<B>Exploration and Operations Review

EX-99 3 f1qmda.htm EXHIBIT 99.2 - 1Q INTERIM MD&A <B>Exploration and Operations Review

INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

May 9, 2006

Forward-looking Statements

This interim MD & A contains statements regarding anticipated asset dispositions, estimated timing of production, the proposed impact of UK legislation, expected royalty rates and taxes, the Company’s outlook for major projects, impact of new accounting pronouncements, outcome of litigation, or other expectations, beliefs, plans, goals, objectives, assumptions and statements about future events or performance that constitute "forward-looking statements" or “forward-looking information” within the meaning of applicable securities legislation.

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 the Company 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;

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

uncertainties related to the litigation process, such as possible discovery of new evidence or acceptance of novel legal theories and the 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);

•

general economic conditions;

•

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

•

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

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 in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", "- Liquidity and Capital Resources", and "- Outlook for 2006", under the heading “Risk Factors” in the Company’s 2005 annual information form as well as 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 – Oil and Gas Information

Throughout this MD & A, 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 U.S., net production volumes are reported after the deduction of these amounts.

You may read any document Talisman furnishes to the SEC at the SEC's public reference rooms at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549 and 500 West Meridian Street, Suite 1400, Chicago, Illinois 60661. You may also obtain copies of the same documents from the public reference room of the SEC at 450 Fifth Street, N.W., Washington D.C. 20549 by paying a fee. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms.

Management’s Discussion and Analysis (MD&A)

(May 9, 2006)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements as at March 31, 2006 and 2005 and the 2005 Audited Consolidated Financial Statements. All comparative percentages are between the quarters ended March 31, 2006 and 2005, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

During the first quarter of 2006, changes were made to the reporting segments, with reclassifications made to the corresponding comparative period. The United Kingdom and Scandinavia, which were reported in aggregate as the North Sea in 2005, are reported separately in 2006. The reporting segment entitled “Other” for 2006 includes North Africa (Algeria and Tunisia) and Trinidad and Tobago, which were reported separately in 2005.

The Company intends to dispose of between 10,000 – 15,000 boe/d of production from non-core assets in Western Canada and the UK during 2006. The impact of these sales will become clearer once the sales process has progressed further.

Quarterly Results Summary (unaudited)

	Three months ended
March 31,	2006	2005
Financial (millions of C$ unless otherwise stated)
Net income	197	258
Exploration and development expenditures	1,203	749
C$ per common share
Net income– Basic	0.54	0.70
– Diluted	0.52	0.68
Production (daily average)
Oil and liquids (bbls/d)	299,977	235,492
Natural gas (mmcf/d)	1,338	1,332
Total mboe/d (6mcf=1boe)	523	457
Production(boe) per common share– Basic	0.13	0.11

Net income for the quarter decreased 24% to $197 million, due to the impact of a $325 million UK income tax rate increase on petroleum profits from 40% to 50%, which was recorded during the first quarter of 2006. This one time non-cash adjustment, combined with increases in royalties, operating expenses, depreciation, depletion and amortization and taxes to more than offset the impact of this period’s improved commodity prices, higher production and a decreased charge for stock-based compensation.

Company Netbacks (unaudited)¹

	Three months ended
March 31,	2006	2005
Oil and liquids ($/bbl)
Sales price	67.85	55.40
Hedging loss	0.09	0.72
Royalties	9.39	7.41
Transportation	1.01	0.84
Operating costs	11.71	10.85
	45.65	35.58
Natural gas ($/mcf)
Sales price	8.52	6.73
Hedging (gain)	(0.10)	-
Royalties	1.73	1.37
Transportation	0.30	0.28
Operating costs	0.84	0.69
	5.75	4.39
Total $/boe (6mcf=1boe)
Sales price	60.66	48.07
Hedging (gain) loss	(0.22)	0.37
Royalties	9.81	7.82
Transportation	1.34	1.26
Operating costs	8.84	7.59
	40.89	31.03

1. Netbacks do not include synthetic oil and pipeline operations. Additional netback information by major product type and region is included elsewhere in this interim report.

During the first quarter, the Company’s average netback was $40.89/boe, which was $9.86/boe or 32% higher than in 2005. The rise in commodity prices, although partially offset by a 6% stronger Canadian dollar in relation to its US counterpart, resulted in a Company realized price of $60.66/boe, which was 26% higher than in 2005. The impact of this $12.59/boe increase in realized price, in addition to hedging gains in the quarter, was partly reduced by increased royalties, operating costs and transportation expenses.

Gross sales for the quarter ended March 31, 2006 were $2.9 billion, a 46% increase over 2005, as increased production combined with higher commodity prices to more than offset the negative impact of a stronger Canadian dollar. Production increased 14% over the prior year, due in part to the Paladin acquisition in late 2005, which yielded increased production of both oil and liquids and natural gas in Scandinavia, Southeast Asia and Australia, and the United Kingdom.

Daily Average Production, before Royalties (unaudited)

	Three months ended
March 31,	2006	2005
Oil and liquids (bbls/d)
North America	56,177	56,275
United Kingdom¹	123,862	112,251
Scandinavia¹	39,529	15,631
Southeast Asia and Australia¹	51,845	28,969
Other¹	28,564	22,366
	299,977	235,492
Natural gas (mmcf/d)
North America	894	929
United Kingdom ²	145	120
Scandinavia	16	9
Southeast Asia and Australia	283	274
	1,338	1,332
Total mboe/d (6mcf=1boe)	523	457

Includes oil volumes transferred into (out of) inventory as at March 31, 2006 of (4,399) bbls/d, (1,648) bbls/d, (1,139) bbls/d and 780 bbls/d in the United Kingdom, Scandinavia, Southeast Asia and Australia, and Other, respectively.

Includes gas acquired for injection and subsequent resale of 14 mmcf/d and 8 mmcf/d in 2006 and 2005, respectively.

The Company’s average oil and liquids production for the quarter was 299,977 bbls/d, up 64,485 bbls/d or 27% from last year. In North America, oil and liquids production averaged 56,177 bbls/d during the quarter, relatively unchanged from 2005. In the United Kingdom, oil and liquids production averaged 123,862 bbls/d, up 11,611 bbls/d or 10% from 2005, due to production increases from asset acquisitions over the past year and development drilling, which more than offset the impact of natural declines. The Montrose/Arbroath property, acquired with the Paladin acquisition, added 12,056 bbls/d during the quarter. Development drilling at Clyde resulted in oil and liquids production of 16,321 bbls/d (up 36%) and at the Ross/Blake field, production was 19,872 bbls/d, up 69% from the corresponding period of 2005, when a shutdown stopped production for over a month. In Scandinavia, oil and liquids production increased more than 150% from last year, averaging 39,529 bbls/d. Production from the Varg field (acquired in February of last year) averaged 12,524 bbls/d, up from 6,563 bbls/d in 2005. The acquired Brage assets produced an average of 8,058 bbls/d during the quarter. The Veslefrikk and Siri fields (acquired through the Paladin acquisition) produced an average of 6,321 bbls/d and 3,808 bbls/d, respectively, during 2006. In Southeast Asia and Australia, oil and liquids production averaged 51,845 bbls/d, up 22,875 bbls/d or 79% over 2005. In Indonesia, production increased 66%, to average 11,378 bbls/d. The acquisition of the SE Sumatra field yielded 4,421 bbls/d of the total increase of 4,523 bbls/d. Oil and liquids production in Malaysia/Vietnam was 35,306 bbls/d, up 13,191 bbls/d or 60% from 2005 due to the commencement of production at PM-305 in the second half of last year. Assets acquired in Australia at the end of 2005 averaged 5,161 bbls/d during the quarter. Production from Other areas increased 28%, averaging 28,564 bbls/d, due to a full quarter of production from Trinidad which averaged 11,461 bbls/d (where production commenced during the first quarter of 2005). In Algeria production averaged 16,174 bbls/d, up 11% from 2005, when it was impacted by a plant turnaround at the MLN facilities. Production from the acquired assets in Tunisia produced an average of 929 bbls/d during the quarter.

During the quarter, natural gas production remained constant at an average of 1.3 bcf/d, as natural declines in North America were offset by additional production volumes in the United Kingdom and Scandinavia. In North America, natural gas production was 894 mmcf/d, a decrease of 35 mmcf/d or 4% from last year. Talisman currently has approximately 100 mmcf/d of natural gas behind pipe, temporarily shut-in or awaiting tie-in. In the United Kingdom, natural gas production was 145 mmcf/d, an increase of 25 mmcf/d or 21% over last year, resulting from the acquisition of the Goldeneye property, which was acquired as part of the Paladin purchase in late 2005. In Scandinavia, natural gas production averaged 16 mmcf/d, an increase of 7 mmcf/d over last year. In Southeast Asia and Australia, natural gas production was 283 mmcf/d, an increase of 9 mmcf/d or 3% over last year. Production in Malaysia/Vietnam averaged 87 mmcf/d this quarter, a decrease of 31 mmcf/d or 26% due to lower demand from the buyer in both January and February of this year, coupled with the impact of higher demand from the buyer in March 2005. Indonesia gas production increased 26% over last year, averaging 196 mmcf/d, with higher Corridor sales to Caltex and to Singapore Power, in addition to the Offshore NW Java property, acquired through the Paladin purchase.

In the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted and sold to third parties. Volumes transferred into and out of inventory for the period ended March 31, 2006, have been separately identified in footnote 1 to the Daily Average Production Volumes table above.

Prices and Exchange Rates (unaudited)

	Three months ended
March 31,	2006	2005
Oil and liquids ($/bbl)
North America	49.58	46.50
United Kingdom	71.01	56.69
Scandinavia	73.42	61.59
Southeast Asia and Australia	73.49	60.35
Other	70.43	59.81
	67.85	55.40
Natural gas ($/mcf)
North America	8.79	7.07
United Kingdom	10.11	7.14
Scandinavia	3.51	4.82
Southeast Asia and Australia	7.08	5.44
	8.52	6.73
Total $/boe (6mcf=1boe)	60.66	48.07
Hedging (gain) loss, not included in the above prices Oil and liquids ($/bbl)	0.09	0.72
Natural gas ($/mcf)	(0.10)	-
Total $/boe (6mcf=1boe)	(0.22)	0.37
Benchmark prices and foreign exchange rates WTI (US$/bbl)	63.48	50.03
Brent (US$/bbl)	61.79	47.62
NYMEX (US$/mmbtu)	9.08	6.32
AECO (C$/gj)	8.79	6.34
US/Canadian dollar exchange rate	0.87	0.82
Canadian dollar / pound sterling exchange rate	2.02	2.32

Excludes synthetic oil

Talisman’s first quarter commodity price averaged $60.66/boe, up $12.59/boe or 26% from last year. During the quarter, the average WTI oil price was US$63.48 per barrel, 27% higher than 2005. The Company’s realized price of $67.85/bbl was 22% higher than last year due to the stronger Canadian dollar and the impact of wider differentials in Canada.

The AECO reference price increased 39% from last year, which is partially reflected in the 24% increase in North America natural gas prices to $8.79/mcf during the quarter.

For the quarter ended March 31, 2006, Talisman recorded net hedging gains on commodity based derivative financial instruments of $10 million, associated with gains on natural gas of $0.10/mcf, which more than offset losses on oil and liquids of $0.09/bbl, compared to losses of $15 million for oil and liquids ($0.72/bbl) during the same period in 2005. As of April 1, 2006, the Company has derivative and physical contracts for approximately 5% of its remaining 2006 estimated production. A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2005 Consolidated Financial Statements and in note 8 to the March 31, 2006 Interim Consolidated Financial Statements.

Royalties¹(unaudited)

	Three months ended
March 31,	2006		2005
	%	$ millions	%	$ millions
North America	21	198	20	166
United Kingdom	2	16	2	10
Scandinavia	0	1	-	-
Southeast Asia and Australia	37	195	37	109
Other	28	50	30	36
	16	460	16	321

Royalty rates do not include synthetic oil

The Company’s royalty expense for the first quarter was $460 million (16%), up $139 million from $321 million (16%), in 2005. This 43% increase in the total royalty expense is the result of increases in both commodity prices and production. In North America, the rate increased slightly, to 21%, as a result of new production in areas with price sensitive rates. The decrease in Other rates from 30% to 28%, was due primarily to a higher proportion of production from Trinidad, where the royalty rate averaged 16% in 2006.

Operating Expenses and Unit Operating Costs (unaudited)

	Three months ended
March 31,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	6.55	119	5.16	98
United Kingdom	14.03	183	13.51	152
Scandinavia	17.33	68	16.51	25
Southeast Asia and Australia	3.70	33	2.63	18
Other	3.43	8	5.07	10
	8.84	411	7.59	303
Synthetic oil	37.11	9	40.36	7
Pipeline		16		14
		436		324

During the first quarter, total operating expenses increased by $112 million to $436 million, primarily due to increased volumes associated with assets acquired during 2005. In North America, unit operating costs increased 27% to $6.55/boe due to increases in processing charges, maintenance and power costs. In the UK, total operating costs increased 20% or $31 million, to $183 million, due mainly to the impact of assets acquired last year, increased fuel costs and higher maintenance costs at Claymore. In Scandinavia, operating costs rose $43 million, to $68 million as a result of the prior year acquisitions. Acquisitions accounted for $9 million of the $15 million increase in operating costs in Southeast Asia and Australia, to $33 million. The commencement of production from Block PM-305 in Malaysia in August of last year accounted for an additional $3 million of this total 83% increase.

Transportation Expenses (unaudited)

	Three months ended
*March 31,*	2006		2005
	$/boe	$millions	$/boe	$millions
North America	1.16	22	0.86	17
United Kingdom	1.51	20	1.43	17
Scandinavia	2.24	8	1.61	2
Southeast Asia and Australia	1.20	11	2.06	14
Other	0.93	2	1.08	2
	1.34	63	1.26	52

During the current quarter, transportation expense increased 21% to $63 million due to increases in both production and rates.

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

	Three months ended
March 31,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	13.67	252	12.04	228
United Kingdom	12.16	162	11.37	136
Scandinavia	18.82	72	18.28	28
Southeast Asia and Australia	6.50	58	4.57	31
Other	8.87	23	9.09	18
	12.04	567	10.71	441

The 2006 first quarter DD&A expense was $567 million, up 29% from the same quarter of 2005, due to an increase in the per unit DD&A rate and higher production. The DD&A rate in North America increased 14% to 13.67/boe, due to higher drilling costs and increased capital expenditures on infrastructure projects in addition to increased land amortization costs. The total DD&A expense in the UK increased 19%, to $162 million, as a result higher production and costs associated with the prior year’s acquisitions. In Scandinavia, total DD&A charges increased $44 million to $72 million, due to the increased production and costs related to the acquisitions in 2005. The DD&A rate and total expense for Southeast Asia and Australia increased by 42% and 87%, respectively, due to the impact of the new production from Block PM-305 in Malaysia. In Other, the DD&A charge increased 28% to $23 million, as a result of increased production in Algeria and Trinidad, in addition to the impact of new production in Tunisia from the Paladin acquisition.

Other ($ millions except where noted) (unaudited)

March 31,	Three months ended
March 31,	2006	2005
G&A ($/boe)	1.26	1.22
Dry hole expense	64	46
Stock-based compensation	46	166
Other expense	24	24
Interest costs capitalized	13	2
Interest expense	52	42
Other revenue	44	36

General and administrative (G&A) expense increased over the same quarter of last year due mainly to additional personnel and salary increases. On a per unit basis, G&A was $1.26/boe, up 3% from the corresponding period in 2005.

Dry hole expense for the first quarter of 2006 was $64 million, with $18 million in North America, $6 million in the UK, $7 million in Scandinavia and $25 million in Other. A $10 million charge for insurance premiums and $8 million related to the UK Windfarm are included in Other expense of $24 million. Other revenue of $44 million included $39 million of pipeline and processing revenue. Interest expense increased over the prior year as a result of the increased level of debt over the same period of last year. Capitalized interest expense is associated with the Tweedsmuir, Wood and Blane development projects in the UK. Tweedsmuir and Wood are scheduled to come on production during the first quarter of 2007 and Blane is scheduled to come on production in the second quarter of 2007.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units as at March 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. Over the quarter, $46 million was expensed in 2006, of which $68 million was cash and $(22) million non-cash. Over the course of the quarter, the average exercise price of all outstanding options increased from $26.14 per share to $31.19 per share, with a total of 23.2 million options outstanding at March 31, 2006. See note 5 to the March 31, 2006 Interim Consolidated Financial Statements.

Since the introduction of the cash feature, approximately 97% of options that have been exercised, have been exercised for cash, with only 3% exercised for shares, resulting in virtually no dilution of shares.

Taxes ($ millions) (unaudited)

Effective Income Tax Rate

March 31,	Three months ended
March 31,	2006	2005
Income before taxes	1,095	489
Less PRT Current Deferred	92 (2)	33 10
Total PRT	90	43
	1,005	446
Income tax expense
Current income tax	332	185
Future income tax	476	3
Total income tax expense	808	188
Effective income tax rate	80%	42%

The effective tax rate is expressed as a percentage of pre-tax income adjusted for Petroleum Revenue Tax (PRT), which is deductible in determining taxable income. The Company’s effective tax rate for the current quarter is higher than in 2005 due primarily to the impact of a $325 million UK income tax rate increase on petroleum profits from 40% to 50%. Exclusive of this one time non-cash adjustment, the current quarter’s effective rate is 48%. Higher revenues from increased production and prices combined with increased taxable income in higher tax jurisdictions (e.g. Norway) and the 10% increase in UK tax rates resulted in higher current taxes during the current quarter. Increased commodity prices and production in the UK also increased PRT.

In the second quarter of 2006, the Company expects to record a $67 million gain in reduced future taxes, related to reductions of the Alberta and Saskatchewan provincial tax rates.

In the UK, proposed legislation would provide the Company with the option to elect to defer 2005 capital expenditure claims for tax purposes to 2006 or later, which at a higher tax rate, would result in an estimated reduction of approximately $75 million in current taxes. Details surrounding this proposed legislation continue to be clarified and the Company expects the legislation to become law later this year. The Company is currently evaluating the impact of this legislation and expects to make a decision once the law is passed.

Capital Expenditures ($ millions) (unaudited)

	Three months ended
March 31,	2006	2005
North America	721	461
United Kingdom	268	169
Scandinavia	52	238
Southeast Asia and Australia	60	76
Other	100	37
	1,201	981

Capital expenditures include exploration and development expenditures and net asset acquisitions but exclude administrative capital.

North America capital expenditures for the current quarter on exploration of $306 million and development of $416 million, included the drilling of 128 net gas wells and 15 net oil wells and $1 million for net asset dispositions. Expenditures in the UK during the first quarter were comprised of $11 million of exploration spending and development spending of $257 million, which included the ongoing development of the Tweedsmuir, Wood, Enoch and Blane fields. In Scandinavia, the Company spent $31 million on exploration, $22 million on development and $1 million for net asset dispositions. In Southeast Asia and Australia, capital expenditures of $60 million included $16 million of exploration spending and development spending of $44 million, primarily on the Suban Phase 2 project and ongoing development on PM-3 CAA. In Other, the Company spent $16 million on development activities in North Africa, $10 million on exploration and $10 million on development in Trinidad, $51 million on exploration in Alaska and $13 million on exploration activities in the rest of the world. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2006 section of the Company’s December 31, 2005 MD&A.

Long-term Debt and Liquidity

At March 31, 2006, Talisman’s long-term debt was $4.3 billion, the same as at year-end, although the cash balance at period end increased by $314 million, as cash provided from operating activities was greater than cash used in investing and financing activities.

During the quarter, the Company completed a US$500 million offering of 5.85% notes due February 1, 2037 and a $350 million offering of 4.44% notes due January 27, 2011. Interest on both notes is payable semi-annually. The proceeds were used to repay a portion of the outstanding Paladin acquisition credit facility. The $350 million notes were immediately swapped into US dollars, the Company’s functional currency, whereby the Company entered into a cross currency interest rate swap in order to hedge the foreign exchange exposure on this Canadian dollar denominated liability. As a result, the Company is effectively paying interest semi-annually at a rate of 5.05% on a notional amount of US$304 million.

In connection with the funding of the acquisition of Paladin in 2005, the Company arranged a $2.6 billion (₤1.3 billion), unsecured non-revolving credit facility. At March 31, 2006, $976 million was drawn on this facility. Subsequent to the end of the current quarter, total borrowings under this facility were reduced to $680 million. This repayment was financed through a combination of cash on hand and draws under the Company’s revolving credit facilities. The remaining amount outstanding under this facility must be repaid by October 2006. This is expected to be funded from a combination of excess cash provided by operating activities, draws on existing credit facilities and proceeds of net asset dispositions.

At quarter end, debt to debt plus book equity was 42%. For the 12 months ended March 31, 2006, the debt to cash provided by operating activities ratio was 0.79:1.

In March of this year, the Company renewed its normal course issuer bid (NCIB) with the Toronto Stock Exchange (TSX). Pursuant to the NCIB, the Company may purchase for cancellation up to 18,313,400 of its common shares (representing 5% of the 366,267,990 common shares outstanding as at March 21, 2006), during the 12 month period commencing March 28, 2006 and ending March 27, 2007. The price that the Company will pay for shares acquired under the NCIB will be the market price at the time of purchase or such other price as may be permitted by the TSX. A copy of the Notice of Intention to Make a Normal Course Issuer Bid may be obtained without charge from Talisman.

In March 2006, the Company announced plans to implement a three-for-one share split of its issued and outstanding common shares. The decision has been approved by Talisman’s Board of Directors and is subject to shareholder and regulatory approval.

As at March 31, 2006 there were 366,271,590 common shares outstanding, increasing to 366,286,390 at May 3, 2006.

As at March 31, 2006 there were 23,237,439 stock options and 2,936,710 cash units outstanding. During April and May of 2006, 412,177 stock options were exercised for cash, 14,800 stock options were exercised for shares, 11,450 stock options were granted and 14,625 were cancelled, with 22,807,287 stock options outstanding at May 3, 2006. Subsequent to March 31, 2006, 66,824 cash units were exercised, with 2,869,886 cash units outstanding at May 3, 2006.

Talisman’s investment grade senior unsecured long-term debt credit ratings from Dominion Bond Rating Service (“DBRS”), Moody’s Investor Service, Inc. (“Moody’s”) and Standard & Poor’s (“S&P”) are BBB (high), Baa2 (stable) and BBB+ (with a negative outlook), respectively.

Talisman continually investigates strategic acquisitions and opportunities, some of which may be material. In connection with any such transactions, the Company may incur debt or issue equity.

Sensitivities

Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated impact of these factors on the Company’s financial performance for the remainder of 2006 is summarized in the following table and is based on an average WTI oil price of US$64.60/bbl, a NYMEX natural gas price of US$7.75/mmbtu and exchange rates of C$1=US$0.86 and £1=C$2.04.

Approximate Impact for 2006³ (millions of dollars)	Net Income	Cash Provided by Operating Activities
Volume changes
Oil – 1,000 bbls/d	7	14
Natural gas – 10 mmcf/d	8	15
Price changes¹
Oil – US$1.00/bbl	48	72
Natural gas (North America)² – C$0.10/mcf	14	19
Exchange rate changes
US$ increased by US$0.01	43	81
£ increase by C$0.025	(4)	(3)

The impact of commodity contracts outstanding as of April 1, 2006 has been included.

Price sensitivity on natural gas relates to North American natural gas only. The Company’s exposure to changes in the UK, Scandinavia and Malaysia/Vietnam natural gas prices is not material. Most of the Indonesia natural gas price is based on the price of crude oil and accordingly has been included in the price sensitivity for oil except for a small portion, which is sold at a fixed price.

Assumes a decision is taken later this year to defer 2005 UK capital expenditure claims for tax purposes to 2006.

Summary of Quarterly Results (millions of Cdn. dollars unless otherwise stated)

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

	Three months ended (unaudited)
	2006	2005				2004
	March 31	Dec. 31	Sept. 30	June 30	March 31	Dec. 31	Sept. 30	June 30
Gross sales	2,877	2,891	2,606	2,080	1,977	1,828	1,788	1,705
Total revenue	2,471	2,433	2,189	1,748	1,677	1,402	1,355	1,337
Net income ¹	197	533	430	340	258	121	122	193
Per common share amounts (Cdn dollars)
Net income ¹	0.54	1.45	1.17	0.93	0.70	0.32	0.32	0.50
Diluted net income ¹	0.52	1.42	1.14	0.91	0.68	0.31	0.31	0.50

Net income and net income before discontinued operations and extraordinary items are the same.

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters ended March 31, 2006.

In the first quarter of 2006, gross sales decreased by $14 million over the previous quarter due to decreased natural gas prices in North America. Net income for the quarter decreased by $336 million, primarily due to the impact of a one time non-cash adjustment of $325 million related to a UK income tax rate increase.

During the fourth quarter of 2005, gross sales rose by $285 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea. Net income for the quarter increased by $103 million, as the increased revenue combined with reduced stock-based compensation charges to more than offset the impact of increases in operating, depreciation, depletion and amortization, royalty and tax expenses.

During the third quarter of 2005, higher commodity prices and production increased gross sales by $526 million. Net income for the quarter increased by $90 million, as the increased revenue more than offset the impact of increases in stock-based compensation, royalty and tax expenses.

In the second quarter of 2005, gross sales rose due to increased commodity prices, which were partially offset by reduced production. Net income increased in the quarter as higher revenue combined with reductions in stock-based compensation charges, transportation and other expenses more than offset the impact of increases in operating costs, royalties, taxes, dry hole costs and exploration expenses.

During the first quarter of 2005, gross sales rose over the last quarter of 2004, as a result of higher commodity prices, increased production and reduced hedging losses. Net income increased in the quarter as increased revenue combined with reductions in dry hole costs, exploration expenses, impairments, DD&A and G&A to more than offset the impact of increases in stock-based compensation charges, royalties, operating costs and taxes.

During the fourth quarter of 2004, gross sales increased due to higher volumes and gas prices, which more than offset the impact of a stronger Canadian dollar and increased hedging losses. Net income remained relatively constant as reductions in stock-based compensation, operating expenses and dry hole costs were offset by increases in DD&A, impairments and G&A expenses as well as a loss on disposal of fixed assets.

In the third quarter of 2004, gross sales rose as the increase in oil prices more than offset the reduction in production, resulting from maintenance shutdowns. Net income in the third quarter declined from the previous quarter, as the increase in revenue was more than offset by increases in hedging losses, dry hole costs, exploration expenses and current income taxes. In the second quarter of 2004, gross sales continued to rise due to increases in both commodity prices and production, partially offset by increased hedging losses. A higher charge for stock-based compensation and reduced tax rate reductions resulted in a drop in net income during the second quarter of 2004 from the previous quarter.

New Canadian Accounting Pronouncements

The Canadian Institute of Chartered Accountants (CICA) has issued a number of accounting pronouncements, some of which may impact the Company’s reported results and financial position in future periods.

Comprehensive Income / Financial Instruments / Hedges

The CICA issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments (CICA 3855) and Hedges (CICA 3865). The new standards will bring Canadian rules in line with current rules in the US. The standards will introduce the concept of “Comprehensive Income” to Canadian GAAP and will require that an enterprise (a) classify items of comprehensive income by their nature in a financial statement and (b) display the accumulated balance of comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to comprehensive income and be brought into net income at the time the underlying hedged item is settled. This standard will be effective for Talisman’s 2007 reporting. Any instruments that do not qualify for hedge accounting will be marked-to-market with the adjustment (tax effected) flowing through the income statement.

Talisman has hedges in place that carry into 2007 and beyond, and the impact is being reviewed for significance on the statements.

Risks and Uncertainties

Litigation

Talisman continues to be subject to a lawsuit brought by the Presbyterian Church of Sudan and others commenced in November 2001 under the Alien Tort Claims Act in the United States District Court for the Southern District of New York (the Court). The lawsuit, which is seeking class action status, alleges that the Company conspired with, or aided and abetted, the Government of Sudan to commit violations of international law in connection with the Company's now disposed of interest in oil operations in Sudan. On August 30, 2005, the Court denied Talisman's motion for Court approval to appeal the Court's prior denial of Talisman's motion for judgment on the pleadings, which sought dismissal of the lawsuit. Also on August 30, 2005, the Court declined to dismiss the lawsuit in response to the filing of a Statement of Interest by the US Department of Justice, expressing the US Government's view that the lawsuit interferes with US-Canada relations. On September 20, 2005, the Court denied, for the second time, the plaintiffs' motion to certify the lawsuit as a class action. On October 5, 2005, the plaintiffs filed papers to appeal the decision denying class action status. The Company has filed papers opposing the plaintiffs’ appeal. On April 28, 2006 the Company filed a Motion for Summary Judgment, requesting the Court to dismiss the lawsuit or, alternatively, to restrict the plaintiffs' claims to factual disputes supported by admissible evidence. Talisman believes the lawsuit is entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Use of BOE equivalents

Unless otherwise stated, references to production represent Talisman’s working interest share (including royalty interests and net profits interests) before deduction of royalties. Throughout the MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas 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 approximate energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Additional information related to the Company can be found on SEDAR at www.sedar.com.

Talisman Energy Inc.
Product Netbacks
(unaudited)

		Three months ended March 31
(C$ - production before royalties)		2006	2005	2006	2005
		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	49.58	46.50	8.79	7.07
America	Hedging loss (gain)	-	3.10	(0.16)	-
	Royalties	10.60	9.87	1.81	1.39
	Transportation	0.59	0.45	0.23	0.17
	Operating costs	7.76	6.32	1.02	0.79
		30.63	26.76	5.89	4.72
United	Sales price	71.01	56.69	10.11	7.14
Kingdom	Hedging loss	0.21	-	-	-
	Royalties	0.69	0.50	0.67	0.50
	Transportation	1.38	1.24	0.36	0.41
	Operating costs	15.86	14.93	0.78	0.93
		52.87	40.02	8.30	5.30
Scandinavia	Sales price	73.42	61.59	3.51	4.82
	Royalties	0.32	-	-	-
	Transportation	1.55	0.45	2.04	2.33
	Operating costs	18.51	18.05	-	-
		53.04	43.09	1.47	2.49
Southeast	Sales price	73.49	60.35	7.08	5.44
Asia and	Royalties	29.97	25.27	2.12	1.75
Australia	Transportation	0.22	0.08	0.38	0.55
	Operating costs	5.22	4.08	0.34	0.28
		38.08	30.92	4.24	2.86
Other	Sales price	70.43	59.81	-	-
	Royalties	20.08	18.18	-	-
	Transportation	0.93	1.08	-	-
	Operating costs	3.44	5.07	-	-
		45.98	35.48	-	-
Total Company	Sales price	67.85	55.40	8.52	6.73
	Hedging loss (gain)	0.09	0.72	(0.10)	-
	Royalties	9.39	7.41	1.73	1.37
	Transportation	1.01	0.84	0.30	0.28
	Operating costs	11.71	10.85	0.84	0.69
		45.65	35.58	5.75	4.39

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

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

		Three months ended
		March 31
(US$ - production net of royalties)		2006	2005
North	Oil and liquids (US$/bbl)
America	Sales price	42.93	37.93
	Hedging loss	-	3.22
	Transportation	0.65	0.46
	Operating costs	8.55	6.54
		33.73	27.71
	Natural gas (US$/mcf)
	Sales price	7.62	5.76
	Hedging (gain)	(0.17)	-
	Transportation	0.25	0.17
	Operating costs	1.11	0.80
		6.43	4.79
United Kingdom	Oil and liquids (US$/bbl)
	Sales price	61.49	46.25
	Hedging loss	0.18	-
	Transportation	1.21	1.02
	Operating costs	13.87	12.27
		46.23	32.96
	Natural gas (US$/mcf)
	Sales price	8.76	5.82
	Transportation	0.33	0.36
	Operating costs	0.72	0.81
		7.71	4.65
Scandinavia	Oil and liquids (US$/bbl)
	Sales price	63.59	50.47
	Transportation	1.35	0.38
	Operating costs	16.11	16.35
		46.13	35.31
	Natural gas (US$/mcf)
	Sales price	3.04	3.94
	Transportation	1.77	1.90
		1.27	2.04
Southeast Asia	Oil and liquids (US$/bbl)
and Australia	Sales price	63.65	49.26
	Transportation	0.32	0.11
	Operating costs	7.63	5.72
		55.70	43.43
	Natural gas (US$/mcf)
	Sales price	6.13	4.44
	Transportation	0.47	0.67
	Operating costs	0.42	0.34
		5.24	3.43
Other	Oil (US$/bbl)
	Sales price	60.81	48.88
	Transportation	1.12	1.26
	Operating costs	4.08	5.95
		55.61	41.67

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

		Three months ended
		March 31
(US$ - production net of royalties)		2006	2005
Total Company	Oil and liquids (US$/bbl)
	Sales price	58.74	45.22
	Hedging loss	0.09	0.68
	Transportation	1.02	0.80
	Operating costs	11.81	10.22
		45.82	33.52
	Natural gas (US$/mcf)
	Sales price	7.37	5.49
	Hedging (gain)	(0.11)	-
	Transportation	0.32	0.29
	Operating costs	0.91	0.72
		6.25	4.48

(1) Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty volumes. Unit operating costs include pipeline operations for the United Kingdom. Netbacks do not include synthetic oil.