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EX-5 6 mda.htm INTERIM MD&A Q1 2004 <B>[Nice title page goes here]

MANAGEMENT’S DISCUSSION AND ANALYSIS

May 4, 2004

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Forward-looking Statements

This Management's Discussion and Analysis contains forward-looking information as contemplated by Canadian securities regulators’ Form 51-102F1 and forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking statements”). These statements include, among others, statements regarding future projects and growth, anticipated cash flow, estimated volumes and timing of future production, business plans for development and drilling, or other expectations, beliefs, plans, goals, objectives, assumptions or statements about future events or performance.

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. These risks include, but are not limited to:

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the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas);

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risks and uncertainties involving geology of oil and gas deposits;

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the uncertainty of reserve estimates;

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

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

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health, safety and environmental risks;

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uncertainties as to the availability and cost of financing;

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

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

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general economic conditions;

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

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

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and the possibility that government policies 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 Talisman's operations or financial results are included in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", and "- Outlook for 2004". Additional information may also be found in Talisman'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 Talisman's management at the time the statements are made. Talisman assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change.

Note Regarding 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”). Information about 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.

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 United States, net production volumes are reported after the deduction of these amounts.

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Management's Discussion and Analysis (MD&A)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements. All comparative percentages are between the quarters ended March 31, 2004 and 2003, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

Quarterly results summary

			Pro forma Sudan operations and gain on sale³
	Three months ended March 31,
	2004	2003(Restated)⁴	2003(Restated)⁴
Financial (millions of Canadian dollars unless otherwise stated)
Cash flow¹	779	845	769
Net income¹	223	574	234
Exploration and development expenditures	614	455	453
Per common share (dollars)
Cash flow¹– Basic	6.09	6.52	5.93
– Diluted	5.98	6.44	5.86
Net income²– Basic	1.70	4.38	1.76
– Diluted	1.67	4.33	1.74
Production (daily average production)
Oil and liquids (bbls/d)	230,136	247,369	194,487
Natural gas (mmcf/d)	1,236	1,096	1,096
Total mboe/d (6mcf=1boe)	436	430	377

Amounts are reported prior to preferred security charges of $9 million ($5 million, net of tax) for the three months ended March 31, 2004 (2003 - $10 million; $6 million, net of tax).

Per common share amounts for net income and diluted net income are reported after preferred security charges.

Pro forma is before the gain on sale of the Sudan operations in 2003 and excludes Sudan results of operations for the period January 1 to March 12, 2003 (sale closing date).

Restatement of prior year to effect retroactive adoption of the new accounting policy on asset retirement obligation as at January 1, 2004. See note 1 to the Interim Consolidated Financial Statements.

Both cash flow and net income decreased from the first quarter of 2003 primarily due to the sale of the Sudan operations in March of last year. On a pro forma basis, after removing the gain on sale and the Sudan operations, cash flow increased from $769 million to $779 million. Net income on a pro forma basis decreased slightly from $234 million to $223 million ($1.70/share) due to production gains of 16% and the benefit of tax rate reductions being more than offset by the impact of the stronger Canadian dollar and stock-based compensation charges.

On March 12, 2003, Talisman completed the sale of its indirectly held interest in the Greater Nile Oil Project for net proceeds of $1,012 million and a gain of $296 million. See note 7 to the Interim Consolidated Financial Statements.

Company Netbacks

	Three months ended March 31,
Company netbacks (including Sudan)	2004	2003	2002
Oil and liquids ($/bbl)
Sales price	41.00	44.85	31.27
Hedging expense (income)	2.67	3.14	(0.75)
Royalties	6.00	8.53	5.52
Operating costs	9.98	9.36	7.38
	22.35	23.82	19.12
Natural gas ($/mcf)
Sales price	5.89	7.48	3.55
Hedging expense (income)	0.04	0.25	(0.33)
Royalties	1.15	1.40	0.63
Operating costs	0.64	0.72	0.61
	4.06	5.11	2.64
Total ($/boe) (6mcf=1boe)
Sales price	38.32	44.86	27.41
Hedging expense (income)	1.52	2.44	(1.23)
Royalties	6.43	8.47	4.85
Operating costs	7.06	7.22	5.94
	23.31	26.73	17.85

Netbacks do not include synthetic oil and pipeline operations. Additional netback information by major product type and region is included at the end of this MD&A.

During 2004, Talisman’s netbacks averaged $23.31/boe, down from the first quarter of 2003 due mainly to the 15% increase in the value of the Canadian dollar against its US counterpart, which lowered the Canadian dollar reported commodity prices for both oil and natural gas. The Company’s royalty rate dropped 2% to 17% in the current period due to the sale of the Sudan interest. Unit operating costs decreased to $7.06/boe helped by higher production volumes from new low operating cost areas.

Revenue

Revenue for the first quarter was $1.5 billion, with oil and liquids contributing 56% and natural gas contributing 44% of revenue. The 1% increase in production, mostly from the Company’s international operations, was overshadowed by lower Canadian dollar commodity prices. More than 90% of the Company’s revenues are either received in US dollars or are closely referenced to US dollars. The Company converts these revenues to Canadian dollars for reporting purposes.

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	Three months ended March 31,
Production (daily average production)	2004	2003	2002
Oil and liquids (bbls/d)
North America	58,291	61,466	63,611
North Sea	123,245	108,759	132,718
Southeast Asia	35,602	21,360	23,034
Algeria	12,998	2,902	-
Sudan	-	52,882	58,608
	230,136	247,369	277,971
Natural gas (mmcf/d)
North America	872	870	823
North Sea	133	136	119
Southeast Asia	231	90	102
	1,236	1,096	1,044
Total mboe/d (6mcf=1boe)	436	430	452

Production highlights for the quarter include a doubling of Southeast Asia production to over 74,000 boe/d, a 13% increase in North Sea oil and liquids production and additional Algerian production from the MLN fields. These increases more than offset last year’s contribution from Sudan.

Excluding Sudan, oil and liquids production increased 18% over 2003. Current year North Sea oil and liquids production averaged 123,245 bbls/d, up 14,486 bbls/d over last year. These results reflect completion of the Halley development and minor asset acquisitions. Southeast Asia oil and liquids production in the current quarter averaged 35,602 bbls/d, up 67% from 2003 as a result of the completion of the PM-3 phase 2 project in the fourth quarter of last year. Algeria production averaged 12,998 bbls/d, up 348% from the 2,902 bbls/d in 2003, as a result of the MLN fields, which commenced production during the middle of 2003. In North America, oil and liquids production of 58,291 bbls/d was down 5% from the same quarter of last year due to natural declines and emphasis on gas.

Natural gas production averaged 1.2 bcf/d in the current quarter, up 13% from the first quarter of 2003, mainly due to Southeast Asia operations where gas production in Malaysia/Vietnam started at the end of last year and averaged 96 mmcf/d in this quarter. Indonesia increased 45 mmcf/d, a 50% increase over last year to a current quarter average of 135 mmcf/d with Corridor sales to Caltex and new sales to Singapore. The tie in of new wells in North America offset natural declines as production in 2004 increased slightly compared to last year. North Sea natural gas production decreased 3% in 2004 to 133 mmcf/d.

	Three months ended March 31,
Prices and Exchange Rates	2004	2003	2002
Oil and liquids ($/bbl)
North America	37.05	42.74	26.82
North Sea	41.55	46.14	33.87
Southeast Asia	43.91	47.08	32.84
Algeria	44.62	40.33	-
Sudan	-	43.89	29.35
	41.00	44.85	31.27
Natural gas ($/mcf)
North America	6.42	8.03	3.29
North Sea	5.63	4.93	5.04
Southeast Asia	4.08	6.09	3.96
	5.89	7.48	3.55
Total $/boe (6mcf=1boe)	38.32	44.86	27.41
Hedging loss (income)-excluded from the above prices Oil and liquids ($/bbl)	2.67	3.14	(0.75)
Natural gas ($/mcf)	0.04	0.25	(0.33)
Total $/boe (6mcf=1boe)	1.52	2.44	(1.23)
Benchmark prices and foreign exchange rates WTI (US$/bbl)	35.15	33.86	21.64
Brent (US$/bbl)	31.95	31.51	21.15
NYMEX (US$/mmbtu)	5.69	6.60	2.38
AECO (C$/GJ)	6.26	7.51	3.17
US / Canadian dollar exchange rate	0.759	0.662	0.627
Canadian dollar / pound sterling exchange rate	2.424	2.420	2.274

Excludes synthetic oil.

Talisman’s first quarter commodity price averaged $38.32/boe. Ongoing unrest in the Middle East, uncertainties over Iraqi oil supplies and continued strong demand for oil, especially in Southeast Asia contributed to a 4% increase in the WTI oil price to US$35.15, but a strengthened Canadian dollar (US$0.76 compared to US$0.66 for the same period in 2003), resulted in lower average Canadian dollar prices realized by Talisman.

During the quarter, Talisman recorded net hedging losses related to commodity based derivative financial instruments of $55 million for oil and liquids ($2.67/bbl) and $5 million for natural gas ($0.04/mcf). These hedges represented 34% of oil and liquids production, 10% of North America gas production and 22% of total boe production for the quarter. Currently, the Company has derivative and physical contracts for approximately 23% of its remaining 2004 estimated production (35% of the Company’s oil and liquids production and 13% of North American gas production). A summary of the contracts outstanding is included in notes 9 and 10 of the December 31, 2003 Consolidated Financial Statements, which has been updated in note 5 to the March 31, 2004 Interim Consolidated Financial Statements.

	Three months ended March 31,
Royalties	2004		2003		2002
	%	$ millions	%	$ millions	%	$ millions
North America	21	143	21	181	21	81
North Sea	2	9	1	4	6	27
Southeast Asia	33	75	28	39	26	27
Algeria	51	27	50	5	-	-
Sudan	-	-	46	97	39	60
	17	254	19	326	18	195

Excludes synthetic oil

Royalty expense for the first quarter was $254 million and averaged 17%, down from 19% ($326 million) in 2003. The total amount of royalties and the effective royalty rate decreased from 2003 due to the impact of the sale of the Sudan operations and lower commodity prices. This reduction in royalty rates was partially offset by increases in Southeast Asia, as a result of the payout of cost recovery pools at Corridor and production increases in Malaysia/Vietnam.

	Three months ended March 31,
Operating expenses	2004		2003		2002
	$/boe	$ millions	$/boe	$ millions	$/boe	$ millions
North America	4.96	91	5.04	92	4.41	79
North Sea	12.24	162	12.22	145	9.28	127
Southeast Asia	3.22	22	6.49	21	5.17	19
Algeria	3.51	4	6.23	2	-	-
Sudan	-	-	3.73	18	2.89	15
	7.06	279	7.22	278	5.94	240
Synthetic oil	19.00	5	22.10	5	16.71	4
Pipeline		12		11		12
		296		294		256

Operating expenses remained relatively flat at $296 million in the first quarter of 2004, as an increase in the North Sea was offset by the sale of Sudan operations. Unit operating costs decreased by 2% in 2004 due to increased production. Southeast Asia unit operating costs dropped in half as total expenses remained relatively flat with a 103% increase in boe production. Algerian unit costs were down 44% from the previous quarter due to the increase in oil production in the current quarter. North Sea operating expenses increased due to recent acquisitions, however unit costs remained relatively unchanged.

	Three months ended March 31,
DD&A	2004		2003 ¹		2002 ¹
	$/boe	$ millions	$/boe	$ millions	$/boe	$ millions
North America	9.49	176	8.99	167	8.29	150
North Sea	12.23	162	12.83	152	11.39	156
Southeast Asia	6.60	44	5.82	19	6.10	22
Algeria	6.09	7	7.90	2	-	-
Sudan	-	-	3.98	19	4.32	23
	9.81	389	9.27	359	8.63	351

Restatement of prior years to effect retroactive adoption of the new accounting policy on asset retirement obligation as at January 1, 2004. See note 1 to the Interim Consolidated Financial Statements.

The 2004 first quarter DD&A expense was $389 million, up 8% from the same quarter of 2003 as a result of increased current quarter production in Southeast Asia and Algeria at rates higher than the rates on the Sudan production sold. The North America rate increased due to additional expenditures in the US and the Vista Midstream acquisition in 2003.

Other ($ millions except where noted)	Three months ended March 31,
Other ($ millions except where noted)	2004	2003	2002
G&A ($/boe)	0.98	0.99	0.75
Dry hole expense	79	72	27
Stock-based compensation	30	-	-
Other expense (income)	3	(7)	51
Interest expense	38	40	38
Interest costs capitalized	3	7	7
Other revenue	22	23	21

Dry hole expense for the quarter was $79 million, with $31 million expensed in North America and $25 million in the North Sea, including $8 million relating to the Eta 2 redrill well and $14 million relating to the Cyrus well.

Stock-based compensation expense relates to the appreciated value of the Company’s outstanding stock options and cash units at March 31, 2004, which was first expensed during the second quarter of 2003.

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Taxes ($ millions)	Three months ended March 31,
Taxes ($ millions)	2004	2003 ¹	2002 ¹
Current income tax	51	92	51
Future income tax	15	91	(3)
Petroleum revenue tax	24	33	41
	90	216	89
Effective tax rate	23%	24%	32%

The effective tax rate is based on pre-tax income adjusted for production revenue tax, which is deductible in determining taxable income. The Company’s effective tax rate for the current quarter is lower than in 2003 due to the impact of Canadian corporate tax rate reductions of $31 million. Excluding these tax rate reductions, the effective tax rate on the Company’s income this quarter would have been 34%. The Company’s effective tax rate for last year is low due to the inclusion of the gain on the sale of the Sudan operations. Excluding the gain, the effective tax rate on the Company’s income last year would have been 39%. Current income taxes decreased in 2004, primarily due to the sale of Sudan operations and lower cash taxes at Corridor.

Capital expenditures ($ millions)	Three months ended March 31,
Capital expenditures ($ millions)	2004	2003	2002
North America	381	636	287
North Sea	119	78	148
Southeast Asia	53	80	50
Algeria	3	15	17
Sudan	-	2	25
Other	74	18	36
	630	829	563

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

North America capital expenditures include $378 million for exploration and development with the drilling of 127 gas wells and 23 oil wells. North Sea expenditures were comprised of $40 million of exploratory spending, including the Cyrus well at $14 million and development spending of $81 million at various fields. The majority of the Southeast Asia spending related to the ongoing development of PM-3 CAA in Malaysia/Vietnam, including the drilling of eight development wells. Other expenditures in the first quarter of 2004 included spending in Trinidad of $50 million, primarily progressing the Angostura development towards first oil anticipated in early 2005, and spending in Alaska of $14 million. Additional information regarding Talisman’s planned 2004 exploration and development expenditures is included in the Outlook for 2004 section of the Company’s December 31, 2003 MD&A.

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Long-term debt and liquidity

Talisman’s total debt, exclusive of the preferred securities, at March 31, 2004 was $2.4 billion ($2.0 billion, net of cash and cash equivalents) up from $2.2 billion at year end. This increase resulted primarily from the elimination of hedge accounting treatment of the US dollar cross currency and interest rate swap contracts. As a result, the 250 million pounds sterling Eurobond has been converted to Canadian dollars at current quarter end rates. Previously, this debt was converted using historical foreign exchange rates contained in the cross currency and interest rate swap contracts.

At quarter end, debt to debt plus equity was 32% (29% net of cash and cash equivalents). Had the preferred securities been classified as debt, the ratio would have been 34% (32% net of cash and cash equivalents). For the 12 months ended March 31, 2004, the debt to cash flow ratio was 0.88:1.

In February of this year, the Company redeemed one half of its outstanding Junior Subordinated Debentures. The redemption was funded from current cash flow, with the $16 million (net of tax) difference between the carrying value and the redemption cost credited to retained earnings. In March 2004, the Company gave notice of its intention to exercise its right to redeem the remaining outstanding Junior Subordinated Debentures as of June 15, 2004.

In March of this year, the Company renewed its normal course issuer bid to permit the purchase of up to 6,401,603 of its common shares, representing 5% of the total number of common shares outstanding at the time of the renewal.

In March 2004, 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, 2004 there were 128,032,078 common shares outstanding.

Asset Retirement Obligations (future site restoration and abandonment liabilities)

The Company has asset retirement obligations related to the estimated costs of future dismantlement, site restoration and abandonment of oil and gas properties, including offshore production platforms, gas plants and facilities. Effective January 1, 2004, the Company adopted, on a retroactive basis, a new accounting standard that changed the method of accruing for costs associated with the retirement of fixed assets, which an entity is legally obligated to incur. The Company has recorded the fair value of the liability for asset retirement obligations in the period incurred and a corresponding increase in the carrying amount of the related property, plant and equipment asset. See note 1 to the Interim Consolidated Financial Statements for details pertaining to this restatement and the impact on current period results of operations.

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Hedge Accounting

The Company has adopted the new accounting guideline on Hedging Relationships (AcG 13), effective January 1, 2004. This guideline, in addition to supplementing and interpreting existing hedging requirements under Canadian GAAP, established certain other conditions required before hedge accounting may be applied.

Effective January 1, 2004, the Company’s US dollar cross currency and interest rate swap contracts were no longer designated as hedges of the Eurobond, which resulted in a revaluation of this Eurobond debt and a deferred gain of $17 million, which is being amortized over the period to 2009. The swap contracts were terminated in 2004 for cash proceeds of $138 million and resulted in an additional gain of $15 million. The termination of these contracts did not accelerate the recognition of the deferred gain into income. The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales.

The Company’s long-term debt denominated in UK pounds sterling and Canadian dollars has been designated as hedges of the Company’s net investments in the UK and Canadian self-sustaining operations. Unrealized foreign exchange gains and losses resulting from the translation of this debt are included in a separate component of shareholders’ equity described as cumulative foreign currency translation.

Non-GAAP financial measures

This MD&A includes references to terms used in the oil and gas industry such as cash flow and cash flow per share. These terms are not defined by Generally Accepted Accounting Principles 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, appears as a separate caption on the Company’s cash flow statement and represents net income before exploration costs, DD&A, future taxes and other non-cash expenses.

Use of BOE equivalents

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 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.

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