Talisman Energy Inc

EX-5 6 q1mda.htm Q1 MD&A Talisman Energy Inc

MANAGEMENT’S DISCUSSION AND ANALYSIS

May 4, 2005

Forward-looking Statements

This interim Management's Discussion and Analysis ("MD & A") contains statements about expected royalty rates, the 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 2005", under the heading “Risk Factors” in the Company’s 2004 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.

Throughout this MD & A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas 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 ration 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.

Management's Discussion and Analysis (MD&A)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements as at March 31, 2005 and 2004 and the 2004 Audited Consolidated Financial Statements. All comparative percentages are between the quarters ended March 31, 2005 and 2004, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Quarterly results summary (unaudited)

	Three months ended
March 31,	2005	2004
Financial (millions of C$ unless otherwise stated)
Net income¹	258	218
Exploration and development expenditures	749	614
C$ per common share²
Net income¹– Basic	0.70	0.57
– Diluted	0.68	0.56
Production (daily average)
Oil and liquids (bbls/d)	235,492	230,136
Natural gas (mmcf/d)	1,332	1,236
Total mboe/d (6mcf=1boe)	457	436
Production(boe) per common share– Basic	0.11	0.10

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 to the Interim Consolidated Financial Statements.

Prior period per share amounts have been retroactively restated to reflect the impact of the Company’s three for one stock split. See note 1 to the Interim Consolidated Financial Statements.

Net income for the quarter increased 18% to $258 million, as the impact of this period’s improved commodity prices, 5% higher production and decreased hedging losses more than offset increases in operating expenses, depreciation, depletion and amortization, stock-based compensation and taxes.

Company Netbacks (unaudited)

	Three months ended
March 31,	2005	2004
Oil and liquids ($/bbl)
Sales price	55.40	41.15
Hedging expense	0.72	2.67
Royalties	7.41	6.00
Transportation	0.84	0.87
Operating costs	10.43	9.26
	36.00	22.35
Natural gas ($/mcf)
Sales price	6.73	6.13
Hedging expense	-	0.04
Royalties	1.37	1.15
Transportation	0.28	0.25
Operating costs	0.69	0.63
	4.39	4.06
Total $/boe (6mcf=1boe)
Sales price	48.07	39.09
Hedging expense	0.37	1.52
Royalties	7.82	6.43
Transportation	1.26	1.19
Operating costs	7.38	6.64
	31.24	23.31

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 quarter, the Company’s average netback was $31.24/boe, 34% higher than 2004. The rise in commodity prices, although partially offset by a 7% stronger Canadian dollar in relation to its US counterpart, resulted in a Company realized price of $48.07/boe which was $8.98/boe (23%) higher than in 2004. The impact of this increase in realized price, along with decreased hedging losses was reduced by increased royalties, operating costs and transportation expenses resulting in an increased netback of $7.93/boe.

Gross sales

Gross sales for the quarter ended March 31, 2005 were $2.0 billion, a 27% increase over 2004, as increased natural gas production in North America and Southeast Asia, first oil production from Trinidad and increased oil and liquids production in the North Sea and Algeria combined with higher commodity prices to more than offset the negative impact of a stronger Canadian dollar.

Daily Average Production (unaudited)

	Three months ended
March 31,	2005	2004
Oil and liquids (bbls/d)
North America	56,275	58,291
North Sea	127,882	123,245
Southeast Asia	28,969	35,602
Algeria	14,540	12,998
Trinidad	7,826	-
	235,492	230,136
Natural gas (mmcf/d)
North America	929	872
North Sea¹	129	133
Southeast Asia	274	231
	1,332	1,236
Total mboe/d (6mcf=1boe)	457	436

Includes gas acquired for injection and subsequent resale of 8 mmcf/d in both 2005 and 2004

The Company’s average oil and liquids production for the quarter was 235 mbbls/d, up 2% compared to last year. In Trinidad, first oil came on production in January of 2005 and during the quarter, in spite of some early facilities constraints, averaged 7,826 bbls/d, exiting the quarter at a March monthly average of 12,025 bbls/d. In the North Sea, oil and liquids production averaged 127,882 bbls/d, up 4% from 2004 as production increases from development drilling and asset acquisitions over the past year were partially offset by the impact of maintenance work which shut down the Ross/Blake field for over a month. During the quarter, the Company completed the acquisition of the Varg field producing assets in Norway,. Southeast Asia oil and liquids production in the current quarter averaged 28,969 bbls/d, down 6,633 bbls/d or 19% from 2004 due to the expiry of the Tanjung and Jambi contracts. Oil and liquid production in Malaysis/Vietnam was up 984 bbls/d or 5% from 2004. Algeria production averaged 14,540 bbls/d, up 12% from 2004 despite a two week planned shutdown of the MLN facilities in the current quarter. In North America, oil and liquids production averaged 56,275 bbls/d during the quarter, down 3% from 2004 due to natural declines and the Company’s continued focus on natural gas.

During the quarter, natural gas production averaged a record 1.3 bcf/d, 8% above last year, mainly due to production increases in both North America and Southeast Asia. In North America, natural gas production was 929 mmcf/d, an increase of 57 mmcf/d or 7% over last year, with production increases in Appalachia, up 68 mmcf/d to 120 mmcf/d, Monkman, up 25 mmcf/d to 108 mmcf/d, and Bigstone/Wild River, up 11 mmcf/d to 102 mmcf/d more than offsetting decreases resulting from natural declines in other areas. In Southeast Asia, natural gas production was 274 mmcf/d, an increase of 43 mmcf/d or 19% over last year. Production in Malaysia/Vietnam averaged 119 mmcf/d this quarter, an increase of 23 mmcf/d. Indonesia gas production increased 15% over last year averaging 155 mmcf/d with higher Corridor sales to Caltex and to Singapore. North Sea natural gas production decreased 3% during the quarter to 129 mmcf/d.

Prices and Exchange Rates (unaudited)

	Three months ended
March 31,	2005	2004
Oil and liquids ($/bbl)
North America	46.50	37.56
North Sea	57.29	41.55
Southeast Asia	60.35	44.10
Algeria	60.90	44.62
Trinidad	57.78	-
	55.40	41.15
Natural gas ($/mcf)
North America	7.07	6.61
North Sea	6.98	5.85
Southeast Asia	5.44	4.50
	6.73	6.13
Total $/boe (6mcf=1boe)	48.07	39.09
Hedging loss not included in the above prices Oil and liquids ($/bbl)	0.72	2.67
Natural gas ($/mcf)	-	0.04
Total $/boe (6mcf=1boe)	0.37	1.52
Benchmark prices and foreign exchange rates WTI (US$/bbl)	50.03	35.15
Brent (US$/bbl)	47.62	31.95
NYMEX (US$/mmbtu)	6.32	5.69
AECO (C$/gj)	6.34	6.26
US/Canadian dollar exchange rate	0.815	0.759
Canadian dollar / pound sterling exchange rate	2.319	2.424

Excludes synthetic oil

Talisman’s first quarter commodity price averaged $48.07/boe, up $8.98/boe or 23% from last year. Continuing strong demand, especially in China and India, contributed to crude oil’s price remaining at near record levels. Although the average benchmark price of WTI oil, at US$ 50.03 per barrel, was 42% higher than 2004, the stronger Canadian dollar and the wider heavy oil differentials limited the increase in the Company’s realized price to 35% over the same period last year, at $55.40/bbl of oil and liquids.

Although the AECO reference price increased only 1% from last year, the proportion of the Company’s North American gas sales in the US increased from 6% last year to 13% of sales in the current quarter, which resulted in a 7% increase in North America natural gas prices to $7.07/mcf during the quarter.

For the quarter ended March 31, 2005, Talisman recorded net hedging losses on commodity based derivative financial instruments of $15 million, all associated with oil and liquids ($0.72/bbl), compared to losses of $55 million for oil and liquids ($2.67/bbl) and $5 million for natural gas ($0.04/mcf) during the same period in 2004. As of April 1, 2005, the Company has derivative and physical contracts for approximately 2% of its remaining 2005 estimated production. A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2004 Consolidated Financial Statements and in note 7 to the March 31, 2005 Interim Consolidated Financial Statements.

Royalties¹(unaudited)

	Three months ended
March 31,	2005		2004²
	%	$ millions	%	$ millions
North America	20	166	20	143
North Sea	1	10	2	9
Southeast Asia	37	109	32	75
Algeria	40	32	51	27
Trinidad	11	4	-	-
	16	321	17	254

Royalty rates do not include synthetic oil

During the second quarter of 2004, the Company reclassified transportation costs on a retroactive basis. Previously, these costs had been partially netted off against realized prices. This change reduced the royalty rate which is a percentage of reported prices. Accordingly, 2004 royalty rates have been restated. See note 1 to the Interim Consolidated Financial Statements.

The Company’s royalty expense for the first quarter was $321 million (16%), up from $254 million (17%), in 2004. Total royalty expense increased as a result of increases in both commodity prices and production, as the royalty rate remained relatively constant. In Southeast Asia, the rate increased due to the impact of the payout of cost recovery pools at Corridor during the first quarter of 2004. In addition rates for oil in Malaysia/Vietnam are tied to recently attained cumulative production threshold levels, which increased the rate to 34% from 32%. The Algeria royalty rate decreased as a portion of the revenue stream is allocated to profit oil, which increases the Algeria taxes payable while reducing the Company’s effective royalty rate. The Algerian government’s total take for the quarter including royalties and taxes equalled approximately 51%, similar to 2004 when no current taxes were payable. The 51% total government take is expected to continue for the next few years.

Operating Expense (unaudited)

	Three months ended
March 31,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	5.16	98	4.96	91
North Sea	13.19	177	11.16	148
Southeast Asia	2.63	18	3.20	22
Algeria	5.64	7	1.71	2
Trinidad	4.00	3	-	-
	7.38	303	6.64	263
Synthetic oil	40.36	7	19.00	5
Pipeline		14		12
		324		280

During the first quarter, total operating expenses increased by $44 million to $324 million, with the North Sea comprising $29 million of the 16% total increase from last year primarily related to the addition of the Varg production. Unit operating costs averaged $7.38/boe, up from $6.64/boe last year. North Sea unit operating costs increased $2.03/boe to $13.19/boe, due in part to maintenance costs from the extended shutdown at Ross/Blake and higher unit costs associated with the Varg field in Norway. In North America, unit operating costs increased due to higher processing fees and operational maintenance. Unit operating costs in Southeast Asia were down 18% to $2.63/boe due to increased production from Malaysia/Vietnam. Algeria unit operating costs increased due to minor adjustments related to prior periods in each of the reported quarters.

Transportation Expenses (unaudited)

Effective in the second quarter of 2004, the Company began accounting for transportation costs as expenses, on a retroactive basis. Previously, these costs had been either netted off against the realized price or included as a component of operating costs, depending on the circumstances in the various geographic segments. Prior year comparatives have been restated to reflect this change in accounting policy. See note 1 to the Interim Consolidated Financial Statements for further details. The reclassification has no impact on cash provided by operating activities or net income. The resulting transportation expenses for 2004 and comparable results for the current year are set forth in the table below:

	Three months ended
*March 31,*	2005		2004
*Oil and liquids*	$/bbl	$millions	$/bbl	$millions
North America	0.45	3	0.51	3
North Sea	1.14	13	1.11	13
Southeast Asia	0.08	-	0.25	1
Algeria	1.65	2	1.79	2
Natural gas	$/mcf		$/mcf
North America	0.17	14	0.20	15
North Sea	0.54	6	0.37	4
Southeast Asia	0.55	14	0.42	9
		52		47

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

	Three months ended
March 31,	2005		2004
	$/boe	$ millions	$/boe	$ millions
North America	12.04	228	9.49	176
North Sea	12.16	164	12.23	162
Southeast Asia	4.57	31	6.60	44
Algeria	6.80	9	6.09	7
Trinidad	13.33	9	-	-
	10.71	441	9.81	389

The 2005 first quarter DD&A expense was $441 million, up 13% from the same quarter of 2004, due to an increase in the per unit DD&A rate and higher production. The DD&A rate in North America increased primarily due to higher drilling costs and capital expenditures on infrastructure projects. The DD&A rate and total expense for Southeast Asia decreased as a result of the increase in reserves, primarily from Corridor, as total boe production remained relatively constant.

Other ($ millions except where noted) (unaudited)

March 31,	Three months ended
March 31,	2005	2004
G&A ($/boe)	1.22	0.98
Dry hole expense	46	79
Stock-based compensation	166	30
Other expense (income)	24	3
Interest costs capitalized	2	3
Interest expense	42	47
Other revenue	36	22

General and administrative (G&A) expense increased over the same quarter of last year due to higher staff costs, increased costs associated with corporate governance initiatives, and higher legal and pension costs.

Dry hole expense for the first quarter of 2005 was $46 million, $17 million of which was expensed in the North Sea for the North Saltire and Jenny wells. In North America dry hole expense was $18 million and included $9 million for the Sukunka a-37-J well. Other expense of $24 million included a write-down related to the North Saltire property of $23 million. Other revenue of $36 million included $29 million of pipeline and processing revenue.

Stock-based compensation expense relates to the increase in value of the Company’s outstanding stock options and cash units at March 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. The $166 million expense for the current quarter is due in part to 1.5 million options being exercised for cash at an average share price of $40.08 and an average exercise price of $17.09 for a cash expense of $35 million. The remaining $131 million expense for the current quarter is a result of a 28% increase in the Company’s share price in the current quarter and the corresponding impact on the mark to market liability of the vested and prorated vested options and cash units outstanding.

Since the introduction of the cash feature, approximately 98% of options that have been exercised, have been exercised for cash, resulting in reduced dilution of shares.

Taxes ($ millions) (unaudited)

Effective Income Tax Rate

March 31,	Three months ended
March 31,	2005	2004¹
Income before taxes	489	304
Less PRT Current Deferred	33 10	17 7
Total PRT	43	24
	446	280
Income tax expense
Current income tax	185	51
Future income tax	3	11
Total income tax expense	188	62
Effective income tax rate	42%	22%

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 2004 due to the effect of increased taxable income in higher tax jurisdictions (e.g. Norway) during the current quarter and the impact of Canadian corporate tax rate reductions of $31 million in 2004. Excluding this adjustment, the effective tax rate on the Company’s income in the first quarter of 2004 would have been 33%. During 2005, current tax increased to $185 million as a result of both higher commodity prices and increased production, which also increased PRT on North Sea operations.

Capital expenditures ($ millions) (unaudited)

	Three months ended
March 31,	2005	2004
North America	461	381
North Sea	407	119
Southeast Asia	76	53
Algeria	2	3
Trinidad	15	50
Other	20	24
	981	630

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 $173 million and development of $279 million, included the drilling of 111 gas wells and 14 oil wells and $9 million for net asset acquisitions. Expenditures in the North Sea during the first quarter were comprised of $22 million of exploration spending, development spending of $162 million, which included the ongoing development of the Tweedsmuir field and $223 million primarily related to the acquisition of producing assets at Varg and extensive exploration acreage in Norway. In Southeast Asia, capital expenditures of $76 million included $14 million of exploration spending and development spending of $62 million, primarily on the South Angsi field development in Block PM-305 and ongoing development on Block PM 3. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2005 section of the Company’s December 31, 2004 MD&A.

Long-term debt and liquidity

At March 31, 2005, Talisman’s long-term debt was $2.9 billion, up from $2.5 billion at year-end. This increase resulted primarily from the repurchase of eight million common shares and the acquisition of the Varg assets in Norway, partially offset by cash provided by operating activities in excess of exploration and development capital expenditures.

At quarter end, debt to debt plus book equity was 38%. For the 12 months ended March 31, 2005, the debt to cash provided by operating activities ratio was 0.93:1.

During the first quarter of this year, the Company repurchased a total of 8,016,400 common shares under its normal course issuer bid (NCIB) at an average price of $37.35/share. In March of this year, the Company renewed its NCIB to permit the purchase of up to 18,437,285 common shares, representing 5% of the total common shares outstanding at the time of the renewal. 949,200 common shares of the total were repurchased under the renewed NCIB.

In May 2004, the Company implemented a three for one split of its issued and outstanding common shares. All per share statistics for 2004 have been restated to reflect this share split. As at March 31, 2005, there were 367,231,290 common shares outstanding, the same number as at April 30, 2005.

During April 2005, stock options for 423,550 shares were exercised for cash.

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

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)
	2005	2004				2003
	March 31	Dec. 31	Sept. 30	June 30	March 31	Dec. 31	Sept. 30	June 30
Gross sales	1,977	1,827	1,788	1,705	1,554	1,351	1,272	1,220
Total revenue	1,677	1,401	1,355	1,337	1,262	1,128	1,077	1,023
Net income ^{1, 2}	258	121	122	193	218	104	121	190
Per common share amounts (Cdn dollars)
Net income ^{1, 2}	0.70	0.32	0.32	0.50	0.57	0.27	0.31	0.49
Diluted net income ^{1, 2}	0.68	0.31	0.31	0.50	0.56	0.27	0.31	0.48

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, 2005.

During the first quarter of 2005, revenue 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 the 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, revenue increased over the previous quarter as increases in total volumes combined with higher gas prices to more than offset the impact of a stronger Canadian dollar and increased hedging losses. Net income remained relatively constant in the quarter 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, revenue rose over the second quarter 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 first two quarters of 2004, revenue continued to rise due to increases in both commodity prices and production. These factors combined with the benefit of tax rate reductions to increase net income in the first quarter of 2004 over the last quarter of 2003. A higher charge for stock-based compensation and lower tax rate reductions resulted in a slight drop in net income during the second quarter of 2004 from the previous quarter.

Net income during the second quarter of 2003 increased by $160 million due to a reduction in the Canadian federal and provincial tax rates. The Company began recording stock-based compensation in the second quarter. The second quarter’s net income was reduced by a $105 million ($70 million after tax) catch-up expense relating to outstanding stock options. The third and fourth quarters of 2003 included an additional $80 million ($50 million after tax) of stock-based compensation expense.

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), which will be effective for the reporting year-end 2007. 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. It is expected that 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 does not currently have any hedges in place that carry into 2006 so the impact would not be significant based on the current positions.

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 lawsuit 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. In December 2004, Talisman filed a motion for judgment on the pleadings, seeking dismissal of the lawsuit on the grounds that the Court lacks subject matter jurisdiction to hear the lawsuit, and filed its opposition papers to the certification of the lawsuit as a class action. On March 25, 2005, the Court refused to certify the lawsuit as a class action. On March 15, 2005, the US Department of Justice submitted a Statement of Interest to the Court expressing the US Government's view that the lawsuit interferes with US-Canada relations. The Court subsequently asked the litigants to file submissions in relation to this development. It is uncertain when the Court will make a decision in relation to these matters. Talisman believes the lawsuit to be entirely without merit and is continuing to vigorously defend itself and does not expect the lawsuit to have a material adverse effect.

Kyoto

The Kyoto protocol, ratified by the Canadian Federal Government in December 2002, came into force on February 16, 2005. The protocol commits Canada to reducing greenhouse gas emissions to six percent below 1990 levels over the period 2008-2012. The Federal Government released a framework outlining its Climate Change action plan on April 13, 2005. The plan as released contains few technical details regarding the implementation of the Government's greenhouse gas reduction strategy. The Climate Change Working Group of Canadian Association of Petroleum Producers continues to work with the Federal and Alberta governments to develop an approach for implementing targets and enabling greenhouse gas control legislation, which protects the industry's competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.

As the federal government has yet to release a detailed Kyoto compliance plan, Talisman is unable to predict the impact of potential regulations upon its business; however, it is possible that the Company would face increases in operating costs in order to comply with the greenhouse gas emissions legislation.

Use of BOE equivalents

Unless otherwise stated references to production represent Talisman’s working interest share (including royalty interests and net prior to interest) 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

		Three months ended		Three months ended
		March 31		March 31
(C$ - production before royalties)		2005	2004	2005	2004
		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	46.50	37.56	7.07	6.61
America	Hedging (gain)	3.10	3.07	-	0.06
	Royalties	9.87	7.57	1.39	1.32
	Transportation	0.45	0.51	0.17	0.19
	Operating costs	6.32	5.90	0.79	0.77
		26.76	20.51	4.72	4.27
North Sea	Sales price	57.29	41.55	6.98	5.85
	Hedging (gain)	-	3.55	-	-
	Royalties	0.43	0.13	0.47	0.66
	Transportation	1.14	1.11	0.54	0.37
	Operating costs	14.55	12.86	0.86	0.28
		41.17	23.90	5.11	4.54
Southeast	Sales price	60.35	44.10	5.44	4.50
Asia	Hedging (gain)	-	-	-	-
	Royalties	25.27	17.82	1.75	0.81
	Transportation	0.08	0.25	0.55	0.42
	Operating costs	4.08	4.78	0.28	0.29
		30.92	21.25	2.86	2.98
Algeria	Sales price	60.90	44.62
	Hedging (gain)	-	-
	Royalties	24.53	22.59
	Transportation	1.65	1.80
	Operating costs	5.64	1.71
		29.08	18.52
Trinidad	Sales price	57.78	-
	Hedging (gain)	-	-
	Royalties	6.38	-
	Operating costs	4.00	-
		47.40	-
Total Company	Sales price	55.40	41.15	6.73	6.13
	Hedging (gain)	0.72	2.67	-	0.04
	Royalties	7.41	6.00	1.37	1.15
	Transportation	0.84	0.87	0.28	0.25
	Operating costs	10.43	9.26	0.69	0.63
		36.00	22.35	4.39	4.06


Netbacks do not include synthetic oil or pipeline operations.

Talisman Energy Inc.
Additional Information for US Readers
Product Netbacks
		Three months ended
		March 31
(US$ - production net of royalties)		2005	2004
North	Oil and liquids (US$/bbl)
America	Sales price	37.93	28.50
	Hedging (gain)	3.22	2.90
	Transportation	0.46	0.48
	Operating costs	6.54	5.62
		27.71	19.50
	Natural gas (US$/mcf)
	Sales price	5.76	5.02
	Hedging (gain)	-	0.06
	Transportation	0.17	0.19
	Operating costs	0.80	0.73
		4.79	4.04
North Sea	Oil and liquids (US$/bbl)
	Sales price	46.76	31.52
	Hedging (gain)	-	2.68
	Transportation	0.94	0.84
	Operating costs	12.00	9.79
		33.82	18.21
	Natural gas (US$/mcf)
	Sales price	5.69	4.44
	Hedging (gain)	-	-
	Transportation	0.48	0.31
	Operating costs	0.76	0.24
		4.45	3.89
Southeast Asia	Oil and liquids (US$/bbl)
	Sales price	49.26	33.47
	Hedging (gain)	-	-
	Transportation	0.11	0.32
	Operating costs	5.72	6.08
		43.43	27.07
	Natural gas (US$/mcf)
	Sales price	4.44	3.41
	Hedging (gain)	-	-
	Transportation	0.67	0.39
	Operating costs	0.34	0.27
		3.43	2.75
Algeria	Oil (US$/bbl)
	Sales price	49.73	33.87
	Hedging (gain)	-	-
	Transportation	2.26	2.76
	Operating costs	7.70	2.66
		39.77	28.45
Trinidad	Oil (US$/bbl)
	Sales price	47.11	-
	Hedging (gain)	-	-
	Operating costs	3.61	-
		43.50	-
Total Company	Oil and liquids (US$/bbl)
	Sales price	45.22	31.23
	Hedging (gain)	0.68	2.35
	Transportation	0.79	0.77
	Operating costs	9.84	8.20
		33.91	19.91
	Natural gas (US$/mcf)
	Sales price	5.49	4.66
	Hedging (gain)	-	0.04
	Transportation	0.29	0.24
	Operating costs	0.72	0.58
		4.48	3.80
Netbacks do not include synthetic oil or pipeline operations.