CALGARY, Alberta - November 26, 1998 -

6-K 1 f332002tlm3qresults.htm TALISMAN THIRD QUARTER RESULTS CALGARY, Alberta - November 26, 1998 -

N E W S R E L E A S E

Talisman Three Month Cash Flow $657 Million

$1.9 Billion Year to Date

Company Announces Sudan Sale

CALGARY, Alberta – October 30, 2002 – Talisman Energy Inc. reported third quarter cash flow of $657 million ($4.87/share), an increase of 12% over a year ago and up 1% on the previous quarter. Production averaged 438,000 boe/d, an increase of 4% over the third quarter of 2001 and down 3% over the second quarter.

Net income was $151 million ($1.08/share), an increase of 25% compared to $121 million ($0.86/share) a year ago and $90 million ($0.62/share) in the previous quarter. Realized commodity prices were up 6% versus the same quarter last year.

“Third quarter numbers have come in as expected and show continued financial strength. With our announced sale of Sudan, strong financial results and ongoing exploration success, Talisman is well positioned to continue to generate growth in shareholder value,” said Dr. Jim Buckee, President and Chief Executive Officer. “We are committed to delivering at least 5-10% growth in production per share this year, next year and in the future, through successful execution of our business plan and significant share repurchases.

“In 2003, we expect 5% growth on a comparable basis, with or without Sudan, to be accomplished largely through share repurchases. We will start buying back shares right away using our existing normal course issuer bid. New production from Algeria and Malaysia later in 2003 should generate 5-10% organic growth in 2004.”

Operating Summary

•

Talisman today announced the sale of its Sudan assets for C$1.2 billion, with the sale expected to close on or about December 31, 2002.

•

The J-1 discovery in the North Sea tested at 6,600 bbls/d. The discovery is estimated to contain 40-70 mmbbls of oil in place.

•

In the North Sea, the Blake Flank pilot development was approved and is scheduled to start production in the third quarter of 2003.

•

Production from the Halley field commenced in July, averaging 8,900 boe/d for the quarter.

•

The second Appalachian gas well in the northeast United States was non-commercial.

•

Talisman plans to drill its first exploration well in Utah in the fourth quarter.

•

Successful drilling increased Alberta Foothills production 29% above 2001. The Company has added significantly to its landholdings in the Foothills.

•

The Monkman deep well commenced production in September and a follow-up well will spud in November.

•

In Malaysia, PM-3 Commercial Agreement Area development is on budget and on schedule for production startup in September 2003. The first two wellhead towers are in place and development drilling has started.

•

Talisman drilled a successful oil appraisal well at Bunga Kekwa in Malaysia, enhancing exploration prospects in the area.

Management’s Discussion and Analysis (MD&A)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements. The calculation of barrels of oil equivalent (boe) is based on a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil equivalent. All comparative percentages are between the quarters ended September 30, 2002 and September 30, 2001, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

	Three months ended September 30			Nine months ended September 30
	2002	2001		2002	2001
Financial (millions of Canadian dollars unless otherwise stated)
Cash flow^1&4	657	587		1,886	1,992
Net income^{1 & 3}	151	121		342	693
Exploration and development expenditures	443	489		1,391	1,337
Per common share (dollars)
Cash flow^1&4– Basic	4.87	4.35		14.03	14.72
– Diluted	4.80	4.28		13.78	14.45
Net income^{2 & 3}– Basic	1.08	0.86		2.41	5.00
– Diluted	1.06	0.85		2.36	4.90
Production (daily average production)
Oil and liquids (bbls/d)	267,393	258,190	273,467		241,006
Natural gas (mmcf/d)	1,024	986	1,039		986
Total boe/d (6mcf=1boe)	437,865	422,459	446,665		405,406

Amounts are reported prior to preferred security charges of $11 million ($6 million, net of tax) for the three months ended September 30, 2002 (2001 - $10 million; $5 million, net of tax).

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

Comparative 2001 net income and related per share amounts have been restated in accordance with a new CICA accounting standard (see Accounting Changes).

Cash flow is a Non-GAAP measure and represents net income before exploration costs, DD&A, future taxes and other non-cash expenses.

Cash flow for the quarter ended September 30, increased 12% to $657 million ($4.87/share) with a 4% (15,400 boe/d) increase in production and a 12% increase in liquids prices, more than offsetting a 9% decrease in natural gas prices and higher operating costs. Net income for the quarter increased to $151 million ($1.08/share). Cash flow for the first nine months was $1.9 billion, consistent with $2 billion in 2001. Net income for the first nine months of 2002 has been reduced compared to 2001 due largely to a one time second quarter non-cash adjustment related to a legislated increase in the UK corporate tax rate ($128 million) and the Kildrummy impairment in the North Sea recorded in the first quarter ($32 million, net of tax).

	Three months ended September 30		Nine months ended September 30
Production (daily average production)	2002	2001	2002	2001
Oil and liquids (bbls/d)
Canada	61,266	65,845	62,632	66,250
North Sea	124,106	116,696	128,577	102,665
Southeast Asia	21,976	21,307	22,500	19,531
Sudan	60,045	54,342	59,758	52,560
	267,393	258,190	273,467	241,006
Natural gas (mmcf/d)
Canada	809	810	817	797
North Sea	122	88	126	98
Southeast Asia	93	88	96	91
	1,024	986	1,039	986
Total boe/d (6mcf=1boe)	437,865	422,459	446,665	405,406

Both liquids and natural gas production are up 4% from a year ago with growth coming from the North Sea and Sudan. Compared to the second quarter, production is down 3%, mostly in the North Sea with small reductions in other areas. Production for the remainder of 2002 is expected to average between 440,000 and 450,000 boe/d.

North Sea liquids production is up 6% or 7,410 bbls/d during the quarter compared to last year but is down 4% compared to the second quarter. Halley commenced production in July and contributed 7,800 bbls/d during the third quarter (8,900 boe/d including gas). Hannay, which commenced production in March 2002, averaged 2,900 bbls/d during the third quarter, up 20% from the second quarter, although production continued to be impacted by operational issues. The Ross/Blake core area averaged 26,609 bbls/d, up 23% from 2001 with the inclusion of Blake, however, production during the quarter was temporarily reduced due to water treatment issues, now resolved, which contributed to a drop of 4,049 bbls/d for the core area compared to the second quarter. Production from Beatrice for the quarter averaged 6,493 bbls/d, up 75% compared to 2001. Beatrice in 2001 did not include production for the full quarter. Tartan is down 3,476 bbls/d from last year and 4,818 bbls/d from the second quarter mainly due to a planned shut-down. Natural decline and maintenance at other fields also contributed to the drop from the second quarter.

Liquids production in Canada is down 7% from a year ago due to minor non-core property dispositions and natural declines, partially offset by development drilling at Chauvin and other core areas.

Southeast Asia liquids production averaged 21,976 bbls/d due to the inclusion of production from Malaysia/Vietnam PM3 CAA (5,211 bbls/d) which offset natural declines in the Indonesian blocks. Indonesian production averaged 16,765 bbls/d for the quarter, with declines mitigated by a successful fracture stimulation program at Tanjung.

Sudan production increased 10% due to facilities enhancements, increased pipeline capacity, additional use of electrical submersible pumps, pipeline drag reducing agents and ongoing development drilling.

Natural gas production for the quarter in Canada averaged 809 mmcf/d with ongoing development drilling offsetting minor non-core property dispositions, production declines, the impact of routine scheduled plant maintenance, infrastructure constraints and delays experienced in bringing on new production. Production for the quarter is down from the second quarter due to increased plant turnarounds some of which were timed to coincide with the planned Peace Pipeline shutdown.

North Sea natural gas production for the quarter is up 39% from last year due to a temporary increase in pipeline capacity available to Talisman and the acquisition of Lundin Oil’s interest in the Brae field. Production is down 11% from the second quarter primarily at Brae as the Company’s temporary access to incremental pipeline capacity was curtailed. A shutdown at K4/K5 contributed to the reduced production.

Southeast Asia natural gas production is dependent on demand from Caltex, currently the only purchaser of gas from Corridor. During the third quarter, production averaged 93 mmcf/d with OK Block (8 mmcf/d) offsetting the drop in demand from Caltex. Natural gas production from OK Block commenced at the end of the first quarter. As a result of the sales to Caltex declining below their minimum commitment of approximately 100 mmcf/d, Talisman recorded $6 million of deferred revenue during the quarter ($19 million for the nine months). Caltex demand is expected to remain at the current level for the remainder of 2002.

	Three months ended September 30		Nine months ended September 30
Netbacks	2002	2001	2002	2001
Oil and liquids ($/bbl)
Sales price	39.64	35.33	35.77	36.76
Hedging expense (income)	0.63	(0.04)	(0.01)	0.07
Royalties	6.66	6.18	6.16	6.98
Operating costs	8.89	6.96	7.81	7.10
	23.46	22.23	21.81	22.61
Natural gas ($/mcf)
Sales price	3.32	3.66	3.64	5.88
Hedging expense (income)	(0.30)	(0.18)	(0.26)	0.13
Royalties	0.51	0.66	0.60	1.35
Operating costs	0.72	0.58	0.65	0.59
	2.39	2.60	2.65	3.81
Total $/boe	19.87	19.63	19.50	22.69

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.

World oil prices are up from a year ago and have been increasing throughout 2002 to approximately US$30/bbl. Talisman’s crude oil prices increased 12% year-over-year compared to an increase of 6% in WTI over the same period benefiting from a change in North Sea oil production mix and narrowing crude differentials.

Talisman’s natural gas price in Canada decreased 8% compared to the third quarter of 2001 and is down 42% on a year to date basis compared to 2001. During the quarter, Canadian natural gas prices were down relative to NYMEX due primarily to reduced availability of export pipeline capacity. This differential is expected to narrow during the fourth quarter. The change in Talisman’s Canadian natural gas price during the quarter was partially mitigated by fixed price contracts. A summary of fixed price contracts outstanding is included in Note 5 to the Interim Consolidated Financial Statements. North Sea natural gas prices decreased 8% from a year ago on lower spot prices but increased slightly from the second quarter of 2002. Southeast Asia natural gas prices are tied to oil prices in that gas production is exchanged for Duri Crude based on its energy value. An adjustment to Corridor’s gas price relating to prior periods decreased the quarter’s Southeast Asia reported natural gas price by $0.88/mcf. Corridor’s gas price for the fourth quarter is expected to return to a level more closely tied to the price of crude oil.

The strengthening oil prices during the quarter resulted in $15 million ($0.63/bbl) of losses on oil hedges. The decrease in North American gas prices resulted in a $28 million ($0.30/mcf) gain on financial gas hedges for the quarter. These results compare to $1 million ($0.04/bbl) and $16 million ($0.18/mcf) of gains on oil and gas hedges in the third quarter of 2001. See Note 5 to the Interim Consolidated Financial Statements for a summary of derivative contracts outstanding.

As a result of the CICA deferring the Accounting Guideline on Hedging Relationships, the Company will continue to record the cash payments and receipts on its three-way collars as part of hedging activities.

	Three months ended September 30		Nine months ended September 30
Average royalty rates (%)	2002	2001	2002	2001
Canada	19	21	19	25
North Sea	5	6	5	5
Southeast Asia	29	21	27	21
Sudan	32	35	36	40
	16	18	17	21

The average royalty rate for the Company decreased, compared to last year, primarily as a result of lower natural gas prices in Canada. Southeast Asia royalties increased due to the depletion of a cost recovery pool at Tanjung and the inclusion of production from PM3 CAA, which has a royalty rate of 31%. Royalties in Sudan are impacted by price changes, production levels and the timing of expenditures. The overall royalty rate in the North Sea averaged 5% with a small drop in liquids royalties offsetting a natural gas rate increase. The natural gas royalty rate in the North Sea increased to 15% as a result of the acquisition of Lundin Oil’s carried interest in the Brae field. In conjunction with the change in UK fiscal terms, the UK announced its intention to abolish government royalties at a date to be determined in the future.

	Three months ended September 30		Nine months ended September 30
Operating costs ($/boe)	2002	2001	2002	2001
Canada	4.90	4.18	4.48	4.23
North Sea	11.47	9.00	9.74	9.13
Southeast Asia	6.58	5.26	5.81	5.16
Sudan	4.07	2.78	3.85	3.46
	7.11	5.60	6.28	5.66

Canadian operating costs averaged $4.90/boe, up 17% from the third quarter of 2001, with unit costs of $5.91/bbl (2001- $5.12/bbl) for liquids and $0.74/mcf (2001 $0.62/mcf) for natural gas. Unit operating costs increased in the third quarter due to plant turnarounds, phasing of costs and general industry cost pressures.

North Sea unit operating costs increased to $11.47/boe for the quarter due mainly to higher maintenance expenditures and the strengthening of the UK pound sterling versus the Canadian dollar. Liquids operating costs averaged $12.74/bbl up from $9.92/bbl in 2001. Increased maintenance and well workovers at Tartan and Claymore contributed $1.17/bbl to the increase. The strengthening UK pound increased liquids unit operating costs by $0.88/bbl. Production from Halley and Hannay helped mitigate the unit cost increases during the quarter.

Southeast Asia unit operating costs averaged $0.69/mcf for natural gas (2001 $0.50/mcf) and $8.30/bbl for liquids (2001 $6.82/bbl). Higher overhead allocations from the operator of Corridor caused natural gas unit costs to increase in 2002. A turnaround at Tanjung contributed $1.00/bbl to the higher liquids operating costs. Operating costs at PM3 CAA in Malaysia were $8.32/bbl.

Sudan unit operating costs averaged $4.07/bbl due to the increase in use of production enhancing measures such as drag reducing agents and electrical submersible pumps.

Exploration and Development Expenditures ($ millions)	Three months ended September 30		Nine months ended September 30
	2002	2001	2002	2001
Canada	181	241	613	648
North Sea	106	154	360	467
Southeast Asia	76	35	181	69
Sudan	32	37	78	88
Other	48	22	159	65
	443	489	1,391	1,337

Exploration and development expenditures totalled $1.4 billion for the first nine months of 2002. The total capital budget for the year is expected to be $2.2 billion. In Canada, the focus continues to be on natural gas exploration and development. In the North Sea, a significant portion of the amount spent during the first nine months was on development at Hannay, Halley, Tartan and Claymore. In Southeast Asia, the majority of the capital spend related to the Malaysia/Vietnam development. In Sudan, two-thirds of the amount spent in the first nine months of 2002 related to development activities with the remainder spent on exploration. Other exploration and development expenditures for the first nine months of 2002 included $57 million spent in Trinidad, $77 million in Algeria and $8 million in Colombia.

DD&A ($/boe)	Three months ended September 30		Nine months ended September 30
DD&A ($/boe)	2002	2001	2002	2001
Canada	8.51	8.54	8.35	7.85
North Sea	14.04	11.99	12.75	11.72
Southeast Asia	6.06	6.48	6.09	6.46
Sudan	4.18	3.93	4.21	3.97
	9.53	8.85	9.08	8.36

Depreciation, depletion and amortization expense increased with higher production. The overall DD&A rate increased with higher capital spending and a change in production mix with a higher percentage of the Company’s total production sourced from the UK. The DD&A rate decreased in Southeast Asia due to increased Corridor natural gas reserves in Indonesia which is partially offset by the higher DD&A rate associated with PM3 CAA production in Malaysia/Vietnam.

Other ($ millions except where noted)	Three months ended September 30		Nine months ended September 30
Other ($ millions except where noted)	2002	2001	2002	2001
G&A ($/boe)	0.81	0.64	0.81	0.71
Interest costs capitalized	7	2	18	14
Dry hole expense	73	26	125	81
Other expense	(14)	59	60	61
Interest expense	38	44	122	103
Other revenue	21	17	60	60

Other expense for the quarter ended September 30, includes foreign exchange gains of $2 million. In the third quarter of 2001, other expense included foreign exchange losses of $60 million, primarily related to the US dollar denominated long-term debt.

Increased exploration drilling and the focus on deeper, riskier and higher value targets in Canada during the past year has resulted in higher dry hole expense for the quarter of $73 million, with $70 million in Canada and $3 million in Sudan.

Other expense in the nine months ended September 30, 2002 includes an impairment charge recorded during the first quarter of $45 million ($32 million after tax) relating to the North Sea Kildrummy project. The results of the second appraisal well indicated that the reserves were not sufficient for field development under present economic circumstances.

Taxes ($ millions)	Three months ended September 30		Nine months ended September 30
Taxes ($ millions)	2002	2001	2002	2001
Current income tax	68	82	192	276
Future income tax	8	(19)	130	90
Petroleum revenue tax	30	35	106	115
	106	98	428	481

The Company’s effective tax rate, after adjusting for petroleum revenue tax, which is deductible for income tax purposes, was 33% for the quarter (2001 – 34%). The comparable rate for the first nine months of 2002 was 48% (2001 – 35%), which was impacted by a one time second quarter non-cash increase of $116 million in the future tax liability as a result of changes to the UK and Alberta corporate tax rates.

Long-term Debt and liquidity

Cash flow for the third quarter exceeded capital expenditures resulting in a reduction in the Company’s indebtedness at September 30, 2002. At quarter end, the Company’s debt-to-debt plus equity was 37%, down from 41% at year end (with the Company’s preferred securities classified as equity). Debt to cash flow was 1.15:1 (based on previous 12 months).

The current portion of long-term debt as shown at December 31, 2001 has been eliminated as a result of the Company’s ability to refinance amounts due within one year with existing bank facilities.

During 2002, the Company renewed its $500 million medium term notes Canadian shelf prospectus, completed a $571 million (£250 million) Eurobond offering and renewed its normal course issuer bid to permit the purchase of up to 6,716,781 of its common shares. No shares have been repurchased during 2002.

The Company entered into a partial term hedge to effectively convert the Eurobond indebtedness into a US dollar floating rate liability.

Possible sale of Sudan Operations

As disclosed in Note 6 to the September 30, 2002 Interim Consolidated Financial Statements, the Company has negotiated a sale of its operations in Sudan subject to government approvals and other closing conditions. The impact of the sale of the Sudan operations is not included in the financial results of the Company as at September 30, 2002. Readers are referred to the segmented information in Note 15 of the December 31, 2001 Audited Consolidated Financial Statements and Note 7 of the September 30, 2002 Interim Consolidated Financial Statements in which the Sudan operations are reported as a separate operating segment.

Accounting changes

As disclosed in the notes to the September 30, 2002 and December 31, 2001 Consolidated Financial Statements, effective January 1, 2002, the following accounting changes were implemented:

The Company adopted the US dollar as its functional currency to reflect the increased exposure to the US dollar as a result of the growth in international operations. The Canadian and UK operations are considered to be self-sustaining with the Canadian dollar and Pound Sterling as their respective functional currencies. The adoption of the Pound Sterling as the functional currency of the UK operations is the result of the increased financial self-sustainability of this operation and its overall exposure to Pound Sterling transactions. The method used to translate the Company’s results and financial position for items and transactions denominated in non-US currency is described in the notes to the Interim Financial Statements.

Due to the weakening of the Canadian dollar during the third quarter vis-à-vis the US dollar and Pound Sterling, had the Company not made the above change to its functional currency, the net income for the quarter ended September 30, 2002 would have been approximately $90 million lower. Had the UK operations continued to be accounted for as being integrated with the parent Company’s operations, the Company would have recorded a $40 million reduction to net income for the quarter ended September 30, 2002.

The Company’s financial results continue to be displayed in Canadian dollars using the method described in the notes to the Interim Financial Statements.

In accordance with a new CICA accounting standard, the Company ceased the deferral and amortization of the gains or losses on foreign currency denominated long-term debt. The new standard has been applied retroactively and the financial statements of comparative periods have been restated. The impact of the new standard on the current quarter’s results was to decrease net income by $4 million. For the nine months ended September 30, net income was decreased $12 million. As indicated above, the 2001 comparative financial statements have been restated to include the impact of the new accounting standard as if the standard had been effective January 1, 2001. The restatement decreased the net income for the quarter ended September 30, 2001 by $35 million and $45 million for the nine months then ended.

Amortization of goodwill ceased and goodwill is now subject to ongoing annual impairment reviews, or as economic events dictate, based on the fair value of reporting units. This change did not have a significant impact on the current quarter’s financial results.

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 fourth quarter of 2002 is summarized in the following table and is based on a WTI oil price of US$27.50/bbl and a Henry Hub natural gas price of US$3.20/mmbtu.

Approximate impact on fourth quarter 2002 (millions of dollars)	Net Income	Cash Flow¹
Volume changes
Oil – 1,000 bbls/d	1	2
Natural gas – 10 mmcf/d	1	2
Price changes²
Oil – US$1.00/bbl	14	14
Natural gas (Canada)³ – C$0.10/mcf	2	4
Exchange rate changes
C$ decrease by US$0.01	7	11
£ increase by C$0.036	(2)	-

1 Components of cash flow are set out in note 14 to the December 31, 2001 Consolidated Financial Statements.

The impact of commodity contracts in place at September 30, 2002 has been included. At WTI prices above US$28.49/bbl the impact of a $1.00/bbl change will be reduced.

Price sensitivity on natural gas relates to Canadian natural gas only. The Company’s exposure to changes in North Sea natural gas prices is not material. Indonesia natural gas price is based on the price of crude oil and accordingly has been included in the price sensitivity for oil.

Exploration and Operations Review

Canada

Production in Canada in the third quarter was 196,035 boe/d, 2% lower than the third quarter of 2001 and the second quarter of 2002. These slightly lower volumes are due to phasing of plant turnarounds, increased cycle times, particularly in the Greater Arch, and backouts from constrained infrastructure in the Foothills area. During the first nine months, Talisman participated in 319 gross wells, of which 215 were operated. A total of 168 gas wells and 117 oil wells were drilled with an 89% success rate. Major drilling areas were the Greater Arch (68), Chauvin (42), Foothills (16), Bigstone/Wild River (20) and West Whitecourt (24).

A successful 2001/2002 drilling program has pushed Alberta Foothills gas production up 29% over the same quarter of last year. The Talisman Basing 14-3-47-20 well (100%) was drilled and brought on stream during the third quarter, producing at an initial rate of 12.3 mmcf/d net sales gas. A number of other operated and non-operated wells were successfully drilled and brought on production during the quarter, including wells at Redcap, Stolberg and Chungo, each with initial production rates exceeding 10 mmcf/d gross sales gas. High activity in the Foothills area is creating a variety of infrastructure issues. In response, Talisman has several gas compression projects underway and will be constructing the new “Erith” Pipeline to connect Foothills production to Talisman’s Edson plant in late 2003.

In addition to the Foothills drilling success, Talisman has been actively expanding its undeveloped land position along the Northern Alberta Foothills trend. In the under-explored area northwest of Findley, the Company has successfully completed a series of acquisitions, farm-ins and crown land purchases which bring Talisman’s total landholdings along this trend to 73,480 hectares (37,454 hectares net to Talisman). To date we have identified over 40 potential locations on this land base and will be proceeding with an expanded drilling program in 2003.

In the third quarter, 26 wells were drilled in the Greater Arch area, of which 20 were gas and three were oil, resulting in an 88% success rate.

At Monkman, the B-79-j well came on production in September. A follow-up deep location will spud in November. Triassic development continues with two wells currently drilling.

As part of our ongoing rationalization program, Talisman completed 22 asset transactions during the quarter. Year to date, $50 million in asset transactions was completed, resulting in cash generation of $4 million.

United States

The Ballymoney #1 well in New York State was rig released on October 5 at a total depth of 15,079 feet. The well was non-commercial.

Final approvals were received to commence drilling our first gas test on a large block of land on the Wasatch Plateau in Utah. The well will be drilled in the fourth quarter.

North Sea

Production in the North Sea in the third quarter 2002 was 144,371 boe/d, up 10% over the third quarter of 2001, but down from 151,741 boe/d in the second quarter of 2002. Extended planned maintenance shutdowns at Clyde, Tartan, MacCulloch and K4/K5 in the Netherlands during the summer were the major cause of this decrease. Shutdowns also occurred at Blake/Ross due to water treatment problems.

First production from the Halley well was achieved in July at an initial rate of 15,000 bbls/d, declining as anticipated to 6,000 bbls/d by the end of the third quarter.

A new well was brought on production at MacCulloch (Talisman 20%) at an initial production rate of 14,500 bbls/d gross.

A number of drilling challenges were faced during the quarter. Coiled tubing drilling operations at Buchan were suspended after the drill string became stuck in the B6 well bore. Also, operational difficulties were encountered on the Drum and ETA exploration wells that are being drilled from the Claymore and Clyde platform drilling rigs, respectively. We are making progress in the resolution of these difficulties but development drilling programs on these facilities have been delayed.

A successful exploration well, J-1, was drilled in the Buchan area. The 21/1a-19 well successfully tested the J-1 exploration prospect 10 kilometres northeast of the Buchan field. The well tested 6,600 bbls/d of 40^o API oil from 82 feet of net pay. Two sidetrack wells were drilled to appraise the discovery; one delineated the northern edge of the field while the other encountered 141 feet of high quality net pay. There are other related prospects in the Buchan Block that will be drilled in 2003.

A subsea leak on the Claymore water injection system that constrained production was repaired, allowing the enhanced water injection system to be fully commissioned at over 200,000 bbls of water per day. Production at the Claymore and Scapa fields is expected to increase by over 5,000 bbls/d during the next year.

The Blake flank pilot development project was approved and is expected to start production at 12,000 bbls/d (Talisman 53.6% working interest) in the third quarter of 2003.

Three acquisitions that will expand exploration plays around existing core areas are expected to close during the fourth quarter.

Indonesia

Production during the third quarter of 2002 was largely unchanged compared to both third quarter 2001 and second quarter 2002.

The Suban-8 well started drilling in early October. Another well at Suban-9 is expected to start drilling in December.

The facilities to sell additional gas to Caltex are expected to be ready for production in the first quarter of 2003; although additional gas sales may be limited, there will be an increase in take or pay quantities. The Singapore gas sales project is expected to start production in the first quarter of 2004. Negotiations for additional gas sales to Malaysia, Singapore, Batam, Sumatra and Java are very active and a memorandum of understanding was signed with Malaysia, which is intended to result in additional gas sales from Corridor starting in 2005.

Terms were agreed for Talisman’s participation in a consortium to take an interest in the new Indonesia trunk gas pipeline company, TransGas Indo. The transaction will give Talisman a 6% interest in the pipeline company and is expected to close during the fourth quarter of 2002.

Malaysia/Vietnam

The development of the PM3 Commercial Agreement Area remains on budget and scheduled to start production in the third quarter of 2003. The first two wellhead towers at Bunga Seroja A platform and Bunga Raya B platform have been installed and development drilling has started at the Bunga Raya B platform with one drilling rig and a second drilling rig is expected to start at Bunga Seroja A platform during the first week in November.

During the third quarter, two successful development wells were drilled at the existing Bunga Kekwa facility. These wells are now on production at 2,250 bbls/d and 2,180 bbls/d.

A consortium including Talisman (30% working interest) was successful in bidding for the large Block 46/02 in Vietnam adjacent to PM3 Commercial Agreement Area. The formal award of the block is anticipated in the fourth quarter of 2002.

Algeria

In Algeria, development in Block 405 continued during the quarter. First oil production is expected from Ourhoud near the end of 2002.

The Greater MLN project is 51% complete and first production is expected in the second quarter of 2003. To date, 21of the 34 planned development wells have been drilled, some of those wells being conversions of previous appraisal wells. Initial development planning has started for the MLSE discoveries in the south of Block 405.

Trinidad

Development planning for the oil development at Kairi and Canteen progressed during the quarter. Project sanction is anticipated at year end 2002 with first oil production before year end 2004.

The seismic contract for the Eastern Block was awarded at the end of July and most of the required seismic permitting is complete. On Block 3a offshore, 3-D seismic acquisition is expected to start at the end of October

Sudan

Production in Sudan continued to be over 60,000 bbls/d, up 10% from the third quarter of 2001 and level with the second quarter of 2002. Current production remains constrained by pipeline and process plant capacity. The Munga field started production on August 13, 2002.

The initial appraisal program for the Diffra area in Block 4 was completed and a field development plan submitted to the government. Wells at Diffra (1,000 bbls/d and 9.3 mmcf/d) and Hamam (3,200 bbls/d) were tested during the quarter. The appraisal program for the Unity satellite area continued and successful wells were drilled at Talih South 1 and Talih East 1. In total, five exploration wells and two development wells were drilled in the quarter and all were successful.

Talisman Energy Inc. is one of the largest independent Canadian oil and gas producers with operations in Canada, the North Sea, Indonesia, Malaysia, Vietnam and Sudan. Talisman is also conducting exploration in Algeria, Trinidad, Colombia and the United States. Talisman has adopted the International Code of Ethics for Canadian Business and is committed to maintaining high standards of excellence in corporate citizenship and social responsibility wherever it does business. The Company's shares are listed on The Toronto Stock Exchange in Canada and the New York Stock Exchange in the United States under the symbol TLM.

For further information, please contact:

David Mann, Manager, Investor Relations & Corporate Communications

Phone:

(403) 237-1196

Fax:

(403) 237-1210

E-mail:

tlm@talisman-energy.com

Website:

www.talisman-energy.com

This press release contains “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995, including estimates of future production, cash flows and net income, business plans for drilling and exploration, anticipated completion dates and results of exploration, development, maintenance and refurbishment projects, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words such as “expects”, “anticipates”, “plans”, “estimates”, or “intends”, or stating that certain actions, events or results “may” or “will” be taken, occur or be achieved). 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 reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration, development maintenance or refurbishment projects or capital expenditures; and health, safety and environmental risks); uncertainties as to the availability and cost of financing; risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action in countries such as Indonesia, Sudan, Algeria or Colombia); the effect of United States sanctions against Sudan and the possibility of changes in U.S. law or policy with respect to companies doing business in Sudan; fluctuations in oil and gas prices and foreign currency exchange rates; and the possibility that government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors, which could affect the Company’s operations or financial results, are included 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.

33/02