Exploration and Operations Review

EX-99 3 mda.htm 2Q INTERIM MD&A Exploration and Operations Review

INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

July 27, 2006

Forward-looking Statements

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

Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements. These risks and uncertainties include:

•

the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;

•

risks and uncertainties involving geology of oil and gas deposits;

•

the uncertainty of reserves estimates and reserves life;

•

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

•

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

•

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

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

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

•

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

•

general economic conditions;

•

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

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

We caution that the foregoing list of risks and uncertainties is not exhaustive. Additional

information on these and other factors, which could affect the Company's operations or financial results, are included in the Company's Annual Report under the headings "Management's Discussion and Analysis- Risks and Uncertainties", "- Liquidity and Capital Resources", and "- Outlook for 2006", under the heading “Risk Factors” in the Company’s 2005 annual information form as well as in the Company's other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission.

Forward-looking statements are based on the estimates and opinions of the Company's management at the time the statements are made. The Company assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change, except as required by law.

Advisory – Oil and Gas Information

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

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

Management’s Discussion and Analysis (MD&A)

(July 27, 2006)

This discussion and analysis should be read in conjunction with the Interim Consolidated Financial Statements as at June 30, 2006 and Talisman’s 2005 Audited Consolidated Financial Statements and MD&A. All comparative percentages are between the quarters ended June 30, 2006 and 2005, unless stated otherwise. All amounts are in Canadian dollars unless otherwise indicated.

The United Kingdom and Scandinavia, which were classified as the North Sea in 2005, are reported separately in 2006. The reporting segment entitled “Other” for 2006 includes North Africa (Algeria and Tunisia) and Trinidad and Tobago, which were reported separately in 2005. During the second quarter of 2006, activities in Alaska, which previously had been included in the “Other” reporting segment, were reclassified in North America. Reclassifications have been made for all corresponding reported periods.

During the second quarter of 2006, the Company entered into agreements to sell certain non-core oil and gas assets in Western Canada (proceeds of $379 million) and the United Kingdom (proceeds of US$414 million). Operating results from these assets are included in net income from discontinued operations. All but three of the agreements for sale of Western Canada assets closed as of June 30, 2006, with the resulting after-tax gain on disposal of assets of $78 million included in net income from discontinued operations. The three remaining agreements closed in July 2006. The agreements for the sale of United Kingdom assets are expected to close in the fourth quarter of 2006. Assets covered by all agreements not closed as at June 30, 2006 are reported as assets of discontinued operations on the Consolidated Balance Sheets. Gains on dispositions of assets covered by agreements not closed as at June 30, 2006, will be recorded when the agreements close later in 2006. See note 2 to the Interim Consolidated Financial Statements.

Quarterly Results Summary

	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
Financial (millions of C$ unless otherwise stated)
Net income from continuing operations	584	326	764	571
Net income from discontinued operations	102	14	119	27
Net income	686	340	883	598
C$ per common share¹
Net income– Basic	0.62	0.31	0.80	0.54
– Diluted	0.61	0.30	0.78	0.53
Net income from continuing operations
– Basic	0.53	0.30	0.70	0.52
– Diluted	0.51	0.29	0.68	0.51
Production (daily average)
Oil and liquids (bbls/d)	245,008	222,338	268,632	225,136
Natural gas (mmcf/d)	1,273	1,260	1,282	1,279
Continuing operations (mboe/d)	457	432	482	438
Discontinued operations (mboe/d)	16	12	16	13
Total mboe/d (6 mcf = 1 boe)	473	444	498	451
Total production(boe) per common share¹–Basic	0.039	0.037	0.082	0.074

All per share amounts have been retroactively restated to reflect the Company’s three-for-one share split. See note 5 to the Interim Consolidated Financial Statements.

Net income for the quarter increased 102% to $686 million, due in part to the after-tax gain on sale of assets of $78 million, as reported in results of discontinued operations (See note 2 to the Interim Consolidated Financial Statements).

Net income from continuing operations during the second quarter increased 79% to $584 million over the same period of 2005, as a result of a $178 million future tax recovery due to Canadian federal and provincial tax rate reductions, increased revenue from both higher production and commodity prices and reduced charges for stock-based compensation, partially offset by increased operating expenses and DD&A charges.

Company Netbacks^{1, 2}

	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
Oil and liquids ($/bbl)
Sales price	74.39	58.58	70.85	56.98
Hedging loss	0.37	0.86	0.22	0.79
Royalties	13.57	8.32	11.31	7.86
Transportation	1.01	0.86	1.01	0.85
Operating costs	15.74	12.49	13.56	11.66
	43.70	36.05	44.75	35.82
Natural gas ($/mcf)
Sales price	6.94	7.31	7.72	7.02
Hedging (gain)	(0.19)	-	(0.15)	-
Royalties	1.36	1.53	1.54	1.45
Transportation	0.22	0.22	0.26	0.25
Operating costs	0.90	0.74	0.87	0.72
	4.65	4.82	5.20	4.60
Total $/boe (6 mcf = 1 boe)
Sales price	59.01	51.41	59.87	49.72
Hedging (gain) loss	(0.35)	0.44	(0.28)	0.40
Royalties	11.02	8.73	10.39	8.27
Transportation	1.16	1.09	1.25	1.18
Operating costs	10.89	8.57	9.82	8.08
	36.29	32.58	38.69	31.79

Netbacks do not include synthetic oil, pipeline operations and the impact of the net change in oil inventory volumes.

Includes impact of discontinued operations.

Talisman’s average netback was $36.29/boe in the quarter, 11% higher than in 2005. Commodity prices rose in all reporting segments, with the exception of natural gas prices in North America, which decreased 16%. Higher prices were offset by a stronger Canadian dollar which rose 11% relative to the US dollar, as well as increased royalties, operating costs and transportation expenses. Realized prices averaged $59.01/boe, 15% higher than in 2005.

Gross sales from continuing operations for the quarter were $2.4 billion, an 18% increase over 2005 with higher production and commodity prices. Production increased 6% over the prior year, due in part to the Paladin acquisition in late 2005.

Daily Average Production, before Royalties

	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
Oil and liquids (bbls/d)
North America	50,939	52,726	52,204	52,851
United Kingdom¹	93,632	92,401	106,295	100,168
Scandinavia¹	29,638	22,820	34,556	19,245
Southeast Asia and Australia¹	53,471	27,082	52,662	28,020
Other¹	17,328	27,309	22,915	24,852
	245,008	222,338	268,632	225,136
Natural gas (mmcf/d)
North America	862	879	867	887
United Kingdom² Scandinavia	84 13	95 6	102 15	107 8
Southeast Asia and Australia	314	280	298	277
	1,273	1,260	1,282	1,279
Continuing operations (mboe/d)	457	432	482	438
Discontinued operations (mboe/d)
North America
- oil and liquids (bbls/d)	2,583	3,190	2,640	3,244
- natural gas (mmcf/d)	22	32	22	33
United Kingdom
- oil and liquids (bbls/d)	4,846	3,449	4,805	3,837
- natural gas (mmcf/d)	26	-	26	-
Discontinued operations (mboe/d)	16	12	16	13
Total mboe/d (6 mcf = 1 boe)	473	444	498	451

Includes oil volumes produced into inventory for the three months ended June 30, 2006 of 93.2 mbbls, 43.3 mbbls, 145.8 mbbls and 130.3 mbbls in the United Kingdom, Scandinavia, Southeast Asia and Australia, and Other, respectively.

Includes oil volumes produced into inventory, excludes oil volumes sold (out of ) inventory, for the six months ended June 30, 2006 of (302.7) mbbls, (105.0) mbbls, 39.2 mbbls and 231.6 mbbls in the United Kingdom, Scandinavia, Southeast Asia and Australia, and Other, respectively.

Includes gas acquired for injection and subsequent resale of 28 mmcf/d and 21 mmcf/d in the second quarter and year to date periods of 2006, respectively, and of 9 mmcf/d for both periods of 2005.

Oil and liquids production from continuing operations for the quarter averaged 245,008 bbls/d, up 10% from last year. In North America, oil and liquids production averaged 50,939 bbls/d during the quarter, down 3% from 2005. Production from new development wells in the Southern Alberta Foothills was more than offset by natural declines. In the United Kingdom, oil and liquids production averaged 93,632 bbls/d, up 1% from 2005, due to production increases from asset acquisitions over the past year and development drilling which were partially offset by planned facilities shutdowns at Piper (for Tweedsmuir tie-ins), Beatrice and Clyde. In addition, there were unplanned shutdowns for a Scapa riser failure, repairs to a compressor at Tartan and repairs to Galley flowlines. In Scandinavia, oil and liquids production increased 30%. The increase in production from the prior year’s acquisitions was offset by a decrease in production from the Varg field (acquired in February of last year) which averaged 6,887 bbls/d, down from 15,118 bbls/d in 2005 due to water breakthrough on two wells. In Southeast Asia and Australia, oil and liquids production averaged 53,471 bbls/d, up 97% over 2005. In Indonesia, production increased 117%, due in part to the acquisitions of the SE Sumatra and Offshore NW Java fields. Oil and liquids production in Malaysia/Vietnam was 36,526 bbls/d, up 66% due to the commencement of production at PM-305 in the second half of last year. Assets acquired in Australia at the end of 2005 produced 5,940 bbls/d during the quarter. Production from Other areas decreased 37%. In Trinidad, production averaged 7,648 bbls/d, down from 11,252 bbls/d in 2005 due to an extended, planned turnaround. In Algeria, production averaged 8,743 bbls/d, down 7,314 bbls/d due to the failure of the gas reinjection compressor motor at the MLN facilities on May 1, 2006. Production from Tunisia averaged 937 bbls/d during the quarter.

Natural gas production increased slightly, averaging 1.3 bcf/d during the quarter with plant turnarounds in North America offset by additional volumes in Southeast Asia and Australia. In North America, natural gas production was 862 mmcf/d, a decrease of 2% from last year due to operational issues, program delays and plant turnarounds. Talisman currently has approximately 95 mmcf/d of natural gas behind pipe, temporarily shut-in or awaiting tie-in. In the United Kingdom, natural gas production was 84 mmcf/d, a decrease of 12% over last year as volumes from Brae were reduced in accordance with the Brae Gas Offtake Profile. In Scandinavia, natural gas production averaged 13 mmcf/d, an increase of 7 mmcf/d over last year. In Southeast Asia and Australia, natural gas production was 314 mmcf/d, an increase of 12% over last year. Production in Malaysia/Vietnam averaged 109 mmcf/d, an increase of 6 mmcf/d. Indonesia gas production increased 15% over last year, averaging 204 mmcf/d, with higher Corridor sales to Singapore Power and the addition of the Offshore NW Java property.

In the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted and sold to third parties. Volumes transferred into and out of inventory for the period ended June 30, 2006, have been separately identified in footnote 1 to the Daily Average Production Volumes table above.

Prices and Exchange Rates

	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
Oil and liquids ($/bbl)
North America	63.34	48.16	56.28	47.33
United Kingdom	75.97	59.74	73.22	58.10
Scandinavia	77.25	62.32	75.07	62.03
Southeast Asia and Australia	78.92	67.60	76.26	63.87
Other	78.60	62.72	73.54	61.42
	74.39	58.58	70.85	56.98
Natural gas ($/mcf)
North America	6.52	7.72	7.66	7.39
United Kingdom	8.61	6.37	9.46	6.80
Scandinavia Southeast Asia and Australia	5.54 7.57	4.82 6.36	4.42 7.34	4.82 5.91
	6.94	7.31	7.72	7.02
Total $/boe (6 mcf = 1 boe)	59.01	51.41	59.87	49.72
Hedging (gain) loss, not included in the above prices Oil and liquids ($/bbl)	0.37	0.86	0.22	0.79
Natural gas ($/mcf)	(0.19)	-	(0.15)	-
Total $/boe (6 mcf = 1 boe)	(0.35)	0.44	(0.28)	0.40
Benchmark prices and foreign exchange rates WTI (US$/bbl)	70.72	53.22	67.13	51.66
Brent (US$/bbl)	69.59	51.63	65.66	49.64
NYMEX (US$/mmbtu)	6.82	6.80	7.95	6.56
AECO (C$/gj)	5.95	6.99	7.37	6.67
US/Canadian dollar exchange rate	0.89	0.80	0.88	0.81
Canadian dollar / pound sterling exchange rate	2.05	2.31	2.04	2.31

Excludes synthetic oil

During the quarter, WTI oil prices averaged US$70.72/bbl, 33% higher than 2005, although a stronger Canadian dollar and wider differentials in Canada moderated the increase in the Company’s realized price for oil and liquids to 27% over last year.

Talisman’s realized natural gas price was 5% below last year, largely reflecting the impact of lower AECO prices in North America.

For the quarter ended June 30, 2006, Talisman recorded net hedging gains of $15 million. Gains on natural gas ($0.19/mcf) more than offset losses on oil and liquids ($0.37/bbl) and compared to losses of $18 million for oil and liquids ($0.86/bbl) during the same period in 2005. As of July 1, 2006, the Company had derivative and physical contracts for approximately 4% of its remaining 2006 estimated production. A summary of the contracts outstanding is included in notes 11 and 12 to the December 31, 2005 Consolidated Financial Statements and in note 9 to the June 30, 2006 Interim Consolidated Financial Statements.

Royalties¹

	Three months ended
June 30,	2006		2005
	%	$ millions	%	$ millions
North America	20	152	20	167
United Kingdom	2	14	2	14
Scandinavia	-	1	-	-
Southeast Asia and Australia	44	260	35	116
Other	29	32	31	49
	19	459	17	346
	Six months ended
June 30,	2006		2005
	%	$ millions	%	$ millions
North America	20	343	20	325
United Kingdom	2	30	2	24
Scandinavia	-	2	-	-
Southeast Asia and Australia	40	455	36	225
Other	29	82	31	85
	17	912	17	659

Royalty rates do not include synthetic oil

Royalty expense for the second quarter was $459 million (19%), up from $346 million (17%), in 2005. This increase in the royalty expense is the result of increases in commodity prices, production and increased rates in Malaysia/Vietnam. In Southeast Asia and Australia, the royalty rate increased to 44% from 35% a year earlier, as rates in Malaysia/Vietnam averaged 58% during the quarter due to PM-305 and PM3 becoming cost current in the first quarter of 2006 and third quarter of 2005, respectively. The decrease in Other rates from 31% to 29%, was due primarily to lower production in Algeria.

Operating Expenses and Unit Operating Costs

	Three months ended
June 30,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	7.37	128	5.80	101
United Kingdom	19.14	172	16.17	149
Scandinavia	26.14	72	21.14	50
Southeast Asia and Australia	4.67	41	2.78	18
Other	5.33	7	3.08	8
	10.89	420	8.58	326
Synthetic oil	32.02	10	29.05	8
Pipeline		20		14
		450		348
	Six months ended
June 30,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	6.96	241	5.48	192
United Kingdom	16.30	346	14.73	295
Scandinavia	21.14	141	19.22	77
Southeast Asia and Australia	4.20	74	2.70	36
Other	4.15	15	3.97	18
	9.82	817	8.08	618
Synthetic oil	34.28	19	33.68	15
Pipeline		36		29
		872		662

Total operating expenses increased by $102 million, primarily due to increased volumes and higher power and maintenance costs. In North America, unit operating costs increased 27% due to plant turnarounds and increases in processing charges and maintenance costs. In the United Kingdom, total operating costs increased 15% with higher volumes and increased fuel, power, maintenance and turnaround costs. In Scandinavia, operating costs rose $22 million with higher volumes, maintenance at Varg and a higher FPSO day rate at Varg. Additional volumes accounted for $19 million of increased operating costs in Southeast Asia and Australia, to $41 million. The commencement of production from Block PM-305 in Malaysia in August of last year accounted for an additional $4 million.

Transportation Expenses

	Three months ended
*June 30,*	2006		2005
	$/boe	$millions	$/boe	$millions
North America	0.94	16	0.92	16
United Kingdom	1.51	15	1.39	13
Scandinavia	1.29	4	1.57	4
Southeast Asia and Australia	1.19	11	1.00	7
Other	0.84	2	0.99	3
	1.16	48	1.09	43
	Six months ended
*June 30,*	2006		2005
	$/boe	$millions	$/boe	$millions
North America	1.05	38	0.89	33
United Kingdom	1.51	33	1.41	29
Scandinavia	1.83	12	1.59	6
Southeast Asia and Australia	1.20	22	1.53	21
Other	0.89	4	1.03	5
	1.25	109	1.18	94

During the current quarter, transportation expense increased 12% to $48 million due to increases in both production and rates.

Depreciation, Depletion and Amortization (DD&A)

	Three months ended
June 30,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	14.29	253	12.52	227
United Kingdom	12.80	125	11.59	112
Scandinavia	20.43	60	16.15	35
Southeast Asia and Australia	5.52	54	4.32	29
Other	7.62	13	9.66	24
	12.05	505	10.90	427
	Six months ended
June 30,	2006		2005
	$/boe	$ millions	$/boe	$ millions
North America	13.99	498	12.31	447
United Kingdom	12.17	265	11.61	243
Scandinavia	19.99	132	16.91	63
Southeast Asia and Australia	6.03	112	4.47	60
Other	8.22	36	9.34	42
	12.00	1,043	10.84	855

The 2006 second quarter DD&A expense was $505 million, up 18% from the same quarter of 2005. The DD&A rate in North America increased 14% with increased spending on land, higher drilling costs and increased capital expenditures on infrastructure projects. DD&A expense in the United Kingdom increased 12% as a result of higher production and costs associated with the prior year’s acquisitions. In Scandinavia, total DD&A charges increased $25 million with increased production and costs related to the acquisitions in 2005. The DD&A expense for Southeast Asia and Australia increased by 86% largely due to the impact of the new production from Block PM-305 in Malaysia. In Other, the DD&A charge decreased $11 million to $13 million, as a result of decreased production in Algeria and Trinidad, partially offset by the impact of new production in Tunisia.

Other ($ millions)

June 30,	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
G&A	55	52	115	102
Dry hole expense	19	51	83	97
Stock-based compensation	(46)	111	-	277
Other expense	48	(19)	72	5
Interest costs capitalized	16	4	29	6
Interest expense	43	41	87	83
Other revenue	49	38	93	74

General and administrative (G&A) expense increased over the same quarter of last year due mainly to additional personnel and salary increases. On a per unit basis, G&A was $1.30/boe, up from $1.27/boe in the corresponding period in 2005.

Dry hole expense for the second quarter of 2006 was $19 million, with $11 million in North America and $8 million in Other. Other expense of $48 million includes a foreign exchange loss of $35 million and $9 million in spending related to the United Kingdom Windfarm. Other revenue of $49 million includes $43 million of pipeline and processing revenue, which was up 39% over 2005. Interest expense increased over the prior year as a result of increased debt. Capitalized interest expense is associated with the Tweedsmuir, Wood and Blane development projects in the United Kingdom. Tweedsmuir and Wood are scheduled to come on production during the first quarter of 2007 and Blane is scheduled to come on production in the second quarter of 2007.

Stock-based compensation expense relates to the closing value of the Company’s outstanding stock options and cash units as at June 30, 2006. The Company’s stock-based compensation expense or recovery is based on the difference between the Company’s share price and the exercise price of its stock options and cash units. During the quarter, the Company recorded a stock-based compensation recovery of $46 million, representing the aggregate of the $40 million cash payment to employees in settlement for fully accrued option liabilities on options exercised, offset by a non-cash mark-to-market adjustment of $(86) million resulting from the 6% decrease in the Company’s share price. Over the course of the quarter, the average exercise price of all outstanding options increased from $10.40 per share to $10.50 per share, with a total of 67.3 million options outstanding at June 30, 2006. See note 6 to the June 30, 2006 Interim Consolidated Financial Statements.

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

Taxes ($ millions)

Effective Income Tax Rate

June 30,	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
Income from continuing operations before taxes	826	590	1,888	1,058
Less PRT Current Deferred	73 (8)	35 (3)	162 (9)	68 6
Total PRT	65	32	153	74
	761	558	1,735	984
Income tax expense
Current income tax	183	209	510	391
Future income tax	(6)	23	461	22
Total income tax expense	177	232	971	413
Effective income tax rate	23%	42%	56%	42%

The effective tax rate is expressed as a percentage of pre-tax income adjusted for Petroleum Revenue Tax (PRT), which is deductible in determining taxable income. The Company’s effective tax rate for the current quarter is lower than in 2005 due primarily to the impact of a $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions. Exclusive of this one time non-cash adjustment, the current quarter’s effective rate is 47%, as a result of higher revenues, combined with increased taxable income in higher tax jurisdictions (e.g. Norway) and the 10% increase in United Kingdom tax rates. Increased commodity prices and production in the United Kingdom also increased PRT.

In the United Kingdom, recently amended legislation provides the Company with the option to defer 2005 capital expenditure claims for tax purposes to 2006 or later. At the higher tax rate applicable after 2005, this deferral would effectively result in an estimated reduction of approximately $75 million in current taxes, which would be realized during 2006 and 2007.

Capital Expenditures¹ ($ millions)

	Three months ended		Six months ended
June 30,	2006	2005	2006	2005
North America²	537	268	1,308	739
United Kingdom	297	232	565	400
Scandinavia	66	101	119	338
Southeast Asia and Australia	61	74	121	150
Other²	47	34	96	63
	1,008	709	2,209	1,690

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

During the second quarter of 2006, the Company made changes to the North America reporting segment to include activities in Alaska, which previously had been included in the “Other” reporting segment. Reclassifications have been made for all corresponding reported periods.

Capital expenditures in North America for the current quarter include $280 million for exploration and $257 million for development. Expenditures in the United Kingdom included $57 million for exploration and $240 million for development, which included the ongoing development of the Tweedsmuir, Wood, Enoch and Blane fields. In Scandinavia, the Company spent $34 million on exploration and $32 million on development. In Southeast Asia and Australia, development spending was $60 million, primarily on the Suban Phase 2 project and ongoing development on the PM-3 CAA. In Other, the Company spent $11 million on development and $2 million on exploration in North Africa, $16 million on exploration and $5 million on development in Trinidad and $13 million on exploration activities in the rest of the world. There have been no significant changes in the Company’s outlook for the major projects underway as discussed in the Outlook for 2006 section of the Company’s December 31, 2005 MD&A.

Long-term Debt and Liquidity

At June 30, 2006, Talisman’s long-term debt was $4.0 billion, including the current portion of long-term debt of $403 million, down from $4.3 billion at year-end, as cash provided from operating activities and proceeds from dispositions were greater than cash used in investing and financing activities, the payment of dividends and share repurchases.

In connection with the funding of the acquisition of Paladin in 2005, the Company arranged a $2.6 billion (₤1.3 billion), unsecured non-revolving credit facility. At June 30, 2006, $403 million was drawn on this facility which is included in current portion of long-term debt. Subsequent to the end of the current quarter, total borrowings under this facility were reduced to $298 million. This repayment was financed through a combination of proceeds of net asset dispositions, cash on hand and draws under the Company’s revolving credit facilities. The remaining amount outstanding under this facility must be repaid by October 2006. This is expected to be funded from a combination of excess cash provided by operating activities, draws on existing credit facilities and proceeds of net asset dispositions.

At quarter end, debt to debt plus book equity was 37%. For the 12 months ended June 30, 2006, the debt to cash provided by operating activities ratio was 0.75:1.

In March of this year, the Company renewed its normal course issuer bid (NCIB) with the Toronto Stock Exchange (TSX). Pursuant to the NCIB, the Company may purchase for cancellation up to 54,940,200 of its common shares (representing 5% of the outstanding common shares of the Company as at March 21, 2006, on a post share split basis), during the 12 month period commencing March 28, 2006 and ending March 27, 2007. The price that the Company will pay for shares acquired under the NCIB will be the market price at the time of purchase or such other price as may be permitted by the TSX. During the first six months of 2006 the Company repurchased 3,000,000 common shares for $54 million (2005 – 24,049,200 common shares for $299 million). All 3,000,000 common share repurchases in 2006 have been made under the normal course issuer bid renewed in March 2006. A copy of the Notice of Intention to Make a Normal Course Issuer Bid may be obtained without charge from Talisman.

In May 2006, the Company implemented a three-for-one share split of its issued and outstanding common shares. All share and per share statistics have been retroactively restated to reflect this share split.

As at June 30, 2006 there were 1,095,976,620 common shares outstanding, increasing to 1,096,042,020 at July 24, 2006.

As at June 30, 2006 there were 67,290,571 stock options and 8,563,533 cash units outstanding. During July of 2006, 452,340 stock options were exercised for cash, 65,400 stock options were exercised for shares, 527,990 stock options were granted and 56,325 were cancelled, with 67,244,496 stock options outstanding at July 24, 2006. Subsequent to June 30, 2006, 132,900 cash units were granted, and 53,575 cash units were exercised, with 8,642,858 cash units outstanding at July 24, 2006.

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

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

Sensitivities

Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated impact of these factors on the Company’s financial performance for the remainder of 2006 is summarized in the following table and is based on an average WTI oil price of US$68.54/bbl, a NYMEX natural gas price of US$7.35/mmbtu and exchange rates of C$1=US$0.89 and £1=C$2.04.

Approximate Impact for 2006¹ (millions of dollars)	Net Income	Cash Provided by Operating Activities
Volume changes
Oil – 1,000 bbls/d	8	15
Natural gas – 10 mmcf/d	7	14
Price changes²
Oil – US$1.00/bbl	46	66
Natural gas (North America)³ – C$0.10/mcf	15	20
Exchange rate changes
US$ increased by US$0.01	41	76
£ increase by C$0.025	(4)	(4)

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

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

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

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
	2006		2005				2004
	June 30	March 31	Dec. 31	Sept. 30	June 30	March 31	Dec. 31	Sept. 30
Gross sales	2,396	2,784	2,806	2,550	2,027	1,924	1,777	1,730
Total revenue	2,001	2,385	2,356	2,139	1,701	1,632	1,358	1,305
Net income from continuing operations	584	180	510	412	326	245	111	107
Net income	686	197	533	430	340	258	121	122
Per common share amounts¹ (Cdn dollars)
Net income from continuing operations	0.53	0.16	0.46	0.37	0.30	0.22	0.10	0.09
Diluted net income from continuing operations	0.52	0.16	0.45	0.36	0.29	0.21	0.10	0.09
Net income	0.62	0.18	0.48	0.39	0.31	0.23	0.11	0.11
Diluted net income	0.61	0.17	0.47	0.38	0.30	0.23	0.10	0.10

All per share amounts have been retroactively restated to reflect the Company’s three-for-one share split. See note 5 to the Interim Consolidated Financial Statements.

The following discussion highlights some of the more significant factors that impacted the results in the eight most recently completed quarters ended June 30, 2006.

During the second quarter of 2006, gross sales decreased by $388 million over the previous quarter due to decreased production. Net income from continuing operations for the quarter increased by $404 million, primarily due to the impact of a $178 million recovery of future taxes related to Canadian federal and provincial tax rate reductions and the $325 million future tax charge in the first quarter.

In the first quarter of 2006, gross sales decreased by $22 million over the previous quarter due to decreased natural gas prices in North America. Net income from continuing operations for the quarter decreased by $330 million, primarily due to the impact of a one time non-cash adjustment of $325 million related to a United Kingdom income tax rate increase.

During the fourth quarter of 2005, gross sales rose by $256 million over the previous quarter due to increased natural gas prices in North America and increased production in the North Sea. Net income from continuing operations for the quarter increased by $98 million, as the increased revenue combined with reduced stock-based compensation charges to more than offset the impact of increases in operating, depreciation, depletion and amortization, royalty and tax expenses.

During the third quarter of 2005, higher commodity prices and production increased gross sales by $523 million. Net income from continuing operations for the quarter increased by $86 million, as the increased revenue more than offset the impact of increases in stock-based compensation, royalty and tax expenses.

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

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

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

In the third quarter of 2004, gross sales rose as the increase in oil prices more than offset the reduction in production, resulting from maintenance shutdowns. Net income from continuing operations 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.

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.

Stock-Based Compensation

In July 2006, the Emerging Issues Committee (EIC) of the CICA issued EIC-162, Stock-based compensation for employees eligible to retire before the vesting date. EIC-162 clarifies the accounting for stock-based compensation plans that allow for vesting of stock-based awards after an employee's retirement. If the employee is eligible to retire on the grant date of an award, related compensation cost is to be recognized in full at that date as there is no ongoing service requirement to earn the award. If the employee becomes eligible to retire during the vesting period, the compensation cost is to be recognized over the period from the grant date to the retirement eligibility date. EIC-162 is effective for interim and annual periods ending on or after December 31, 2006. Talisman currently recognizes stock-based compensation in accordance with the conclusions of EIC-162 and we do not expect the adoption of EIC-162 will have a material impact on our results of operations or financial position.

Comprehensive Income / Financial Instruments / Hedges

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

Talisman has hedges in place that carry into 2007 and beyond, and we do not expect the adoption of these standards will have a material impact on the results of operations, or net financial position.

Risks and Uncertainties

Litigation

Talisman continues to be subject to a lawsuit brought by the Presbyterian Church of Sudan and others commenced in November 2001 under the Alien Tort Claims Act in the United States District Court for the Southern District of New York (the Court). The lawsuit 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. The plaintiffs have twice attempted to certify the lawsuit as a class action. In March 2005 and in September 2005, the Court rejected the plaintiffs' effort to certify two different classes (or groups) of plaintiffs. On July 19, 2006, the Second Circuit Court of Appeals denied the plaintiffs' request to appeal the Court's refusal to certify the lawsuit as a class action. On April 28, 2006 the Company filed a Motion for Summary Judgment, requesting the Court to dismiss the lawsuit or, alternatively, to restrict the plaintiffs' claims to factual disputes supported by admissible evidence. Talisman believes the lawsuit is entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Use of BOE equivalents

Unless otherwise stated, references to production represent Talisman’s working interest share (including royalty interests and net profits interests) before deduction of royalties. Throughout the MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an approximate energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Talisman Energy Inc.
Product Netbacks


		Three months ended		Six months ended
		June 30		June 30
(US$ - production net of royalties)		2006	2005	2006	2005
North	Oil and liquids (US$/bbl)
America	Sales price	56.45	38.73	49.52	38.33
	Hedging (gain)	-	3.71	-	3.46
	Transportation	0.64	0.54	0.64	0.50
	Operating costs	9.78	7.24	9.15	6.89
		46.03	27.24	39.73	27.48
	Natural gas (US$/mcf)
	Sales price	5.81	6.21	6.71	5.99
	Hedging (gain)	(0.32)	-	(0.25)	-
	Transportation	0.20	0.18	0.22	0.17
	Operating costs	1.27	0.89	1.19	0.84
		4.66	5.14	5.55	4.98
United Kingdom	Oil and liquids (US$/bbl)
	Sales price	67.61	48.05	64.21	47.09
	Hedging (gain)	0.86	-	0.48	-
	Transportation	1.37	0.93	1.28	0.98
	Operating costs	19.89	14.80	16.55	13.44
		45.49	32.32	45.90	32.67
	Natural gas (US$/mcf)
	Sales price	7.65	5.13	8.28	5.51
	Transportation	0.23	0.43	0.29	0.39
	Operating costs	0.59	0.64	0.66	0.74
		6.83	4.06	7.33	4.38
Scandinavia	Oil and liquids (US$/bbl)
	Sales price	68.72	50.12	65.80	50.25
	Transportation	1.42	0.80	1.38	0.63
	Operating costs	25.14	17.78	20.00	16.57
		42.16	31.54	44.42	33.05
	Natural gas (US$/mcf)
	Sales price	4.93	3.87	3.89	3.92
	Transportation	(0.40)	1.86	0.80	1.88
		5.33	2.01	3.09	2.04
Southeast Asia	Oil and liquids (US$/bbl)
and Australia	Sales price	70.34	54.38	67.07	51.75
	Transportation	0.38	0.34	0.35	0.22
	Operating costs	13.78	5.87	10.44	5.80
		56.18	48.17	56.28	45.73
	Natural gas (US$/mcf)
	Sales price	6.75	5.11	6.46	4.78
	Transportation	0.46	0.27	0.46	0.46
	Operating costs	0.39	0.36	0.40	0.35
		5.90	4.48	5.60	3.97
Other	Oil (US$/bbl)
	Sales price	69.63	50.41	64.16	49.72
	Transportation	1.06	1.15	1.10	1.20
	Operating costs	6.79	3.58	5.10	4.64
		61.78	45.68	57.96	43.88
Total Company	Oil and liquids (US$/bbl)
	Sales price	66.22	47.12	62.17	46.16
	Hedging (gain)	0.41	0.81	0.23	0.74
	Transportation	1.09	0.80	1.05	0.80
	Operating costs	17.14	11.66	14.19	10.94
		47.58	33.85	46.70	33.68
	Natural gas (US$/mcf)
	Sales price	6.18	5.88	6.77	5.68
	Hedging (gain)	(0.22)	-	(0.17)	-
	Transportation	0.25	0.23	0.29	0.26
	Operating costs	1.00	0.76	0.96	0.74
		5.15	4.89	5.69	4.68

Per US reporting practice, netbacks calculated using US$ and production after deduction of royalty volumes.
Netbacks do not include synthetic oil, pipeline operations and the impact of the change in oil inventory volumes.

Talisman Energy Inc.
Product Netbacks


		Three months ended June 30				Six months ended June 30
(C$ - production before royalties)		2006	2005	2006	2005	2006	2005	2006	2005
		Oil and liquids ($/bbl)		Natural gas ($/mcf)		Oil and liquids ($/bbl)		Natural gas ($/mcf)
North	Sales price	63.34	48.16	6.52	7.72	56.28	47.33	7.66	7.39
America	Hedging (gain)	-	3.68	(0.29)	-	-	3.39	(0.22)	-
	Royalties	13.56	9.77	1.21	1.53	12.04	9.82	1.51	1.46
	Transportation	0.56	0.54	0.18	0.18	0.58	0.49	0.20	0.17
	Operating costs	8.64	7.18	1.16	0.88	8.19	6.75	1.09	0.84
		40.58	26.99	4.26	5.13	35.47	26.88	5.08	4.92
United	Sales price	75.97	59.74	8.61	6.37	73.22	58.10	9.46	6.80
Kingdom	Hedging (gain)	0.95	-	-	-	0.54	-	-	-
	Royalties	1.05	0.96	0.41	0.56	0.85	0.71	0.56	0.53
	Transportation	1.52	1.14	0.24	0.49	1.44	1.19	0.31	0.45
	Operating costs	22.01	18.11	0.63	0.73	18.60	16.41	0.71	0.84
		50.44	39.53	7.33	4.59	51.79	39.79	7.88	4.98
Scandinavia	Sales price	77.25	62.32	5.54	4.82	75.07	62.03	4.42	4.82
	Royalties	0.31	-	-	-	0.31	-	-	-
	Transportation	1.60	1.00	(0.48)	2.30	1.57	0.78	0.91	2.32
	Operating costs	28.06	22.13	-	-	22.63	20.49	-	-
		47.28	39.19	6.02	2.52	50.56	40.76	3.51	2.50
Southeast	Sales price	78.92	67.60	7.57	6.36	76.26	63.87	7.34	5.91
Asia and	Royalties	40.90	27.46	2.17	1.88	35.55	26.34	2.15	1.82
Australia	Transportation	0.20	0.25	0.37	0.24	0.21	0.16	0.37	0.39
	Operating costs	7.41	4.34	0.31	0.31	6.33	4.21	0.32	0.30
		30.41	35.55	4.72	3.93	34.17	33.16	4.50	3.40
Other	Sales price	78.60	62.72	-	-	73.54	61.42	-	-
	Royalties	23.03	19.31	-	-	21.20	18.81	-	-
	Transportation	0.84	0.99	-	-	0.90	1.03	-	-
	Operating costs	5.35	3.08	-	-	4.16	3.97	-	-
		49.38	39.34	-	-	47.28	37.61	-	-
Total Company	Sales price	74.39	58.58	6.94	7.31	70.85	56.98	7.72	7.02
	Hedging (gain)	0.37	0.86	(0.19)	-	0.22	0.79	(0.15)	-
	Royalties	13.57	8.32	1.36	1.53	11.31	7.86	1.54	1.45
	Transportation	1.01	0.86	0.22	0.22	1.01	0.85	0.26	0.25
	Operating costs	15.74	12.49	0.90	0.74	13.56	11.66	0.87	0.72
		43.70	36.05	4.65	4.82	44.75	35.82	5.20	4.60

Includes discontinued operations

Netbacks do not include synthetic oil, pipeline operations and the impact of the change in oil inventory volumes.