Exchange

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

Eight Consecutive Years of Record Cash Flow

	Three months ended			Year ended
December 31	2006	2005	% Change	2006	2005	% Change

Cash flow ($mm) ¹	1,126	1,468	(23)	4,748	4,672	2
Cash flow ($/share) ¹	1.04	1.34	(22)	4.35	4.23	3
Net income ($mm)	598	533	12	2,005	1,561	28
Net income ($/share)	0.55	0.48	15	1.84	1.41	30

Long-term debt ($mm at year-end)	4,560	4,263
Shares outstanding (mm at year-end)	1,064	1,099

¹ non-GAAP measure

Cash flow in 2006 was a record $4,748 million on gross sales of $10,030 million. Cash flow per share increased 2.8% to $4.35. Significant increases came from higher oil prices ($1,043 million), increased volumes ($479 million) and hedging gains ($143 million). These gains were offset by lower natural gas prices ($369 million) and the impact of a stronger Canadian dollar on realized prices ($679 million), increased operating costs ($313 million) and lost production due to asset sales ($124 million).

Net income for the year totaled $2,005 million, $444 million higher than last year. Significant changes in non-cash items included increased future tax ($421 million), higher depreciation, depletion and amortization ($316 million) and lower stock based compensation ($589 million) expense. Net income for the year included an after tax gain on asset sales of $432 million.

Fourth quarter cash flow fell 23%, largely due to a 21% drop in netbacks with North American natural gas netbacks down 44% compared to the fourth quarter of 2005. Net income for the quarter included an after tax gain on asset sales of $285 million.

The Company no longer calculates a diluted cash flow per share amount. Since the introduction in mid-2003 of a cash payment feature attached to the outstanding stock options, approximately 97% of options have been exercised using the cash payment feature. Since the diluted per share calculation assumes all options will be exercised for shares, with no adjustment to account for the fact that actual options exercised for cash have resulted in a reduction of cash flow, management feels that the diluted cash flow per share figure is not relevant as the underlying assumptions are not a realistic view of actual or expected results.

Talisman uses the successful efforts accounting method. The differences between the full cost and successful efforts methods of accounting make it difficult to compare net income between companies. In periods of growth and high exploration spending, it is likely that net income determined using the full cost method would be higher than net income determined using the more conservative successful efforts method.

Cash Flow

Below is a reconciliation of cash provided by operating activities calculated in accordance with generally accepted accounting principles (GAAP) to cash flow (which is a non-GAAP measure of financial performance). Please refer to the advisory section in this news release entitled Non-GAAP Financial Measures for further explanation and details.

($ millions)	Three months ended		Year ended
December 31,	2006	2005 (Restated)	2006	2005 (Restated)
Cash provided by operating activities	988	1,699	4,374	4,871
Changes in non-cash working capital	138	(231)	374	(199)
Cash flow	1,126	1,468	4,748	4,672

Earnings from Continuing Operations $1.6 Billion

In order to better illustrate Talisman’s operating performance on an internally consistent basis, the Company has calculated an earnings from continuing operations number. This is a non-GAAP measure. This metric adjusts for significant one-time events, as well as other non-operational impacts on earnings such as the mark-to-market effect of changes in share prices on stock based compensation expense and changes to tax rates. This calculation does not reflect differing accounting policies and conventions between companies.

($ millions, except per share amounts)

	Three months ended		Year ended
December 31	2006	2005	2006	2005
Net income	598	533	2,005	1,561
Operating income from discontinued operations	40	70	197	207
Gain on disposition of discontinued operations	209	-	356	-
Net income from discontinued operations	249	70	553	207
Net income from continuing operations	349	463	1,452	1,354
Insurance expenses¹	-	-	10	2
Stock-based compensation (tax adjusted)²	65	88	32	447
Tax effects of unrealized foreign exchange gains on foreign denominated debt³	(51)	(1)	(27)	50
Tax rate reductions and other³	(31)	2	116	-
Earnings from continuing operations⁴	332	552	1,583	1,853
Per share⁴	0.31	0.50	1.45	1.68

1	Insurance costs relate to the current liability associated with past claims experience that is expected to be billed in future premiums.

Stock-based compensation expense relates to the mark-to-market value of the Company’s outstanding stock options and cash units at December 31, 2006. The Company’s stock-based compensation expense is based on the difference between the Company’s share price and its stock options or cash units exercise price.

3	Tax adjustments include the impact of Canadian corporate tax rate reductions and a 10% supplemental tax increase in the UK in 2006, as well as future taxes relating in part to unrealized foreign exchange gains associated with the impact of a stronger Canadian dollar on foreign denominated debt.

4 This is a non-GAAP measure.

Production per share up by 4.4%

	Three Months Ended			Year Ended
December 31	2006	2005	% Change	2006	2005	% Change
Oil and liquids (bbls/d)
North America	47,054	54,254	(13)	49,846	53,611	(7)
United Kingdom	102,064	120,922	(16)	102,742	107,020	(4)
Scandinavia	32,677	38,996	(16)	32,474	25,696	26
Southeast Asia	51,953	49,111	6	51,582	35,476	45
Other	20,733	25,902	(20)	21,559	25,488	(15)
Synthetic oil	4,027	2,854	41	3,431	2,693	27
Total oil and liquids	258,508	292,039	(11)	261,634	249,984	5
Natural gas (mmcf/d)
North America	942	907	4	910	915	(1)
United Kingdom	118	138	(14)	126	111	14
Scandinavia	16	13	23	14	9	56
Southeast Asia	288	286	1	292	284	3
Total natural gas	1,364	1,344	1	1,342	1,319	2
Total mboe/d	486	516	(6)	485	470	3

Production for the year averaged 485,000 boe/d, an increase of 3% over 2005 and Talisman increased production per share by 4.4%. During 2006, the Company announced the sale of non-core assets with total production volumes of approximately 57,000 boe/d net to Talisman. The estimated impact of asset sales on Talisman’s reported production volumes was approximately 4,880 boe/d for the year and 12,200 boe/d in the fourth quarter.

Talisman increased its oil and liquids production by 5% over the prior year. North American liquids production decreased, reflecting the Company’s ongoing focus on natural gas in North America, declines from existing fields as well as asset sales. Total North Sea volumes increased reflecting the impact of acquired assets in Scandinavia late in 2005. UK volumes fell, largely due to extended platform turnarounds. Liquids production in Southeast Asia increased with a full year of production from the South Angsi field, first production from the start up of the Naga Kecil well in Block PM-314, startup of the Bunga Tulip field in the fourth quarter and assets acquired in late 2005.

Natural gas volumes increased by 2%. North American volumes were down slightly year over year largely reflecting asset sales. Talisman’s North Sea gas volumes are largely demand driven (relatively little gas storage in the UK). Increased sales in Indonesia to Singapore Power and Caltex more than offset lower volumes in Malaysia/Vietnam due to an extended maintenance shutdown caused by bad weather and lower natural gas nominations.

Fourth quarter volumes were 486,000 boe/d, a decrease of 6% over the comparable period a year earlier. Fourth quarter liquid volumes fell reflecting asset sales in North America and the UK and an extended shutdown in Trinidad, due to equipment failure, which is now repaired.

Talisman’s fourth quarter gas volumes were up largely on the strength of a 4% increase in North America, despite the loss of approximately 23 mmcf/d in the quarter due to asset sales. Positive drilling results and the startup of the Talisman operated Lynx and Palliser Pipelines were the main contributors. UK fourth quarter natural gas sales were down from the prior year due primarily to asset sales.

On December 12, 2006, the Company issued guidance for expected 2007 production volumes. Talisman expects production to average 485,000 boe/d in 2007 with a confidence level of plus or minus 5%. This includes the impact of the 57,000 boe/d of asset sales announced to date (the Brae asset sale is expected to close late in 2007).

116% Production Replacement

Talisman replaced 116% of production through drilling additions and revisions to proved reserves in 2006. Talisman increased its total proved reserves by 2% to 1.67 billion boe. Net of royalties, the Company had 1.37 billion boe of proved reserves (up 4%).

At year-end, Talisman had 5.4 tcf of proved natural gas reserves and 767 mmbbls of proved oil and liquids reserves.

The Company added a record 471 bcf of proved natural gas reserves in North America, replacing 142% of production through drilling and revisions. Internationally, Talisman replaced 123% of liquids production organically.

Proved Reserves
	Oil & Natural Gas Liquids	Natural Gas	BOE
	(mmbbls)	(bcf)	(mm)
December 31, 2005	736	5,417	1,639
Discoveries, extensions and additions	80	564	174
Net acquisitions	11	(61)	1
Net Revisions and Transfers	34	(34)	28
Production	(94)	(483)	(175)
Total proved December 31, 2006	767	5,403	1,667
Total probable December 31, 2006	544	2,650	986

At year-end, Talisman had a reserves life index of 9.5 years for proved reserves and 15.2 years for proved and probable reserves.

Talisman’s proved reserves are comprised of approximately 46% of high quality oil and liquids and 54% natural gas. Approximately 38% of the Company’s total proved reserves are in North America with the North Sea accounting for 29% and Southeast Asia for 27%. At year-end, the Company had 986 mmboe of probable reserves, which comprise a large part of Talisman’s development inventory.

Exploration and development spending during 2006 totaled $4.4 billion, excluding Syncrude and Midstream expenditures. Net of acquisitions and divestitures, capital spending was $3.7 billion.

Talisman has an internal qualified reserves engineer who evaluates all of the Company’s reserves estimates. In addition, approximately 86% of Talisman’s proved reserves have been reviewed by outside engineering firms over the past four years.

The reserves replacement ratio of 116% (before acquisitions) was calculated by dividing the sum of changes (revisions of estimates, improved recovery and discoveries) to estimated proved oil and gas reserves during 2006 by the Company’s 2006 conventional production. Detailed reserves reconciliation tables are provided elsewhere in this news release.

Netbacks

Total Company	Three Months Ended		Year Ended
December 31	2006	2005	2006	2005
WTI oil price US$/bbl	60.17	60.05	66.25	56.70
NYMEX gas price US$/mmbtu	6.62	12.85	7.26	8.55

Talisman netback ($/boe)
Sales price	53.07	64.26	57.45	56.67
Hedging (Loss)/Gain	0.52	(0.43)	0.37	(0.46)
Royalties	7.99	10.56	9.58	9.41
Operating cost	10.39	9.04	9.98	8.41
Transportation	1.27	1.26	1.28	1.21
Netback ($/boe) ¹	33.94	42.97	36.98	37.18
Oil and liquids netback ($/bbl)	39.20	41.96	43.46	40.62
Natural gas netback ($/mcf)	4.67	7.38	4.92	5.56

1.	Netbacks do not include synthetic oil and pipeline operations. Additional netback information by major product type and region is contained elsewhere in this news release.

Talisman’s realized oil and gas equivalent netback decreased by 0.5% to average $36.98/boe in 2006.

Sales prices averaged $57.45/boe, an increase of 1%, reflecting an increase in world oil prices and Talisman's international natural gas prices, offset largely by the drop in North American natural gas prices. Although most oil and natural gas sales are priced off US dollar denominated benchmarks, Talisman reports its netbacks in Canadian dollars. The Canadian dollar strengthened 6% against its US counterpart in 2006. This had an adverse effect on Talisman’s reported netbacks.

Royalty rates were unchanged at 17% in 2006.

Unit operating costs averaged $9.98/boe, an increase of 19% over the previous year. The increase is due to a change in Talisman’s production mix as well as increased spending on maintenance, extended turnarounds and higher power costs.

Talisman reported a small hedging gain, although the Company remained relatively unhedged throughout the year.

Liquidity and Capital Resources

Talisman’s long-term debt at year end was $4.6 billion ($4.5 billion net of cash), up from $4.3 billion at the end of last year. During 2006, the Company generated $4.4 billion of cash provided by operating activities and spent $4.6 billion on exploration and development (including midstream and Syncrude) and received proceeds from net asset sales of $668 million. The Company repurchased approximately 35 million common shares during 2006 and an additional 15.5 million shares subsequent to year end at a total cost of $958 million. In March 2006, the Company renewed its Normal Course Issuer Bid (NCIB) to permit the purchase of up to 54,940,200 common shares, representing 5% of the total common shares outstanding at that time. In December 2006, Talisman amended the current NCIB to the maximum permitted by the TSX, being 10% of the public float on March 22, 2006 (109,767,000 common shares). The NCIB expires in March 2007 and the Company has received Board of Directors’ approval to renew the NCIB for another year.

Two common share dividends were paid in 2006 for a total of $163 million (an aggregate of $0.15/share). The Company’s dividend is determined semi-annually by the Board of Directors. At year-end, there were 1,064 million common shares outstanding, down from 1,099 million at December 31, 2005.

At the end of 2006, Talisman’s trailing debt to cash flow ratio was 0.96 and debt-to-debt plus equity was 38%.

Capital Spending ^1,⁴	2006	% Change	2005
(millions of dollars)

North America¹	2,420	49	1,623
United Kingdom¹	1,208	38	875
Scandinavia¹	332	129	145
Southeast Asia¹	331	9	305
Other^1,2	249	35	184
Corporate, IS and Administrative	36	29	28
	4,576	45	3,160
Acquisitions ³	204	(62)	536
Dispositions	(119)	441	(22)
Discontinued operations ⁵	(715)	(1,621)	47
Total	3,946	6	3,721

1 Excludes corporate acquisitions.

2 Other includes Algeria, Tunisia, Trinidad and Tobago, Colombia, Peru, Qatar and Gabon.

3 Includes the Auk/Fulmar assets acquired in the UK for $181 million in 2006.

4 Includes interest costs that are capitalized on major projects until facilities are completed and ready for use.

5 2006 includes proceeds on dispositions of $753 million net of capital expenditures of $38 million.

During 2006, the Company spent $3 billion on development and $1.5 billion on exploration.

Natural gas continued to be the focus of the Company’s capital investment activities in North America, supplemented by low risk oil projects. Of the $2.4 billion of capital spending in North America, $1.1 billion related to exploration activities and development accounted for $1.3 billion. The Company’s North America drilling program had a 98% success rate, drilling 496 successful gas wells and 194 oil wells. Exploration and development spending was concentrated in the predominantly gas producing core areas in the Alberta Foothills, Greater Arch, Deep Basin, Monkman/BC Foothills, Edson and Appalachia regions.

Total capital spending in the UK was $1.2 billion, including $138 million for exploration and $1.1 billion for development. Major areas of activity included the ongoing development of the Tweedsmuir, Blane, Wood, Enoch and Affleck projects and drilling and recompletion activity Orion, Tartan and Claymore fields. A total of 24 successful development wells were drilled in 2006, in addition to six exploration wells.

In Scandinavia, total expenditures were $332 million and included $102 million on exploration and $230 million on development. In addition to project development costs at Rev of $27 million, five successful development wells were drilled during 2006, in addition to two exploration wells.

Malaysia/Vietnam accounted for $241 million of the $331 million of total capital spending in Southeast Asia with the ongoing development of the Northern Fields in PM-3 CAA. Talisman participated in nine successful development wells in Malaysia/Vietnam during 2006 and one successful exploration well. A total of $76 million was spent in Indonesia, primarily on the Suban Phase 2 development to supply natural gas to West Java in 2007. A total of 19 successful development wells and two successful exploration wells were drilled in Indonesia.

Capital spending in Other included $74 million in North Africa with Talisman participating in 13 successful exploration and development wells in Algeria and two wells in Tunisia. In Trinidad and Tobago, a total of $84 million was spent, primarily on Block 2c development drilling and the Eastern Block onshore exploration activity. A total of four development wells and four exploration wells were drilled in Trinidad and Tobago. During 2006, the Company spent $91 million in the rest of the world, including $22 million in Qatar on exploration drilling.

Additional Information

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


($/boe)	2006	% Change	2005

North America	14.18	13	12.57
United Kingdom	12.60	14	11.07
Scandinavia	19.78	19	16.65
Southeast Asia	6.17	28	4.83
Other	9.17	(2)	9.37
	12.26	13	10.81

Total Depreciation, Depletion and Amortization Expense (includes accretion of ARO)
(millions of dollars)	2006	2005

North America	1,024	908
United Kingdom	440	397
Scandinavia	248	157
Southeast Asia	224	144
Other	69	83
	2,005	1,689

The Company’s 2006 DD&A expense increased $316 million, or 19%, to $2 billion, with a per unit rate of $12.26/boe ($10.81/boe in 2005) due primarily to recently acquired assets and high levels of capital spending. DD&A rates in North America increased to $14.18/boe, primarily due to higher drilling costs, increased capital expenditures on infrastructure projects as well as increased land amortization costs. In North America, total DD&A expense increased 13% to $1,024 million. In the UK, total expense increased 11% to $440 million, as DD&A rates increased 14% to $12.60/boe, but were partially offset by a 3% reduction in boe production.

In Scandinavia, total expense increased by $91 million to $248 million, as DD&A rates increased 19% to $19.78/boe, combined with a 28% increase in boe production. Total DD&A expense for Southeast Asia increased by $80 million, or 56%, to $224 million due to the impact of a 28% increase in the rate to $6.17/boe and a 21% increase in boe production. Total Other DD&A expense decreased by 17% to $69 million, primarily as a result of a decrease in production, as the rate decreased 2% to $9.17/boe.

Dry Hole Expense
(millions of dollars)	2006	2005

North America	135	122
United Kingdom	26	38
Scandinavia	11	15
Southeast Asia	15	11
Other ¹	109	55
	296	241

1 In 2006, Other includes Trinidad and Tobago, Colombia, Qatar, Peru and Gabon.

During 2006, the Company incurred dry hole expense of $296 million, $55 million higher than last year. In North America, dry hole expense was $135 million. In the UK, a total of three wells were expensed for a total of $26 million. The Company also wrote off one well in Scandinavia, two wells in Southeast Asia and seven wells in the rest of the world.

Exploration Expense
(millions of dollars)	2006	2005

North America	168	143
United Kingdom	25	29
Scandinavia	30	24
Southeast Asia	22	40
Other	73	39
	318	275

Exploration expense consists of geological and geophysical costs, seismic, land lease rentals and indirect exploration expenses. These costs are expensed as incurred under the successful efforts method of accounting. The majority of the $43 million increase to $318 million relates to increased exploration activity in North America and other potential growth areas.

Corporate and Other
(millions of dollars)	2006	2005

G&A expense	233	201
Interest expense	166	163
Capitalized interest	72	19
Stock-based compensation	51	633
Other revenue	119	112
Other expense	(29)	39

General and administrative (G&A) expense increased due to additional personnel, salary increases and higher administrative costs. On a unit basis, G&A was $1.31/boe (2005 - $1.17/boe; 2004 - $1.14/boe).

The sum of interest on long-term debt and capitalized interest was $238 million during 2006, up from $182 million in 2005 on higher debt levels in the current year. Interest capitalized in 2006 is primarily associated with the Tweedsmuir development project in the UK, which is scheduled to come on production early in the second quarter of 2007. In addition, interest costs of $18 million in 2006, $3 million in 2005 and nil in 2004, have been allocated to discontinued operations.

Other revenue includes pipeline and custom treating revenues of $103 million for 2006, compared to $88 million for 2005. Other expense during 2006 included the gain on sale of a royalty interest in an undeveloped lease of $108 million, partially offset by foreign exchange losses of $24 million and costs related to the Beatrice Wind Farm of $22 million.

Stock-Based Compensation

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at December 31, 2006. The Company’s stock-based compensation expense is based on the difference between the Company’s share price and its stock options, or cash units exercise price. A total of $51 million was expensed in 2006. The Company paid cash of $159 million ($153 million in 2005) to employees in settlement of fully accrued option liabilities for options exercised. Comparatively, during 2005 the 90% increase in the Company’s share price resulted in an expense of $633 million. Over the course of 2006, the average exercise price of all outstanding options increased from $8.71 per share to $10.79 per share, with a total of 63.9 million options outstanding at December 31, 2006.

The Company’s stock option plans provide employees and directors who hold stock options with the choice upon exercise to purchase a share of the Company at the stated exercise price or to receive a cash payment in exchange for surrendering the option. The cash payment is equal to the appreciated value of the stock option as determined based on the difference between the option’s exercise price and the approximate share price at the time of surrender. The cash payment alternative is expected to result in reduced shareholder dilution in the future as it is anticipated that most holders of the stock options (now and in the future) will elect to take a cash payment. Such cash payments made by the Company to stock option holders are deductible by the Company for income tax purposes, making these plans more cost-effective.

Since the introduction of the cash feature, approximately 97% of options that have been exercised have been exercised for cash, resulting in reduced dilution of shares.

Additional stock-based compensation expense or recoveries in future periods is dependent on the movement of the Company’s share price and the number of outstanding options and cash units.

Income Taxes

The Company’s effective tax rate for 2006, after deducting Petroleum Revenue Tax (PRT), was 47%, compared to 45% in 2005. A number of events in the past two years have affected the Company’s effective tax rates, including tax rate increases in the UK, tax rate reductions in Canada and acquisitions of producing assets in Norway in 2005.

Effective Income Tax Rate
(millions of dollars)	2006	2005

Income from continuing operations before tax	3,046	2,643
Less PRT
Current	256	147
Future	34	37
	290	184
	2,756	2,459
Income tax expense/(recovery)
Current	752	978
Future	552	127
	1,304	1,105
Effective income tax rate (%)	47	45

In 2006, future tax expense increased $425 million to $552 million, as the Company recorded a $325 million charge related to the income tax rate increase on petroleum profits from 40 to 50% in the UK, partially offset by a recovery of future taxes of $178 million related to Canadian federal and provincial tax rate reductions and $34 million in the UK related to the deferral of 2005 capital expenditure claims to 2006 and 2007 for tax purposes.

A normalized effective tax rate after removing the impact of the UK and Canadian tax rate changes and the tax on unrealized foreign exchange gains on foreign denominated debt would have been 44% in 2006 and 43% in 2005. The increase in the 2006 effective tax rate results, in part, from a higher tax rate in the UK. Foreign exchange rate fluctuations over the past several years have resulted in taxes on gains related to inter-company loans and non-C$ denominated debt, for which there is no corresponding component of the unrealized gain reflected in income before taxes.

Current income tax expense decreased to $752 million in 2006, due primarily to higher capital allowances in the UK and lower US charges due to reduced natural gas prices.

The UK government levies PRT on North Sea fields that received development approval before April 1993, based on gross profit after allowable deductions, including capital and operating expenditures. PRT, which is deductible for purposes of calculating corporate income tax, increased as a result of both higher prices and volumes on fields in the UK subject to PRT. In addition to the UK, PRT is levied in Australia and other countries where $66 million and $16 million, respectively, were recorded during 2006.

Talisman Energy Inc. is an independent upstream oil and gas company headquartered in Calgary, Alberta, Canada. Talisman has operations in Canada and its subsidiaries operate in the North Sea, Southeast Asia, Australia, North Africa, the United States and Trinidad and Tobago. Talisman’s subsidiaries are also active in a number of other international areas. Talisman is committed to conducting its business in an ethically, socially and environmentally responsible manner. The Company is a participant in the United Nations Global Compact and included in the Dow Jones Sustainability (North America) Index. Talisman's shares are listed on the Toronto Stock Exchange in Canada and the New York Stock Exchange in the United States under the symbol TLM.

For further information, please contact:

David Mann, Senior Manager, Corporate Christopher J. LeGallais

& Investor Communications Senior Manager, Investor Relations

Phone: 403-237-1196 Fax: 403-237-1210 Phone: 403-237-1957 Fax: 403-237-1210

E-mail: tlm@talisman-energy.com Email: tlm@talisman-energy.com

xx-07

Forward-Looking Statements

This news release contains statements that constitute forward-looking statements and forward-looking information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation. These forward-looking statements include, among others, statements regarding: estimates of future sales, future production and production per share; business plans for drilling, exploration and development; the estimated amounts and timing of capital expenditures; the estimated timing of development, including new production; business strategy and plans or budgets; outlook for oil and gas prices; ongoing asset dispositions and share re-purchases planned for 2007; royalty rates and exchange rates; and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

Statements concerning oil and gas reserves contained in this news release may be deemed to be forward-looking statements as they involve the implied assessment that the reserves described can be profitably produced in the future, based on certain estimates and assumptions.

Often, but not always, forward-looking statements use words or phrases such as: “expects”, “does not expect” or “is expected”, “anticipates” or “does not anticipate”, “plans” or “planned”, “estimates” or “estimated”, “projects” or “projected”, “forecasts” or “forecasted”, “believes”, “intends”, “likely”, “possible”, “probable”, “scheduled” , “positioned”, “goal” , “objective” or state that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved.

Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking statements throughout this news release. Statements which discuss future business plans for drilling, exploration and development assume that the extraction of crude oil, natural gas and natural gas liquids remains economic. For the purposes of preparing this document, Talisman assumed a US$65.00/bbl West Texas Intermediate oil price, a US$7.50/mmbtu New York Mercantile Exchange natural gas price, a US$/Canadian$ exchange rate of $0.90 and a Canadian$/British £ rate of 2.05.

Forecasted production volumes are based on the mid-point of the estimated production range. Statements regarding estimated future production and production growth, as well as estimated financial results that are derived from or depend upon future production estimates (such as cash provided by operating activities) incorporate the estimated impact of the sale of the Company’s indirect Syncrude interest which was completed on January 2, 2007, the anticipated completion of the UK Brae asset sale and the non-core asset disposition program in Canada. The completion of any contemplated asset disposition is contingent on various factors including favorable market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approvals for such dispositions. The amount of taxes and cash payments made upon surrender of existing stock options is inherently difficult to predict.

Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by Talisman and described in the forward-looking statements. These risks and uncertainties include:

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

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

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

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

·	potential delays (due, for example, to harsh weather conditions) or changes in plans with respect to exploration or development projects or capital expenditures;

·	fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

·	the outcome and effects of completed acquisitions, as well as any future acquisitions or dispositions;

·	the ability of the Company to integrate any assets it has acquired or may acquire or the performance of those assets;

·	health, safety and environmental risks;

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

·	uncertainties related to the litigation process, such as possible discovery of new evidence or acceptance of novel legal theories and difficulties in predicting the decisions of judges and juries;

·	risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);

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

·	changes in general economic and business conditions;

·	the effect of acts of, or actions against, international terrorism;

·	the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;

·	results of the Company’s risk mitigation strategies, including insurance and any hedging programs; and

·	the Company’s ability to implement its business strategy.

We caution that the foregoing list of risks and uncertainties is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results are included: (1) under the heading “Risk Factors” in the Company’s Annual Information Form; and (2) under the headings “Management’s Discussion and Analysis - Risks and Uncertainties” and “Outlook for 2006” and elsewhere in the Company’s 2005 Annual Report Financial Review. Additional information may also be found in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission.

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

Reserves Data and Other Oil and Gas Information

Talisman’s disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities, which permits Talisman to provide disclosure in accordance with US disclosure requirements. The information provided by Talisman may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). Talisman’s net proved reserves have been calculated using the standards contained in Regulation S-X of the US Securities and Exchange Commission. US practice is to disclose net proved reserves after deduction of estimated royalty burdens, including net profits interests. Talisman makes additional voluntary disclosure of gross proved reserves. Probable reserves which Talisman also discloses voluntarily have been calculated using the definition for probable reserves set out by the Society of Petroleum Engineers/World Petroleum Congress. In this news release, Talisman’s estimates of proved reserves and probable reserves are based on the same price assumptions. Further information on the differences between the US requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in Talisman’s Annual Information Form.

The exemption granted to Talisman also permits it to disclose internally evaluated reserves data. All reserves data in this news release reflects Talisman’s estimates of its reserves. While Talisman annually obtains an independent audit of a portion of its reserves, no independent reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this news release.

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

Throughout this news release, Talisman makes reference to production volumes. Such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments. In the United States, net production volumes are reported after the deduction of these amounts.

The reserves life index of 9.5 years for proved reserves was calculated by dividing the year end proved reserves by the Company’s 2006 conventional production. The reserves life index of 15.2 years for proved and probable reserves was calculated by dividing the year end proved and probable reserves by the Company’s 2006 conventional production.

The Company's management uses reserves replacement ratios, as described above, as an indicator of the Company's ability to replenish annual production volumes and grow its reserves. It should be noted that a reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely, based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not include the cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.

The SEC normally permits oil and gas companies to disclose in their filings with the SEC only proved reserves that have been demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Any probable reserves, contingent and prospective resources and the calculations with respect thereto included in this news release do not meet the SEC’s standards for inclusion in documents filed with the SEC.

Notwithstanding that Talisman is not required to disclose contingent and prospective resources, it has done so using the definition for contingent and prospective resources set out by the Society of Petroleum Engineers / World Petroleum Congress (“SPE/WPC”). There is essentially no material difference between the SPE/WPC definitions for contingent and prospective resources and the definitions set out in the Canadian Oil and Gas Handbook.

Contingent resources are those quantities of oil and/or gas which are estimated, on a given date, to be potentially recoverable from known accumulations, but which are not currently considered to be commercially recoverable.

Prospective resources are those quantities of oil and/or gas which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations. There is no certainty that prospective resources will be discovered. Talisman's estimate for its international exploration portfolio, including Alaska and the Northwest Territories, of 5 billion boe of prospective resources, is calculated on the basis of the P50 estimate of such prospective resources without reduction for the probability of exploration success or failure.

Non-GAAP measures

This news release includes references to financial measures commonly used in the oil and gas industry such as cash flow, cash flow per share and earnings from operations. These terms are not defined by Generally Accepted Accounting Principles (GAAP) in either Canada or the US. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of cash flow, cash flow per share and earnings from operations may not be comparable to similarly titled measures by other companies.

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

Earnings from continuing operations is 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. This term is not defined by GAAP in either Canada or the U.S. The Company uses this information to evaluate performance of core operational activities on a comparable basis between periods.

Talisman Energy Inc.
Highlights(4)
(unaudited)

	Three months ended		Years ended
	December 31		December 31
	2006	2005	2006	2005
Financial
(millions of Canadian dollars unless otherwise stated)
Cash flow	1,126	1,468	4,748	4,672
Net income	598	533	2,005	1,561
Exploration and development expenditures	1,320	980	4,578	3,179
Per common share (Canadian dollars)
Cash flow	1.04	1.34	4.35	4.23
Net income	0.55	0.48	1.84	1.41
Production
(daily average)
Oil and liquids (bbls/d)
North America	47,054	54,254	49,846	53,611
United Kingdom¹	102,064	120,922	102,742	107,020
Scandinavia¹	32,677	38,996	32,474	25,696
Southeast Asia¹	51,953	49,111	51,582	35,476
Other¹	20,733	25,902	21,559	25,488
Synthetic oil	4,027	2,854	3,431	2,693
Total oil and liquids	258,508	292,039	261,634	249,984
Natural gas (mmcf/d)
North America	942	907	910	915
United Kingdom²	118	138	126	111
Scandinavia	16	13	14	9
Southeast Asia	288	286	292	284
Total natural gas	1,364	1,344	1,342	1,319
Total mboe/d	486	516	485	470
Prices ³
Oil and liquids ($/bbl)
North America	50.90	54.84	56.73	52.62
United Kingdom	67.40	66.24	72.11	64.07
Scandinavia	69.14	67.43	73.79	67.72
Southeast Asia	67.21	68.30	74.62	68.79
Other	66.78	66.26	71.65	65.40
Crude oil and natural gas liquids	64.48	64.62	69.82	62.78
Synthetic oil	66.93	71.42	68.52	69.88
Total oil and liquids	64.52	64.68	69.80	62.86
Natural gas ($/mcf)
North America	6.94	12.25	7.12	9.05
United Kingdom	7.52	8.76	8.50	7.30
Scandinavia	4.60	3.80	4.92	4.30
Southeast Asia	5.75	6.72	6.95	6.40
Total natural gas	6.72	10.63	7.20	8.30
Total ($/boe) (includes synthetic)	53.18	64.30	57.53	56.74
(1) Includes oil volumes produced into inventory for the year ended December 31, 2006 of 1,896 bbls/d, 500 bbls/d, 825 bbls/d and 936 bbls/d in the UK, Scandinavia, Southeast Asia, and Other, respectively, and for the year ended December 31, 2005 of 2,308 bbls/d, 1,362 bbls/d, 1,055 bbls/d and 1,242 bbls/d in the UK, Scandinavia, Southeast Asia and Other respectively.
(2) Includes gas acquired for injection and subsequent resale of 18 mmcf/d and 15 mmcf/d for the years 2006 and 2005, respectively.
(3) Prices are before hedging.
(4) Includes continuing and discontinued operations

Talisman Energy Inc.
Consolidated Statements of Income
(unaudited)

	Three months ended		Years ended
	December 31		December 31
(millions of C$)	2006	2005	2006	2005
		(restated -		(restated -
Revenue		see note 1)		see note 1)
Gross sales	2,195	2,682	9,362	8,888
Hedging (gain) loss	(23)	20	(66)	77
Gross sales, net of hedging	2,218	2,662	9,428	8,811
Less royalties	352	463	1,603	1,516
Net sales	1,866	2,199	7,825	7,295
Other	35	28	119	112
Total revenue	1,901	2,227	7,944	7,407

Expenses
Operating	424	380	1,651	1,338
Transportation	53	54	207	185
General and administrative	70	58	233	201
Depreciation, depletion and amortization	519	467	2,005	1,689
Dry hole	176	77	296	241
Exploration	111	96	318	275
Interest on long-term debt	43	42	166	163
Stock-based compensation	98	121	51	633
Other	(98)	30	(29)	39
Total expenses	1,396	1,325	4,898	4,764
Income from continuing operations before taxes	505	902	3,046	2,643
Taxes
Current income tax	106	288	752	978
Future income tax (recovery)	(9)	90	552	127
Petroleum revenue tax	59	61	290	184
	156	439	1,594	1,289
Net income from continuing operations	349	463	1,452	1,354
Net income from discontinued operations (note 1)	249	70	553	207
Net income	598	533	2,005	1,561

Per common share (C$)
Net income from continuing operations	0.32	0.42	1.33	1.23
Diluted net income from continuing operations	0.32	0.41	1.29	1.20
Net income from discontinued operations	0.23	0.06	0.51	0.18
Diluted net income from discontinued operations	0.22	0.06	0.50	0.18
Net income	0.55	0.48	1.84	1.41
Diluted net income	0.54	0.47	1.79	1.38
Average number of common shares outstanding (millions)	1,078	1,099	1,092	1,104
Diluted number of common shares outstanding (millions)	1,106	1,128	1,122	1,131

See accompanying notes

Consolidated Statements of Retained Earnings
(unaudited)

	Three months ended		Years ended
	December 31		December 31
(millions of C$)	2006	2005	2006	2005

Retained earnings, beginning of period	4,502	2,894	3,316	2,170
Net income	598	533	2,005	1,561
Common share dividends	(81)	(63)	(163)	(125)
Purchase of common shares	(434)	(48)	(573)	(290)
Retained earnings, end of period	4,585	3,316	4,585	3,316

See accompanying notes

Talisman Energy Inc.
Consolidated Balance Sheets
(unaudited)



December 31 (millions of C$)	2006	2005
Assets		(restated)
Current		(note 1)
Cash and cash equivalents	103	145
Accounts receivable	1,136	1,219
Inventories	368	170
Prepaid expenses	25	20
Assets of discontinued operations	443	793
	2,075	2,347

Accrued employee pension benefit asset	50	57
Other assets	102	74
Goodwill	1,543	1,434
Property, plant and equipment	17,691	14,196
Assets of discontinued operations (note 1)	-	246
	19,386	16,007
Total assets	21,461	18,354


Liabilities
Current
Bank indebtedness	39	15
Accounts payable and accrued liabilities	2,477	2,336
Income and other taxes payable	412	649
Liabilities of discontinued operations (note 1)	235	238
	3,163	3,238

Deferred credits	59	74
Asset retirement obligations	1,865	1,223
Other long-term obligations	157	216
Long-term debt	4,560	4,263
Future income taxes	4,350	3,367
Liabilities of discontinued operations (note 1)	-	178
	10,991	9,321

Non-controlling interest	-	66
Contingencies and commitments
Shareholders' equity
Common shares	2,533	2,609
Contributed surplus	67	69
Cumulative foreign currency translation	122	(265)
Retained earnings	4,585	3,316
	7,307	5,729
Total liabilities and shareholders' equity	21,461	18,354

See accompanying notes

Talisman Energy Inc.
Consolidated Statements of Cash Flows
(unaudited)

	Three months ended		Years ended
	December 31		December 31
(millions of C$)	2006	2005	2006	2005
		(restated -		(restated -
Operating		see note 1)		see note 1)
Net income from continuing operations	349	463	1,452	1,354
Items not involving cash	673	775	2,690	2,631
Exploration	111	96	318	275
	1,133	1,334	4,460	4,260
Changes in non-cash working capital	(138)	231	(374)	199
Cash provided by continuing operations	995	1,565	4,086	4,459
Cash (used in) provided by discontinued operations	(7)	134	288	412
Cash provided by operating activities	988	1,699	4,374	4,871
Investing
Corporate acquisitions	-	(2,549)	(66)	(2,549)
Capital expenditures
Exploration, development and corporate	(1,321)	(974)	(4,576)	(3,159)
Acquisitions	(195)	277	(201)	(260)
Proceeds of resource property dispositions	110	6	112	17
Changes in non-cash working capital	190	136	246	138
Discontinued operations	382	(298)	715	(331)
Cash used in investing activities	(834)	(3,402)	(3,770)	(6,144)
Financing
Long-term debt repaid	(1,020)	(285)	(4,570)	(1,294)
Long-term debt issued	1,399	1,848	4,786	3,129
Common shares purchased	(499)	(55)	(656)	(352)
Common share dividends	(81)	(63)	(163)	(125)
Deferred credits and other	(23)	(12)	(77)	(9)
Changes in non-cash working capital	-	-	-	(3)
Cash (used in) provided by financing activities	(224)	1,433	(680)	1,346
Effect of translation on foreign currency cash and cash equivalents	-	25	10	19
Net increase (decrease) in cash and cash equivalents	(70)	(245)	(66)	92
Cash and cash equivalents, net of bank indebtedness, beginning of period	134	375	130	38
Cash and cash equivalents, net of bank indebtedness, end of period	64	130	64	130

See accompanying notes.

ABBREVIATED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The Consolidated Financial Statements of Talisman Energy Inc. (“Talisman” or the “Company”) have been prepared by management in accordance with Canadian generally accepted accounting principles. Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted.

1. DISCONTINUED OPERATIONS

United Kingdom

During the second quarter of 2006, Talisman entered into agreements to dispose of certain non-core oil and gas producing assets in the UK for proceeds of $392 million. Operating results are included in net income from discontinued operations and the related assets and liabilities are reported as assets or liabilities of discontinued operations on the Consolidated Balance Sheets. A gain on disposition of assets of $209 million, net of tax ($nil), has been recorded in net income from discontinued operations.

During the fourth quarter of 2006, Talisman entered into an agreement to dispose of additional non-core oil and gas properties for consideration of US$550 million with an effective date of January 1, 2007. Completion is expected in the fourth quarter of 2007. The proceeds of sale will be adjusted for net cash flow from the properties from January 1, 2007 until closing. The proceeds and gain on sale will be impacted by the timing of closing, foreign exchange rate movements, closing costs, interest on the sales proceeds, oil and gas prices, production volumes together with operating results during the period to closing.

North America

During 2006, Talisman entered into agreements to dispose of certain non-core oil and gas producing assets in Western Canada for proceeds of $361 million. Operating results are included in net income from discontinued operations and the related assets and liabilities are reported as assets or liabilities of discontinued operations on the Consolidated Balance Sheets. A gain on disposition of assets of $147 million, net of tax ($61 million), has been recorded in net income from discontinued operations.

Also during 2006, Talisman announced its intention to sell all of its oil sands assets, comprised of a 1.25% indirect interest in Syncrude Canada and interests in undeveloped leases. Operating results from the Syncrude Canada interest are included in net income from discontinued operations and the related assets and liabilities are reported as assets or liabilities of discontinued operations on the Consolidated Balance Sheets. The sale of Talisman’s indirect interest in Syncrude Canada closed subsequent to year-end for total proceeds of $477 million, consisting of cash of $234 million, net of adjustments, and 8,189,655 units of Canadian Oil Sands Trust. The resulting gain of approximately $236 million, net of tax ($73 million), will be recorded in 2007 as part of discontinued operations. The Company is required to hold the Canadian Oil Sands Trust units for a minimum of four months.

During the fourth quarter of 2006, Talisman announced plans to sell additional oil and gas producing assets in Western Canada. These assets are not included in the results of discontinued operations as at December 31, 2006 but are expected to be reclassified in 2007.

During 2006, the Company completed the sale of a royalty interest in an undeveloped lease for a gain of $76 million, net of tax ($32 million), which has been recorded in continuing operations.

Details on results of discontinued operations are presented in the tables below. Comparative periods for both North America and UK segments have been restated.

		As at December 31, 2006			As at December 31, 2005
		North America	United Kingdom	Total	North America	United Kingdom	Total
Assets
	Current assets	7	30	37	22	70	92
	Property, plant and equipment, net	150	213	363	324	553	877
	Goodwill	14	29	43	21	49	70
Total assets¹		171	272	443	367	672	1,039

Liabilities
	Current liabilities	2	53	55	5	42	47
	Asset retirement obligations	1	78	79	17	80	97
	Future income taxes	-	22	22	-	166	166
	Other long-term obligations	1	78	79	1	105	106
Total liabilities¹		4	231	235	23	393	416
Net assets of discontinued operations		167	41	208	344	279	623
1 In 2005, assets of $246 million and liabilities of $178 million have been classified as long term as the sale of the properties related to these assets and liabilities is expected to close later in 2007.

		For the 3 months ended December 31
		North America		United Kingdom		Total
		2006	2005	2006	2005	2006	2005
Revenue
	Gross sales	25	62	103	169	128	231
	Royalties	6	10	4	15	10	25
Revenues, net of royalties		19	52	99	154	118	206
Expenses
	Operating, marketing and general	7	17	19	25	26	42
	Interest¹	-	1	-	2	-	3
	Depreciation, depletion and amortization	-	9	15	35	15	44
Income from discontinued operations before income taxes		12	25	65	92	77	117
	Taxes	3	9	34	38	37	47
	Gain on disposition, net of tax	-	-	209	-	209	-
Net income from discontinued operations		9	16	240	54	249	70


		For the 12 months ended December 31
		North America		United Kingdom		Total
		2006	2005	2006	2005	2006	2005
Revenue
	Gross sales	156	218	570	499	726	717
	Royalties	26	33	42	45	68	78
Revenues, net of royalties		130	185	528	454	658	639
Expenses
	Operating, marketing and general	48	55	85	86	133	141
	Interest¹	7	1	11	2	18	3
	Depreciation, depletion and amortization	20	38	101	116	121	154
Income from discontinued operations before income taxes		55	91	331	250	386	341
	Taxes	16	31	173	103	189	134
	Gain on disposition, net of tax	147	-	209	-	356	-
Net income from discontinued operations		186	60	367	147	553	207

1 Interest has been allocated to discontinued operations calculated on the portion of the Acquisition Credit Facility that was required to be repaid with proceeds from property dispositions.

2. Selected Cash Flow Information
	Three months ended		Years ended
	December 31		December 31
	2006	2005	2006	2005


Items not involving cash
Depreciation, depletion and amortization	519	467	2,005	1,689
Property impairments	-	6	-	31
Dry hole	176	77	296	241
Net gain on asset disposals	(105)	(1)	(106)	(3)
Stock-based compensation (recovery)	79	91	(108)	480
Future taxes and deferred petroleum revenue tax	11	118	586	165
Other	(7)	17	17	28
Items not involving cash	673	775	2,690	2,631

3. Segmented Information

	North America (1)				United Kingdom (2)				Scandinavia (3)
	Three months		Years		Three months		Years		Three months		Years
	ended		ended		ended		ended		ended		ended
	December 31		December 31		December 31		December 31		December 31		December 31
(millions of Canadian dollars)	2006	2005	2006	2005	2006	2005	2006	2005	2006	2005	2006	2005
Revenue
Gross sales	822	1,255	3,332	3,911	558	630	2,476	2,258	200	211	890	614
Hedging (gain) loss	(25)	21	(86)	78	2	(1)	20	(1)	-	-	-	-
Royalties	147	251	632	783	-	3	5	10	1	-	4	-
Net sales	700	983	2,786	3,050	556	628	2,451	2,249	199	211	886	614
Other	24	14	78	76	6	13	28	35	3	-	11	-
Total revenue	724	997	2,864	3,126	562	641	2,479	2,284	202	211	897	614
Segmented expenses
Operating	134	116	505	422	176	166	690	614	57	61	259	180
Transportation	17	23	73	75	16	14	54	43	7	5	27	15
DD&A	268	234	1,024	908	114	115	440	397	61	55	248	157
Dry hole	84	47	135	122	11	-	26	38	1	15	11	15
Exploration	46	41	168	143	10	9	25	29	12	10	30	24
Other	(103)	(2)	(108)	(14)	10	15	33	54	(1)	(1)	-	-
Total segmented expenses	446	459	1,797	1,656	337	319	1,268	1,175	137	145	575	391
Segmented income before taxes	278	538	1,067	1,470	225	322	1,211	1,109	65	66	322	223
Non-segmented expenses
General and administrative
Interest
Stock-based compensation
Currency translation
Total non-segmented expenses
Income from continuing
operations before taxes
Capital expenditures
Exploration	207	230	1,080	707	30	31	138	129	25	19	102	36
Development	379	252	1,166	844	312	239	1,070	746	93	9	230	109
Midstream	56	42	174	72	-	-	-	-	-	-	-	-
Exploration and development	642	524	2,420	1,623	342	270	1,208	875	118	28	332	145
Property acquisitions
Midstream acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures (6)
Property, plant and equipment			7,957	6,730			6,131	4,112			1,558	1,407
Goodwill			269	270			450	394			697	643
Other			694	652			479	384			139	169
Discontinued operations			171	367			272	672			-	-
Segmented assets			9,091	8,019			7,332	5,562			2,394	2,219
Non-segmented assets
Total assets (7)

(1) North America					(3) Scandinavia
Canada	657	886	2,611	2,780	Norway				188	201	819	604
US	67	111	253	346	Denmark				14	10	78	10
Total revenue	724	997	2,864	3,126	Total revenue				202	211	897	614
Canada			7,510	6,227	Norway						1,321	1,149
US			447	503	Denmark						237	258
Property, plant and equipment (7)			7,957	6,730	Property, plant and equipment (7)						1,558	1,407

(2) United Kingdom
United Kingdom	540	623	2,406	2,228
Netherlands	22	18	73	56
Total revenue	562	641	2,479	2,284
United Kingdom			6,081	4,067
Netherlands			50	45
Property, plant and equipment (7)			6,131	4,112

(6) Excludes corporate acquisitions.
(7) Current year and prior year represent balances as at December 31.



Southeast Asia(4)				Other (5)				Total
Three months		Years		Three months		Years		Three months		Years
ended		ended		ended		ended		ended		ended
December 31		December 31		December 31		December 31		December 31		December 31
2006	2005	2006	2005	2006	2005	2006	2005	2006	2005	2006	2005

471	459	2,125	1,527	144	127	539	578	2,195	2,682	9,362	8,888
-	-	-	-	-	-	-	-	(23)	20	(66)	77
151	174	797	553	53	35	165	170	352	463	1,603	1,516
320	285	1,328	974	91	92	374	408	1,866	2,199	7,825	7,295
2	1	2	1	-	-	-	-	35	28	119	112
322	286	1,330	975	91	92	374	408	1,901	2,227	7,944	7,407

42	29	161	87	15	8	36	35	424	380	1,651	1,338
11	10	46	43	2	2	7	9	53	54	207	185
57	45	224	144	19	18	69	83	519	467	2,005	1,689
15	4	15	11	65	11	109	55	176	77	296	241
7	20	22	40	36	16	73	39	111	96	318	275
(1)	1	9	1	2	5	12	5	(93)	18	(54)	46
131	109	477	326	139	60	306	226	1,190	1,092	4,423	3,774
191	177	853	649	(48)	32	68	182	711	1,135	3,521	3,633

								70	58	233	201
								43	42	166	163
								98	121	51	633
								(5)	12	25	(7)
								206	233	475	990

								505	902	3,046	2,643

42	32	72	74	68	46	161	138	372	358	1,553	1,084
65	45	259	231	33	21	88	46	882	566	2,813	1,976
-	-	-	-	-	-	-	-	56	42	174	72
107	77	331	305	101	67	249	184	1,310	966	4,540	3,132
								192	3	204	536
								-	-	-	-
								(111)	(7)	(119)	(22)
								11	9	36	28
								1,402	971	4,661	3,674
		1,561	1,465			484	482			17,691	14,196
		123	123			4	4			1,543	1,434
		351	348			71	75			1,734	1,628
		-	-			-	-			443	1,039
		2,035	1,936			559	561			21,411	18,297
										50	57
										21,461	18,354

(4) Southeast Asia
Indonesia				127	(62)	558	408
Malaysia				132	333	551	539
Vietnam				5	15	30	28
Australia				58	-	191	-
Total revenue				322	286	1,330	975
Indonesia						417	371
Malaysia						879	818
Vietnam						54	23
Australia						211	253
Property, plant and equipment (7)						1,561	1,465

(5) Other
Trinidad & Tobago				27	(17)	186	194
Algeria				61	109	174	214
Tunisia				3	-	14	-
Total revenue				91	92	374	408
Trinidad & Tobago						246	275
Algeria						199	162
Tunisia						15	15
Other						24	30
Property, plant and equipment (7)						484	482

Talisman Energy Inc.
Product Netbacks
(unaudited)

		Three months ended December 31				Twelve months ended December 31
(C$ - production before royalties)		2006	2005	2006	2005	2006	2005	2006	2005
		Oil and liquids ($/bbl)		Natural gas ($/mcf)		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	50.90	54.84	6.94	12.25	56.73	52.62	7.12	9.05
America	Hedging (gain) loss	-	4.28	(0.28)	-	-	3.99	(0.26)	-
	Royalties	10.20	10.69	1.20	2.46	11.91	10.79	1.30	1.80
	Transportation	0.58	0.51	0.17	0.23	0.57	0.50	0.19	0.19
	Operating costs	9.33	8.33	1.05	0.95	8.57	7.24	1.07	0.90
		30.79	31.03	4.80	8.61	35.68	30.10	4.82	6.16
United	Sales price	67.40	66.24	7.52	8.76	72.11	64.07	8.50	7.30
Kingdom	Hedging (gain) loss	0.12	(0.09)	-	-	0.52	(0.03)	-	-
	Royalties	0.50	1.07	0.07	0.52	0.74	0.87	0.46	0.53
	Transportation	1.58	1.26	0.37	0.40	1.52	1.21	0.33	0.42
	Operating costs	21.38	16.38	0.84	1.11	19.83	16.67	0.71	0.91
		43.82	47.62	6.24	6.73	49.50	45.35	7.00	5.44
Scandinavia	Sales price	69.14	67.43	4.60	3.80	73.79	67.72	4.92	4.30
	Royalties	0.24	0.14	-	-	0.33	0.05	-	-
	Transportation	1.82	1.28	1.14	0.43	1.80	1.11	1.10	1.48
	Operating costs	21.34	19.28	-	-	22.42	18.98	-	-
		45.74	46.73	3.46	3.37	49.24	47.58	3.82	2.82
Southeast	Sales price	67.21	68.30	5.75	6.72	74.62	68.79	6.95	6.40
Asia	Royalties	25.02	27.27	1.30	1.98	32.36	27.28	1.86	1.95
	Transportation	0.35	(0.12)	0.35	0.43	0.27	0.09	0.38	0.41
	Operating costs	6.19	5.04	0.43	0.30	6.63	4.48	0.36	0.30
		35.65	36.11	3.67	4.01	35.36	36.94	4.35	3.74
Other	Sales price	66.78	66.26	-	-	71.65	65.40	-	-
	Royalties	23.93	19.05	-	-	22.41	19.41	-	-
	Transportation	1.09	0.96	-	-	0.94	1.00	-	-
	Operating costs	7.44	3.97	-	-	4.99	3.89	-	-
		34.32	42.28	-	-	43.31	41.10	-	-
Total Company	Sales price	64.48	64.62	6.72	10.63	69.82	62.78	7.20	8.30
	Hedging (gain) loss	0.05	0.77	(0.19)	-	0.21	0.85	(0.17)	-
	Royalties	9.18	8.81	1.11	2.14	10.97	8.64	1.33	1.71
	Transportation	1.14	0.86	0.24	0.29	1.07	0.86	0.25	0.27
	Operating costs	14.91	12.25	0.89	0.82	14.11	11.81	0.87	0.76
		39.20	41.93	4.67	7.38	43.46	40.62	4.92	5.56

Unit operating costs include pipeline operations for the United Kingdom.
Netbacks do not include synthetic oil.

Talisman Energy Inc.
Production net of royalties (1)
(unaudited)

	Three months ended		Twelve months ended
	December 31		December 31
	2006	2005	2006	2005

Oil and liquids (bbls/d)
North America	37,627	43,676	39,382	42,613
United Kingdom	101,306	118,972	101,682	105,582
Scandinavia	32,561	38,916	32,327	25,676
Southeast Asia	32,611	29,505	29,211	21,406
Other	13,303	18,533	14,816	17,994
Synthetic oil (Canada)	3,244	2,743	2,979	2,587
Total oil and liquids	220,652	252,345	220,397	215,858

Natural gas (mmcf/d)
North America	779	725	744	733
United Kingdom	117	129	119	103
Scandinavia	16	13	14	9
Southeast Asia	223	202	214	198
Total natural gas	1,135	1,069	1,091	1,043

Total mboe/d	410	430	402	390

(1) Information provided per US reporting practice of calculating production after deduction of royalty volumes.

Talisman Energy Inc.

Product Netbacks (1)

(unaudited)

Three months ended

Twelve months ended

December 31

(US$ - production net of royalties)

2006

2005 (2)

2006

2005 (2)

North

Oil and liquids (US$/bbl)

America

Sales price

44.66

46.75

50.06

43.55

Hedging loss

4.53

4.16

Transportation

0.64

0.54

0.64

0.52

Operating costs

10.26

8.82

9.57

7.54

33.76

32.86

39.85

31.33

Natural gas (US$/mcf)

Sales price

6.08

10.44

6.27

7.51

Hedging (gain)

(0.30)

(0.28)

Transportation

0.18

0.25

0.20

0.20

Operating costs

1.11

1.02

1.15

0.93

5.09

9.17

5.20

6.38

United Kingdom

Oil and liquids (US$/bbl)

Sales price

59.10

56.49

63.48

53.10

Hedging loss

0.10

(0.08)

0.47

(0.02)

Transportation

1.40

1.10

1.35

1.01

Operating costs

18.92

14.23

17.66

13.99

38.68

41.24

44.00

38.12

Natural gas (US$/mcf)

Sales price

6.60

7.48

7.47

6.06

Transportation

0.33

0.36

0.31

0.37

Operating costs

0.75

1.00

0.66

0.82

5.52

6.12

6.50

4.87

Scandinavia

Oil and liquids (US$/bbl)

Sales price

60.66

57.51

64.94

56.41

Transportation

1.60

1.09

1.59

0.93

Operating costs

18.78

16.50

19.86

15.78

40.28

39.92

43.49

39.70

Natural gas (US$/mcf)

Sales price

4.03

3.25

4.34

3.57

Transportation

1.02

0.36

0.97

1.21

3.01

2.89

3.37

2.36

Southeast Asia

Oil and liquids (US$/bbl)

Sales price

59.00

58.25

65.84

57.24

Transportation

0.50

(0.16)

0.42

0.12

Operating costs

8.77

7.16

10.33

6.18

49.73

51.25

55.09

50.94

Natural gas (US$/mcf)

Sales price

5.05

5.73

6.13

5.29

Transportation

0.40

0.52

0.46

0.49

Operating costs

0.50

0.37

0.44

0.35

4.15

4.84

5.23

4.45

Other

Oil (US$/bbl)

Sales price

58.65

56.51

62.94

54.10

Transportation

1.49

1.15

1.20

1.17

Operating costs

10.08

4.75

6.37

4.58

47.08

50.61

55.37

48.35

Total Company

Oil and liquids (US$/bbl)

Sales price

56.57

55.10

61.50

52.07

Hedging loss

0.05

0.76

0.22

0.82

Transportation

1.17

0.85

1.12

0.83

Operating costs

15.35

12.12

14.77

11.36

40.00

41.37

45.39

39.06

Natural gas (US$/mcf)

Sales price

5.89

9.07

6.33

6.89

Hedging (gain)

(0.21)

(0.19)

Transportation

0.25

0.32

0.27

0.28

Operating costs

0.94

0.88

0.94

0.80

4.91

7.87

5.31

5.81

(1) Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty volumes.

(2) Unit operating costs include pipeline operations for the UK.

Netbacks do not include synthetic oil.

Continuity of Net Proved Reserves ¹

	North America ²	United Kingdom ³	Scandinavia ⁴	Southeast Asia ⁵	Other ⁶	Total
Crude Oil and Liquids (mmbbls)
Total proved
Proved reserves at December 31, 2003	158.4	240.8	14.2	52.5	34.7	500.6
Discoveries, additions and extensions	14.0	29.7	-	2.0	8.1	53.8
Purchase of reserves	0.2	34.0	-	0.9	-	35.1
Sale of reserves	(2.1)	(3.3)	-	-	-	(5.4)
Net revisions and transfers	(2.5)	26.8	(2.8)	(1.3)	(6.9)	13.3
2004 Production	(15.8)	(42.1)	(2.2)	(7.9)	(3.1)	(71.1)
Proved reserves at December 31, 2004	152.2	285.9	9.2	46.2	32.8	526.3
Discoveries, additions and extensions	10.6	42.3	2.1	16.4	3.8	75.2
Purchase of reserves	0.1	32.8	41.9	17.0	0.7	92.5
Sale of reserves	-	-	(0.9)	-	-	(0.9)
Net revisions and transfers	(5.2)	30.1	1.6	(16.0)	1.1	11.6
2005 Production	(15.5)	(38.6)	(9.3)	(7.7)	(6.6)	(77.7)
Proved Reserves at December 31, 2005	142.2	352.5	44.6	55.9	31.8	627.0
Discoveries, additions and extensions	8.4	28.7	28.6	(2.9)	7.3	70.1
Purchase of reserves	-	26.2	-	-	-	26.2
Sale of reserves	(7.3)	(6.8)	-	-	-	(14.1)
Net revisions and transfers	9.3	14.3	0.4	11.6	(0.3)	35.3
2006 Production	(14.3)	(37.1)	(11.8)	(10.7)	(5.4)	(79.3)
Proved Reserves at December 31, 2006	138.3	377.8	61.8	53.9	33.4	665.2
Proved Developed
December 31, 2003	155.4	207.9	3.9	18.6	14.6	400.4
December 31, 2004	142.6	247.6	4.7	19.2	27.0	441.1
December 31, 2005	132.0	274.2	34.8	35.8	22.3	499.1
December 31, 2006	130.1	252.9	25.6	36.9	25.8	471.3
Natural Gas (bcf)
Total proved
Proved reserves at December 31, 2003	2,080.7	222.2	13.4	986.7	211.0	3,514.0
Discoveries, additions and extensions	370.6	8.0	-	521.9	-	900.5
Purchase of reserves	19.1	0.1	-	-	-	19.2
Sale of reserves	(57.1)	(0.5)	-	-	-	(57.6)
Net revisions and transfers	(19.2)	(23.2)	(3.2)	93.5	5.5	53.4
2004 Production	(260.6)	(38.3)	(1.2)	(47.3)	-	(347.4)
Proved reserves at December 31, 2004	2,133.5	168.3	9.0	1,554.8	216.5	4,082.1
Discoveries, additions and extensions	274.9	23.1	0.3	81.7	-	380.0
Purchase of reserves	11.7	56.9	4.4	30.8	1.2	105.0
Sale of reserves	(1.1)	-	-	-	-	(1.1)
Net revisions and transfers	2.5	15.8	(2.3)	(94.0)	(2.9)	(80.9)
2005 Production	(265.6)	(33.0)	(3.2)	(73.1)	-	(374.9)
Proved reserves at December 31, 2005	2,155.9	231.1	8.2	1,500.2	214.8	4,110.2
Discoveries, additions and extensions	356.8	33.1	65.9	(18.9)	14.8	451.7
Purchase of reserves	2.9	-	-	-	-	2.9
Sale of reserves	(35.8)	(20.5)	-	-	-	(56.3)
Net revisions and transfers	51.1	(28.1)	7.4	47.7	(0.2)	77.9
2006 Production	(253.3)	(37.5)	(5.2)	(78.3)	(0.1)	(374.4)
Proved reserves at December 31, 2006	2,277.6	178.1	76.3	1,450.7	229.3	4,212.0
Proved Developed
December 31, 2003	1,890.4	199.5	1.2	593.9	-	2,685.0
December 31, 2004	1,788.2	148.0	2.0	624.0	-	2,562.2
December 31, 2005	1,771.8	174.9	6.2	548.8	0.8	2,502.5
December 31, 2006	1,860.9	123.2	8.6	895.5	0.5	2,888.7

Notes:
1 See oil and gas advisories.
2 North American net proved reserves exclude synthetic crude oil reserves: 2004 - 35.2 mmbbls; 2005 - 34.3 mmbbls; and 2006 - 32.0 mmbbls.
3 United Kingdom for 2004 includes the Netherlands but excludes Germany.
4 Scandinavia for 2004 includes Norway but excludes Denmark.
5 Southeast Asia for 2004 includes Indonesia and Malaysia/Vietnam but excludes Australia.
6 Other includes Algeria, Tunisia and Trinidad and Tobago but excludes Tunisia in 2003 and 2004.


Continuity of Gross Proved Reserves¹
	North America²	United Kingdom³	Scandinavia⁴	Southeast Asia⁵	Other⁶	Total
Crude Oil and Liquids (mmbbls)
Total proved
Proved reserves at December 31, 2003	190.2	242.3	14.1	84.4	48.2	579.2
Discoveries, additions, and extensions	17.3	29.8	-	13.0	13.9	74.0
Purchase of reserves	0.2	34.1	-	1.3	-	35.6
Sale of reserves	(2.6)	(3.3)	-	-	-	(5.9)
Net revisions and transfers	(2.2)	27.5	(2.9)	3.4	(8.5)	17.3
2004 Production	(19.9)	(42.5)	(2.1)	(13.0)	(5.0)	(82.5)
Proved reserves at December 31, 2004	183.0	287.9	9.1	89.1	48.6	617.7
Discoveries, additions, and extensions	12.6	41.9	2.0	12.7	8.5	77.7
Purchase of reserves	0.2	32.8	42.1	22.1	0.8	98.0
Sale of reserves	-	-	(0.9)	-	-	(0.9)
Net revisions and transfers	(2.8)	32.5	1.8	(1.3)	3.6	33.8
2005 Production	(19.6)	(39.1)	(9.3)	(12.9)	(9.3)	(90.2)
Proved Reserves at December 31, 2005	173.4	356.0	44.8	109.7	52.2	736.1
Discoveries, additions, and extensions	10.4	28.8	28.6	(0.9)	13.2	80.1
Purchase of reserves	-	26.2	-	-	-	26.2
Sale of reserves	(8.8)	(6.8)	-	-	-	(15.6)
Net revisions and transfers	9.8	14.1	0.3	8.3	1.4	33.9
2006 Production	(18.2)	(37.5)	(11.8)	(18.8)	(7.9)	(94.2)
Proved reserves at December 31, 2006	166.6	380.8	61.9	98.3	58.9	766.5
Proved Developed
December 31, 2003	186.4	209.2	3.8	29.5	25.5	454.4
December 31, 2004	171.0	249.3	4.7	39.9	38.9	503.8
December 31, 2005	161.0	277.4	34.9	67.7	34.7	575.7
December 31, 2006	156.4	255.7	25.7	70.2	43.3	551.3
Natural Gas (bcf)
Total proved
Proved reserves at December 31, 2003	2,644.9	241.6	13.5	1,572.0	223.5	4,695.5
Discoveries, additions, and extensions	478.5	8.0	-	765.3	-	1,251.8
Purchase of reserves	22.8	0.1	-	-	-	22.9
Sale of reserves	(72.7)	(0.5)	-	-	-	(73.2)
Net revisions and transfers	(113.2)	(30.0)	(3.2)	(58.7)	(7.0)	(212.1)
2004 Production	(324.9)	(40.3)	(1.3)	(95.2)	-	(461.7)
Proved reserves at December 31, 2004	2,635.4	178.9	9.0	2,183.4	216.5	5,223.2
Discoveries, additions, and extensions	361.0	23.7	0.3	129.1	-	514.1
Purchase of reserves	16.8	56.9	4.4	38.9	1.4	118.4
Sale of reserves	(1.2)	-	-	-	-	(1.2)
Net revisions and transfers	28.6	16.3	(2.2)	(3.4)	(1.3)	38.0
2005 Production	(333.8)	(35.2)	(3.3)	(103.6)	-	(475.9)
Proved reserves at December 31, 2005	2,706.8	240.6	8.2	2,244.4	216.6	5,416.6
Discoveries, additions, and extensions	457.8	34.6	65.9	(9.1)	14.9	564.1
Purchase of reserves	3.7	-	-	-	-	3.7
Sale of reserves	(44.2)	(20.5)	-	-	-	(64.7)
Net revisions and transfers	13.0	(32.7)	7.4	(20.0)	(1.5)	(33.8)
2006 Production	(332.0)	(39.2)	(5.2)	(106.5)	(0.1)	(483.0)
Proved reserves at December 31, 2006	2,805.1	182.8	76.3	2,108.8	229.9	5,402.9
Proved Developed
December 31, 2003	2,404.0	218.8	1.3	920.9	-	3,545.0
December 31, 2004	2,207.3	158.6	2.0	858.2	-	3,226.1
December 31, 2005	2,226.5	183.5	6.2	793.2	0.9	3,210.3
December 31, 2006	2,295.0	126.4	8.6	1,307.8	0.5	3,738.3

Notes:
1 See oil and gas advisories.
2 North American gross proved reserves exclude synthetic crude oil reserves: 2003 - 42.3 mmbbls; 2004 - 41.2 mmbbls; 2005 - 40.2 mmbbls; 2006 - 38.9 mmbbls.
3 United Kingdom for 2004 includes the Netherlands but excludes Germany.
4 Scandinavia for 2004 includes Norway but excludes Denmark.
5 Southeast Asia for 2004 includes Indonesia and Malaysia/Vietnam but excludes Australia.
6 Other includes Algeria, Tunisia and Trinidad and Tobago but excludes Tunisia in 2003 and 2004.