TALISMAN ANNOUNCES TEST RATE OF

EX-99 2 frontend.htm 2005 YEAR END RESULTS - PRESS RELEASE TALISMAN ANNOUNCES TEST RATE OF

N E W S R E L E A S E

TALISMAN ENERGY GENERATES $4.7 BILLION IN CASH FLOW IN 2005

516,000 BOE/D FOURTH QUARTER PRODUCTION

189% PROVED RESERVES REPLACEMENT

CALGARY, Alberta – March 1, 2006 – Talisman Energy Inc. released its 2005 consolidated financial and operating results today. The Company set new quarterly and annual records for production, cash flow and earnings from operations.

Cash flow¹ increased 60% to $4,672 million ($12.69/share), compared to $2,916 million ($7.61/share) a year ago. The Company generated $1,468 million ($4.01/share) in cash flow during the fourth quarter, more than double the $679 million ($1.78/share) a year earlier.

Net income was $1,561 million ($4.24/share), an increase of 139% over the $654 million ($1.71/share) in 2004. Net income during the fourth quarter was $533 million ($1.45/share), an increase of 340% versus $121 million ($0.32/share) a year ago.

Earnings from operations¹ were $2,058 million ($5.59/share), compared to $764 million ($1.99/share) in 2004. During the fourth quarter of 2005, Talisman generated $621 million ($1.70/share) in earnings from operations. This was a 322% increase over the $147 million ($0.39/share) for the comparable period a year earlier.

Talisman increased its annual production by 7% to 470,000 boe/d. Oil and liquids production was up 9% to 249,984 bbls/d. The 21,550 bbls/d increase came predominantly from the North Sea (up 10,855 bbls/d) and the first year of production from Trinidad and Tobago, which averaged 10,111 bbls/d. Talisman increased natural gas production by 5% to 1.3 bcf/d. The Company grew its North American natural gas volumes by 3% to 915 mmcf/d and natural gas volumes in Southeast Asia by 9% to 284 mmcf/d.

Production in the fourth quarter averaged 516,000 boe/d, an increase of 14% over the same period in 2004. On November 18, 2005, the Company effectively acquired control of Paladin Resources plc. Paladin contributed an average of 5,650 boe/d for the year based on production from that date.

"2005 was a great year," said Dr. Jim Buckee, President and Chief Executive Officer. "We had a very strong fourth quarter, with production growth of 14%, minor hedges and cash flow per share up 125% over 2004. For the full year, we grew production per share by 11% and replaced 189% of production with high quality reserves. This includes replacement of 162% of North Sea liquids production and 117% of North America natural gas production through discoveries, additions and revisions. Talisman’s momentum will continue in 2006 and beyond from a number of significant developments already in progress.

"We have continued to grow our North American gas volumes at a time when the industry is struggling to maintain production levels. Gas volumes in the fourth quarter were up 2% over the same period a year ago, averaging 907 mmcf/d. We estimate that we currently have about 100 mmcf/d of gas awaiting tie-in or completion of infrastructure, with a number of projects underway to bring this gas to market.

"North Sea liquids production was 25% above the fourth quarter of 2004. We had successful development programs in the Clyde, Claymore, Tartan, Gyda and Varg areas. In total, we drilled 28 successful oil and gas wells in the North Sea last year. The acquired Paladin assets were producing about 45,000 boe/d (worldwide) in December. I think shareholders will be very pleased with the Paladin acquisition as we continue to develop the opportunity set.

"Production in Southeast Asia was up 18% in the fourth quarter with strong demand for Corridor gas in both Indonesia and Singapore. Production volumes in the quarter also benefited from the South Angsi field in Malaysia, commissioned in August, which was producing over 17,000 bbls/d net to Talisman at year end. Elsewhere, production from the Greater Angostura Project in Trinidad and Tobago started in January 2005 and contributed over 10,000 bbls/d for the year.

"I am feeling very sanguine about the future. Our capital spending program is $4.4 billion this year, of which approximately half is directed at drilling. Talisman has no shortage of economic drilling prospects. North America accounts for approximately 45% of our total capital program. Although there have been industry-wide cost pressures, we continue to take steps to mitigate them. All of our projects are economic and we have the rigs needed to carry out our programs.

"We have a $1.6 billion capital program in the North Sea, with the newly acquired Paladin properties accounting for about one-quarter of our North Sea spending this year. We have completed about 50% of the 45,000 bbls/d Tweedsmuir Project, with first production expected at the end of the first quarter of next year. Expansion of the Corridor gas project is underway in Indonesia, with first sales to West Java also commencing in the first quarter of 2007. In Malaysia/Vietnam, the Northern Fields development is underway, which will add incremental volumes in 2008. We expect to produce between 515,000-545,000 boe/d in 2006 prior to planned asset sales and deliver top line growth of about 10% annually through at least 2008.

“Our international exploration program saw discoveries in the North Sea, Malaysia/Vietnam, Peru and Tunisia in 2005. We have a very exciting program in 2006, with 16 high impact wells planned. In Alaska, the first well of the planned two well program spud in February and is currently drilling ahead. Our first onshore exploration well in Trinidad spud at the end of September 2005 and is expected to be completed in early March, with further drilling planned for 2006. We are evaluating options in Peru, including additional drilling, to follow on from the successful Situche Central well. A further well is also planned in Qatar in the fourth quarter. We also have continuous exploration drilling in both the UK and Norwegian sectors of the North Sea. The Paladin acquisition brought acreage with many additional drilling locations and exploration upside.

“Oil and gas prices were up approximately 40% last year; I continue to believe that we remain in a higher oil price environment. Even with WTI prices averaging US$56.70/bbl, oil demand increased again last year, reaching 83 mmbbls/d. The industry needs to add an estimated 4-6 mmbbls/d of new production capacity every year to offset declines from existing fields and political unrest in many petroleum exporting countries has also kept upward pressure on oil prices. Higher prices are required to ration demand and bring on new supplies.

Seven Consecutive Years of Record Cash Flow

Cash flow in 2005 was $4,672 million on gross sales of $9,554 million.

	Three months ended			Year ended
December 31	2005	2004	%	2005		2004	%
Cash flow ($mm) ¹	1,468	679	116	4,672		2,916	60
Cash flow ($/share) ¹	4.01	1.78	125	12.69		7.61	67
Net income ($mm)	533	121	340	1,561		654	139
Net income ($/share)	1.45	0.32	358	4.24		1.71	148
Long term debt ($mm at year end)				4,263	2,457
Shares outstanding (mm at year end)				366	375

¹ non-GAAP measure

Cash flow was $1.8 billion above 2004 levels. Significant increases came from higher prices ($3,023 million), increased volumes ($377 million) and lower hedging losses ($403 million less than last year). These gains were offset by higher royalties and taxes ($1,076 million), the impact of a stronger Canadian dollar on realized prices ($720 million) and increased operating costs ($261 million).

Net income for the year totaled $1,561 million, approximately $900 million higher than last year. Increased cash flow was offset by non-cash items, including increased future tax ($322 million), depreciation, depletion and amortization ($193 million) and stock based compensation ($391 million) expense.

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 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.

Liquidity and Capital Resources

Talisman’s long-term debt at year end was $4.3 billion, up from $2.5 billion at the end of last year. During 2005, the Company generated $4.9 billion of cash provided by operating activities and spent $3.2 billion on exploration and development and a net $3.1 billion on acquisitions. The Company repurchased 9,089,100 common shares under its normal course issuer bid (NCIB) during 2005, for a total of $355 million ($39.01/share).

Two common share dividends were paid in 2005 for a total of $125 million (an aggregate of $0.34/share). The Company’s dividend is determined semi-annually by the Board of Directors. At year end, there were 366 million common shares outstanding, down from 375 million at December 31, 2004.

At the end of 2005, Talisman’s ratio of debt to cash provided by operating activities was 0.88:1 and the ratio of debt to debt plus equity was 43%.

Earnings from Operations up 169%

In order to better illustrate Talisman’s operating performance on an internally consistent basis, the Company has calculated an earnings from operations number. 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.

Earnings from operations were $2,058 million in 2005.

($ millions, except per share amounts)

	Three months ended		Year ended
December 31	2005	2004	2005	2004
Net income	533	121	1,561	654
Stock-based compensation ^1,2	88	5	446	119
Tax effects of unrealized foreign exchange gains on foreign denominated debt ²	(1)	15	49	37
Tax rate reductions and other ²	2	6	2	(46)
Earnings from operations ³	621	147	2,058	764
$ per share ³	1.70	0.39	5.59	1.99

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at December 31, 2005, which was first expensed during the second quarter of 2003. 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.

Tax adjustments include the impact of Canadian corporate tax rate reductions in 2004, as well as future taxes relating in part to unrealized foreign exchange gains associated with the impact of a stronger Canadian dollar on foreign currency denominated debt and insurance expenses.

This is a non-GAAP measure.

In certain of Talisman’s international operations, production is stored in tanks until there is sufficient quantity of oil to fill a tanker. As a result of an increase in unlifted oil volumes, which were previously insignificant, the Company has changed its practice for recording revenue. Unlifted oil volumes are now recorded as inventory, at cost. Had this change not been initiated net income in the fourth quarter would have been $43 million higher, $15 million of which relates to prior periods.

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 section in this news release entitled Advisory - Non-GAAP Financial Measures for further explanation and details.

($ millions)	Three months ended		Year ended
December 31,	2005	2004	2005	2004 (Restated)
Cash provided by operating activities	1,699	725	4,871	3,119
Changes in non-cash working capital	(231)	(46)	(199)	(203)
Cash flow	1,468	679	4,672	2,916

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, 2005.

The Company’s stock option plans were amended during 2003 to 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 alternative is expected to result in reduced shareholder dilution in the future as it is anticipated that most holders of the stock options 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 have been exercised for cash.

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. As a result of record high share prices throughout the year, $633 million was expensed in 2005, of which $480 million was non-cash and $153 million cash.

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.

Production per share up by 11%

	Three Months Ended		Year Ended
December 31	2005	2004	2005	2004
Oil and liquids (bbls/d)
North America	57,108	57,322	56,304	57,392
North Sea	159,918	127,943	132,716	121,861
Southeast Asia and Australia	49,111	35,018	35,476	35,644
North Africa	15,112	15,329	15,377	13,537
Trinidad and Tobago	10,790	-	10,111	-
	292,039	235,612	249,984	228,434
Natural gas (mmcf/d)
North America	907	891	915	885
North Sea	151	121	120	114
Southeast Asia and Australia	286	280	284	260
	1,344	1,292	1,319	1,259
000 boe/d	516	451	470	438
000 boe/d (net of royalties)	430	379	390	365
boe per share (gross)			0.47	0.42

Production for the year averaged 470,000 boe/d, an increase of 7% over 2004 and Talisman increased production per share by 11%. Fourth quarter volumes were 516,000 boe/d, an increase of 14% over the comparable period a year earlier. Production from the acquired Paladin properties averaged 5,650 boe/d for the year. Consolidation of the Paladin assets occurred on November 18, 2005.

Talisman increased its oil and liquids production by 9% over the prior year and 24% compared to the fourth quarter of 2004. North American liquids volumes were down slightly, reflecting declines from existing fields and the Company’s focus on natural gas. The increase in North Sea liquids volumes reflects the Paladin acquisition as well as successful drilling programs at Clyde, Claymore, Tartan, Varg and Gyda. Liquids volumes in Southeast Asia and Australia were up 40% in the fourth quarter of 2005 with commencement of production from the South Angsi field in Malaysia. At year end, South Angsi was producing 17,244 bbls/d net to Talisman. Talisman also recorded its first oil volumes from Trinidad and Tobago in 2005 with the startup of the Greater Angostura Project.

Total natural gas volumes were up 5% for the year. Talisman increased its gas production in North America by 3% in 2005 on the strength of a successful natural gas drilling program. Natural gas sales in Southeast Asia and Australia were up 9% with higher demand for Corridor gas from Caltex and Singapore Power.

On December 19, 2005, the Company issued guidance for expected 2006 production volumes, with a range of 515,000-545,000 boe/d, before planned asset sales.

189% Production Replacement

Talisman Proved Reserves (excluding Syncrude)	Oil & NGLs ¹ (million barrels)	Natural Gas ¹ (billion cu ft)	BOE ¹ (millions)
Dec 31, 2004	618	5,223	1,488
Discoveries, additions and extensions	78	514	163
Net acquisitions	97	118	117
Revisions	33	38	40
Production	(90)	(476)	(169)
Total Proved Dec 31, 2005	736	5,417	1,639
Total Probable Dec 31, 2005	493	2,704	943

¹ Talisman working interest reserves before royalties payable, plus royalty interests and net profits interest

Talisman replaced 189% of production from all sources in 2005 (proved reserves) and 120% through drilling and revisions. At year end, Talisman had 5.4 tcf of proved natural gas reserves (up 4%) and 736 mmbbls of proved oil and liquids reserves (up 19%). Talisman increased its total proved reserves by 10% to 1.6 billion boe. Net of royalties, Talisman had 1.3 billion boe of proved reserves (up 9%).

At year end, Talisman had a reserve life index of 9.7 years for proved reserves and 15.2 years for proved and probable reserves.

Approximately 45% of Talisman’s reserves are high quality oil and liquids and 55% natural gas. North America accounts for 38% of the Company’s total proved reserves, the North Sea 27% and Southeast Asia and Australia 30%. At year end, the Company had 943 mmboe of probable reserves, which comprise a large part of Talisman’s development inventory.

Exploration and development spending during 2005 totalled $3,079 million, excluding Syncrude and midstream expenditures. Including the Paladin acquisition, $3.1 billion was spent on acquisitions (net of dispositions).

Talisman has an internal qualified reserves engineer who reviews all of the Company’s reserves estimates. In addition, approximately 80% of Talisman’s proved reserves have been reviewed by outside engineering firms over the past three years.

Over the past three years, Talisman has added 611 mmboe of proved reserves through discoveries, additions and extensions (including revisions) and 784 mmboe of proved reserves including net acquisitions. During this period, exploration and development spending was $7,405 million and $11,586 million including acquisitions and dispositions. Detailed reserves reconciliation tables are provided elsewhere in this news release.

The reserves replacement ratio of 120% (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 2005 by the Company’s 2005 conventional production. The reserves replacement ratio of 189% was calculated by dividing the sum of changes (revisions of estimates, improved recovery, discoveries, acquisitions and dispositions) to estimated proved oil and gas reserves during 2005 by the Company’s 2005 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.

Netbacks up 73% in the Fourth Quarter

Total Company	Three Months Ended		Year Ended
December 31	2005	2004	2005	2004
WTI oil price US$/bbl	60.05	48.29	56.70	41.40
NYMEX gas price US$/mcf	12.85	6.87	8.55	6.09

Talisman netback ($/boe)
Sales price	64.26	43.88	56.67	42.75
Hedging Loss	(0.43)	(3.99)	(0.46)	(3.02)
Royalties	10.56	6.80	9.41	7.04
Operating cost	9.04	7.06	8.41	7.26
Transportation	1.26	1.20	1.21	1.20
Netback ($/boe) ¹	42.97	24.83	37.18	24.23
Oil and liquids netback ($/bbl)	41.93	24.04	40.62	23.99
Natural gas netback ($/mcf)	7.38	4.30	5.56	4.08

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.

World oil prices continued to increase during 2005, up 37% over 2004 levels, with WTI reaching US$70.85 in August 2005. Oil demand continued to grow in 2005, reaching an estimated 83 mmbbls/d, an increase of 1.5%. Lack of significant spare production capacity, especially for higher quality crude oil, and continuing political unrest in a number of oil exporting regions contributed to higher prices.

NYMEX gas prices were up 40% on average, tracking oil prices. Gas prices have also weakened of late, reflecting “demand destruction” in the US from higher prices and growing inventory levels due to mild winter weather.

Hedging losses were down significantly with most of the remaining 2005 hedges entered into two to three years ago. The Company’s average royalty rate increased from 16% in 2004 to 17% in 2005, reflecting higher prices.

Unit operating costs increased by 16% to $8.41/boe. Much of the increase in operating costs is due to higher energy prices, which also benefit Talisman. Additional increases were due to a change in production mix, specifically, increased volumes from Norway. The Company expects unit operating cost increases in the 5% range this year. However, Talisman anticipates bringing on a mix of low cost projects over the next two to three years which should result in lower average unit operating costs.

Talisman’s netbacks averaged $37.18/boe in 2005, an increase of 53%. North Sea oil and liquids netbacks averaged $45.76/bbl, up 81%. North American natural gas netbacks averaged $6.16/mcf, up 39%.

Additional Information

Corporate and Other

(millions of dollars)	2005	2004¹
G & A expense	201	183
Interest expense	166	173
Capitalized interest	19	13
Stock-based compensation	633	171
Other revenue	165	85
Other expense	39	89

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

The sum of interest on long-term debt and capitalized interest remained relatively flat at $185 million during 2005. Interest capitalized over the last year is associated with the Tweedsmuir development project in the North Sea, which is scheduled to come on production late in the first quarter of 2007.

Other revenue includes pipeline and custom treating revenues of $141 million for 2005, compared to $73 million in 2004. Pipeline revenues in the North Sea increased $61 million.

Capital Spending^{1, 3}

(millions of dollars)	2005	2004
North America	1,763	1,500
North Sea	1,392	721
Southeast Asia and Australia	305	235
North Africa	27	8
Trinidad and Tobago	72	191
Other²	134	125
Corporate, IS and Administrative	28	26
	3,721	2,806

Includes expenditures for exploration, development and asset acquisitions net of dispositions, but excludes corporate acquisitions.

Other includes Colombia, Peru, Qatar and Alaska.

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

Natural gas continues to be the focus of the Company’s capital investment activities in North America, supplemented by low risk oil projects. Of the $1.8 billion of capital spending in North America, $658 million related to exploration activities and development accounted for $951 million. The Company participated in 495 gross gas wells and 171 gross oil wells in North America with a success rate of 97%. 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. In addition, the Company spent $154 million on property acquisitions, net of dispositions.

Total capital spending in the North Sea was $1.4 billion, including $165 million for exploration, $867 million for development and $360 million for net property acquisitions. Development activity included ongoing development of the Tweedsmuir project, as well as drilling and recompletion activity within the Clyde, Tartan, Piper and Claymore fields in the UK and the Gyda and Varg fields in Norway. A total of 25 successful development wells and three successful exploration wells (including the 13/23b-5 well, adjacent to the Ross and Blake fields and 16/22-7 near the Balmoral field) were drilled in the North Sea during 2005. The corporate acquisition of Paladin added producing assets in both the UK and Norway in addition to exploration acreage.

Malaysia/Vietnam accounted for $250 million of the $305 million of total capital spending in Southeast Asia, with the South Angsi field development in PM-305 and the PM-3 CAA development. Talisman participated in 10 successful development wells and six successful exploration wells in Malaysia/Vietnam in 2005. A total of $55 million was spent in Indonesia, primarily on the Suban phase 2 development.

Capital spending in North Africa totaled $27 million in 2005, with Talisman participating in 10 successful wells. In Trinidad and Tobago, a total of $72 million was spent primarily on Angostura development and the Eastern Block onshore exploration activity. A potentially significant exploration discovery was made in northern Peru.

During 2005, the Company spent $49 million in Alaska on seismic and preparations for exploration drilling. Talisman spent $24 million in Colombia on exploration drilling during 2005, as well as $20 million on exploration drilling in Peru and $14 million on seismic and exploration drilling in Qatar.

Spending plans for 2006 were provided on December 19, 2005. Talisman expects to spend approximately $4.4 billion on exploration and development this year.

Depreciation, Depletion and Amortization Expense

	2005		2004
	$/boe	$millions	$/boe	$millions
North America	12.42	946	10.47	785
North Sea	12.23	670	12.83	661
Southeast Asia and Australia	4.98	144	6.02	174
North Africa	6.80	36	5.99	30
Trinidad and Tobago	13.11	47	-	-
	10.88	1,843	10.29	1,650

The Company’s 2005 depreciation, depletion and amortization expense increased 6% to $10.88/boe. DD&A rates in North America increased to $12.42/boe with higher drilling costs, increased spending on infrastructure projects and increased land costs. In the North Sea, unit DD&A rates fell by 5% due to 2004 reserves additions and a lower pound sterling exchange rate. Unit DD&A rates in Southeast Asia decreased by 17% as a result of increased reserves in Malaysia/Vietnam and the expiry of the Tanjung concession.

Income Taxes

The Company’s effective tax rate for 2005, after deducting Petroleum Revenue Tax (PRT), was 44% compared to 36% in 2004.

Effective Income Tax Rate

(millions of dollars)	2005	2004¹
Income before tax	2,984	1,150
Less PRT
Current	150	124
Future	39	5
	189	129
	2,795	1,021
Income tax expense / (recovery)
Current	1,058	478
Future	176	(111)
	1,234	367
Effective income tax rate (%)	44	36

. Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants (“CICA”) accounting standard for financial instruments. The change to this standard requires that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. See note 1 of the abbreviated notes to the Consolidated Financial Statements.

A normalized effective tax rate after removing the impact of the Canadian and UK tax rate changes and the tax on unrealized foreign exchange gains on foreign denominated debt would have been 42% in 2005 and 38% in 2004. The increase in the 2005 effective tax rate results in part from a higher proportion of income from Norway in addition to the impact of increased taxable income in North America, the UK and Southeast Asia and Australia at higher marginal rates of tax. Foreign exchange rate fluctuations over the past two years have resulted in taxes on gains related to inter-company loans and non-Canadian dollar denominated debt, for which there is no corresponding component of the unrealized gain reflected in income before taxes.

Current income tax expense increased to $1,058 million in 2005, due primarily to higher commodity prices and volumes, which resulted in increases in current taxes of $222 million in Norway, $157 million in Southeast Asia, $67 million in the UK, $53 million in North America and $14 million in North Africa. In Trinidad and Tobago, production first came onstream during 2005 and current income tax expense was $64 million.

In December 2005, the UK government announced an income tax rate increase on petroleum profits from 40% to 50%, which will be effective during the second quarter of 2006 and includes a one time non-cash “catch-up” expense estimated to be approximately $300 million.

The UK government levies PRT on North Sea fields which 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. During 2005, $14 million of PRT was recorded in countries other than the UK.

Talisman Energy Inc. is a large, 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, including Colombia, Gabon, Peru, Romania and Qatar. Talisman is committed to conducting its business in an ethically, socially and environmentally responsible manner and is a participant in the United Nations Global Compact, a voluntary initiative that brings together companies, governments, civil society and other groups to advance human rights, labour and environmental principles. 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 & Investor Communications

Phone:

403-237-1196 Fax: 403-237-1210

E-mail:

tlm@talisman-energy.com

05-06

Advisory – 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.

Forward-looking statements are included throughout this news release, which include, among others, statements regarding:

•

estimates of future sales, production and production per share and operations or financial performance;

•

business plans for drilling, exploration and development;

•

the estimated amounts and timing of capital expenditures;

•

the estimated timing of development, including new production;

•

estimates of operating costs;

•

business strategy and plans or budgets;

•

outlook for oil and gas prices;

•

anticipated liquidity, capital resources and debt levels;

•

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 resources 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 business plans for drilling, exploration and development in 2006 assume that the extraction of crude oil, natural gas and natural gas liquids remains economic. In preparing its 2006 budget Talisman assumed a US$57/bbl West Texas Intermediate oil price, a US$9.00/mmbtu New York Mercantile Exchange natural gas price, a US$/Canadian$ exchange rate of $0.84 and a Canadian$/British £ rate of 2.10 in determining the 2006 planned operations described in this news release.

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 which are derived from or depend upon future production estimates do not reflect the impact of any potential asset acquisitions or dispositions. The completion of any contemplated asset dispositions 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;

•

risks and uncertainties involving geology of oil and gas deposits;

•

the uncertainty of reserves estimates and reserves life;

•

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

•

potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

•

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

•

the outcome and effects of 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);

•

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 elsewhere in the Company’s 2004 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.

Advisory – 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 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. 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 qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this report.

Throughout this press 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 press release, Talisman makes reference to production volumes. Where not otherwise indicated, such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments. In the United States, net production volumes are reported after the deduction of these amounts.

The reserves life index of 9.7 years for proved reserves was calculated by dividing the year end proved reserves by the Company’s 2005 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 2005 conventional production.

Advisory – non-GAAP financial measures

Included in this news release are references to financial measures commonly used in the oil and gas industry such as cash flow and 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. Cash flow, as commonly used in the oil and gas industry, 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 with peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with Canadian GAAP as an indicator of the Company’s performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. Debt to cash flow is a non-GAAP measure. Earnings from 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 Generally Accepted Accounting Principles in either Canada or the United States. The Company uses this information to evaluate performance of core operational activities on a comparable basis between periods. Our reported results of cash flow, cash flow per share and earnings from operations may not be comparable to similarly titled measures reported by other companies.

Talisman Energy Inc.
Highlights
(unaudited)

	Three months ended		Years ended
	December 31		December 31
	2005	2004	2005	2004
Financial			(restated (1))
(millions of Canadian dollars unless otherwise stated)
Cash flow	1,468	679	4,672	2,916
Net income	533	121	1,561	654
Exploration and development expenditures	980	728	3,179	2,538
Per common share (Canadian dollars)
Cash flow	4.01	1.78	12.69	7.61
Net income	1.45	0.32	4.24	1.71
Production
(daily average)
Oil and liquids (bbls/d)
North America	54,254	54,464	53,611	54,393
North Sea	159,918	127,943	132,716	121,861
Southeast Asia and Australia	49,111	35,018	35,476	35,644
North Africa	15,112	15,329	15,377	13,537
Trinidad and Tobago	10,790	-	10,111	-
Synthetic oil	2,854	2,858	2,693	2,999
Total oil and liquids	292,039	235,612	249,984	228,434
Natural gas (mmcf/d)
North America	907	891	915	885
North Sea	151	121	120	114
Southeast Asia and Australia	286	280	284	260
Total natural gas	1,344	1,292	1,319	1,259
Total mboe/d	516	451	470	438
Prices (2)
Oil and liquids ($/bbl)
North America	54.84	44.05	52.62	42.11
North Sea	66.53	50.26	64.78	48.29
Southeast Asia and Australia	68.30	53.81	68.79	51.29
North Africa	68.02	46.50	66.71	51.17
Trinidad and Tobago	63.78	-	63.40	-
Crude oil and natural gas liquids	64.62	49.10	62.78	47.45
Synthetic oil	71.42	61.61	69.88	52.19
Total oil and liquids	64.68	49.24	62.86	47.51
Natural gas ($/mcf)
North America	12.25	6.99	9.05	6.83
North Sea	8.35	6.08	7.08	5.55
Southeast Asia and Australia	6.72	4.55	6.40	4.74
Total natural gas	10.63	6.38	8.30	6.28
Total ($/boe) (includes synthetic)	64.30	44.00	56.74	42.81

(1) Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants ("CICA") accounting standard for financial instruments. The changes to this standard required the Company's preferred securities, all of which were redeemed in 2004, to be treated as debt rather than equity. See note 1 to the Abbreviated Notes to the Consolidated Financial Statements.

(2) Prices are before hedging.

(3) Includes unlisted oil volumes as at December 31, 2005 of 3,670 bbls/d, 1,400 bbls/d, 650 bbls/d for the

North Sea, Southeast Asia and Australia, North Africa and Trinidad and Tobago, respectively.

(4) Includes gas acquired for injection and subsequent resale of 23 mmcf/d and 3 mmcf/d for the three months ended December 31, 2005 and 2004 respectively and 15 mmcf/d and 5 mmcf/d in the full years 2005 and 2004 respectively.

Talisman Energy Inc.
Consolidated Balance Sheets
(unaudited)


December 31 (millions of Canadian dollars)	2005	2004
Assets		(restated)
Current		note 1)
Cash and cash equivalents	130	38
Accounts receivable	1,311	836
Inventories	170	78
Prepaid expenses	20	18
	1,631	970

Accrued employee pension benefit asset	57	61
Other assets	74	64
Goodwill	1,504	466
Property, plant and equipment	15,073	10,847
	16,708	11,438
Total assets	18,339	12,408


Liabilities
Current
Accounts payable and accrued liabilities	2,383	1,302
Income and other taxes payable	649	341
	3,032	1,643

Deferred credits	74	70
Asset retirement obligations	1,320	1,272
Other long-term obligations	217	35
Long-term debt	4,263	2,457
Future income taxes	3,638	2,100
	9,512	5,934

Non-controlling interest	66	-
Contingencies and commitments
Shareholders' equity
Common shares	2,609	2,666
Contributed surplus	69	71
Cumulative foreign currency translation	(265)	(76)
Retained earnings	3,316	2,170
	5,729	4,831
Total liabilities and shareholders' equity	18,339	12,408

See accompanying notes.

Talisman Energy Inc.
Consolidated Statements of Income
(unaudited)
	Three months ended		Years ended
(millions of Canadian dollars	December 31		December 31
except as otherwise noted)	2005	2004	2005	2004
				(restated
Revenue				note 1)
Gross sales	2,891	1,828	9,554	6,874
Less hedging loss	20	165	77	480
Gross sales, net of hedging	2,871	1,663	9,477	6,394
Less royalties	488	281	1,595	1,124
Net sales	2,383	1,382	7,882	5,270
Other	50	20	165	85
Total revenue	2,433	1,402	8,047	5,355

Expenses
Operating	416	302	1,459	1,198
Transportation	60	50	206	192
General and administrative	58	64	201	183
Depreciation, depletion and amortization	511	447	1,843	1,650
Dry hole	77	89	241	311
Exploration	96	71	275	238
Interest on long-term debt	45	38	166	173
Stock-based compensation	121	7	633	171
Other	30	74	39	89
Total expenses	1,414	1,142	5,063	4,205
Income before taxes	1,019	260	2,984	1,150
Taxes
Current income tax	315	204	1,058	478
Future income tax (recovery)	107	(99)	176	(111)
Petroleum revenue tax	64	34	189	129
	486	139	1,423	496
Net income	533	121	1,561	654

Per common share (Canadian dollars)
Net income	1.45	0.32	4.24	1.71
Diluted net income	1.42	0.31	4.14	1.68
Average number of common shares outstanding (millions)	366	381	368	383
Diluted number of common shares outstanding (millions)	376	387	377	390
See accompanying notes.

Consolidated Statements of Retained Earnings
(unaudited)
	Three months ended		Years ended
	December 31		December 31
(millions of Canadian dollars)	2005	2004	2005	2004
		(restated		(restated
		note 1)		note 1)
Retained earnings, beginning of period	2,894	2,327	2,170	1,852
Net income	533	121	1,561	654
Common share dividends	(63)	(56)	(125)	(114)
Purchase of common shares	(48)	(222)	(290)	(222)
Retained earnings, end of period	3,316	2,170	3,316	2,170
See accompanying notes.

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

	Three months ended		Years ended
	December 31		December 31
(millions of Canadian dollars)	2005	2004	2005	2004
				(restated
Operating				note 1)
Net income	533	121	1,561	654
Items not involving cash	839	487	2,836	2,024
Exploration	96	71	275	238
	1,468	679	4,672	2,916
Changes in non-cash working capital	231	46	199	203
Cash provided by operating activities	1,699	725	4,871	3,119
Investing
Corporate acquisitions	(2,549)	-	(2,549)	-
Capital expenditures
Exploration, development and corporate	(988)	(735)	(3,206)	(2,565)
Acquisitions	(7)	(18)	(544)	(317)
Proceeds of resource property dispositions	6	70	17	75
Investments	-	4	(4)	-
Changes in non-cash working capital	136	110	142	50
Cash used in investing activities	(3,402)	(569)	(6,144)	(2,757)
Financing
Long-term debt repaid	(285)	(99)	(1,294)	(1,069)
Long-term debt issued	1,848	330	3,129	912
Short-term borrowings	-	-
Common shares issued (purchased)	(55)	(286)	(352)	(284)
Common share dividends	(63)	(56)	(125)	(114)
Deferred credits and other	(12)	(29)	(9)	164
Changes in non-cash working capital	-	(2)	(3)	(10)
Cash provided by (used in) financing activities	1,433	(142)	1,346	(401)
Effect of translation on foreign currency cash and cash equivalents	25	(4)	19	(21)
Net (decrease) increase in cash and cash equivalents	(245)	10	92	(60)
Cash and cash equivalents, beginning of period	375	28	38	98
Cash and cash equivalents, end of period	130	38	130	38

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. Change in accounting policy

Preferred securities

Effective January 1, 2005 the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants (“CICA”) accounting standard for financial instruments. The change to this standard requires that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. Previously preferred securities charges were charged directly to retained earnings but under these changes to the accounting standard they would have been charged to interest expense. In addition, since the preferred securities would have been treated as debt, the balance would have been revalued at each balance sheet date with the offsetting movement reflected in the cumulative foreign currency translation account. As a result there would not have been a gain on the redemption of the preferred securities. There was no impact to the 2005 results as the preferred securities were fully redeemed by the end of the second quarter in 2004.

The adjustment required to the December 31, 2004 Consolidated Balance Sheet to implement this change in accounting is as follows:

	As previously reported	Adjustments	As restated
Cumulative foreign currency translation	(150)	74	(76)
Retained earnings	2,244	(74)	2,170

The adjustment to the Consolidated Statement of Income for the year ended December 31, 2004 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	158	15	173
Future income tax (recovery)	(105)	(6)	(111)
Net income	663	(9)	654
Preferred securities charges, net of tax	(9)	9	-
Gain on redemption of preferred securities, net of tax	23	(23)	-
Net income available to common shareholders	677	(23)	654

Per common share (Canadian dollars)
Net income	1.77	(.06)	1.71
Diluted net income	1.74	(.06)	1.68

The adjustment to the Consolidated Statement of Income for the year ended December 31, 2003 is as follows:

	As previously reported	Adjustments	As restated
Interest on long-term debt	137	41	178
Future income tax (recovery)	(48)	(5)	(53)
Net income	1,012	(36)	976
Preferred securities charges, net of tax	(22)	22	-
Net income available to common shareholders	990	(14)	976

Per common share (Canadian dollars)
Net income	2.56	(.03)	2.53
Diluted net income	2.53	(.03)	2.50

2. Selected Cash Flow Information
	Three months ended		Years ended
	December 31		December 31
	2005	2004	2005	2004
				(restated
				note 1)
Net income	533	121	1,561	654
Items not involving cash
Depreciation, depletion and amortization	511	447	1,843	1,650
Property impairments	6	31	31	31
Dry hole	77	89	241	311
Net loss (gain) on asset disposals	(1)	28	(3)	30
Stock-based compensation	91	(10)	480	89
Future taxes and deferred petroleum revenue tax	137	(84)	215	(106)
Other	18	(14)	29	19
	839	487	2,836	2,024
Exploration	96	71	275	238
	1,468	679	4,672	2,916
Changes in non-cash working capital	231	46	199	203
Cash provided by operating activities	1,699	725	4,871	3,119

3. Segmented Information
	North America (1)				North Sea (2)				Southeast Asia and Australia (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)	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004	2005	2004
Revenue
Gross sales	1,317	812	4,129	3,115	988	659	3,320	2,385	459	291	1,527	1,120
Hedging	21	47	78	151	(1)	118	(1)	329	-	-	-	-
Royalties	261	143	816	599	19	10	56	37	174	102	553	391
Net sales	1,035	622	3,235	2,365	970	531	3,265	2,019	285	189	974	729
Other	14	14	76	62	35	6	88	23	1	-	1	-
Total revenue	1,049	636	3,311	2,427	1,005	537	3,353	2,042	286	189	975	729
Segmented expenses
Operating	131	114	478	421	247	159	859	662	29	24	87	98
Transportation	24	18	75	75	24	18	79	66	10	11	43	42
DD&A	242	227	946	785	206	179	670	661	45	32	144	174
Dry hole	46	38	122	128	15	14	53	109	4	12	11	25
Exploration	36	36	128	123	19	6	53	28	20	3	40	20
Other	(1)	34	(10)	18	14	16	54	30	1	(12)	1	(9)
Total segmented expenses	478	467	1,739	1,550	525	392	1,768	1,556	109	70	326	350
Segmented income before taxes	571	169	1,572	877	480	145	1,585	486	177	119	649	379
Non-segmented expenses
General and administrative
Interest
Stock-based compensation
Currency translation
Total non-segmented expenses
Income before taxes
Capital expenditures
Exploration	212	181	658	590	50	11	165	150	32	16	74	54
Development	261	246	879	821	253	101	867	357	45	62	231	201
Midstream	42	34	72	41	-	-	-	-	-	-	-	-
Exploration and development	515	461	1,609	1,452	303	112	1,032	507	77	78	305	255
Property acquisitions
Midstream acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment			6,985	6,214			6,072	3,074			1,465	1,050
Goodwill			291	291			1,086	75			123	100
Other			663	419			614	347			348	221
Segmented assets			7,939	6,924			7,772	3,496			1,936	1,371
Non-segmented assets
Total assets
	Three months		Years						Three months		Years
	ended		ended						ended		ended
	December 31		December 31						December 31		December 31
(1) North America	2005	2004	2005	2004	(2) North Sea				2005	2004	2005	2004
Canada	938	568	2,965	2,199	United Kingdom				775	492	2,683	1,897
US	111	68	346	228	Netherlands				18	11	56	36
Total revenue	1,049	636	3,311	2,427	Norway				202	34	604	109
Canada			6,551	5,738	Denmark				10	-	10	-
US			434	476	Total revenue				1,005	537	3,353	2,042
Property, plant and equipment			6,985	6,214	United Kingdom						4,620	2,858
					Netherlands						45	41
					Norway						1,149	175
					Denmark						258	-
					Property, plant and equipment						6,072	3,074

3. Segmented Information
	North Africa (4)					Trinidad & Tobago					Other					Total
	Three months		Years			Three months		Years			Three months		Years			Three months				Years
	ended		ended			ended		ended			ended		ended			ended				ended
	December 31		December 31			December 31		December 31			December 31		December 31			December 31				December 31
(millions of Canadian dollars)	2005	2004	2005	2004		2005	2004	2005	2004		2005	2004	2005	2004		2005		2004		2005	2004
Revenue
Gross sales	69	66	349	254		58	-	229	-		-	-	-	-		2,891		1,828		9,554	6,874
Hedging	-	-	-	-		-	-	-	-		-	-	-	-		20		165		77	480
Royalties	25	26	135	97		9	-	35	-		-	-	-	-		488		281		1,595	1,124
Net sales	44	40	214	157		49	-	194	-		-	-	-	-		2,383		1,382		7,882	5,270
Other	-	-	-	-		-	-	-	-		-	-	-	-		50		20		165	85
Total revenue	44	40	214	157		49	-	194	-		-	-	-	-		2,433		1,402		8,047	5,355
Segmented expenses
Operating	6	5	24	17		3	-	11	-		-	-	-	-		416		302		1,459	1,198
Transportation	2	3	9	9		-	-	-	-		-	-	-	-		60		50		206	192
DD&A	7	9	36	30		11	-	47	-		-	-	-	-		511		447		1,843	1,650
Dry hole	-	4	-	4		2	12	21	12		10	9	34	33		77		89		241	311
Exploration	-	-	-	-		1	3	5	21		20	23	49	46		96		71		275	238
Other	-	-	-	-		-	1	-	1		4	19	1	19		18		58		46	59
Total segmented expenses	15	21	69	60		17	16	84	34		34	51	84	98		1,178		1,017		4,070	3,648
Segmented income before taxes	29	19	145	97		32	(16)	110	(34)		(34)	(51)	(84)	(98)		1,255		385		3,977	1,707
Non-segmented expenses
General and administrative																58		64		201	183
Interest																45		38		166	173
Stock-based compensation																121		7		633	171
Currency translation																12		16		(7)	30
Total non-segmented expenses																	236		125			993	557
Income before taxes																1,019		260		2,984	1,150
Capital expenditures
Exploration	2	-	2	-		15	5	51	33		47	37	134	125		358		250		1,084	952
Development	13	1	25	8		8	34	21	158		-	-	-	-		580		444		2,023	1,545
Midstream	-	-	-	-		-	-	-	-		-	-	-	-		42		34		72	41
Exploration and development	15	1	27	8		23	39	72	191		47	37	134	125		980		728		3,179	2,538
Property acquisitions																3		36		536	330
Midstream acquisitions																-		-		-	-
Proceeds on dispositions																(7)		(74)		(22)	(88)
Other non-segmented																9		6		28	26
Net capital expenditures																985		696		3,721	2,806
Property, plant and equipment				177	178				275	182				99	149							15,073	10,847
Goodwill			4	-				-	-				-	-						1,504	466
Other			43	36				24	11				13	-						1,705	1,034
Segmented assets			224	214				299	193				112	149						18,282	12,347
Non-segmented assets																				57	61
Total assets																				18,339	12,408

	Three months		Years			Three months		Years
	ended		ended			ended		ended
	December 31		December 31			December 31		December 31
(3) Southeast Asia and Australia	2005	2004	2005	2004	(4) North Africa	2005	2004	2005	2004
Indonesia	115	80	408	346	Algeria	42	40	212	157
Malaysia	165	106	539	363	Tunisia	2	-	2	-
Vietnam	6	3	28	20	Total revenue	44	40	214	157
Australia	-	-	-	-	Algeria			162	178
Total revenue	286	189	975	729	Tunisia			15	-
Indonesia			371	327	Property, plant and equipment			177	178
Malaysia			818	701
Vietnam			23	22
Australia			253	-
Property, plant and equipment			1,465	1,050

Talisman Energy Inc.
Product Netbacks
(unaudited)

		Three months ended December 31				Twelve months ended December 31
(C$ - production before royalties)		2005	2004 (1)	2005	2004	2005	2004 (1)	2005	2004
		Oil and liquids ($/bbl)		Natural gas ($/mcf)		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	54.84	44.05	12.25	6.99	52.62	42.11	9.05	6.83
America	Hedging (gain)	4.28	8.64	-	0.04	3.99	5.95	-	0.10
	Royalties	10.69	8.76	2.46	1.20	10.79	8.59	1.80	1.31
	Transportation	0.51	0.46	0.23	0.21	0.50	0.49	0.19	0.20
	Operating costs	8.33	7.79	0.95	0.80	7.24	6.75	0.90	0.79
		31.03	18.40	8.61	4.74	30.10	20.33	6.16	4.43
North Sea	Sales price	66.53	50.26	8.35	6.08	64.78	48.29	7.08	5.55
	Hedging (gain)	(0.07)	10.02	-	-	(0.02)	7.36	-	-
	Royalties	0.84	0.52	0.48	0.37	0.71	0.43	0.49	0.42
	Transportation	1.27	1.09	0.40	0.38	1.19	1.14	0.50	0.35
	Operating costs	17.14	12.61	0.96	0.72	17.14	14.06	0.82	0.55
		47.35	26.02	6.51	4.61	45.76	25.30	5.27	4.23
Southeast	Sales price	68.30	53.81	6.72	4.55	68.79	51.29	6.40	4.74
Asia and	Royalties	27.27	21.94	1.98	1.20	27.28	21.24	1.95	1.19
Australia	Transportation	(0.12)	0.18	0.43	0.38	0.09	0.23	0.41	0.41
	Operating costs	5.04	5.60	0.30	0.25	4.48	5.57	0.30	0.27
		36.11	26.09	4.01	2.72	36.94	24.25	3.74	2.87
North Africa	Sales price	68.02	46.50	5.80	-	66.71	51.17	5.80	-
	Royalties	25.00	18.48	-	-	25.72	19.65	-	-
	Transportation	1.65	1.64	-	-	1.65	1.76	-	-
	Operating costs	5.06	3.77	-	-	4.52	3.51	-	-
		36.31	22.61	5.80	-	34.82	26.25	5.80	-
Trinidad and	Sales price	63.78	-			63.40	-
Tobago	Royalties	10.73	-			9.82	-
	Operating costs	2.45	-			2.94	-
		50.60	-			50.64	-
Total Company	Sales price	64.62	49.10	10.63	6.38	62.78	47.45	8.30	6.28
	Hedging (gain)	0.77	7.53	-	0.03	0.85	5.42	-	0.07
	Royalties	8.81	6.85	2.14	1.12	8.64	6.84	1.71	1.21
	Transportation	0.86	0.84	0.29	0.26	0.86	0.88	0.27	0.26
	Operating costs	12.25	9.84	0.82	0.67	11.81	10.32	0.76	0.66
		41.93	24.04	7.38	4.30	40.62	23.99	5.56	4.08

(1) Unit operating costs include pipeline operations for the North Sea. Prior years have been restated accordingly.
Netbacks do not include synthetic oil.

Talisman Energy Inc.
Product Netbacks (1)
(unaudited)

		Three months ended		Twelve months ended
		December 31		December 31
(US$ - production net of royalties)		2005	2004 (2)	2005	2004 (2)
North	Oil and liquids (US$/bbl)
America	Sales price	46.75	36.05	43.55	32.44
	Hedging (gain)	4.53	8.81	4.16	5.81
	Transportation	0.54	0.47	0.52	0.48
	Operating costs	8.82	7.96	7.54	6.55
		32.86	18.81	31.33	19.60
	Natural gas (US$/mcf)
	Sales price	10.44	5.74	7.51	5.26
	Hedging (gain)	-	0.04	-	0.10
	Transportation	0.25	0.21	0.20	0.19
	Operating costs	1.02	0.79	0.93	0.76
		9.17	4.70	6.38	4.21
North Sea	Oil and liquids (US$/bbl)
	Sales price	56.74	41.14	53.74	37.23
	Hedging (gain)	(0.06)	8.27	(0.02)	5.77
	Transportation	1.10	0.90	1.00	0.89
	Operating costs	14.83	10.40	14.37	10.89
		40.87	21.57	38.39	19.68
	Natural gas (US$/mcf)
	Sales price	7.13	4.99	5.88	4.29
	Transportation	0.36	0.33	0.44	0.29
	Operating costs	0.87	0.63	0.73	0.47
		5.90	4.03	4.71	3.53
Southeast Asia	Oil and liquids (US$/bbl)
and Australia	Sales price	58.25	43.93	57.24	39.49
	Transportation	(0.16)	0.25	0.12	0.30
	Operating costs	7.16	7.72	6.18	7.32
		51.25	35.96	50.94	31.87
	Natural gas (US$/mcf)
	Sales price	5.73	3.72	5.29	3.65
	Transportation	0.52	0.43	0.49	0.42
	Operating costs	0.37	0.28	0.35	0.27
		4.84	3.01	4.45	2.96
North Africa	Oil (US$/bbl)
	Sales price	58.04	38.06	55.16	39.48
	Transportation	2.22	2.22	2.22	2.20
	Operating costs	6.82	5.10	6.09	4.41
		49.00	30.74	46.85	32.87
	Natural gas (US$/mcf)
	Sales price	4.97	-	4.97	-
		4.97	-	4.97	-
Trinidad and	Oil (US$/bbl)
Tobago	Sales price	54.35	-	52.44	-
	Operating costs	2.49	-	2.86	-
		51.86	-	49.58	-
Total Company	Oil and liquids (US$/bbl)
	Sales price	55.10	40.16	52.07	36.57
	Hedging (gain)	0.76	7.15	0.82	4.90
	Transportation	0.85	0.80	0.83	0.79
	Operating costs	12.12	9.34	11.36	9.25
		41.37	22.87	39.06	21.63
	Natural gas (US$/mcf)
	Sales price	9.07	5.23	6.89	4.84
	Hedging (gain)	-	0.03	-	0.07
	Transportation	0.32	0.26	0.28	0.25
	Operating costs	0.88	0.67	0.80	0.63
		7.87	4.27	5.81	3.89

(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 North Sea. Prior years have been restated accordingly.
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
	2005	2004	2005	2004

Oil and liquids (bbls/d)
North America	43,676	43,636	42,613	43,303
North Sea	157,888	126,622	131,258	120,768
Southeast Asia and Australia	29,505	20,738	21,406	20,884
North Africa	9,558	9,235	9,449	8,338
Trinidad and Tobago	8,975	-	8,545	-
Synthetic oil (Canada)	2,743	2,748	2,587	2,868
Total oil and liquids	252,345	202,979	215,858	196,161

Natural gas (mmcf/d)
North America	725	738	733	715
North Sea	142	113	112	105
Southeast Asia and Australia	202	206	198	194
North Africa	-	-	-	-
Total natural gas	1,069	1,057	1,043	1,014

Total mboe/d	430	379	390	365

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

Continuity of Gross Proved Reserves¹
	North America²	North Sea³	Southeast Asia and Australia⁴	North Africa⁵	Trinidad and Tobago	Sudan	Total
Crude Oil and Liquids (mmbbls)
Total proved
Proved reserves at December 31, 2002	199.1	249.7	60.6	27.4	19.2	160.9	716.9
Discoveries, additions, and extensions	16.0	8.2	25.2	3.9	-	-	53.3
Purchase of reserves	1.3	21.1	-	-	-	-	22.4
Sale of reserves	(5.3)	-	-	-	-	(156.1)	(161.4)
Net revisions and transfers	(0.1)	18.7	7.6	0.1	-	-	26.3
2003 Production	(20.8)	(41.3)	(9.0)	(2.4)	-	(4.8)	(78.3)
Proved reserves at December 31, 2003	190.2	256.4	84.4	29.0	19.2	0.0	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)	24.6	3.4	(0.7)	(7.8)	-	17.3
2004 Production	(19.9)	(44.6)	(13.0)	(5.0)	-	-	(82.5)
Proved Reserves at December 31, 2004	183.0	297.0	89.1	37.2	11.4	-	617.7
Discoveries, additions, and extensions	12.6	43.9	12.7	8.6	(0.1)	-	77.7
Purchase of reserves	0.2	74.9	22.1	0.8	-	-	98.0
Sale of reserves	(0.0)	(0.9)	-	-	-	-	(0.9)
Net revisions and transfers	(2.8)	34.3	(1.3)	2.7	0.9	-	33.8
2005 Production	(19.6)	(48.4)	(12.9)	(5.6)	(3.7)	-	(90.2)
Proved reserves at December 31, 2005	173.4	400.8	109.7	43.7	8.5	-	736.1
Proved Developed
December 31, 2002	190.0	212.6	19.7	4.8	-	143.4	570.5
December 31, 2003	186.4	213.0	29.5	25.5	-	-	454.4
December 31, 2004	171.0	254.0	39.9	27.9	11.0	-	503.8
December 31, 2005	161.0	312.3	67.7	26.2	8.5	-	575.7
Natural Gas (bcf)
Total proved
Proved reserves at December 31, 2002	2,593.4	262.1	1,528.3	-	223.5	-	4,607.3
Discoveries, additions, and extensions	351.5	1.0	107.0	-	-	-	459.5
Purchase of reserves	107.1	14.4	-	-	-	-	121.5
Sale of reserves	(14.3)	-	-	-	-	-	(14.3)
Net revisions and transfers	(77.0)	17.5	(20.6)	-	-	-	(80.1)
2003 Production	(315.8)	(39.9)	(42.7)	-	-	-	(398.4)
Proved reserves at December 31, 2003	2,644.9	255.1	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)	(33.2)	(58.7)	-	(7.0)	-	(212.1)
2004 Production	(324.9)	(41.6)	(95.2)	-	-	-	(461.7)
Proved reserves at December 31, 2004	2,635.4	187.9	2,183.4	-	216.5	-	5,223.2
Discoveries, additions, and extensions	361.0	24.0	129.1	-	-	-	514.1
Purchase of reserves	16.8	61.3	38.9	1.4	-	-	118.4
Sale of reserves	(1.2)	-	-	-	-	-	(1.2)
Net revisions and transfers	28.6	14.1	(3.4)	-	(1.3)	-	38.0
2005 Production	(333.8)	(38.5)	(103.6)	-	-	-	(475.9)
Proved reserves at December 31, 2005	2,706.8	248.8	2,244.4	1.4	215.2	-	5,416.6
Proved Developed
December 31, 2002	2,278.7	232.8	723.8	-	-	-	3,235.3
December 31, 2003	2,404.0	220.1	920.9	-	-	-	3,545.0
December 31, 2004	2,207.3	160.6	858.2	-	-	-	3,226.1
December 31, 2005	2,226.5	189.7	793.2	0.9	-	-	3,210.3

Notes:

1 See oil and gas advisory.

2 North American net proved reserves exclude synthetic crude oil reserves: 2002 - 43.2 mmbls; 2003 – 42.3 mmbbls; 2004 – 41.2 mmbbls; and 2005 - 40.2 mmbbls.

3 North Sea for 2002 includes the UK and the Netherlands; for 2003 and 2004 the North Sea includes the UK, the Netherlands and Norway, but excludes Denmark.

4 Southeast Asia and Australia for 2002, 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.

5 North Africa for 2002, 2003 and 2004 includes Algeria, but excludes Tunisia.

Continuity of Net Proved Reserves ¹

	North America ²	North Sea³	Southeast Asia and Australia⁴	North Africa⁵	Trinidad and Tobago	Sudan	Total
Crude Oil and Liquids (mmbbls)
Total proved
Proved reserves at December 31, 2002	164.1	247.6	36.1	13.9	18.9	94.3	574.9
Discoveries, additions and extensions	13.1	8.3	17.0	2.3	-	-	40.7
Purchase of reserves	1.1	21.1	-	-	-	-	22.2
Sale of reserves	(4.6)	-	-	-	-	(91.7)	(96.3)
Net revisions and transfers	1.1	19.4	4.8	0.5	(0.8)	-	25.0
2003 Production	(16.4)	(41.4)	(5.4)	(0.1)		(2.6)	(65.9)
Proved reserves at December 31, 2003	158.4	255.0	52.5	16.6	18.1	(0.0)	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)	24.0	(1.3)	0.3	(7.2)	-	13.3
2004 Production	(15.8)	(44.3)	(7.9)	(3.1)	-	-	(71.1)
Proved Reserves at December 31, 2004	152.2	295.1	46.2	21.9	10.9	-	526.3
Discoveries, additions and extensions	10.6	44.4	16.4	4.7	(0.9)	-	75.2
Purchase of reserves	0.1	74.7	17.0	0.7	-	-	92.5
Sale of reserves	(0.0)	(0.9)	-	-	-	-	(0.9)
Net revisions and transfers	(5.2)	31.7	(16.0)	0.3	0.8	-	11.6
2005 Production	(15.5)	(47.9)	(7.7)	(3.5)	(3.1)	-	(77.7)
Proved Reserves at December 31, 2005	142.2	397.1	55.9	24.1	7.7	-	627.0
Proved Developed
December 31, 2002	157.2	210.8	11.9	2.4	-	84.1	466.4
December 31, 2003	155.4	211.8	18.6	14.6	-	-	400.4
December 31, 2004	142.6	252.3	19.2	16.5	10.5	-	441.1
December 31, 2005	132.0	309.0	35.8	14.6	7.7	-	499.1
Natural Gas (bcf)
Total proved
Proved reserves at December 31, 2002	1,986.1	237.9	968.9	-	220.0	-	3,412.9
Discoveries, additions and extensions	276.3	1.0	64.0	-	-	-	341.3
Purchase of reserves	92.2	14.4	-	-	-	-	106.6
Sale of reserves	(11.4)	-	-	-	-	-	(11.4)
Net revisions and transfers	(14.9)	19.8	(6.1)	-	(9.0)	-	(10.2)
2003 Production	(247.6)	(37.5)	(40.1)	-	-	-	(325.2)
Proved reserves at December 31, 2003	2,080.7	235.6	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)	(26.4)	93.5	-	5.5	-	53.4
2004 Production	(260.6)	(39.5)	(47.3)	-	-	-	(347.4)
Proved reserves at December 31, 2004	2,133.5	177.3	1,554.8	-	216.5	-	4,082.1
Discoveries, additions and extensions	274.9	23.4	81.7	-	-	-	380.0
Purchase of reserves	11.7	61.3	30.8	1.2	-	-	105.0
Sale of reserves	(1.1)	-	-	-	-	-	(1.1)
Net revisions and transfers	2.5	13.5	(94.0)	-	(2.9)	-	(80.9)
2005 Production	(265.6)	(36.2)	(73.1)	-	-	-	(374.9)
Proved reserves at December 31, 2005	2,155.9	239.3	1,500.2	1.2	213.6	-	4,110.2
Proved Developed
December 31, 2002	1,746.9	210.0	471.6	-	-	-	2,428.5
December 31, 2003	1,890.4	200.7	593.9	-	-	-	2,685.0
December 31, 2004	1,788.2	150.0	624.0	-	-	-	2,562.2
December 31, 2005	1,771.8	181.1	548.8	0.8	-	-	2,502.5

Notes:

1 See oil and gas advisory.

2 North American net proved reserves exclude synthetic crude oil reserves: 2002 - 36.7 mmbls; 2003 – 35.8 mmbbls; 2004 – 35.2 mmbbls; and 2005 - 34.3 mmbbls.

3 North Sea for 2002 includes the UK and the Netherlands; for 2003 and 2004 the North Sea includes the UK, the Netherlands and Norway, but excludes Denmark.

4 Southeast Asia and Australia for 2002, 2003 and 2004 includes Indonesia and Malaysia/Vietnam, but excludes Australia.

5 North Africa for 2002, 2003 and 2004 includes Algeria, but excludes Tunisia.