010 – $3 million), which is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets.

Share-Based Payments Expense

The Company uses the Black-Scholes option pricing model to estimate the fair value of equity-settled share-based payment plans, with the following assumptions:


	December 31, 2011	December 31, 2010

Expected volatility	45%	42%

Risk free interest rate	1.3%	2.6%

Expected term (years)	5	5

Expected forfeiture rate	3.5%	3.4%

Expected annual dividend yield	1.2%	1.1%

The expected volatility is based on the historical volatility of the Company's common shares over a historical period that matches the expected term of the share-based payment plans. The risk-free rate is based on Government of Canada bond yields for terms that match the expected term of the share-based payment plans. The expected term for each option tranche is estimated at the end of each reporting period. The expected dividend rate takes into account historical dividend payments and the Company's expectation for future payments.

During the year ended December 31, 2011, the Company recorded share-based payments recovery of $310 million (2010 – $212 million expense) in respect of the plans described above as follows: stock options – $332 million recovery (2010 –

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$146 million expense), cash units – $56 million recovery (2010 – $18 million expense), 2008 PSU plan – $nil (2010 – $3 million recovery), long-term PSU plan – $78 million expense (2010 – $51 million expense) and RSUs – $nil (2010 – $nil).

During the year ended December 31, 2011, the Company recorded a net increase in contributed surplus of $78 million relating to its long-term PSU plan, compared to a net decrease of $9 million for the year ended December 31, 2010 which related to the settlement of the 2008 PSU plan.

During the year ended December 31, 2011, the Company paid cash of $14 million (2010 – $54 million) to employees in settlement of fully accrued option liabilities for options exercised. In addition, the Company capitalized share-based payments expense of $9 million (2010 – $3 million).

Of the combined liability for cash-settled stock option, cash unit, DSU and RSU plans of $244 million (December 31, 2010 – $703 million; January 1, 2010 – $613 million), $230 million (December 31, 2010 – $637 million; January 1, 2010 – $538 million) is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets and $14 million (December 31, 2010 – $66 million; January 1, 2010 – $75 million) is included in other long-term obligations.

The total number of options and cash units expected to vest as at December 31, 2011 was 68 million, with a weighted average remaining contractual life of six years, a weighted average exercise price of $16.84 and an aggregate intrinsic value of $33 million.

21. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of accumulated other comprehensive income are as follows:


		2011		2010

Balance, beginning of year

Derivative financial instruments designated as cash flow hedges		2		–

Foreign currency translation adjustments		786		1,194

		788		1,194

Other comprehensive income (loss) for the year

Derivative financial instruments designated as cash flow hedges

	Gains arising during the year	–		13

	Gains recognized in net income	–		(11	)

Foreign currency translation adjustments		–		(408	)

Actuarial losses relating to pension and other post-employment benefits		(26	)	(12	)

		(26	)	(418	)

Actuarial losses transferred to retained earnings		26		12

Balance, end of year

Derivative financial instruments designated as cash flow hedges		2		2

Foreign currency translation adjustments		786		786

		788		788

22. FINANCIAL INSTRUMENTS

Talisman's financial assets and liabilities at December 31, 2011 consisted of cash and cash equivalents, accounts receivable, investments, bank indebtedness, accounts payable and accrued liabilities, long-term debt (including the current portion) and risk management assets and liabilities arising from the use of derivative financial instruments.

The Company is exposed to financial risks arising from its financial assets and liabilities. The financial risks include market risk related to foreign exchange rates, interest rates and commodity prices, credit risk and liquidity risk.

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Fair Value of Financial Assets and Liabilities

The fair values of cash and cash equivalents, accounts receivable, bank indebtedness, and accounts payable and accrued liabilities approximate their carrying values due to the short-term maturity of those instruments. The note receivable, which settled in 2011, was classified as a financial asset at fair value through the Consolidated Statement of Income and presented at fair value calculated using discounted cash flows.

Borrowings under bank credit facilities are short-term in nature and are market rate-based, thus, carrying value approximates fair value. The fair value of public debentures and notes is based on market quotations, which reflect the discounted present value of the principal and interest payments using the effective yield for instruments having the same term and risk characteristics. The fair values of private notes are based on estimations provided by third parties. The fair value of Talisman's floating rate debt is determined by discounting future estimated coupon payments at the current market interest rate. The fair value of Talisman's long-term debt at December 31, 2011 was $5.1 billion (December 31, 2010 – $4.6 billion; January 1, 2010 – $3.9 billion), while the carrying value was $4.9 billion (December 31, 2010 – $4.2 billion; January 1, 2010 – $3.6 billion).

The fair values of all other financial assets and liabilities approximate their carrying values.

Risk management assets and liabilities are recorded at their estimated fair values. To estimate fair value, the Company uses quoted market prices when available, or models that utilize observable market data. In addition to market information, the Company incorporates transaction-specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. The Company's non-performance risk is determined based on third party quotes for the Company's debt instruments with maturity dates that are similar, or in close approximation, to the maturity dates of the corresponding financial instrument. The Company's risk management assets decreased by $3 million as a result of incorporating non-performance risk. The Company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

•: Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis;
•: Level 2 – inputs other than quoted prices included within level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Company obtains information from sources such as the New York Mercantile Exchange (NYMEX) and independent price publications; and
•: Level 3 – inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value, such as the Company's internally developed assumptions about market participant assumptions used in pricing an asset or liability, for example, an estimate of future cash flows used in the Company's internally developed present value of future cash flows model that underlies the fair value measurement.

In forming estimates, the Company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement. The valuation of over the counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that rely primarily on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorized as level 2.

Fair values for cross currency and interest rate derivative instruments are determined based on the estimated cash payment or receipt necessary to settle the contract. Cash payments or receipts are based on discounted cash flow analysis using current market rates and prices. Fair values for commodity price derivatives are based on discounted cash flow analysis using current market rates and prices and option pricing models using forward pricing curves and implied volatility, as appropriate, which are compared to quotes received from financial institutions for reasonability.

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The following table presents the Company's risk management assets measured at fair value for each hierarchy level at December 31, 2011:

	Level 1 inputs	Level 2 inputs	Level 3 inputs	Total fair value

Interest rate swaps	–	36	–	36

Commodity collars	–	30	–	30

Risk management assets	–	66	–	66

The following table sets forth a reconciliation of changes in the fair value of the assets classified as level 3 in the fair value hierarchy during 2011:


	2011		2010

Balance, beginning of year	42		40

Realized and unrealized gains (losses)	(2	)	2

Cash received	(40	)	–

Balance, end of year	–		42

At December 31, 2010, a note receivable relating to a 2008 asset disposition was classified as level 3 in the fair value hierarchy. During the year ended December 31, 2011, this note receivable was settled for $40 million and a deferred gain of $15 million was recognized, which is included in 'Gain on asset disposals' on the Consolidated Statement of Income. No other transfers in or out of level 3 occurred during 2011.

Unobservable inputs utilized to determine the fair value of the note receivable included the weighted average cost of capital and volatility of the common shares of the counterparty.

Risk Management Assets, Liabilities, Gains and Losses


		December 31,	December 31,	January 1,
Derivative instrument	Balance sheet presentation	2011	2010	2010

Interest rate swaps	Current assets	12	13	13

Interest rate swaps	Non-current assets	24	25	13

Cross-currency swaps	Current assets	–	46	–

Cross-currency swaps	Non-current assets	–	–	27

Commodity contracts	Current assets	30	60	16

Risk management assets		66	144	69

Cross-currency swaps	Current liabilities	–	–	1

Commodity contracts	Current liabilities	–	117	265

Commodity contracts	Non-current liabilities	–	–	6

Risk management liabilities		–	117	272

During the year ended December 31, 2011, the Company recorded a loss on held-for-trading financial instruments of $210 million (2010 – $87 million gain).

Currency Risk

Talisman operates internationally and is therefore exposed to foreign exchange risk. Talisman's primary exposure is from fluctuations in the US$ relative to the C$, UK£, and NOK.

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Talisman manages its foreign exchange exposure in a number of ways. By denominating most of its borrowings in US$, the Company is able to reduce some of its economic exposure to currency fluctuations. Talisman also manages its translation exposure by generally matching internal borrowings with its subsidiaries' functional currencies. The Company purchases foreign currencies, mostly at spot value, to meet its current foreign currency obligations as they come due.

Prior to 2011, the Company designated loans denominated in UK£ as an effective net investment hedge of its UK operations. During the year ended December 31, 2010, losses of $14 million were included in other comprehensive loss. These losses are attributable to the translation of Talisman's UK£250 million denominated debt. Following a change in the functional currency of the UK operations on January 1, 2011, foreign exchange gains of $2 million were recorded as a reduction of other expenses during the year ended December 31, 2011.

In respect of financial instruments existing at December 31, 2011, a 1% strengthening of the US$ against the other currencies noted above, with all other variables assumed constant, would have resulted in an increase of $15 million in net income and a $nil impact on other comprehensive loss during the year ended December 31, 2011. A similar weakening of the US$ would have had the opposite impact.

In conjunction with the issuance of the C$350 million 4.44% medium-term notes in January 2006, the Company entered into a cross-currency swap in order to hedge the foreign exchange exposure on this C$ denominated liability. As a result, the Company was effectively paying interest semi-annually in US$ at a rate of 5.054% on a notional amount of $304 million. The cross-currency swap was designated as a cash flow hedge. The notes were repaid in January 2011 and the hedge was settled.

Interest Rate Risk

Talisman is exposed to interest rate risk principally by virtue of its borrowings. Borrowing at floating rates exposes Talisman to short-term movements in interest rates. Borrowing at fixed rates exposes Talisman to reset risk (i.e. at debt maturity). Risk management activities aim to manage the mix of fixed-to-floating debt to best manage the trade-off between longer-term interest rate reset risk and shorter-term volatility in interest rates.

In order to mitigate its exposure to interest rate changes, Talisman enters into interest rate swaps from time to time to manage the ratio of fixed rate debt to floating rate debt. At December 31, 2011, the Company had fixed-to-floating interest rate swap contracts with a total notional amount of $300 million that expire on May 15, 2015. During the year ended December 31, 2011, the fair value of the fixed-to-floating interest rate swaps decreased by $1 million.

In respect of financial instruments existing at December 31, 2011, a 1% increase in interest rates would have resulted in a $14 million decrease in net income and a $nil impact on other comprehensive loss during the year ended December 31, 2011.

Credit Risk

Talisman is exposed to credit risk, which is the risk that a customer or counterparty will fail to perform an obligation or settle a liability, resulting in financial loss to the Company. Talisman manages exposure to credit risk by adopting credit risk guidelines approved by the Board of Directors that limit transactions according to counterparty creditworthiness. The Company routinely assesses the financial strength of its joint participants and customers, in accordance with the credit risk guidelines. Talisman's credit policy requires collateral to be obtained from counterparties considered to present a material risk of non-payment, which would include entities internally assessed as high risk or those with ratings below investment grade. Collateral received from customers at December 31, 2011 included $30 million of letters of credit. At December 31, 2011, an allowance of $65 million ($22 million, net of tax) for a doubtful account was recorded in respect of a balance owing by a counterparty that had filed for bankruptcy.

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The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The Company's policy allows it to deposit cash balances at financial institutions subject to a sliding scale limit, depending on creditworthiness.

The maximum credit exposure associated with financial assets is the carrying values.

Liquidity Risk

Talisman is exposed to liquidity risk, which is the risk that the Company may be unable to generate or obtain sufficient cash to meet its commitments as they come due. Talisman mitigates this risk through its management of cash, debt, committed credit capacity and its capital program.

Talisman maintains appropriate undrawn capacity in its revolving credit facilities to meet short-term fluctuations from forecasted results. Talisman manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by maintaining appropriate undrawn capacity under committed bank credit facilities. The Company has in place facilities totaling $4 billion that are fully committed through 2014. At December 31, 2011, $402 million of commercial paper and $648 million in the form of bankers' acceptances (C$410 million and US$245 million) was drawn and $30 million was supporting letters of credit. Available borrowing capacity was $3 billion at December 31, 2011.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At January 1, 2012, letters of credit totaling $1.6 billion had been issued under these facilities, of which $1.1 billion were provided as security for the costs of decommissioning obligations in the UK. The remaining outstanding letters of credit relate primarily to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations in other areas.

With the exception of the US commercial paper program described in note 17, the Company has no significant debt maturities until 2014.

Except for commodity price derivative contracts that mature as noted below, long-term debt that matures as outlined in note 17 and other long-term obligations detailed in note 18, all of the Company's financial liabilities are due within one year.

Commodity Price Risk

Talisman is exposed to commodity price risk since its revenues are dependent on the price of crude oil, natural gas and NGLs. Talisman enters into derivative instruments from time to time to mitigate commodity price risk volatility under guidelines approved by the Board of Directors. The Company may hedge a portion of its future production to protect cash flows to allow it to meet its strategic objectives.

The Company had the following commodity price derivative contracts outstanding at December 31, 2011, none of which are designated as hedges:

Two-way collars	Term	bbls/d	Floor/ceiling $/bbl	Fair value

Dated Brent oil index	Jan-Dec 2012	20,000	90.00/148.36	24

Dated Brent oil index	Jan-Jun 2012	9,000	90.00/126.93	1

Dated Brent oil index	Jan-Jun 2012	11,000	90.00/155.16	4

Dated Brent oil index	Jan-Jun 2012	10,000	90.00/123.08	1

Dated Brent oil index	Jul-Dec 2012	7,000	90.00/119.26	–

				30

Subsequent to December 31, 2011, the Company entered into a Dated Brent two-way collar of 3,000 bbls/d for the second half of 2012 with a floor of $90/bbl and a ceiling of $121.35/bbl.

In respect of outstanding financial instruments and assuming forward commodity prices in existence at December 31, 2011, an increase of $1/bbl in the price of oil would have reduced the net fair value of commodity derivatives, thereby resulting in a decrease in net income of $3 million during the year ended December 31, 2011. A similar decrease in the price of oil would have had the opposite impact.

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23. CONTINGENCIES AND COMMITMENTS

Provisions and Contingencies

Talisman's provision for decommissioning is presented in note 15. With the exception of the provisions acquired as part of the Equión acquisition described in note 7, the other provisions recorded by the Company are not material.

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not currently expected to have a material impact on the Company's financial position.

Estimated Future Minimum Commitments¹

Estimated future commitments for 2012 and beyond are as follows:

	2012	2013	2014	2015	2016	Subsequent to 2016	Total

Office leases	52	48	44	19	15	79	257

Vessel leases	243	132	84	83	76	49	667

Transportation and processing commitments²	260	155	144	142	136	727	1,564

Decommissioning liabilities	53	72	81	160	179	4,490	5,035

PP&E and E&E assets³	991	330	98	45	11	–	1,475

Other service contracts	204	89	101	65	19	42	520

	1,803	826	552	514	436	5,387	9,518

1: Future minimum payments denominated in foreign currencies have been translated into US$ based on the December 31, 2011 exchange rate.
2: Certain of the Company's transportation commitments are tied to firm gas sales contracts.
3: PP&E and E&E includes drilling rig commitments to meet a portion of the Company's future drilling requirements, as well as minimum work commitments.

There have been no significant changes in the Company's expected future payment commitments, and the timing of those payments, since December 31, 2011.

Talisman's estimated undiscounted decommissioning liabilities at December 31, 2011 were $5.0 billion (December 31, 2010 – $4.5 billion; January 1, 2010 – $4.6 billion), approximately 60% of which relates to Talisman's UK operations. At December 31, 2011, Talisman had accrued $3.0 billion (December 31, 2010 – $2.6 billion; January 1, 2010 – $2.0 billion), representing the discounted amount of this liability. The Company had provided letters of credit at January 1, 2012 in an amount of $1.1 billion as security for the costs of decommissioning obligations in the UK. In addition, the Company has issued guarantees as security for certain minimum work, future dismantlement, site restoration and abandonment obligations in lieu of letters of credit. Talisman has $254 million of abandonment letters of credit in place from January 1, 2012 until December 31, 2012 in respect of assets held by third parties.

Talisman leases certain of its ocean-going vessels and corporate offices, all of which, with the exception of the leasing arrangements described in note 18, are accounted for as operating leases. In addition to the minimum lease payments, Talisman has ongoing operating commitments associated with the vessels. The majority of the vessel leases have an average

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life of five years, the office leases have an average life of 10 years and the transportation commitment contracts have average lives of between 10 and 15 years.

Talisman has firm commitments for gathering, processing and transportation services that require the Company to pay tariffs to third parties for processing or shipment of certain minimum quantities of crude oil, natural gas and NGLs. The Company anticipates having sufficient production to meet these commitments.

In the case of an operating lease entered into by Talisman as the operator of a jointly controlled asset, the amounts reported represent the net operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed, by joint venture partners, whether the joint venture partners have co-signed the lease or not. Where Talisman is not the operator of a jointly controlled asset, Talisman's share of the lease expense and future minimum lease payments is included in the amounts shown, whether Talisman has co-signed the lease or not. Where lease rentals are dependent on a variable factor, the future minimum lease payments are based on the factor as at the inception of the lease.

During the year ended December 31, 2011, Talisman incurred net rental expense of $461 million (2010 – $578 million) in respect of its operating leases.

Long-Term Sales Contracts

In order to support the Company's investments in natural gas projects outside of North America and the North Sea, Talisman has entered into a number of long-term sales contracts.

The majority of Talisman's Corridor natural gas production in Indonesia is currently sold under long-term sales agreements with PT Chevron Pacific Indonesia (Chevron), Singapore Power and PGN (West Java). Under two sales agreements with Chevron, natural gas sales are at a price equal to 76% of the equivalent value of the Indonesia Crude Price for Duri crude oil. The minimum volume commitment under this contract is approximately 346 bcf over the remaining 10-year life of the contract. Under the agreement with Singapore Power, sales to Singapore from Corridor are referenced to the spot price of high sulphur fuel oil in Singapore. The minimum volume commitment is approximately 190 bcf over the remaining 12-year life of the contract. Sales from Corridor to PGN for their markets in West Java are under long-term contract at a price of approximately $1.91/mcf, with no associated transportation costs. The minimum volume commitment is approximately 650 bcf over the remaining 12-year life of the contract.

Currently, the Company anticipates having sufficient production to meet future delivery requirements.

24. OTHER INCOME


Years ended December 31	2011	2010

Pipeline and customer treating tariffs	53	75

Investment income	6	11

Marketing income	19	21

	78	107

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25. OTHER EXPENSES, NET


Years ended December 31	2011		2010

Foreign exchange gain	(12	)	(15	)

PP&E derecognition	26		28

Taxes, interest and penalties	18		5

Inventory writedowns	8		1

Allowance for doubtful accounts	65		–

Other miscellaneous	56		53

	161		72

26. INCOME TAXES

Significant components of the Company's income tax expense (recovery) are as follows:

Current Tax Expense


	North America	North Sea		Southeast Asia		Other		Total

Year ended December 31, 2011

Current tax	6	769		402		149		1,326

Adjustments related to prior years	11	(4	)	(10	)	(3	)	(6	)

Petroleum Revenue Tax	–	69		52		–		121

	17	834		444		146		1,441

Year ended December 31, 2010

Current tax	13	624		292		69		998

Adjustments related to prior years	–	20		5		(11	)	14

Petroleum Revenue Tax	–	85		39		–		124

	13	729		336		58		1,136

Deferred Tax Expense (Recovery)


	North America	North Sea		Southeast Asia		Other		Total

Year ended December 31, 2011

Origination (reversal) of temporary differences	(206)	202		34		(73	)	(43	)

Adjustments related to prior years	(15)	–		10		3		(2	)

Petroleum Revenue Tax	–	40		12		–		52

Changes in tax rates	(4)	225		–		–		221

	(225)	467		56		(70	)	228

Year ended December 31, 2010

Origination (reversal) of temporary differences	40	(39	)	(19	)	(30	)	(48	)

Adjustments related to prior years	(48)	–		(5	)	11		(42	)

Petroleum Revenue Tax	–	(8	)	(12	)	–		(20	)

	(8)	(47	)	(36	)	(19	)	(110	)

During 2011, the Company made elections for its Canadian subsidiaries to file tax returns in US$ with effect from the beginning of their 2011/12 tax years. Tax on foreign exchange on tax pools has not been recorded since the effective dates of these elections.

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Deferred Tax Assets and Liabilities

The most significant components of the net deferred tax liability are as follows:


	PP&E and E&E assets	Decommissioning liabilities		Tax loss carryforward		Other		Total

At January 1, 2010	3,687	(1,024	)	(116	)	(178	)	2,369

Charged (credited) to tax expense, net	409	(293	)	(314	)	88		(110	)

Acquisition adjustments	29	–		–		–		29

Other	–	–		–		(37	)	(37	)

At December 31, 2010	4,125	(1,317	)	(430	)	(127	)	2,251

Charged (credited) to tax expense, net	1,017	(418	)	(517	)	146		228

Credited to equity	–	–		–		(15	)	(15	)

Acquisition adjustments	219	(8	)	–		–		211

Other	–	–		–		(15	)	(15	)

At December 31, 2011	5,361	(1,743	)	(947	)	(11	)	2,660

Other movements in the net deferred tax liability relate mostly to reclassifications between assets and liabilities, and currency adjustments and risk management assets and liabilities.

At December 31, 2011, Talisman had unused non-capital tax losses of $2.6 billion (December 31, 2010 – $1 billion; January 1, 2010 – $408 million) in respect of which a deferred tax asset was recorded. These losses arose in the US and Canada and expire between 2028 and 2031. Income projections based upon discounted cash flow models, using assumptions consistent with those presented in note 14, show sufficient taxable income to utilize these losses within the carryforward period.

The majority of the $480 million (2010 – $294 million) of unused non-capital tax losses in respect of which no deferred tax asset has been recognized arose in Southeast Asia and South America and will not expire.

No deferred tax liability has been recognized for temporary differences associated with investments in subsidiaries, associates, branches and joint ventures since the Company is in a position to control or jointly control the entity and it is considered probable that these temporary differences will not reverse in the foreseeable future.

Effective Tax Rate

The following provides a reconciliation of the Canadian statutory tax rate of 26.76% (2010 – 28.26%) to the effective tax rate on the Company's total income before income taxes.


Years ended December 31		2011		2010

Income before taxes		2,445		1,971

Statutory income tax rate (%)		26.76%		28.26%

Income taxes calculated at the Canadian statutory rate		654		557

Increase (decrease) in income taxes resulting from:

	Change in statutory tax rates, net	221		–

	Non-taxable income	(54	)	(187	)

	Deductible PRT expense	(81	)	(46	)

	Higher foreign tax rates	799		533

	Share-based payments	(72	)	163

	Uplift	(74	)	(72	)

	Other	103		(26	)

Income tax expense (excluding PRT)		1,496		922

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In March 2011, the UK government announced that, from March 24, 2011, the rate of supplementary charge levied on ring fence profits increased from 20% to 32%. Supplementary charge is levied on ring fence profits in addition to the ring fence corporation tax rate of 30%, which remains unchanged. Consequently, there is now a combined UK corporation tax and supplementary charge rate of 62% for oil and gas companies with fields not subject to PRT and 75% to 81% with fields subject to PRT. If the price of oil falls below a certain level (currently expected to be $75/bbl) for a sustained period of time, the UK government has indicated that it will reduce the supplementary charge rate back towards 20% on a "staged and affordable basis" while prices remain low. As a result of this legislative change, the Company recorded additional current income tax expense of $101 million and additional deferred tax expense of $225 million during the year ended December 31, 2011.

In 2010, changes in Canadian and foreign statutory tax rates did not materially impact the Company's income tax expense.

Unrecognized Tax Benefit

Changes in the Company's unrecognized tax benefit are as follows:


	2011		2010

Unrecognized tax benefit, beginning of year	49		33

Increase due to prior period tax positions	22		30

Decrease due to prior period tax positions	(7	)	–

Decrease due to settlement with taxation authorities	(18	)	(14	)

Unrecognized tax benefit, end of year	46		49

Talisman's entire unrecognized tax benefit as at December 31, 2011 and December 31, 2010, if recognized, would affect the Company's effective tax rate.

The settlement with taxation authorities occurring in 2011 was the result of the Company settling a tax position in Norway regarding the deductibility of insurance premiums.

No significant change in the total unrecognized tax benefit is expected in 2012.

27. SUPPLEMENTAL CASH FLOW INFORMATION

Items Not Involving Cash


Years ended December 31	2011		2010

Depreciation, depletion and amortization	1,949		1,788

Impairment, net of reversals	226		301

Dry hole	241		113

Share-based payments expense (recovery)	(324	)	158

Gain on asset disposals	(192	)	(520	)

Unrealized gain on held-for-trading financial instruments	(61	)	(258	)

Deferred income tax (recovery)	228		(110	)

Foreign exchange	(11	)	3

PP&E derecognition	26		28

Other	42		53

	2,124		1,556

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Changes in Non-Cash Operating Working Capital


Years ended December 31	2011		2010

Accounts receivable	(292	)	(47	)

Inventories	(26	)	(14	)

Prepaid expenses	(4	)	(12	)

Decommissioning expenditures¹	(34	)	(17	)

Accounts payable and accrued liabilities	142		294

Income and other taxes payable	(161	)	163

	(375	)	367

1: $30 million of the decommissioning expenditures in 2011 were to settle liabilities that were recorded in accounts payable and accrued liabilities at December 31, 2010.

Other Cash Flow Information


Years ended December 31	2011	2010

Cash interest paid	254	240

Cash interest received	5	11

Cash income taxes paid	1,592	974

In respect of its exploration and evaluation activities, the Company has included exploration expenditure of $427 million within cash provided by operating activities, and exploration capital expenditure and acquisitions of $750 million and $737 million, respectively, within cash used in investing activities.

28. CASH AND CASH EQUIVALENTS

Of the cash and cash equivalents balance of $474 million, $286 million has been invested in bank deposits and the remainder in highly rated investments with original maturities of less than three months.

Cash and cash equivalents at December 31, 2011 includes $nil (2010 – $63 million) that is restricted and subject to currency controls and other legal restrictions.

29. NET INCOME PER SHARE – BASIC AND DILUTED


(millions)	2011	2010

Weighted average number of common shares outstanding – basic	1,023	1,018

Dilution effect of stock options and PSUs	15	–

Weighted average number of common shares outstanding – diluted	1,038	1,018

Outstanding stock options and PSUs are the only instruments that are dilutive to net income per share.

Basic net income per share is calculated by dividing the net income for the year by the weighted average number of common shares outstanding during the year, excluding shares held in trust to settle long-term PSU plan obligations.

For the diluted net income per share calculation, the net income is adjusted for the change in the fair value of stock options. The weighted average number of shares outstanding during the year is adjusted for options expected to be exercised and management's best estimate of shares expected to be issued in settlement of the Company's obligations pursuant to the long-term PSU plan.

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30. EMPLOYEE BENEFITS

The Company sponsors both defined benefit and defined contribution pension arrangements covering substantially all employees. The Company also provides non-pension post-employment benefits to its Canadian retirees.

Defined benefit pension plans are based on years of service and final average salary. The defined benefit pensions in the UK and Norway, which account for 36% of the accrued benefit obligation at December 31, 2011, will increase at the rate of inflation. Although the Company has no commitment to provide for increases related to inflation on its Canadian defined benefit pension plans, the benefits have generally been increased annually by one-half of the rate of inflation since 2003.

Talisman uses actuarial reports prepared by independent actuaries on the defined benefit pension plans for funding and accounting purposes. The Company uses a December 31 measurement date to value its benefit plan assets and obligations. The most recent actuarial valuation of the Canadian employee and executive pension plans for funding purposes was at December 31, 2010, with the next valuation no later than December 31, 2013. The most recent actuarial valuation of the UK pension scheme for funding purposes was at March 31, 2009, with the next valuation at March 31, 2012.

Actuarial Assumptions

The following significant actuarial assumptions were employed to determine the net benefit expense and the accrued benefit obligations:


	2011	2010

Accrued benefit obligation

Discount rate (%)	4.3	5.2

Rate of compensation increase (%)	4.7	4.8

Benefit expense

Discount rate (%)	5.2	5.8

Expected long-term rate of return on plan assets (%)	5.9	6.1

Assumed health care cost trend rates

Initial health care cost trend rate (%)	10	10

Health care cost trend rate declines to (%)	5	5

Year that cost trend reaches final rate	2036	2036

The discount rate assumptions reflect the prevailing rates available on high quality, fixed-income debt instruments.

The expected long-term rate of return on plan assets is established by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class.

Investment Policies

The Canadian defined benefit pension plans' investment policy provides a framework for managing the plan assets, without undue risk of capital loss and with a reasonable expectation of a rate of return or appreciation in value. Investment managers must manage the plan assets to reasonably track the return of the appropriate index. Equity investments are passively managed to replicate the S&P/TSX Index, the S&P 500 Index and the MSCI EAFE Index. Foreign equity investments are hedged to the Canadian dollar. Investments in bonds and debentures are managed passively to replicate the DEX Long Term Bond Index and are limited to those meeting minimum credit ratings.

The UK defined benefit pension plan's investment policy is designed to spread risks across a range of different sources. This is achieved through asset diversification so as to limit the impact of any single risk. Asset classes considered for the UK pension plan's investments are UK government and corporate bonds, UK and global equities and diversified growth funds. Most plan

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assets are actively managed, with assets re-balanced to the target asset allocation, described below, within a 5% tolerance range.

Plan Assets

The approximate target allocation percentage for the Canadian defined benefit pension plans that account for 29% of total plan assets is 50% equities and 50% bonds. The approximate target allocation for the UK pension plan that accounts for 58% of total plan assets is 45% UK equities, 35% global equities and 20% UK bonds. In late 2011, a new target allocation of 10% UK equities, 35% global equities, 35% diversified growth funds and 20% UK bonds was adopted for the UK pension plan and is gradually being implemented. Plan assets do not include any common shares of Talisman, other than through Canadian equity pooled funds, or any assets used by the Company.

The allocation of the assets of the defined benefit plans is as follows:


	December 31, 2011	December 31, 2010	January 1, 2010

Equity securities (%)	61	64	60

Fixed income (%)	31	30	32

Cash (%)	6	4	6

Real estate (%)	2	2	2

	100	100	100

The Company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. Refer to note 22 for details concerning the three levels of the fair value hierarchy.

The fair values of defined benefit plan assets at December 31, 2011 by asset category were as follows:

		Level 1 inputs	Level 2 inputs	Level 3 inputs	Total fair value

Cash		16	–	–	16

Pooled Funds:

	Canadian companies	–	7	–	7

	US companies	–	14	–	14

	International companies	–	142	–	142

	Bonds	–	72	–	72

	International government securities	–	12	–	12

	Real estate	–	–	6	6

		16	247	6	269

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Obligation, Assets and Funded Status

Information about the Company's defined benefit pension plans is as follows:


	2011				2010
	Pension plans grouped by funded status				Pension plans grouped by funded status

	Surplus		Deficit		Surplus		Deficit

Accrued benefit obligation

Accrued benefit obligation, beginning of year	209		139		58		228

Transition of plans from a surplus to a deficit position	(145	)	145		–		–

Transition of plans from a deficit to a surplus position	–		–		121		(121	)

Current service cost	–		28		14		10

Interest cost	3		15		11		6

Actuarial loss	2		39		12		16

Plan participants' contributions	–		1		1		–

Benefits paid	(5	)	(8	)	(6	)	(5	)

Foreign currency translation	(1	)	(4	)	(2	)	4

Other	–		–		–		1

Accrued benefit obligation, end of year	63		355		209		139

Plan assets

Fair value of plan assets, beginning of year	214		43		62		147

Transition of plans from a surplus to a deficit position	(146	)	146		–		–

Transition of plans from a deficit to a surplus position	–		–		112		(112	)

Expected return on plan assets	4		12		12		1

Actuarial gain (loss) on plan assets	–		(15	)	15		–

Employer contributions	–		26		19		12

Plan participants' contributions	–		1		1		–

Benefits paid	(5	)	(8	)	(6	)	(5	)

Foreign currency translation	(3	)	–		(1	)	–

Fair value of plan assets, end of year	64		205		214		43

Funded status – surplus (deficit)¹	1		(150	)	5		(96	)

1: The net accrued benefit asset and net accrued benefit liability are included in other assets and other long-term obligations, respectively, on the Consolidated Balance Sheets.

During 2012, the Company expects to make contributions of $27 million to its defined benefit pension plans.

At December 31, 2011, the actuarial net present value of the accrued benefit obligation for non-pension post-employment benefits was $13 million (December 31, 2010 – $11 million; January 1, 2010 – $11 million). Non-pension post-employment benefits include medical, dental and life insurance benefits for current and future Canadian retired employees.

Of the aggregate accrued benefit obligation of $355 million at December 31, 2011, $99 million related to plans that are unfunded. The $78 million deficit of one unfunded plan is secured by letters of credit in the amount of $110 million.

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History of Deficit and Experience Gains and Losses


Years ended December 31	2011		2010

Accrued benefit obligation at December 31	418		348

Fair value of plan assets at December 31	269		257

Net deficit	(149	)	(91	)

Experience loss on plan liabilities	(41	)	(28	)

Actual return less expected return on plan assets	(16	)	16

Net Benefit Expense

The net benefit expense for the pension plans recognized in the Consolidated Statements of Income is as follows:


Years ended December 31	2011		2010

Current service cost – defined benefit	28		24

Interest cost	18		17

Expected return on plan assets	(16	)	(13	)

Other	2		1

Defined benefit plan expense	32		29

Defined contribution plan expense	14		13

Net benefit expense	46		42

The actual return on plan assets in 2011 was $nil (2010 – $29 million).

During the year ended December 31, 2011, the net benefit expense for non-pension post-employment benefits was $1 million (2010 – $1 million).

The pension and non-pension post-employment benefits of key management personnel are disclosed in note 32.

Sensitivity Information

A 1% increase or decrease in the assumed medical cost trend rate would have an immaterial impact on both the accrued benefit at December 31, 2011 and the aggregate of service and interest costs during the year ended December 31, 2011.

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31. SEGMENTED INFORMATION

Talisman's activities are conducted in four geographic segments: North America, the North Sea, Southeast Asia and Other. The North America segment includes operations in Canada and the US. The North Sea segment includes operations and exploration activities in the UK and Norway. The Southeast Asia segment includes operations and exploration activities in Indonesia, Malaysia, Vietnam and Papua New Guinea and operations in Australia/Timor-Leste. The Company also conducts operations in Algeria, operations and exploration activities in Colombia, and exploration activities in Peru, Poland, Sierra Leone and the Kurdistan region of northern Iraq. For ease of reference, the activities in Algeria, Colombia, Peru, Poland, Sierra Leone and the Kurdistan region of northern Iraq are referred to collectively as the Other geographic segment.

All activities relate to the exploration, development, production and transportation of oil, liquids and natural gas. Effective January 1, 2011, the composition of the Company's segments changed such that the activities in the UK and Norway are reported as a single North Sea segment since, in management's judgment, the assets in those locations now share similar economic characteristics. Comparative period balances have been restated accordingly.


	North America¹				North Sea²		Southeast Asia³			Other⁴			Total
(millions of US$)	2011		2010		2011	2010	2011		2010	2011	2010		2011		2010

Revenue

Sales	1,695		1,679		4,074	3,526	1,882		1,476	543	194		8,194		6,875

Other income	63		85		14	21	1		1	–	–		78		107

Total revenue and other income	1,758		1,764		4,088	3,547	1,883		1,477	543	194		8,272		6,982

Segmented expenses

Operating	454		487		1,292	1,096	372		280	72	27		2,190		1,890

Transportation	68		59		84	95	55		60	9	7		216		221

DD&A	852		717		671	766	305		277	121	28		1,949		1,788

Impairment	129		116		113	164	(16	)	21	–	–		226		301

Dry hole	6		(11	)	106	70	127		31	2	23		241		113

Exploration	70		52		40	47	208		116	109	159		427		374

Other	22		(25	)	105	91	17		16	29	5		173		87

Total segmented expenses	1,601		1,395		2,411	2,329	1,068		801	342	249		5,422		4,774

Segmented income (loss) before taxes157			369		1,677	1,218	815		676	201	(55	)	2,850		2,208

Non-segmented expenses

General and administrative													431		371

Finance costs													278		276

Share-based payments (recovery) expense													(310	)	212

Currency translation													(12	)	(15	)

(Gain) loss on held-for-trading financial instruments													210		(87	)

Gain on asset disposals													(192	)	(520	)

Total non-segmented expenses													405		237

Income before taxes													2,445		1,971

Capital expenditures

Exploration	198		216		128	133	257		125	138	119		721		593

Development	1,960		1,481		1,077	984	230		317	157	95		3,424		2,877

Midstream	(3	)	3		–	–	–		–	–	–		(3	)	3

Exploration and development	2,155		1,700		1,205	1,117	487		442	295	214		4,142		3,473

Acquisitions													1,319		1,530

Proceeds on dispositions													(569	)	(2,273	)

Other non-segmented													159		78

Net capital expenditures													5,051		2,808

Property, plant and equipment	6,740		5,351		5,809	5,368	2,501		2,296	859	251		15,909		13,266

Exploration and evaluation assets	2,370		1,886		538	540	498		627	548	389		3,954		3,442

Goodwill	140		149		866	866	149		149	162	–		1,317		1,164

Other	987		2,389		645	920	560		628	788	141		2,980		4,078

Segmented assets	10,237		9,775		7,858	7,694	3,708		3,700	2,357	781		24,160		21,950

Non-segmented assets													66		144

Total assets													24,226		22,094

Decommissioning liabilities	394		210		2,390	2,196	208		189	43	15		3,035		2,610

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1	North America	2011	2010

	Canada	1,127	1,454

	US	631	310

	Total revenue and other income	1,758	1,764

	Canada	3,937	3,920

	US	2,803	1,431

	Property, plant and equipment	6,740	5,351

	Canada	1,207	685

	US	1,163	1,201

	Exploration and evaluation assets	2,370	1,886


2	North Sea	2011	2010

	UK	2,835	2,190

	Norway	1,253	1,357

	Total revenue and other income	4,088	3,547

	UK	3,927	3,763

	Norway	1,882	1,605

	Property, plant and equipment	5,809	5,368

	UK	210	260

	Norway	328	280

	Exploration and evaluation assets	538	540


3	Southeast Asia	2011	2010

	Indonesia	974	839

	Malaysia	565	481

	Vietnam	183	52

	Australia	161	105

	Total revenue and other income	1,883	1,477

	Indonesia	1,023	986

	Malaysia	883	1,053

	Vietnam	297	19

	Papua New Guinea	47	26

	Australia	251	212

	Property, plant and equipment	2,501	2,296

	Indonesia	12	27

	Malaysia	41	29

	Vietnam	5	253

	Papua New Guinea	440	318

	Exploration and evaluation assets	498	627


4	Other	2011	2010

	Algeria	256	194

	Colombia	287	–

	Total revenue and other income	543	194

	Algeria	284	251

	Colombia	575	–

	Property, plant and equipment	859	251

	Colombia	75	49

	Kurdistan	303	239

	Peru	133	98

	Other	37	3

	Exploration and evaluation assets	548	389

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32. RELATED PARTY DISCLOSURES

Corporate Structure

The Consolidated Financial Statements include the financial statements of Talisman Energy Inc. and the directly or indirectly wholly owned subsidiaries (unless otherwise noted) listed in the following table. Transactions between subsidiaries are eliminated on consolidation. There were no related party transactions with entities or other parties outside the consolidated group during the years ended December 31, 2011 and 2010.

Company Name		Jurisdiction

504744 Alberta Ltd.		Alberta
7308051 Canada Ltd.		Canada
Amulet Maritime Limited		England
Equión Energía Limited (49%)		England
FEI Shale GP Inc.		Delaware
FEI Shale L.P.		Delaware
FEX GP Inc.		Delaware
FEX L.P.		Delaware
Foreland Oil Limited		British Virgin Islands
Fortuna (US) Investments Limited		Delaware
Fortuna (US) L.P.		Delaware
Fortuna Energy Holding Inc.		Delaware
Fortuna Finance Corporation		Barbados
Fortuna International (Barbados) Inc.		Barbados
Fortuna International Petroleum Corporation		Barbados
Fortuna Resources (Sunda) Limited		British Virgin Islands
FUSI GP Inc.		Delaware
Honner Limited		Papua New Guinea
International Petroleum Corporation		Canada
Keelwood Limited		England
Oleum Insurance Company Limited		Barbados
Paladin Resources Limited		Scotland
Papua Petroleum Pty Ltd.		Australia
Papua Petroleum (PNG) Ltd.		Papua New Guinea
Pittencrieff America Inc.		Nevada
Pittencrieff Resources Inc.		Nevada
Potts Limited		Papua New Guinea
Red Sea Oil Corporation		Canada
Rigel Petroleum (NI) Limited		Northern Ireland
Rift Oil Limited		England
Rigel Petroleum UK Limited		England
Rowell Limited		Papua New Guinea
Talisman (Algeria) B.V.		Netherlands
Talisman (Asia) Ltd.		Alberta
Talisman (Block K 39) B.V.		Netherlands
Talisman (Block K 44) B.V.		Netherlands
Talisman (Block K 9) B.V.		Netherlands
Talisman (Colombia) Oil & Gas Ltd.		Canada
Talisman (Corridor) Ltd.		Barbados
Talisman (Jambi) Ltd.		Alberta
Talisman (Jambi Merang) Limited		England
Talisman (Masalima) Ltd.		Alberta
Talisman (Ogan Komering) Ltd.		Alberta
Talisman (Pasangkayu) Ltd.		Alberta
Talisman (Sageri) Ltd.		Alberta
Talisman (Sumatra) Ltd.		Canada
Talisman (Tunisia) Inc.		Alberta
Talisman (Vietnam 133 & 134) Ltd.		Alberta
Talisman (Vietnam 15-2/01) Ltd.		Alberta
Talisman (Vietnam 46/02) Ltd.		Alberta
Talisman Andaman B.V.		Netherlands
Talisman Australasia Pty Ltd.		Australia
Talisman Caño Sur B.V.		Netherlands
Talisman Colombia Holdco Limited		England
Talisman Energia Brasil Ltda		Brazil
Talisman Energy (Sahara) B.V.		Netherlands
Talisman Energy (UK) Limited		England
Talisman Energy (UK) Pension & Life Scheme Ltd.		England
Talisman Energy Alpha Limited		England
Talisman Energy Beta Limited		England
Talisman Energy Canada		Alberta
Talisman Energy Danmark AS		Norway
Talisman Energy DL Limited		England
Talisman Energy Holdings Ltd.		Alberta
Talisman Energy Investments Norge AS		Norway
Talisman Energy Kimu Alpha Pty Ltd.		Australia
Talisman Energy Kimu Beta Pty Limited		Papua New Guinea
Talisman Energy Niugini Limited		Papua New Guinea
Talisman Energy Norge AS		Norway
Talisman Energy NS Limited		England
Talisman Energy Poland B.V.		Netherlands
Talisman Energy Polska sp. z o.o.		Poland
Talisman Energy Services Inc.		Delaware
Talisman Energy Tangguh B.V.		Netherlands
Talisman Energy USA Inc.		Delaware
Talisman Finance (UK) Limited		England
Talisman Indonesia Ltd.		Alberta
Talisman International (Barbados) Inc.		Barbados
Talisman International Business Corporation		Barbados
Talisman International Holdings B.V.		Netherlands
Talisman K Holdings B.V.		Netherlands
Talisman LNS Limited		England
Talisman Malaysia (PM3) Limited		Barbados
Talisman Malaysia Holdings Limited		Barbados
Talisman Malaysia Limited		Barbados
Talisman Niugini Pty Ltd		Australia
Talisman North Sea Limited		England
Talisman Oil & Gas (Australia) Pty Limited		Australia
Talisman Oil Limited		Barbados
Talisman Oil Trading Limited		England
Talisman Peru B.V.		Netherlands
Talisman Production Norge AS		Norway
Talisman Resources (Bahamas) Limited		Bahamas
Talisman Resources (JPDA 06-105) Pty Limited		Australia
Talisman Resources Norge AS		Norway
Talisman Resources (North West Java) Limited		England
Talisman RTC Sdn.Bhd.		Malaysia
Talisman Sadang B.V.		Netherlands
Talisman Sasol Montney Partnership (50%)		British Columbia
Talisman SEA Pte. Ltd.		Singapore
Talisman Sierra Leone B.V.		Netherlands
Talisman South Mandar B.V.		Netherlands
Talisman South Sageri B.V.		Netherlands
Talisman Transgasindo Ltd.		Barbados
Talisman Transportation (UT) Limited		England
Talisman Trustees (UK) Limited		England
Talisman UK (South East Sumatra) Limited		England
Talisman Vietnam Limited		Barbados
Talisman Vietnam 05-2/10 B.V.		Netherlands
Talisman Vietnam 135-136 B.V.		Netherlands
Talisman Wiriagar Overseas Limited		British Virgin Islands
Teakan Investments Limited		Bermuda
TE Capital S.ar.l		Luxembourg
TE Finance S.ar.l		Luxembourg
TE Global Services Inc.		Delaware
TE Holding S.ar.l		Luxembourg
TE NOK S.ar.l.		Luxembourg
TE Resources S.ar.l		Luxembourg
TE Transworld S.ar.l		Luxembourg
TEGSI (UK) Limited		England
Thang Long Joint Operating Company (60%)		Vietnam
TLM Capital Finance ULC		Nova Scotia
TLM Capital Management Hungary Limited Liability Company		Hungary
TLM Finance Corp.		Alberta
Transasia Pipeline Company Pvt. Ltd. (15%)		Mauritius
Trans Mediterranean Oil Company Ltd.		British Columbia
Transworld Petroleum (U.K.) Limited		England
Triad Minerals Inc.		Canada
Triad Oil Manitoba Ltd.		Manitoba
Truong Son Joint Operating Company (30%)		Vietnam
TV 05-2/10 Holdings B.V.		Netherlands
TV 135-136 Holdings B.V.		Netherlands

125
TALISMAN ENERGY ANNUAL REPORT 2011

Key Management Personnel Compensation

The compensation of key management personnel, consisting of the Company's directors and executive officers, is as follows:


Years ended December 31	2011	2010

Short-term benefits	15	14

Pension and other post-employment benefits	5	4

Termination benefits	4	–

Share-based payments	11	15

	35	33

Short-term benefits comprise salaries and fees, annual bonuses, cash, vehicle and other benefits.

The amount of pension benefits reported represents the attributable amount of the net benefit expense of the plans in which the key management personnel participate.

Termination benefits comprise amounts paid and accrued.

The share-based payments amount reported represents the cost to the Company of key management's participation in share-based payment plans, as measured by the fair value that the individual received based on the value of the shares exercised in the current period.

126
TALISMAN ENERGY ANNUAL REPORT 2011

Supplementary Oil and Gas Information

(unaudited)

The supplemental data on the Company's oil and gas activities was prepared in accordance with the FASB standard Extractive Activities – Oil & Gas. Activities not directly associated with conventional crude oil and natural gas production are excluded from all aspects of this supplementary oil and gas information. Comparable information prepared in accordance with Canadian disclosure requirements (National Instrument 51-101 of the Canadian Securities Administrators) is contained in Appendix A of Talisman's Annual Information Form.

Results of Operations from Oil and Gas Producing Activities


		North America				North Sea		Southeast Asia
Years ended December 31 (millions of $)		Canada		US		UK	Norway	Indonesia	Other SEA²		Other³		Total

2011
Net oil and gas revenue derived from proved reserves¹		1,040		633		2,823	1,252	1,126	756		543		8,173

Less:	Production costs	328		121		921	367	146	226		72		2,181

	Transportation	35		33		37	47	55	–		9		216

	Exploration and dry hole expense	54		29		64	81	114	218		107		667

	Depreciation, depletion and amortization	581		352		492	354	73	217		120		2,189

	Tax expense	12		38		847	329	365	100		91		1,782

Results of operations		30		60		462	74	373	(5	)	144		1,138

2010
Net oil and gas revenue derived from proved reserves¹		1,365		304		2,172	1,354	852	624		194		6,865

Less:	Production costs	421		59		793	296	127	153		27		1,876

	Transportation	48		11		33	62	60	–		7		221

	Exploration and dry hole expense	43		2		76	41	55	90		179		486

	Depreciation, depletion and amortization	562		221		553	440	50	247		29		2,102

	Tax expense	75		4		396	401	269	80		15		1,240

Results of operations		216		7		321	114	291	54		(63	)	940

2009⁴
Net oil and gas revenue derived from proved reserves¹		1,667		126		2,183	986	700	620		265		6,547

Less:	Production costs	555		30		872	285	104	151		48		2,045

	Transportation	55		4		46	54	55	–		8		222

	Exploration and dry hole expense	222		53		48	92	26	302		142		885

	Depreciation, depletion and amortization	894		151		837	411	51	331		48		2,723

	Tax expense (recovery)	(15	)	(43	)	255	112	219	–		33		561

Results of operations		(44	)	(69	)	125	32	245	(164	)	(14	)	111

1: Net oil and gas revenue derived from proved reserves is net of applicable royalties.
2: Other Southeast Asia includes operations in Malaysia, Vietnam, Australia/Timor-Leste and Papua New Guinea.
3: The reporting segment entitled "Other" includes Algeria, Colombia (Equión and Talisman's other Colombia assets), Peru, Poland, Sierra Leone, the Kurdistan region of northern Iraq and, prior to their sales in 2010 and 2009, respectively, Tunisia and Trinidad and Tobago.
4: 2011 and 2010 amounts are reported in US$ and are in accordance with IFRS; 2009 amounts are reported in Canadian dollars and are in accordance with Canadian GAAP.

127
TALISMAN ENERGY ANNUAL REPORT 2011

Capitalized Costs Relating to Oil and Gas Activities


		North America		North Sea		Southeast Asia
Years ended December 31 (millions of $)		Canada	US	UK	Norway	Indonesia	Other SEA¹	Other²	Total

2011
Proved properties		7,037	3,798	8,730	3,890	1,415	3,110	1,323	29,303

Unproved properties		1,196	1,165	195	276	192	259	389	3,672

Incomplete wells and facilities		8	–	15	52	1	45	161	282

		8,241	4,963	8,940	4,218	1,608	3,414	1,873	33,257

Less:	Accumulated depreciation, depletion and amortization	3,660	1,040	4,806	2,012	577	1,463	476	14,034

Net capitalized costs		4,581	3,923	4,134	2,206	1,031	1,951	1,397	19,223

2010
Proved properties		6,554	2,113	8,092	3,280	1,358	2,556	611	24,564

Unproved properties		669	1,202	253	258	137	574	346	3,439

Incomplete wells and facilities		15	–	28	16	16	27	43	145

		7,238	3,315	8,373	3,554	1,511	3,157	1,000	28,148

Less:	Accumulated depreciation, depletion and amortization	3,152	693	4,347	1,669	499	1,251	364	11,975

Net capitalized costs		4,086	2,622	4,026	1,885	1,012	1,906	636	16,173

2009³
Proved properties		10,933	1,351	8,603	3,313	1,275	2,635	410	28,520

Unproved properties		856	410	435	136	70	490	552	2,949

Incomplete wells and facilities		30	10	9	7	2	56	78	192

		11,819	1,771	9,047	3,456	1,347	3,181	1,040	31,661

Less:	Accumulated depreciation, depletion and amortization	4,891	608	4,498	1,414	488	1,176	203	13,278

Net capitalized costs		6,928	1,163	4,549	2,042	859	2,005	837	18,383

1: Other Southeast Asia includes operations in Malaysia, Vietnam, Australia/Timor-Leste and Papua New Guinea.
2: The reporting segment entitled "Other" includes Algeria, Colombia (Equión and Talisman's other Colombia assets), Peru, Poland, Sierra Leone, the Kurdistan region of northern Iraq and, prior to their sale in 2010 and 2009, respectively, Tunisia and Trinidad and Tobago.
3: 2011 and 2010 amounts are reported in US$ and are in accordance with IFRS; 2009 amounts are reported in Canadian dollars and are in accordance with Canadian GAAP.

128
TALISMAN ENERGY ANNUAL REPORT 2011

Costs Incurred in Oil and Gas Activities


		North America				North Sea		Southeast Asia
Years ended December 31 (millions of $)		Canada		US		UK	Norway	Indonesia	Other SEA¹	Other²		Total

2011
Property acquisition costs
	Proved properties	3		208		–	15	–	11	570		807

	Unproved properties	590		51		–	–	–	26	17		684

Exploration costs		93		14		52	116	105	349	248		977

Development costs		528		1,427		554	520	129	96	157		3,411

Decommissioning costs		177		35		34	95	13	3	(2	)	355

Total costs incurred		1,391		1,735		640	746	247	485	990		6,234

2010
Property acquisition costs
	Proved	5		133		–	–	117	–	–		255

	Unproved	3		1,029		–	191	54	39	52		1,368

Exploration costs		199		19		93	87	72	163	234		867

Development costs		581		909		497	485	74	250	100		2,896

Decommissioning costs		66		(11	)	470	18	6	17	7		573

Total costs incurred		854		2,079		1,060	781	323	469	393		5,959

2009³
Property acquisition costs
	Proved	147		1		–	–	2	–	–		150

	Unproved	394		392		–	–	8	343	47		1,184

Exploration costs		339		188		149	157	28	195	217		1,273

Development costs		436		120		523	578	43	385	59		2,144

Decommissioning costs		(17	)	4		208	41	10	5	4		255

Total costs incurred		1,299		705		880	776	91	928	327		5,006

1: Other Southeast Asia includes operations in Malaysia, Vietnam, Australia/Timor-Leste and Papua New Guinea.
2: The reporting segment entitled "Other" includes Algeria, Colombia (Equión and Talisman's other Colombia assets), Peru, Poland, Sierra Leone, the Kurdistan region of northern Iraq and, prior to their sale in 2010 and 2009, respectively, Tunisia and Trinidad and Tobago.
3: 2011 and 2010 amounts are reported in US$ and are in accordance with IFRS; 2009 amounts are reported in Canadian dollars and are in accordance with Canadian GAAP.

129
TALISMAN ENERGY ANNUAL REPORT 2011

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

Future net cash flows were calculated by applying the prescribed average annual prices to the Company's estimated future production of proved reserves and deducting estimates of future development, decommissioning, production and transportation costs, and income taxes. Future costs have been estimated based on existing economic and operating conditions. Future income taxes have been estimated based on statutory tax rates enacted at year-end using existing tax and cost pools. The present values of the estimated future cash flows were determined by applying a 10% discount rate prescribed by the US Financial Accounting Standards Board.

In order to increase the comparability between companies, the standardized measure of discounted future net cash flows necessarily employs uniform assumptions that do not necessarily reflect management's best estimate of future events and anticipated outcomes. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. Accordingly, the Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair market value of the oil and gas properties. Actual future net cash flows will differ significantly from estimates due to, but not limited to, the following:

•: production rates will differ from those estimated both in terms of timing and amount. For example, future production may include significant additional volumes from unproved reserves;
•: future prices and economic conditions will differ from those used in the preparation of the estimates;
•: future production and development costs will be determined by future events and will differ from those used in the preparation of the estimates; and
•: estimated income taxes will differ in terms of amounts and timing dependent on the above factors, changes in enacted rates and the impact of future expenditures on unproved properties.

130
TALISMAN ENERGY ANNUAL REPORT 2011

The standardized measure of discounted future net cash flows was prepared using the following prices:


	2011	2010	2009

Oil and Liquids ($/bbl)

Canada¹	76.79	62.25	48.43

US	74.91	57.66	–

UK	111.01	78.97	60.18

Norway	108.34	78.21	59.61

Indonesia	111.89	78.71	61.09

Other Southeast Asia²	112.11	75.83	59.56

Other³	108.69	78.10	59.30

Total	104.26	75.79	57.82

Natural Gas ($/mcf)

Canada	3.92	4.05	3.53

US	4.19	4.63	3.94

UK	6.51	4.57	3.68

Norway	7.25	4.95	5.18

Indonesia	7.64	6.61	4.78

Other Southeast Asia²	7.61	5.65	4.44

Other³	3.65	–	6.34

Total	5.27	5.22	4.12

1: The price for Talisman's oil in North America is lower than other oil prices as it is a heavier grade.
2: Other Southeast Asia includes Malaysia, Vietnam and Australia/Timor-Leste.
3: Other includes Algeria, Colombia, and prior to their sale in 2010 and 2009, respectively, Tunisia and Trinidad and Tobago.

In order to derive the prices in the cash flow, the following benchmark prices and exchange rates were used:


	2011	2010	2009

WTI ($/bbl)	96.19	79.42	61.18

Dated Brent ($/bbl)	110.96	79.02	59.91

HH gas ($/mmbtu)	4.12	4.37	3.82

AECO-C (C$/gj)	3.57	3.82	3.58

US$/C$	1.01	0.97	0.87

US$/UK£	1.61	1.60	1.79

131
TALISMAN ENERGY ANNUAL REPORT 2011

Discounted Future Net Cash Flows from Proved Reserves


		North America				North Sea				Southeast Asia
Years ended December 31 (millions of $)		Canada		US		UK		Norway		Indonesia		Other SEA²		Other³		Total

2011

Future cash inflows¹		9,951		9,775		27,326		6,195		9,864		4,711		3,320		71,142

Future costs

	Transportation	(315	)	(480	)	(414	)	(150	)	(540	)	–		(75	)	(1,974	)

	Production	(3,576	)	(1,984	)	(14,327	)	(2,811	)	(1,207	)	(1,526	)	(479	)	(25,910	)

	Development and site restoration	(1,490	)	(2,336	)	(6,491	)	(1,276	)	(805	)	(779	)	(364	)	(13,541	)

Future costs		(5,381	)	(4,800	)	(21,232	)	(4,237	)	(2,552	)	(2,305	)	(918	)	(41,425	)

Future inflows before income taxes		4,570		4,975		6,094		1,958		7,312		2,406		2,402		29,717

Future income & production revenue taxes		(809	)	(358	)	(4,447	)	(342	)	(3,061	)	(784	)	(764	)	(10,565	)

Net cash flows		3,761		4,617		1,647		1,616		4,251		1,622		1,638		19,152

Less 10% annual discount for estimated timing of cash flows		(1,516	)	(2,144	)	(236	)	(318	)	(1,551	)	(365	)	(448	)	(6,578	)

Discounted cash flows		2,245		2,473		1,411		1,298		2,700		1,257		1,190		12,574

2010

Future cash inflows¹		10,027		6,029		20,952		4,551		9,612		3,165		1,479		55,815

Future costs

	Transportation	(381	)	(189	)	(398	)	(166	)	(794	)	–		(48	)	(1,976	)

	Production	(3,801	)	(1,014	)	(11,037	)	(2,123	)	(1,103	)	(1,143	)	(268	)	(20,489	)

	Development and site restoration	(1,697	)	(1,289	)	(4,970	)	(852	)	(830	)	(474	)	(121	)	(10,233	)

Future costs		(5,879	)	(2,492	)	(16,405	)	(3,141	)	(2,727	)	(1,617	)	(437	)	(32,698	)

Future inflows before income taxes		4,148		3,537		4,547		1,410		6,885		1,548		1,042		23,117

Future income & production revenue taxes		(1,003	)	(437	)	(2,787	)	(45	)	(2,845	)	(329	)	(347	)	(7,793	)

Net cash flows		3,145		3,100		1,760		1,365		4,040		1,219		695		15,324

Less 10% annual discount for estimated timing of cash flows		(1,258	)	(1,588	)	(18	)	(202	)	(1,709	)	(222	)	(219	)	(5,216	)

Discounted cash flows		1,887		1,512		1,742		1,163		2,331		997		476		10,108

2009

Future cash inflows¹		11,604		2,242		16,101		3,814		7,230		2,807		1,265		45,063

Future costs

	Transportation	(410	)	(8	)	(322	)	(87	)	(727	)	–		(53	)	(1,607	)

	Production	(4,432	)	(489	)	(10,031	)	(1,858	)	(1,068	)	(1,052	)	(307	)	(19,237	)

	Development and site restoration	(2,033	)	(630	)	(4,767	)	(947	)	(572	)	(666	)	(199	)	(9,814	)

Future costs		(6,875	)	(1,127	)	(15,120	)	(2,892	)	(2,367	)	(1,718	)	(559	)	(30,658	)

Future inflows before income taxes		4,729		1,115		981		922		4,863		1,089		706		14,405

Future income & production revenue taxes		(873	)	–		(444	)	273		(2,011	)	(133	)	(240	)	(3,428	)

Net cash flows		3,856		1,115		537		1,195		2,852		956		466		10,977

Less 10% annual discount for estimated timing of cash flows		(1,671	)	(730	)	377		(221	)	(1,251	)	(195	)	(173	)	(3,864	)

Discounted cash flows		2,185		385		914		974		1,601		761		293		7,113

1: Net oil and gas revenue derived from proved reserves is net of applicable royalties.
2: Other Southeast Asia includes Malaysia, Vietnam and Australia/Timor-Leste.
3: Other includes Algeria and Colombia, and prior to their sale in 2010 and 2009, respectively, Tunisia and Trinidad and Tobago.

132
TALISMAN ENERGY ANNUAL REPORT 2011

Principal Sources of Changes in Discounted Cash Flows


Years ended December 31 (millions of $)	2011		2010		2009

Sales of oil & gas produced net of production costs	(5,776	)	(4,768	)	(3,748	)

Net change in prices	8,351		5,416		4,292

Net change in transportation costs	62		(197	)	195

Net changes in production costs	(2,755	)	391		(619	)

Net changes in future development & site restoration costs	(2,052	)	(27	)	(622	)

Development costs incurred during year	1,560		1,603		1,468

Extensions, discoveries and improved recovery	2,132		1,990		930

Revisions of previous reserve estimates	513		679		356

Net purchases	1,039		189		15

Net sales of reserves in place	(75	)	(893	)	(707	)

Accretion of discount	1,556		1,099		729

Net change in taxes	(1,847	)	(2,453	)	(1,278	)

Other	(242	)	(34	)	292

Net change	2,466		(2,995	)	1,303

Continuity of Net Proved Reserves¹


	Canada		US		UK		Norway		Indonesia		Other Southeast Asia		Latin America		Other		Total

Oil and Liquids (mmbbls)
Total Proved

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

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

Discoveries, additions and extensions	2.1		13.7		(4.1	)	2.3		0.4		9.7		–		(0.9	)	23.2

Purchase of reserves	–		0.6		–		–		–		–		15.1		–		15.7

Sale of reserves	(0.3	)	–		–		–		–		–		–		–		(0.3	)

Net revisions and transfers	(3.5	)	0.3		10.4		7.2		4.1		0.5		–		(0.1	)	18.9

2011 Production	(6.3	)	(0.5	)	(25.2	)	(10.0	)	(1.8	)	(5.5	)	(2.3	)	(2.4	)	(54.0	)

Proved reserves at December 31, 2011	62.0		17.3		245.0		52.7		15.5		30.3		12.8		15.5		451.1

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TALISMAN ENERGY ANNUAL REPORT 2011

Proved developed

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

December 31, 2011	59.9		7.3		201.9		17.0		9.9		19.0		6.7		9.0		330.7

Natural Gas (bcf)

Total Proved

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

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

Discoveries, additions and extensions	251.1		799.4		(0.2	)	4.6		36.1		9.2		–		–		1,100.2

Purchase of reserves	–		3.6		–		–		–		–		93.5		–		97.1

Sale of reserves	(165.5	)	–		–		–		–		–		–		–		(165.5	)

Net revisions and transfers	3.5		66.8		(1.4	)	(1.3	)	(94.1	)	(13.0	)	0.2		–		(39.3	)

2011 Production	(150.9	)	(141.9	)	(3.5	)	(15.3	)	(104.0	)	(33.2	)	(10.2	)	–		(459.0	)

Proved reserves at December 31, 2011	1,292.7		1,985.8		18.7		67.6		1,107.2		188.8		83.5		–		4,744.3

Proved developed

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

December 31, 2011	936.5		814.7		18.2		63.1		688.5		149.7		62.3		–		2,733.0

1: Talisman's estimates of its reserves as at December 31, 2011, December 31, 2010 and December 31, 2009 are based on average pricing methodology. Talisman's estimates of its reserves as at December 31, 2008 were prepared on a single-day end-of-year price basis (using existing economical and operating conditions). For definitions of reserves, see notes found on page 58 of this Annual Report.

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TALISMAN ENERGY ANNUAL REPORT 2011

Additional Information

Consolidated Financial Ratios

(unaudited)

The following financial ratios are provided in connection with the Company's shelf prospectuses filed with Canadian and US securities regulatory authorities and are based on the Company's Consolidated Financial Statements that are prepared in accordance with International Financial Reporting Standards.

The interest coverage ratio is for the 12-month period ended December 31, 2011.


December 31, 2011

Interest coverage (times)

Income¹		10.58

Income from continuing operations²		10.58

1: Net income plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
2: Income from continuing operations plus income taxes and interest expense from continuing operations, divided by the sum of interest expense and capitalized interest from continuing operations.

Ratios and Key Indicators


Years ended December 31 (millions of $ unless otherwise stated)		2011¹	2010¹	2009²	2008²	2007²

Net income		776	945	437	3,519	2,078

Cash flow³		3,434	2,954	3,961	6,163	4,327

Exploration and development spending		4,142	3,473	4,245	5,106	4,449

Acquisitions		1,319	1,530	438	452	317

Dispositions		569	2,273	2,774	442	1,477

Debt/debt + equity (%)		33	31	26	26	38

Debt/cash flow (times)		1.4	1.4	1.0	0.7	1.1

Per common share

	Net income ($)	0.76	0.93	0.43	3.46	2.01

	Cash flow ($)³	3.36	2.90	3.90	6.06	4.19

	Production (boe)	0.152	0.150	0.153	0.160	0.160

	Gross proved reserves (at year-end) (boe)⁴	1.45	1.36	1.39	1.41	1.61

Average royalty rate (%)⁵		19	16	15	18	17

Unit operating costs ($/boe)		14.17	12.44	12.91	13.57	12.14

Unit DD&A ($/boe)⁵		12.55	11.76	17.28	16.44	14.74

Return on capital employed (%)⁶		7.4	10.0	4.1	26.6	18.5

Return on active capital employed (%)⁷		13.4	16.2	6.2	38.7	28.5

Return on equity (%)⁸		8.1	10.5	3.9	36.8	27.2

1: Presented in US$ and in accordance with International Financial Reporting Standards.
2: Presented in C$ and in accordance with Canadian GAAP.
3: Non-GAAP measure. See advisory provided.
4: Calculated in accordance with SEC methodology.
5: 2009 and 2008 restated for operations classified as discontinued in 2010.
6: Net income plus tax effected interest/(average shareholders' equity + average debt).
7: Net income plus tax effected interest/(average shareholders' equity + average debt - average non-depleted capital).
8: Net income/average shareholders' equity.

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TALISMAN ENERGY ANNUAL REPORT 2011

Historical Operations Summary


Years ended December 31		2011	2010	2009	2008	2007

Daily average production

Oil (mbbls/d)

	North America	17	17	25	30	32

	North Sea	96	109	117	123	129

	Southeast Asia	30	35	38	32	41

	Other	23	14	16	21	21

Natural gas liquids (mbbls/d)

	North America	6	6	9	10	12

	North Sea	2	4	3	3	3

	Southeast Asia	4	4	3	4	3

Total oil and liquids		178	189	211	224	241

Natural gas (mmcf/d)

	North America	899	778	803	856	876

	North Sea	52	104	77	57	102

	Southeast Asia	506	485	403	334	287

	Other	34	–	–	–	–

Total natural gas		1,491	1,367	1,283	1,247	1,265

Total (mboe/d)		426	417	425	432	452

WTI (average $/bbl)		95.13	79.53	61.79	99.65	72.31

NYMEX gas (average $/mmbtu)		4.07	4.39	4.05	8.95	6.92

US$/C$ exchange rate (year-end)		0.9833	1.0054	0.9555	0.8166	1.0120

Net Production – After Royalties

Information on Net Production and Product Netbacks in US$ is provided for US readers.


Years ended December 31		2011	2010	2009	2008	2007

Oil and liquids (mbbls/d)

	North America	19	18	27	32	34

	North Sea	97	113	120	127	131

	Southeast Asia	17	22	26	17	24

	Other	13	7	9	11	14

Total oil and liquids		146	160	182	187	203

Natural gas (mmcf/d)

	North America	803	718	720	712	721

	North Sea	52	104	77	57	97

	Southeast Asia	351	339	286	223	199

	Other	27	–	–	–	–

Total natural gas		1,233	1,161	1,083	992	1,017

Total (mboe/d)		351	353	362	352	373

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TALISMAN ENERGY ANNUAL REPORT 2011

Product Netbacks – After Royalties¹


Net of Royalties ($)			2011	2010	2009

North America

	Oil and liquids ($/bbl)

		Sales price	75.19	62.59	48.13

		Transportation	1.08	0.90	0.65

		Operating costs	13.40	14.25	12.71

			60.71	47.44	34.77

	Natural gas ($/mcf)

		Sales price	3.93	4.79	4.12

		Transportation	0.21	0.20	0.17

		Operating costs	1.21	1.48	1.43

			2.51	3.11	2.52

North Sea

	Oil and liquids ($/bbl)

		Sales price	110.75	80.13	60.66

		Transportation	1.71	1.44	1.35

		Operating costs	35.78	25.75	22.72

			73.26	52.94	36.59

	Natural gas ($/mcf)

		Sales price	8.62	6.35	4.87

		Transportation	1.24	0.95	1.03

		Operating costs	1.90	0.79	0.65

			5.48	4.61	3.19

Southeast Asia

	Oil and liquids ($/bbl)

		Sales price	115.82	80.54	62.32

		Transportation	1.20	0.88	0.53

		Operating costs	40.99	25.07	16.54

			73.63	54.59	45.25

	Natural gas ($/mcf)

		Sales price	9.30	6.72	5.60

		Transportation	0.37	0.43	0.42

		Operating costs	0.98	0.72	0.58

			7.95	5.57	4.60

Other

	Oil ($/bbl)

		Sales price	110.32	82.69	64.83

		Transportation	1.76	2.87	2.19

		Operating costs	11.82	11.41	10.02

			96.74	68.41	52.62

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TALISMAN ENERGY ANNUAL REPORT 2011

Product Netbacks After Royalties¹ (continued)


Net of Royalties ($)			2011	2010	2009

	Natural Gas ($/mcf)

		Sales price	4.22	–	–

		Transportation	0.06	–	–

		Operating costs	1.86	–	–

			2.30	–	–

Total Company

	Oil and liquids ($/bbl)

		Sales price	107.04	78.19	58.99

		Transportation	1.58	1.35	1.17

		Operating costs	31.49	23.74	19.61

			73.97	53.10	38.21

	Natural gas ($/mcf)

		Sales price	5.92	5.59	4.63

		Transportation	0.31	0.34	0.30

		Operating costs	1.24	1.22	1.17

			4.37	4.03	3.16

1: Pursuant to US reporting practice, netbacks are calculated using US$ and production after deduction of royalty volumes.

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TALISMAN ENERGY ANNUAL REPORT 2011

Historical Gross Proved Reserves¹


	2011		2010		2009		2008		2007

Oil and liquids (mmbbls)

Opening balance	509.7		531.9		544.5		749.3		766.5

Discoveries, additions and extensions	34.8		33.5		29.0		36.9		29.3

Purchase of reserves	19.5		4.7		1.2		0.3		1.1

Sale of reserves	(0.3	)	(19.4	)	(53.7	)	(19.5	)	(18.0	)

Net revisions and transfers	19.1		27.8		87.8		(140.8	)	58.2

Production	(64.8	)	(68.8	)	(76.9	)	(81.7	)	(87.8	)

Closing balance	518.0		509.7		531.9		544.5		749.3

Natural gas (bcf)

Opening balance	5,236.9		5,272.7		5,338.4		5,464.2		5,402.9

Discoveries, additions and extensions	1,235.5		1,151.7		861.7		395.3		475.7

Purchase of reserves	121.7		83.7		24.6		18.1		251.8

Sale of reserves	(180.3	)	(876.4	)	(426.6	)	(65.3	)	(211.3	)

Net revisions and transfers	(52.5	)	104.3		(56.9	)	(17.6	)	0.2

Production	(543.6	)	(499.1	)	(468.5	)	(456.3	)	(455.1	)

Closing balance	5,817.7		5,236.9		5,272.7		5,338.4		5,464.2

boe (mmboe)²

Opening balance	1,382.5		1,410.7		1,434.3		1,659.8		1,667.0

Discoveries, additions and extensions	240.7		225.5		172.6		102.8		108.5

Purchase of reserves	39.8		18.6		5.3		3.3		43.1

Sale of reserves	(30.3	)	(165.5	)	(124.8	)	(30.3	)	(53.2	)

Net revisions and transfers	10.3		45.2		78.3		(143.5	)	58.1

Production	(155.4	)	(152.0	)	(155.0	)	(157.8	)	(163.7	)

Closing balance	1,487.6		1,382.5		1,410.7		1,434.3		1,659.8

1: For definitions of reserves, see notes found on page 58 of this Annual Report.
2: Six mcf of natural gas equals one boe.

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TALISMAN ENERGY ANNUAL REPORT 2011

Continuity of Gross Proved Reserves¹


	Canada		US		UK		Norway		Indonesia		Other Southeast Asia		Latin America		Other		Total

Oil and Liquids (mmbbls)
Total Proved

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

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

Discoveries, additions and extensions	3.1		18.3		(4.2	)	2.3		1.0		13.7		–		0.6		34.8

Purchase of reserves	–		0.7		–		–		–		–		18.8		–		19.5

Sale of reserves	(0.3	)	–		–		–		–		–		–		–		(0.3	)

Net revisions and transfers	(1.7	)	0.6		10.7		7.2		(0.2	)	1.1		(0.1	)	1.5		19.1

2011 Production	(7.7	)	(0.8	)	(25.5	)	(10.0	)	(4.0	)	(8.5	)	(2.8	)	(5.5	)	(64.8	)

Proved reserves at December 31, 2011	72.7		23.1		246.3		52.7		28.9		46.2		15.9		32.2		518.0

Proved developed

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

December 31, 2011	70.3		9.7		203.1		17.0		20.0		31.1		8.3		19.8		379.3

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TALISMAN ENERGY ANNUAL REPORT 2011


	Canada		US		UK		Norway		Indonesia		Other Southeast Asia		Latin America		Other		Total

Natural Gas (bcf)
Total Proved

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

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

Discoveries, additions and extensions	265.9		953.7		(0.2	)	4.6		4.2		7.3		–		–		1,235.5

Purchase of reserves	–		4.8		–		–		–		–		116.9		–		121.7

Sale of reserves	(180.3	)	–		–		–		–		–		–		–		(180.3	)

Net revisions and transfers	(31.6	)	87.3		(1.2	)	(1.3	)	(107.3	)	1.6		–		–		(52.5	)

2011 Production	(160.0	)	(167.5	)	(3.6	)	(15.3	)	(143.4	)	(41.3	)	(12.5	)	–		(543.6	)

Proved reserves at December 31, 2011	1,391.2		2,351.4		18.8		67.6		1,568.7		315.6		104.4		–		5,817.7

Proved developed

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

December 31, 2011	1,016.8		965.0		18.3		63.1		965.9		250.4		77.9		–		3,357.4

1: Talisman's estimates of its reserves as at December 31, 2011, December 31, 2010 and December 31, 2009 are based on average pricing methodology. Talisman's estimates of its reserves as at December 31, 2008 were prepared on a single-day end-of-year price basis (using existing economic and operating conditions). For definitions of reserves, see notes found on page 58 of this Annual Report.

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TALISMAN ENERGY ANNUAL REPORT 2011

Detailed Property Reviews

2011 Acreage

Year ended December 31, 2011 (thousand acres)			Developed		Undeveloped		Total
Property			Gross	Net	Gross	Net	Gross	Net

North America¹

	Shale		43.9	33.6	2,448.7	1,838.9	2,492.6	1,872.5

	Conventional²		1,019.8	645.3	1,539.2	1,140.7	2,559.0	1,786.0

	Frontier³		3.2	0.4	4,966.4	2,814.9	4,969.6	2,815.3

Total North America			1,066.9	679.3	8,954.3	5,794.5	10,021.2	6,473.8

North Sea

	UK

		Northern Business Area	164.2	106.2	338.8	124.1	503.0	230.3

		Central Business Area	104.5	82.5	248.0	153.8	352.5	236.3

		Other UK	–	–	–	–	–	–

	Norway

		Southern North Sea	14.7	9.3	177.8	87.7	192.5	97.0

		Mid North Sea	28.3	8.8	193.3	79.6	221.6	88.4

		Other Norway⁴	–	–	1,250.4	326.4	1,250.4	326.4

Total North Sea			311.7	206.8	2,208.3	771.6	2,520.0	978.4

Southeast Asia

	Indonesia⁵		460.9	75.7	15,299.5	4,523.0	15,760.4	4,598.7

	Malaysia		98.6	37.6	3,522.6	2,336.5	3,621.2	2,374.1

	Vietnam		12.8	2.2	8,548.4	3,676.5	8,561.2	3,678.7

	Australia/Timor-Leste		11.0	4.1	259.8	71.1	270.8	75.2

	Papua New Guinea		–	–	13,712.0	7,375.0	13,712.0	7,375.0

Total Southeast Asia			583.3	119.6	41,342.3	17,982.1	41,925.6	18,101.7

Latin America

	Colombia

		Equión	17.9	3.3	892.7	177.7	910.6	181.0

		Other Colombia	–	–	9,677.2	4,470.5	9,677.2	4,470.5

	Peru		–	–	8,202.1	3,395.2	8,202.1	3,395.2

Total Latin America			17.9	3.3	18,772.0	8,043.4	18,789.9	8,046.7

Other

	Algeria		196.0	34.4	–	–	196.0	34.4

	Rest of World⁶		–	–	1,166.9	725.0	1,166.9	725.0

Total Other			196.0	34.4	1,166.9	725.0	1,362.9	759.4

Total Worldwide			2,175.8	1,043.4	72,443.8	33,316.6	74,619.6	34,360.0

1: "Developed" acreage consists of acreage assigned to productive wells. Each productive shale well has been allocated 80 acres of spacing and, for non-shale wells, the actual Drilling Spacing Unit has been used.
2: "Conventional" acreage is derived by subtracting total shale acreage and total frontier acreage from total acreage. Where the Company has both shale and conventional formations under one title document, acreage is counted only with respect to shale.
3: Frontier includes properties in Alaska, the Northwest Territories, Nunavut and Yukon.
4: Other Norway includes exploration acreage in the Barents Sea.
5: The Corridor PSC constitutes a significant portion of the Company's acreage in Indonesia.
6: Rest of World includes the Kurdistan region of northern Iraq, Sierra Leone and Poland.

142
TALISMAN ENERGY ANNUAL REPORT 2011

2011 Drilling

Exploration¹

Development

Total

Year ended December 31, 2011

Oil²

Gas²

Dry³

Total

Oil²

Gas²

Dry³

Total

Oil²

Gas²

Dry³

Total

North America

Conventional

Gross

–

129

–

145

Net

9.5

5.5

–

15.0

72.2

36.9

–

109.1

81.7

42.4

–

124.1

Shale

Gross

–

272

–

276

278

–

282

Net

–

3.1

–

3.1

2.0

194.2

–

196.2

2.0

197.3

–

199.3

North Sea

Gross

–

Net

–

Norway

Gross

–

Net

1.0

0.2

0.4

1.6

1.8

–

2.6

4.4

2.8

0.2

3.0

6.0

Southeast Asia

Indonesia

Gross

–

Net

0.2

0.1

0.9

1.2

1.3

0.5

–

1.8

1.5

0.6

0.9

3.0

Malaysia

Gross

–

Net

1.0

–

1.0

–

0.8

0.4

1.2

1.0

0.8

0.4

2.2

Vietnam

Gross

–

Net

–

0.3

–

0.3

0.3

–

0.3

Australia/Timor-Leste

Gross

–

Net

–

0.5

–

0.5

0.5

–

0.5

Papua New Guinea

Gross

–

Net

–

0.5

1.0

–

0.5

–

0.5

–

1.0

0.5

1.5

Latin America

Colombia

Gross

–

Net

–

0.5

0.5

0.5

–

0.5

0.5

–

0.5

1.0

Peru

Gross

–

Net

–

Other

Algeria

Gross

–

Net

–

1.4

–

1.4

1.4

–

1.4

Rest of World⁴

Gross

–

Net

–

Total

Gross

129

322

457

147

337

496

Net

11.7

9.4

2.3

23.4

232.9

3.0

315.9

91.7

242.3

5.3

339.3

1: For all geographic areas other than North America, includes stratigraphic wells that have been plugged and abandoned, and excludes exploration wells that are currently suspended and awaiting completion or abandonment.
2: A productive oil or gas well is an exploratory, development or extension well that is not a dry well.
3: A dry well (hole) is an exploratory, development or extension well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. The term "completion" refers to the installation of permanent equipment for the production of oil and gas, or, in the case of a dry hole, to reporting of abandonment to the appropriate agency or authority.
4: Rest of World includes the Kurdistan region of northern Iraq, Sierra Leone and Poland.

143
TALISMAN ENERGY ANNUAL REPORT 2011

Five Year Drilling Results



	2011	2010	2009	2008	2007		2011	2010	2009	2008	2007

North America						International
Total oil wells	100	65	5	138	128	Total oil wells	47	57	59	73	73

Total gas wells	327	243	154	286	288	Total gas wells	10	11	12	37	11

Drilling success (%)	100	100	98	100	98	Drilling success (%)	83	85	86	89	79

144
TALISMAN ENERGY ANNUAL REPORT 2011

145 TALISMAN ENERGY ANNUAL REPORT 2011 Talisman’s commitment to corporate governance and corporate responsibility contributes to the creation of long-term value for the company’s stakeholders. CORPORATE GOVERNANCE RESPONSIBILITIES The principal role of Talisman’s Board of Directors is stewardship of the company, and its fundamental objective is the creation of shareholder value, including the protection and enhancement of the value of the company’s assets. The Board oversees the conduct of the business and management, which, in turn, is responsible for developing long-term strategy and conducting the company’s day-to-day business. In addition, the Board ensures systems are in place to manage the risks and, through the Chief Executive Officer, sets the outlook and direction of the company toward environmental, health and safety policies, regulatory compliance and financial practices and reporting. INDEPENDENCE At year-end 2011, Talisman had 11 directors, all of whom, with the exception of the President and Chief Executive Officer, were independent. The majority of Talisman’s Board committees are also composed entirely of independent directors. EFFECTIVENESS Talisman ensures the continuing effectiveness of its Chairman, committees and individual directors through annual assessments. In addition, ongoing succession and recruitment processes are in place to ensure the continuing effectiveness of the Board and its committees. The Governance and Nominating Committee has established a comprehensive director selection process, which is integrated with the annual assessment process. STOCK EXCHANGE AND REGULATORY COMPLIANCE Talisman’s corporate governance practices satisfy all the existing guidelines for effective corporate governance established by the Canadian Securities Administrators, all of the NYSE corporate governance listing standards applicable to non-US companies and a substantial majority of the NYSE corporate governance listing standards applicable to US companies. Talisman has disclosed the significant differences between its corporate governance practices and the requirements applicable to US companies listed on the NYSE on the company’s website at www.talisman-energy.com.

146 TALISMAN ENERGY ANNUAL REPORT 2011 COMMON SHARES Transfer Agent Computershare Trust Company of Canada Calgary, Toronto, Montreal, Vancouver US Co-transfer Agent Computershare Trust Company N.A. Authorized Unlimited number of common shares Unlimited number of preferred shares issuable in series Issued 1,031,273,751 1 common shares at December 31, 2011 8,000,000 Cumulative Redeemable Rate Reset First Preferred Shares, Series 1, at December 31, 2011 STOCK EXCHANGE LISTINGS Common Shares Symbol: TLM Canada: Toronto Stock Exchange United States: New York Stock Exchange Preferred Shares Symbol: TLM.PR.A Canada: Toronto Stock Exchange PUBLIC DEBT Trustee Computershare Trust Company of Canada 7.25% (US$) unsecured debentures Trustee JP Morgan Chase, London Branch 6.625% (UK£) unsecured notes Trustee Bank of Nova Scotia Trust Company of New York 3.75% (US$) unsecured notes 5.125% (US$) unsecured notes 5.75% (US$) unsecured notes 5.85% (US$) unsecured notes 6.25% (US$) unsecured notes 7.75% (US$) unsecured notes Private Debt 8.25% (US$) unsecured notes 8.5% (US$) unsecured notes Dividends In 2011, the company paid dividends on Talisman’s common shares totaling US$0.27 per share. The dividends were paid on June 30 and December 31. Talisman’s dividend policy is subject to review semi-annually by the Board of Directors. Over the last three-year period, Talisman paid semi-annual dividends on its common shares, totaling C$0.225/share in 2009, C$0.25/share in 2010 and US$0.27/share in 2011. Holders of Series 1 preferred shares are entitled to receive a cumulative quarterly fixed dividend of 4.2% annually for the initial period ending December 31, 2016, as and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 2.77%. Holders of the Series 1 preferred shares will have the right to convert all or any of their shares into an equal number of Series 2 preferred shares, subject to certain conditions, on December 31, 2016 and on December 31 in every fifth year thereafter, and will then be entitled to receive quarterly floating rate cumulative preferential cash dividends equal to the sum of the average rate on 90-day Government of Canada treasury bills plus 2.77%. Annual Meeting The annual meeting of shareholders of Talisman Energy Inc. will be held at 1 p.m. on Tuesday, May 1, 2012, in the Exhibition Hall, North Building, of the TELUS Convention Centre, 136 - 8th Avenue SE, Calgary, Alberta. Shareholders are encouraged to attend the meeting, but those who are unable to do so are requested to participate by voting, using one of the three available methods: (i) telephone, (ii) the internet, or (iii) signing and returning the Form of Proxy or Voting Instruction Form mailed with the Management Proxy Circular. INVESTOR INFORMATION 1 Includes shares held in trust relating to the company’s Performance Share Unit Plan.

147 TALISMAN ENERGY ANNUAL REPORT 2011 CORPORATE INFORMATION Christiane Bergevin 3,4 Quebec, Canada Christiane Bergevin was appointed Executive Vice-President, Strategic Partnerships, Office of the President, of Desjardins Group in August 2009. Prior to that, she was Senior Vice-President and General Manager, Corporate Projects, with SNC-Lavalin Group Inc. For the 18 years prior to that, Ms. Bergevin held several executive and international finance positions with various SNC-Lavalin subsidiaries, including President of SNC-Lavalin Capital Inc., its finance advisory arm, between 2001 and 2008. Donald Carty 1,5 Texas, United States Donald Carty served as Vice Chairman and Chief Financial Officer of Dell Inc. from January 2007 until mid-2008. From 1998 to 2003, he was the Chairman and Chief Executive Officer of AMR Corp. and American Airlines. Prior to that, Mr. Carty served as President of AMR Airline Group and American Airlines. Mr. Carty was the President and Chief Executive Officer of Canadian Pacific Airlines from March 1985 to March 1987. William Dalton 1,3,6 Arizona, United States William Dalton was Chief Executive of HSBC Bank plc from 1998 to 2004, Executive Director of HSBC Holdings plc from 1998 to 2004, Global Head of Personal Financial Services for HSBC Group from 2002 to 2004 and held various positions in the Canadian operations of HSBC prior to 1998. kevin Dunne 4,6 Tortola, British Virgin Islands Kevin Dunne has held various international senior and executive management positions with BP plc, including General Manager of Abu Dhabi Company for Onshore Oil Operations (ADCO), a BP joint venture, from 1994 to 2001, Corporate Associate President of BP Indonesia from 1991 to 1994 and Corporate Head of Strategy for the BP Group based in London from 1990 to 1991. Harold kvisle 2,5,6 Alberta, Canada Harold Kvisle was the President and Chief Executive Officer of TransCanada Corporation from May 2003 and of TransCanada PipeLines Limited (TCPL) from May 2001, until his retirement in June 2010. Prior to his employment with TCPL, Mr. Kvisle was the President of Fletcher Challenge Energy Canada Inc. from 1990 to 1999. Mr. Kvisle has worked in the oil and gas industry since 1975 and in the pipeline and power industries since 1999. John Manzoni 2,4 Alberta, Canada John Manzoni was appointed President and Chief Executive Officer of Talisman Energy Inc. on September 1, 2007. During the 24 years prior to that, Mr. Manzoni held several senior strategic and operational leadership positions with BP plc and its global group of companies. From 2002 to 2007, he served as Chief Executive, Refining and Marketing (BP Group) and was on the board of directors of BP plc. BOARD OF DIRECTORS a a b c d e f b c e f d

148 TALISMAN ENERGY ANNUAL REPORT 2011 Lisa Stewart 5,6 Texas, United States Lisa Stewart became the Chief Executive Officer of Sheridan Production Partners in September 2006. Prior to that, Ms. Stewart was President of El Paso Exploration & Production from February 2004 to August 2006. Prior to her time at El Paso, Ms. Stewart worked for Apache Corporation for 20 years beginning in 1984 in a number of capacities. Her last position with Apache was Executive Vice-President of Business Development and E&P Services. Peter Tomsett 4,5 British Columbia, Canada Peter Tomsett was the President and Chief Executive Officer of Placer Dome Inc. from September 2004 to January 2006. Mr. Tomsett was with Placer Dome for 20 years in a number of capacities. Prior to becoming President and CEO, he was Executive Vice-President of Placer Dome Asia Pacific and Africa. Michael Waites 1,6 British Columbia, Canada Michael Waites became the President and Chief Executive Officer of Finning International Inc. in May 2008. Prior to that, Mr. Waites was Executive Vice President and Chief Financial Officer of Finning. He also served as a member of the board of directors of Finning for three years prior to his appointment as Executive Vice President and Chief Financial Officer. Prior to joining Finning in May 2006, Mr. Waites was Executive Vice President and Chief Financial Officer at Canadian Pacific Railway from July 2000, and was also Chief Executive Officer U.S. Network of Canadian Pacific Railway. Previously, he was Vice President and Chief Financial Officer at Chevron Canada Resources. Charles Williamson 2 Chairman of the Board California, United States Charles Williamson was the Executive Vice-President of Chevron Corporation from August to December 2005. From 2001 to 2005, he was Chairman and Chief Executive Officer of Unocal Corporation (“Unocal”) and held various executive positions within Unocal, including Executive Vice President, International Energy Operations and Group Vice President, Asia Operations prior to 2001. Charles Winograd 1,3 Ontario, Canada Charles Winograd is Senior Managing Partner of Elm Park Credit Opportunities Fund. He is also the President of Winograd Capital Inc. From 2001 to 2008, he was Chief Executive Officer of RBC Capital Markets. When RBC Dominion Securities acquired Richardson Greenshields in 1996, Mr. Winograd became Deputy Chairman and a director. He was appointed to the position of President and Chief Operating Officer of RBC Dominion Securities in 1998. Mr. Winograd held several executive postings in Richardson Greenshields until becoming President and Chief Executive Officer in 1987 and Chairman and Chief Executive Officer in 1991. 1 Member of Audit Committee 2 Member of Executive Committee 3 Member of Governance and Nominating Committee 4 Member of Health, Safety, Environment and Corporate Responsibility Committee 5 Member of Human Resources Committee 6 Member of Reserves Committee g h i j k g i k j h

149 TALISMAN ENERGY ANNUAL REPORT 2011 EXECUTIvES Paul Blakeley Executive Vice-President International Operations (East) Richard Herbert Executive Vice-President International Exploration John Manzoni President and Chief Executive Officer Tony Meggs Executive Vice-President Special Projects Bob Rooney Executive Vice-President Legal and General Counsel Paul Smith Executive Vice-President North American Operations Scott Thomson Executive Vice-President Finance and Chief Financial Officer Helen Wesley Executive Vice-President Corporate Services INVESTOR RELATIONS CONTACTS Scott Thomson Executive Vice-President Finance and Chief Financial Officer p: 403.231.2786 Lyle McLeod Vice-President Investor Relations p: 403.237.1020 David Mann Vice-President Corporate and Investor Communications p: 403.237.1196 EXECUTIVE OFFICE Talisman Energy Inc. 2000, 888 – 3rd Street SW Calgary, Alberta Canada T2P 5C5 p: 403.237.1234 f: 403.237.1902 www.talisman-energy.com e: tlm@talisman-energy.com c d e f g a a b c d e f g h h b

150 TALISMAN ENERGY ANNUAL REPORT 2011 COMMON SHARES 2011 2010 2009 TSX NYSE TSX NYSE TSX NYSE (C$) (US$) (C$) (US$) (C$) (US$) Share price ($) High 24.82 25.21 22.32 22.43 20.17 19.51 Low 11.34 10.75 15.71 14.70 9.92 7.97 Close 12.98 12.75 22.12 22.19 19.69 18.64 Shares traded (millions) First quarter 247.42 186.81 332.76 202.01 329.62 268.68 Second quarter 291.15 197.53 402.61 268.83 368.06 318.14 Third quarter 380.19 294.96 280.43 146.34 300.86 210.37 Fourth quarter 395.79 329.55 249.62 169.04 253.52 194.49 Year 1,314.55 1,008.85 1,265.42 786.22 1,252.06 991.67 Year-end shares outstanding (millions) 1,031 1 1,023 1 1,019 1 Year-end stock options outstanding (millions) 59.0 63.0 69.5 1 Includes shares held in trust relating to the company’s Performance Share Unit Plan. Talisman Common Shares (TSX) Dow Jones Industrial Average (US$) S&P/TSX Composite Index 02 04 06 08 03 05 07 09 11 10 Dec 31 -100 -50 0 50 100 150 200 250 300 MARKET INFORMATION SHARE PRICE GROWTH (PERCENTAGE CHANGE FROM JANUARY 1, 2002)

151 TALISMAN ENERGY ANNUAL REPORT 2011 See the advisories included in Management’s Discussion and Analysis on page 57 of this report. ABBREVIATIONS AND DEFINITIONS See Management’s Discussion and Analysis on page 59 of this report. BOE CONVERSION Throughout this report, 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). This report also includes references to mcf equivalents (mcfes) which are calculated at a conversion rate of one barrel of oil to six thousand cubic feet of gas. Boes and mcfes may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf:1bbl and an mcfe conversion ratio of 1bbl:6mcf are based on an energy equivalence conversion method primarily applicable at the burner tip and do not represent a value equivalency at the well head. RESERVES REPLACEMENT The reserves replacement ratio was calculated by dividing the sum of yearly changes (discoveries, extensions and additions and other revisions, before acquisitions and dispositions and excluding price revisions) to estimated proved oil and gas reserves during 2011 by the company’s production for 2011. The company uses reserves replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves. It should be noted that 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. REPLACEMENT COSTS In this report, 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 similarly 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 (including discontinued operations, but excluding midstream) by gross proved reserves additions. US DOLLARS AND IFRS Dollar amounts are presented in US dollars, except where otherwise indicated. Financial information prior to January 1, 2010 was prepared in accordance with Canadian generally accepted accounting principles then applicable to publically accountable enterprises (CGAAP). The financial information for 2010 and 2011 is presented in accordance with International Financial Reporting Standards (IFRS). IFRS and CGAAP differ from generally accepted accounting principles in the US. NON-GAAP FINANCIAL MEASURES Included in this report are references to financial measures commonly used in the oil and gas industry, such as cash flow and earnings from operations. These terms are not defined by IFRS. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of such measures may not be comparable to similarly titled measures reported by other companies. ADVISORIES

152 TALISMAN ENERGY ANNUAL REPORT 2011 CASH FLOW Year Ended December 31 ($ millions, except per share amounts) 2011 2010 Cash provided by operating activities 2,812 3,144 Changes in non-cash working capital 1 397 (367) Add: Exploration expenditure 427 374 Less: Finance costs (cash) (202) (197) Cash flow 3,434 2,954 Cash flow per share 3.36 2.90 Diluted cash flow per share 3.31 2.90 1 2011 includes an allowance for a doubtful account (net of tax) of $22 million. Cash flow, as commonly used in the oil and gas industry, represents net income before exploration costs, DD&A, deferred taxes and other non-cash expenses. Cash flow is used by the company to assess operating results between years and between peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with IFRS as an indicator of the company’s performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. Diluted cash flow per share is cash flow divided by the diluted number of common shares outstanding during the period, as reported in the annual consolidated financial statements filed on March 5, 2012. A reconciliation of cash provided by operating activities to cash flow is provided above. EARNINGS FROM OPERATIONS Year Ended ($ millions, except per share amounts) 2011 2010 Net income 776 945 Gain on disposal and income from assets sold (tax adjusted) (141) (550) Unrealized gain on financial instruments (tax adjusted) 1 (63) (250) Share-based payments 2 (tax adjusted) (303) 279 Foreign exchange on debt (1) – Impairment losses (tax adjusted) 104 158 Allowance for doubtful account (tax adjusted) 22 – Deferred tax adjustments 3 210 (30) Earnings from operations 604 552 Earnings from operations per share 0.59 0.54 Diluted earnings from operations per share 0.58 0.54 1 Unrealized gain on financial instruments relates to the change in the period of the mark-to-market value of the company’s outstanding commodity derivatives that are classified as held-for-trading financial instruments. 2 Share-based payments relate principally to the mark-to-market value of the company’s outstanding stock options and cash units at December 31. The company uses the Black-Scholes option pricing model to estimate the fair value of its share-based payment plans. 3 Deferred tax adjustments include deferred taxes relating to unrealized foreign exchange gains and losses associated with the impact of fluctuations in the Canadian dollar on foreign denominated debt, intercompany loans and tax pool balances, as well as a remeasurement of UK deferred tax assets and liabilities in response to a statutory rate change. Earnings from 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 operations should not be considered an alternative to, or more meaningful than, net income as determined in accordance with IFRS as an indicator of the company’s performance or liquidity. Earnings from operations per share are earnings from operations divided by the average number of common shares outstanding during the period. Diluted earnings from operations per share are earnings from operations divided by the diluted number of common shares outstanding during the period, as reported in the annual consolidated financial statements filed on March 5, 2012. A reconciliation of net income to earnings from operations is provided above.

designed and produced by smith + associates www.smithandassoc.com Printed on acid-free paper containing 100% post-consumer fibre and processed chlorine free. The inks used are environmentally friendly canola-based inks. Please recycle. 80% XXXX Talisman Energy USA Inc. 50 Pennwood Place Warrendale, Pennsylvania USA 15086 p: +724.814.5300 f: +724.814.5301 www.talismanusa.com Talisman Energy USA Inc. 337 Daniel Zenker Drive Horseheads, New York USA 14845 p: +607.562.4000 f: +607.562.4001 www.talismanusa.com Talisman Energy USA Inc. Talisman Energy Services Inc. 4 Waterway Square Plaza The Woodlands, Texas USA 77380 p: +281.210.2100 www.talismanusa.com Talisman Energy (Uk) Limited Talisman House 163 Holburn Street Aberdeen, Scotland AB10 6BZ p: +1224.352.500 f: +1224.353.400 Talisman Energy Norge AS Verven 4 2000, N4014 Stavanger, Norway p: +47.5200.2000 f: +47.5200.1500 Talisman Energy Polska sp. zo.o Warsaw Financial Center 13th Floor, Ul. Emilli Plater 53 Warsaw, Poland p: +48.22.370.6070 f: +48.22.370.6087 e: warsaw@talisman-energy.com Talisman (Asia) Ltd. Indonesia Stock Exchange Building Tower 1, 11th Floor JI.Jend. Sudirman Kav. 52-53 Jakarta 12190, Indonesia p: +62.21.515.1601 f: +62.21.515.1602 Talisman Malaysia Limited Suite 31.01, Level 33 Menara Citibank 165 Jalan Ampang, 50450 Kuala Lumpur, Malaysia p: +603.2162.6970 f: +603.2162.6972 Talisman SEA Pte. Ltd. Level 14, Marina Bay Financial Centre Tower 2 10 Marina Boulevard Singapore 018983 p: +65.6808.1000 Talisman vietnam Limited Saigon Tower, Level 18 and 19 29 Le Duan Street, District 1, Ho Chi Minh City, Vietnam p: +848.3823.8232 f: +848.3823.8237 Talisman Australasia Pty Ltd. Level 21, AMP Place 10 Eagle Street Brisbane, QLD Australia 4000 Talisman (Colombia) Oil & Gas Ltd. Carrera 7 No. 77-07, Piso 12 Bogota, Colombia p: +571.640.5552 f: +571.317.9293 Talisman (Peru) B.v. Sucursal Peruana Calle Dean Valdivia 148 Edificio Platinum, Torre 1, Piso 2 Centro Empresarial Platinum Plaza Lima 27 Peru p: +011.511.208.6500 f: +011.511.208.6501 Talisman International Holdings B.v. Atrium Building Strawinskylaan 3159 1077 ZX Amsterdam The Netherlands p: +31.20.540.8840 f: +31.20.540.8854 TE Holding S.à r.l. Axento Building Unit B., 4th Floor 3, rue Marcel Fischbach, L-1547 Luxembourg p: +352.2876.0070 INTERNATIONAL OFFICES Talisman Energy Inc. Suite 2000, 888 – 3rd Street SW Calgary, Alberta, Canada T2P 5C5 p: 403.237.1234 f: 403.237.1902 e: tlm@talisman-energy.com

TALISMAN ENERGY INC. Suite 2000, 888 – 3rd Street SW Calgary, Alberta, Canada T2P 5C5 p: 403.237.1234 f: 403.237.1902 e: tlm@talisman-energy.com www.talisman-energy.com TALISMAN ENERGY 2011 ANNUAL REPORT

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Exhibit 99.1