Repsol Oil & Gas Canada (TLM) 6-K Interim Condensed Consolidated Financial Statements

Exhibit 99.2

 INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE PERIOD ENDED SEPTEMBER 30, 2014

1

Management’s Discussion and Analysis (MD&A)

(November 4, 2014)

General

This interim MD&A should be read in conjunction with the unaudited interim condensed Consolidated Financial Statements of Talisman Energy Inc. (‘Talisman’ or ‘the Company’) as at and for the three and nine month periods ended September 30, 2014 and 2013, and the 2013 MD&A and audited annual Consolidated Financial Statements of the Company. The Company’s interim condensed Consolidated Financial Statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting within International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

Talisman’s financial statements are prepared on a consolidated basis and include the accounts of Talisman and its subsidiaries. Substantially all of Talisman’s activities are conducted jointly with others, and the condensed Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities, with the exception of the Company’s investments in Talisman Sinopec Energy UK Limited (TSEUK) and Equion Energía Limited (Equion) which are accounted for using the equity method. Talisman’s investment in the Ocensa pipeline was accounted for using the equity method of accounting until December 19, 2013 when the Company sold its 12.152% equity interest.

All comparisons are between the three month periods ended September 30, 2014 and 2013, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this MD&A are listed in the section “Abbreviations and Definitions”. Unless otherwise indicated, amounts only reflect results from consolidated subsidiaries. Additional information relating to the Company, including its Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.

2

THIRD QUARTER 2014 PERFORMANCE HIGHLIGHTS

· Total production averaged 353,000 boe/d, with production from North America, Colombia, Southeast Asia and Algeria businesses at 323,000 boe/d. Production from ongoing operations in these regions was 318,000 boe/d.

· Total liquids production averaged 135,000 boe/d, with North American production up 11%.

· Net income for the quarter was $425 million compared to a net loss of $54 million in the previous year, mainly driven by mark-to-market gains on commodity derivatives, partially offset by decreased income tax recoveries and losses from the TSEUK joint venture.

FINANCIAL AND OPERATING HIGHLIGHTS

	Nine Months Ended Sept 30,					Q3	Q2		Q1	Q4		Q3		Q2	Q1		Q4
($ millions, unless otherwise stated)	2014		2013			2014	2014		2014	2013		2013		2013	2013		2012
Total revenue and other income1		3,719		3,557		1,136	1,242		1,341	929		1,244		1,190	1,123		1,663
Net income (loss)		679		(170	)	425	(237	)	491	(1,005	)	(54	)	97	(213	)	376
Per common share ($)
Net income (loss)2		0.65		(0.17	)	0.41	(0.23	)	0.47	(0.98	)	(0.05	)	0.09	(0.21	)	0.37
Diluted net income (loss)3		0.57		(0.23	)	0.38	(0.24	)	0.43	(0.98	)	(0.08	)	0.06	(0.21	)	0.31
Production4 (Daily Average - Gross)
Oil and liquids (mbbls/d)		141		130		135	145		142	137		134		126	129		143
Natural gas (mmcf/d)		1,379		1,433		1,310	1,380		1,452	1,505		1,423		1,414	1,461		1,498
Total mboe/d (6mcf = 1boe)		371		368		353	375		384	387		371		361	372		392

1. 2012 restated to reflect the change to equity accounting of Equion. Adjustments relating to TSEUK are effective for the period of December 17, 2012 to December 31, 2012 as the TSEUK joint venture was formed on December 17, 2012.

2. Net income (loss) per share includes an adjustment to the numerator for after-tax cumulative preferred share dividends.

3. Diluted net income (loss) per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options and after-tax cumulative preferred share dividends.

4. Includes the Company’s proportionate interest in production from joint ventures.

During the third quarter of 2014, the Company had net income of $425 million compared to a net loss of $54 million in the same quarter in 2013 as a result of a gain on held-for-trading financial instruments compared to a loss in 2013, partially offset by decreased income tax recoveries and losses from the TSEUK joint venture.

Higher production volumes from ongoing operations in the third quarter of 2014 were due principally to increases in North American production of both oil and liquids and gas as well as increases in oil production in Colombia from the Akacias field.

3

DAILY AVERAGE PRODUCTION

	Three months ended September 30
	Gross before royalties				Net of royalties
	2014		2013			2014	2013
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America		41		37		33	29
Southeast Asia		43		44		28	27
North Sea		14		12		14	12
Other		16		12		8	6
		114		105		83	74
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK		12		20		12	20
Equion		9		9		7	8
		21		29		19	28
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)		135		134		102	102
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America		745		882		648	762
Southeast Asia		494		491		330	327
North Sea		21		4		21	3
Other		-		-		-	-
		1,260		1,377		999	1,092
Natural gas from Joint Ventures (mmcf/d)
TSEUK		1		2		1	2
Equion		49		44		41	36
		50		46		42	38
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)		1,310		1,423		1,041	1,130
Total Daily Production from Consolidated Subsidiaries (mboe/d)
North America		165		184		140	156
Southeast Asia		125		125		83	81
North Sea		18		13		18	13
Other		16		12		8	6
		324		334		249	256
Total Daily Production from Joint Ventures (mboe/d)
TSEUK		12		21		12	21
Equion		17		16		14	13
		29		37		26	34
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)		353		371		275	290
Less production from assets sold or held for sale (mboe/d)
North America		2		30		1	30
Southeast Asia		3		3		2	2
		5		33		3	32
Total production from ongoing operations (mboe/d)		348		338		272	258

4

	Nine months ended September 30
	Gross before royalties				Net of royalties
	2014		2013		2014		2013
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America		43		33		34		26
Southeast Asia		44		43		28		23
North Sea		13		14		14		14
Other		16		11		8		5
		116		101		84		68
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK		16		19		16		19
Equion		9		10		7		8
		25		29		23		27
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)		141		130		107		95
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America		801		868		696		757
Southeast Asia		510		514		344		343
North Sea		19		7		19		7
Other		-		-		-		-
		1,330		1,389		1,059		1,107
Natural gas from Joint Ventures (mmcf/d)
TSEUK		2		2		2		2
Equion		47		42		38		34
		49		44		40		36
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)		1,379		1,433		1,099		1,143
Total Daily Production from Consolidated Subsidiaries (mboe/d)
North America		176		178		151		152
Southeast Asia		129		128		85		80
North Sea		16		15		16		15
Other		16		11		8		5
		337		332		260		252
Total Daily Production from Joint Ventures (mboe/d)
TSEUK		17		20		16		19
Equion		17		16		14		14
		34		36		30		33
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)		371		368		290		285
Less production from assets sold or held for sale (mboe/d)
North America		12		31		11		31
Southeast Asia		3		5		2		3
		15		36		13		34
Total production from ongoing operations (mboe/d)		356		332		277		251

Production represents gross production before royalties, unless noted otherwise. Production identified as net is production after deducting royalties.

Production from ongoing operations was 348 mboe/d, an increase of 3% compared to 2013 due principally to increased oil and liquids production in North America and Colombia, partially offset by lower production in TSEUK, due to phasing of turnaround activity and increased production declines.

In North America, production from ongoing operations increased by 6%, from 154 mboe/d to 163 mboe/d. Capital investment in North America continues to be prioritized towards liquids-rich opportunities, primarily in the Eagle Ford and the Edson area, resulting in oil and liquids production from ongoing operations increasing 11% from 37 mbbls/d to 41 mbbls/d. Natural gas production from ongoing operations increased by 5% from 701 mmcf/d to 736 mmcf/d due principally to growth in the Marcellus and the Eagle Ford.

5

In Southeast Asia, total production from ongoing operations was stable at 122 mboe/d. Total oil and liquids production decreased by 2% due principally to a reduction of the Company’s production entitlement at HST/HSD in Vietnam, as the partner’s exploration carry was fully recovered and natural declines at Kitan in Australia. This was partially offset by increased production from Kinabalu in Malayisa as a result of continued platform debottlenecking and an infill drilling program. Natural gas production increased 1% due principally to increases in Corridor from facility expansion projects brought on-stream in December 2013 partially offset by decreased gas sales demand in PM3.

Production in Norway increased by 38% due principally to prior year turnaround activity in Brage and Blane, increased gas export volumes at Veslefrikk and increased production at Varg as a result of the start-up of the Varg gas export in the first quarter of 2014. In the TSEUK joint venture, production decreased by 43% due principally to turnaround activity at Bleoholm and Tweedsmuir.
 

In the Other segment, including the Equion joint venture, production increased 18% compared to 2013. Liquids production in Colombia increased due principally to additional long-term testing wells in Akacias. Algeria production increased due principally to increased liquids production at EMK from a liquids train brought online in 2014.

VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1,2

	Three months ended September 30						Nine months ended September 30
	2014			2013			2014			2013
North America - bbls/d³		(652	)		-			(235	)		-
Southeast Asia - bbls/d		7,062			(1,231	)		4,617			(1,556	)
North Sea – bbls/d		(435	)		1,924			28			568
Other – bbls/d		6,549			(3,832	)		2,379			(1,591	)
Total produced into (sold out of) inventory – bbls/d		12,524			(3,139	)		6,789			(2,579	)
Total produced into (sold out of) inventory – mmbbls		1.2			(0.3	)		1.9			(0.7	)
Inventory at September 30 - mmbbls		3.1			1.4			3.1			1.4

1. Gross before royalties.

2. Effective January 1, 2013, the North Sea volumes only include Norway.

3. Volumes exclude any amounts capitalized to PP&E.

In the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted. The Company recognizes revenue and the related expenses on crude oil production when liftings have occurred. Volumes presented in the “Daily Average Production” table represent production volumes in the period, which include oil volumes produced into inventory and exclude volumes sold out of inventory.

Volumes in inventory increased from 1.9 mmbbls at June 30, 2014 to 3.1 mmbbls at September 30, 2014 due principally to increased inventories in Algeria and Southeast Asia, partially offset by decreased inventories in North America and the North Sea.

6

COMPANY NETBACKS1,2

	Three months ended September 30
	Gross before royalties				Net of royalties
	2014		2013		2014		2013
Oil and liquids ($/bbl)
Sales price		87.02		97.04		87.02		97.04
Royalties		24.45		30.01		-		-
Transportation		2.20		1.09		3.06		1.58
Operating costs		21.75		22.39		30.25		32.42
		38.62		43.55		53.71		63.04
Natural gas ($/mcf)
Sales price		5.88		5.51		5.88		5.51
Royalties		1.47		1.41		-		-
Transportation		0.29		0.28		0.39		0.38
Operating costs		1.16		1.08		1.55		1.46
		2.96		2.74		3.94		3.67
Total $/boe (6mcf=1boe)
Sales price		53.44		53.11		53.44		53.11
Royalties		14.31		15.23		-		-
Transportation		1.91		1.49		2.62		2.09
Operating costs		12.16		11.49		16.45		15.80
		25.06		24.90		34.37		35.22

1. Netbacks do not include pipeline operations.

2. Amounts shown only represent netbacks from consolidated subsidiaries and exclude netbacks from equity accounted entities.

	Nine months ended September 30
	Gross before royalties				Net of royalties
	2014		2013		2014		2013
Oil and liquids ($/bbl)
Sales price		91.15		94.80		91.15		94.80
Royalties		26.53		32.18		-		-
Transportation		1.74		1.31		2.46		1.99
Operating costs		21.95		22.73		30.96		34.41
		40.93		38.58		57.73		58.40
Natural gas ($/mcf)
Sales price		6.20		5.86		6.20		5.86
Royalties		1.48		1.47		-		-
Transportation		0.26		0.29		0.34		0.39
Operating costs		1.12		1.13		1.47		1.51
		3.34		2.97		4.39		3.96
Total $/boe (6mcf=1boe)
Sales price		55.64		53.27		55.64		53.27
Royalties		14.91		15.93		-		-
Transportation		1.63		1.63		2.22		2.32
Operating costs		11.91		11.62		16.03		16.09
		27.19		24.09		37.39		34.86

1. Netbacks do not include pipeline operations.

2. Amounts shown only represent netbacks from consolidated subsidiaries and exclude netbacks from equity accounted entities.

7

During the quarter, the Company’s average gross netback was $25.06/boe, 1% higher than 2013 due principally to higher realized gas prices in North America and lower royalties on liquids production, partially offset by lower realized prices and royalties on liquids production.

The Company’s realized net sale price was stable. The realized net sale price includes the impact of physical commodity contracts, but does not include the impact of financial commodity price derivatives discussed in the “Risk Management” section of this MD&A.

The corporate royalty rate was 25%, down from 30% in 2013 due principally to lower royalty payments in Southeast Asia.

COMMODITY PRICES AND EXCHANGE RATES1

	Three months ended September 30				Nine months ended September 30
	2014		2013		2014		2013
Oil and liquids ($/bbl)
North America		67.90		73.89		67.32		68.32
Southeast Asia		102.24		108.98		107.91		107.39
North Sea		91.59		111.01		100.53		108.96
Other		91.89		110.68		101.20		106.72
		87.02		97.04		91.15		94.80
Natural gas ($/mcf)
North America		3.72		3.29		4.34		3.51
Southeast Asia		9.07		9.41		9.05		9.72
North Sea		7.22		14.42		8.11		14.73
Other		-		-		-		-
		5.88		5.51		6.20		5.86
Company $/boe (6mcf=1boe)		53.44		53.11		55.64		53.27
Benchmark prices and foreign exchange rates
WTI                       (US$/bbl)		97.17		105.83		99.61		98.14
Dated Brent          (US$/bbl)		101.85		110.36		106.57		108.45
WCS                      (US$/bbl)		77.20		88.88		78.59		75.36
LLS                        (US$/bbl)		101.13		110.15		103.70		109.57
NYMEX                (US$/mmbtu)		4.07		3.60		4.51		3.68
AECO                    (C$/gj)		4.00		2.67		4.32		3.00
C$/US$ exchange rate		1.09		1.04		1.09		1.02
UK£/US$ exchange rate		0.60		0.64		0.60		0.65

1. Amounts shown only represent prices from consolidated subsidiaries and exclude prices from equity investees.

The Company’s overall realized oil and liquids price of $87.02/bbl decreased by 10% compared to 2013. In North America, realized oil and liquids prices decreased 8% due primarily to decreases in benchmark crude prices as well as a heavier weighting towards Natural Gas Liquids (NGL) products compared to 2013. In Southeast Asia realized oil and liquids prices decreased by 6% consistent with decreases in Brent pricing and in the North Sea, prices declined 17% due principally to the decline in Brent pricing and the timing of liftings.

The Company’s overall realized natural gas price of $5.88/mcf increased by 7% compared to 2013. In North America, realized natural gas prices increased by 13% in 2014, consistent with increases in NYMEX prices. In Southeast Asia, realized natural gas prices decreased by 4% due principally to declines in contracts that are linked to oil indices, partially offset by higher fixed-price contracts. For example, Corridor gas prices, where approximately 47% of sales are referenced to Duri crude and Singapore high-sulphur fuel oil on an energy equivalent basis, averaged $9.71/mcf in the third quarter versus $10.67/mcf in the prior year.

8

EXPENSES

Unit Operating Expenses1

	Three months ended September 30
	Gross before royalties				Net of royalties
($/boe)	2014		2013		2014		2013
North America		7.93		7.91		9.30		9.32
Southeast Asia		12.70		12.13		19.24		18.77
North Sea		43.87		59.36		43.87		59.36
Other		16.87		8.34		31.64		18.18
		12.16		11.49		16.45		15.80

	Nine months ended September 30
	Gross before royalties				Net of royalties
($/boe)	2014		2013		2014		2013
North America		8.07		8.61		9.49		10.07
Southeast Asia		11.87		11.20		17.97		17.90
North Sea		53.51		54.58		53.51		54.58
Other		11.93		6.56		22.98		14.08
		11.91		11.62		16.03		16.09

1. 2013 represents unit operating expenses from consolidated subsidiaries, excluding unit operating expenses from equity investees.

Total Operating Expenses1

	Three months ended September 30				Nine months ended September 30
	2014		2013		2014		2013
($ millions)
North America		128		135		396		426
Southeast Asia		114		135		366		384
North Sea		76		57		245		214
Other		21		11		44		24
		339		338		1,051		1,048

1. Represent operating expenses from consolidated subsidiaries, excluding operating expenses from equity investees.

Total operating expenses were stable due principally to increases from the timing of liftings in the North Sea and long-term testing in Colombia, offset by a decrease in Southeast Asia due to the timing of liftings.

In North America, total operating expenses decreased by 5% to $128million due principally to property dispositions in western Canada, partially offset by a gas plant turnaround at Edson, increased production activity and higher gathering and processing fees in the Eagle Ford.

9

In Southeast Asia, total operating expenses decreased by 16% due primarily to the timing of liftings partially offset by additional maintenance in Vietnam and Malaysia. Unit operating expenses increased by 5% due principally to additional maintenance in Vietnam and Malaysia.

In the North Sea, operating expenses in Norway increased by 33% due principally to the timing of liftings, partially offset by higher maintenance costs in Varg in 2013. Unit operating costs in Norway decreased by 26% due to higher production volumes and higher maintenance costs in Varg in 2013 as mentioned above.

In the rest of the world, total operating expenses increased by $10 million compared to the same period in 2013 due to increased long-term production testing in the Akacias field in Colombia, partially offset by the timing of liftings in Algeria.

Unit operating expense for the Company increased 6% compared to 2013 due to the reasons noted above.

Unit Depreciation, Depletion and Amortization (DD&A) Expense1

	Three months ended September 30
	Gross before royalties				Net of royalties
($/boe)	2014		2013		2014		2013
North America		18.46		18.28		21.67		21.53
Southeast Asia		10.20		11.09		15.51		17.09
North Sea		36.30		32.77		36.30		32.77
Other		6.30		7.51		8.52		12.70
		16.00		15.55		20.42		20.28

	Nine months ended September 30
	Gross before royalties				Net of royalties
($/boe)	2014		2013		2014		2013
North America		17.53		18.47		20.60		21.60
Southeast Asia		10.04		9.20		15.19		14.60
North Sea		41.86		31.17		41.86		31.17
Other		9.73		6.39		17.25		12.03
		15.61		14.96		20.12		19.64

1. Represents unit DD&A from consolidated subsidiaries, excluding unit DD&A from equity investees.

Total DD&A Expense1

	Three months ended September 30				Nine months ended September 30
	2014		2013		2014		2013
($ millions)
North America		282		309		844		895
Southeast Asia		111		129		341		326
North Sea		60		33		187		123
Other		5		11		35		23
		458		482		1,407		1,367

1. Represents DD&A expenses from consolidated subsidiaries, excluding DD&A expense from equity investees.

Total DD&A expense decreased by 5% as a result of decreases in North America and Southeast Asia, partially offset by increased expense in the North Sea.

10

DD&A expense in North America decreased by 9% principally due to lower production attributable to property dispositions as well as reserve additions in Marcellus, partially offset by increased production from ongoing operations and an increased depletable base in the Eagle Ford.

In Southeast Asia, DD&A expense decreased by 14% due principally to decreased production entitlement from HST/HSD in Vietnam as well as the timing of liftings. Unit DD&A expense decreased by 8%, due principally to impacts from the reduced production entitlement in HST/HSD.

In the North Sea, DD&A expense for Norway increased by 82% due principally to increased production and the timing of liftings. Unit DD&A expense increased by 11% due to an $11 million adjustment to historic DD&A charges in 2013, partially offset by rate changes in Brage, Varg and Veslefrikk.

In the rest of the world, total DD&A expense decreased due principally to the timing of liftings in Algeria.

Unit DD&A expense for the Company increased by 3% to $16.00/boe due to the reasons noted above.

Impairment1

	Three months ended September 30					Nine months ended September 30
	2014		2013			2014			2013
($ millions)
Impairment losses
North America		-		3			-			3
Southeast Asia		-		1			-			1
North Sea		-		-			190			7
Other		-		-			-			12
		-		4			190			23
Impairment reversals
North America		-		-			(32	)		-
Southeast Asia		-		-			-			-
North Sea		-		-			-			(21	)
Other		-		(2	)		-			(2	)
		-		(2	)		(32	)		(23	)
Net Impairment		-		2			158			-

1. Represents impairment expenses from consolidated subsidiaries, excluding impairment expenses from equity investees.

During the three month period ended September 30, 2014, the Company did not record any impairment losses or reversals.

During the nine month period ended September 30, 2014, the Company recorded $190 million of impairment expense consisting of $130 million in Norway due to withdrawal from an exploration license following technical evaluation and a further $60 million in Norway due to an increase in the decommissioning obligation and asset caused by a 1% decrease in the real discount rate used to measure decommissioning liabilities.

11

The Company recorded an impairment reversal of $32 million in North America in the second quarter of 2014, due to the estimated recoverable amount of assets held for sale exceeding their carrying amounts.

During the three months ended September 30, 2014, the Company declared commerciality and filed a development plan for the K44 license in the Kurdistan Region of Iraq. The Kurdistan Regional Government (KRG) has requested revisions to the development plan, which will require further negotiations between the K44 partners and the KRG within the contractual framework set out in the production sharing contract. The carrying value of the Company’s investment in K44 is $234 million at September 30, 2014.

The Company’s goodwill balance includes $287 million relating to the North Sea. The value of North Sea goodwill is supported by a combination of United Kingdom and Norway asset values, and any potential future diminution of those valuations, as referenced in note 5, to the interim condensed Consolidated Financial Statements, will increase the risk of impairment of North Sea goodwill.

Income (Loss) from Joint Ventures and Associates1

	Three months ended September 30						Nine months ended September 30
	2014			2013			2014			2013
($ millions)
TSEUK		(30	)		(5	)		(107	)		(73	)
Equion		17			33			63			95
Oleoducto Central S.A. (Ocensa)		-			16			-			43
		(13	)		44			(44	)		65

1. Represents the Company’s proportionate interest in joint ventures and associates.

TSEUK Joint Venture

The net loss in TSEUK increased by $25 million compared to prior year due principally to decreased production volumes, lower pricing and increased operating expenses, partially offset by an increase in deferred income tax recovery.

Throughout 2014, TSEUK has been challenged with respect to asset uptime, declining production and emerging potential increases to development and decommissioning cost estimates. These challenges will be factored into the Company’s reserves, planning and impairment processes due to be completed in the fourth quarter of 2014. An adverse movement in any of these factors will result in lower estimated future cash flows than previously anticipated, and under these circumstances there is a risk of impairments. Management expects to reach its conclusions and book impairments, if any, in the fourth quarter of 2014. The total value of the Company’s investment in TSEUK at September 30, 2014 is $637 million. The magnitude of potential impairments could result in a material reduction in the carrying value of the Company’s investment in TSEUK.

EQUION Joint Venture

Income from Equion decreased by $16 million compared to prior year due principally to increased DD&A expenses as well as a higher current tax expense.

12

OCENSA Joint Venture

In December 2013, Talisman sold its 12.152% equity interest in the Ocensa pipeline. Talisman retained its crude oil transportation rights in the pipeline and retained its option to transport proprietary crude and to market any unused capacity to third parties.

Corporate and Other1

	Three months ended September 30					Nine months ended September 30
	2014			2013		2014			2013
($ millions)
General and administrative (G&A) expense		95			106		305			320
Dry hole expense		36			13		64			82
Exploration expense		53			66		162			208
Finance costs		85			87		266			244
Share-based payments expense (recovery)		(17	)		6		(24	)		30
(Gain) loss on held-for-trading financial instruments		(428	)		120		(197	)		(21	)
(Gain) loss on asset disposals		(6	)		1		(560	)		(58	)
Other income		35			41		114			83
Other expenses, net (recovery)		(3	)		47		42			71

1. Represents corporate and other expense from consolidated subsidiaries, excluding corporate and other expense from equity investees.

G&A expense decreased by $11 million relative to 2013 due principally to lower workforce costs.

In the third quarter of 2014, Talisman recorded dry hole expense of $36 million due principally to the write-off of exploration wells in Colombia and Malaysia.

Exploration expense decreased by $13 million due principally to reduced spending in North America and the rest of the world, partially offset by increased spending in Southeast Asia.

Share-based payments recovery during the three month period ended September 30, 2014 was $17 million, mainly due to a reduction in the valuation of outstanding options, Restricted Share Units (RSUs) and Deferred Share Units (DSUs) caused by a decline in the Company’s share price and forfeited units for RSUs and options, partially offset by expenses related to the vesting of the long-term Performance Share Unit (PSU) plan units and the RSUs.

Talisman recorded a gain on held-for-trading financial instruments of $428 million, due principally to a decrease in oil and gas forward prices, partially offset by a reduction in the remaining volumes included under derivative contracts. See the ‘Risk Management’ section of this MD&A for further details concerning the Company’s financial instruments.

Other income consists primarily of $14 million in pipeline and customer treating tariffs along with $13 million in marketing and other income.

Other expense recovery of $3 million includes a foreign exchange gain of $18 million and PP&E derecognition costs of $4 million.

13

INCOME TAXES1

	Three months ended September 30						Nine months ended September 30
	2014			2013			2014			2013
($ millions)
Income (loss) before taxes		467			(70	)		895			118
Less: Petroleum Revenue Tax (PRT)
Current		(3	)		10			4			22
Deferred		4			(1	)		2			2
Total PRT		1			9			6			24
		466			(79	)		889			94
Income tax expense (recovery)
Current income tax		61			161			314			435
Deferred income tax		(20	)		(186	)		(104	)		(171	)
Income tax expense  (recovery) (excluding PRT)		41			(25	)		210			264
Effective income tax rate (%)		9			32			24			281

1. Represents income taxes from consolidated subsidiaries, excluding income taxes from equity investees.

The effective tax rate is expressed as a percentage of income before taxes adjusted for PRT, which is deductible in determining taxable income. The effective tax rate in the third quarter of 2014 was impacted by gains on held-for-trading financial instruments of $428 million, of which a portion are not taxable for tax purposes, partially offset by pre-tax income of $222 million in Southeast Asia where tax rates range from 30% to 55%.

In addition to the jurisdictional mix of income, the effective tax rate was also impacted by:

· The effect of foreign exchange fluctuations in foreign denominated currency tax pools; and

· The non-recognition of deferred tax assets in the United States and Southeast Asia exploration blocks;

· Settlement of prior year appeals with Canada Revenue Agency (CRA).

Current tax expense of $61 million decreased due to lower revenues in Southeast Asia and a $38 million benefit associated with the settlement of appeals in Canada in the third quarter of 2014.

The deferred tax recovery of $20 million in the three month period ended September 30, 2014, compared to a deferred tax recovery of $186 million in the three month period ended September 30, 2013, was due principally to foreign exchange fluctuations in foreign denominated tax pools as well as the recognition of previously unrecognized deferred tax assets in Vietnam in the third quarter of 2013.

14

CAPITAL EXPENDITURES1,2

	Three months ended September 30						Nine months ended September 30
	2014			2013			2014			2013
($ millions)
North America		348			347			949			1,015
Southeast Asia		125			94			308			352
North Sea1		34			99			123			307
Other		29			43			126			112
Exploration and development expenditure from subsidiaries2		536			583			1,506			1,786
Corporate, IS and Administrative		10			19			30			29
Acquisitions		-			105			36			105
Proceeds of dispositions		(102	)		(4	)		(1,494	)		(103	)
Net capital expenditure for subsidiaries		444			703			78			1,817
TSEUK		121			138			454			343
Equion		30			26			64			81
Exploration and development expenditure from joint ventures3		151			164			518			424
Net capital expenditure for consolidated subsidiaries and joint ventures		595			867			596			2,241

1.	Effective January 1, 2013, capital expenditures in the North Sea only relate to Norway.
2.	Excludes exploration expense of $53 million (2013 - $66 million) for the three month period ended September 30, 2014 and $162 million (2013 - $208 million) for the nine month period ended September 30, 2014.
3.	Represents the Company’s proportionate interest, excluding exploration expensed of $3 million net in TSEUK (2013 - $11 million) for the three month period ended September 30, 2014 and $5 million net in TSEUK (2013 - $17 million) for the nine month period ended September 30, 2014.

Net capital expenditure for consolidated subsidiaries and joint ventures, excluding exploration expense, decreased by 31% in the third quarter of 2014 compared to the same quarter in 2013 due principally to reduced spending in Norway and TSEUK, higher proceeds from dispositions and no acquisitions expenditure. This was partially offset by increased spending in Southeast Asia.

North American capital expenditures were relatively stable compared with 2013. Of the $348 million spent in the quarter, $315 million related to development activity, with the majority spent in the Eagle Ford, Marcellus and Edson areas. The remaining capital was mainly invested in exploration drilling activities, largely in the Duvernay.

In Southeast Asia, capital expenditures of $125 million included $59 million on development, with the majority spent in Malaysia, Indonesia and Australia. The majority of the $66 million for exploration was spent in Malaysia and Vietnam.

In Norway, capital expenditures of $34 million included $31 million of development activity, the majority being spent at Brage,Veslefrikk and Brynhild.

In the rest of the world, capital expenditures of $29 million included crude processing facilities in Colombia and exploration and evaluation activities in Colombia and the Kurdistan Region of Iraq.

In the TSEUK joint venture, net capital expenditures of $121 million consisted primarily of development activities at Montrose, Flyndre/Cawdor and Godwin and exploration drilling at Seagull. In the Equion joint venture, net capital expenditures of $30 million were principally for expansion of the Piedemonte facility as well as development wells in Florena and Pauto.

15

ASSET DISPOSALS

North America Dispositions

In July 2014, Talisman sold non-core assets in western Canada for net proceeds of $99 million, resulting in a loss on disposal of $3 million ($3 million after tax).

In April 2014, Talisman sold non-core assets in western Canada for net proceeds of $45 million, after $10 million in working capital adjustments, resulting in a loss on disposal of $3 million ($3 million after tax).

In March 2014, Talisman completed the sale of its Montney acreage in northeast British Columbia for proceeds of $1.3 billion, resulting in a pre-tax gain of $567 million ($493 million after tax).

In May 2013, Talisman completed sales of non-core assets in western Canada forproceeds of $63 million, resulting in a pre-tax gain of $52 million ($39 million after tax).

LIQUIDITY AND CAPITAL RESOURCES

Talisman’s gross debt at September 30, 2014 was $4.7 billion ($4.5 billion, net of cash and cash equivalents and bank indebtedness), compared to $5.2 billion ($4.9 billion, net of cash and cash equivalents and bank indebtedness) at December 31, 2013.

During the quarter, the Company generated $458 million of cash provided by operating activities and incurred capital expenditures of $549 million.

On an ongoing basis, Talisman plans to fund its capital program and acquisitions through a combination of cash on hand, cash provided by operating activities and cash proceeds from the disposition of non-core assets, and also by drawing on the Company’s credit facilities, issuing commercial paper, or issuing equity, long-term notes or debentures under the Company’s shelf prospectuses.

In May 2014, the Company renewed its universal shelf prospectus under the Multi-Jurisdictional Disclosure System pursuant to which it may issue up to $3.5 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units. The Company simultaneously renewed its medium-term note shelf prospectus in Canada pursuant to which it may issue up to C$1 billion of medium-term notes in Canada. Both shelf prospectuses remain valid over a 25 month period.

Talisman manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by maintaining appropriate undrawn capacity under committed bank credit facilities. At September 30, 2014, Talisman had unsecured credit facilities totaling $3.2 billion, consisting of facilities of $3 billion (Facility No. 1), maturing March 19, 2019 and $200 million (Facility No. 2) maturing October 21, 2019. At September 30, 2014, $341 million of commercial paper was outstanding. Available borrowing capacity was $2.9 billion at September 30, 2014.

On May 5, 2014, Talisman amended certain terms of Facility No.1, converting the denomination to US dollars, extending the facility to $3 billion and extending the terms to five years maturing on March 19, 2019. On August 12, 2014, the maturity date of Facility No. 2 was extended to October 21, 2019.

16

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At September 30, 2014, demand letters of credit guaranteed by the Company totaling $1.1 billion were issued, of which $1.0 billion were issued from uncommitted facilities. Of that total, $0.8 billion, issued from shared facilities with Addax, is provided as security for the costs of decommissioning obligations in the UK, as described below. The remaining outstanding letters of credit relate primarily to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations in other areas.

TSEUK is required to provide letters of credit as security in relation to certain decommissioning obligations in the UK pursuant to contractual arrangements under Decommissioning Security Agreements (DSAs). At the commencement of the joint venture, Addax assumed 49% of the decommissioning obligations of TSEUK, Addax’s parent company, China Petrochemical Corporation (Sinopec), has provided an unconditional and irrevocable guarantee for this 49% of the UK decommissioning obligations.

The United Kingdom Government passed legislation in 2013 which provides for a contractual instrument, known as a Decommissioning Relief Deed, for the Government to guarantee tax relief on decommissioning costs at 50%, allowing security under DSAs to be posted on an after-tax basis and reducing the amount of letters of credit required to be posted correspondingly. TSEUK has entered into a Decommissioning Relief Deed with the United Kingdom Government and continues to negotiate with counterparties to amend all DSAs accordingly.

At September 30, 2014, TSEUK has $2.5 billion of demand shared facilities in place under which letters of credit of $1.6 billion have been issued. Total letters of credit issued by TSEUK have been reduced from $1.8 billion at July 1, 2014 to $1.6 billion at September 30, 2014, as a result of selective letters of credit that are now posted on an after-tax basis. The Company intends to complete the process of replacing the remaining letters of credit as planned during the remainder of 2014, recognizing that beneficiary approval is required for these to be placed on an after-tax basis. The Company guarantees 51% of all letters of credit issued under these shared facilities.

The Company has also granted guarantees to various beneficiaries in respect of decommissioning obligations of TSEUK.

Any changes to decommissioning estimates influence the value of letters of credit to be provided pursuant to the DSAs. In addition, the extent to which shared facility capacity is available, and the cost of that capacity, is influenced by the Company’s investment grade credit rating. Since the second quarter of 2014, Talisman was downgraded by Moody’s, Standard &Poor’s, Fitch and Dominion Bond Rating Service to Baa3 (stable), BBB- (stable), BBB- (stable), and BBB (negative trend), respectively. The Company remains investment grade and believes it will continue to have access to capital, as and when needed, at a reasonable cost of funds.

As of September 30, 2014, TSEUK’s total recorded decommissioning liabilities were $3.4 billion. Decommissioning estimates are subject to a significant amount of management judgment given the long dated nature of the assets and the timing of remediation upon cessation of production. The Company reviews its assessment of decommissioning liabilities annually, or where a triggering event causes a review, taking into account new information and industry experience. Management is in the process of reviewing the latest decommissioning liability estimates and believes, based on emerging information, that there is a possibility of increases being confirmed as the process is progressed. At this stage, management has not concluded on the magnitude of the adjustments, if any, but will progress the review process, and make any necessary adjustments to remediation liabilities, in future periods.

17

Talisman manages its balance sheet with reference to its liquidity and a debt-to-cash flow ratio. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from equity accounted entities (defined in accordance with the Company’s debt covenant as cash provided by operating activities before adjusting for changes in non-cash working capital, and exploration expenditure), cash provided by and used in investing activities and available bank credit facilities. The debt-to-cash flow ratio is calculated using debt (calculated by adding the gross debt and bank indebtedness, production payments and finance lease) divided by cash flow for the year.

The Company is in compliance with all of its debt covenants. The Company’s principal financial covenant under its primary bank credit facility is a debt-to-cash flow ratio of less than 3.5:1, calculated quarterly on a trailing 12-month basis as of the last day of each fiscal quarter. For the trailing 12-month period ended September 30, 2014, the debt-to-cash flow ratio was 1.9:1.

The Company established a US commercial paper program in November 2011. The authorized amount under this program is $1 billion. The amount available under the commercial paper program is limited to the availability of backup funds under the Company’s bank credit facilities. At September 30, 2014 the amount of commercial paper outstanding was $341 million and the average interest rate on outstanding commercial paper was 0.6993%. The classification of commercial paper as a current liability at September 30, 2014 reflects management’s intent with respect to its repayment.

A significant proportion of Talisman’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At September 30, 2014, approximately 87% of the Company's trade accounts receivable were aged less than 90 days and the largest single counterparty exposure, accounting for 4% of the total, was with an investment grade counterparty. Concentration of counterparty credit risk is mitigated by having a broad domestic and international customer base of highly rated counterparties.

The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions.  The Company’s policy allows it to deposit cash balances at financial institutions subject to a sliding scale limit, depending on creditworthiness. The maximum credit exposure associated with financial assets is the carrying values.

At September 30, 2014, there were 1,036,166,028 common shares outstanding, of which 4,144,042 were held in trust by the Company resulting in 1,032,021,986 common shares outstanding for accounting purposes. During the three month period ended September 30, 2014, Talisman declared common share dividends of $0.0675 per share for an aggregate dividend of $69 million. Subsequent to September 30, 2014, no stock options were exercised for shares and 450,000 common shares were purchased and held in trust for the long-term PSU plan. At October 30, 2014 1,036,166,028 shares were outstanding, of which 4,594,042 were held in trust by the Company resulting in 1,031,571,986 common shares outstanding for accounting purposes.

At September 30, 2014, there were 8,000,000 Series 1 preferred shares outstanding. Holders of Series 1 preferred shares are entitled to receive cumulative quarterly fixed dividends of 4.2% per annum for the initial period ending December 31, 2016, if, as, and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 2.77%. During the three month period ended September 30, 2014, Talisman declared preferred share dividends of C$0.2625per share for an aggregate dividend of $2million.

18

At September 30, 2014, there were 34,912,646 stock options, 11,393,395 RSUs, 2,959,056 DSUs and 10,597,860 long-term PSUs outstanding.

Subsequent to September 30, 2014, no stock options were granted, surrendered for cash, or exercised for shares, and 667,596 were forfeited with 34,245,050 outstanding at October 30, 2014. Subsequent to September 30, 2014, no PSUs were granted, and long-term PSUs forfeitures were reduced by 10,116, with 10,607,976 outstanding at October 30, 2014. Subsequent to September 30, 2014, no RSUs were granted, 19,266 were exercised and 113,981 were forfeited with 11,260,148 outstanding at October 30, 2014. There were 226 DSUs granted subsequent to September 30, 2014, no DSUs were exercised, with 2,959,282 outstanding at October 30, 2014.

The Company may purchase shares on the open market which are held in trust and used to satisfy its obligation to settle long-term PSUs. The 2011 long-term PSU grant vested on December 31, 2013 and was settled in March 2014 based on the vesting of 75% of the PSUs granted as approved by the Board of Directors.

During the nine month period ended September 30, 2014, 1,769,900 common shares were purchased on the open market for $17 million and held in trust for the long-term PSU plan (During the same period in 2013 – no common shares were purchased). Between October 1 and October 30, 2014, 450,000 common shares were purchased on the open market for $4 million and held in trust for the long-term PSU plan.

Talisman continually monitors its portfolio of assets and investigates business opportunities in the oil and gas sector. The Company may make acquisitions, investments or dispositions, some of which may be material. In connection with any acquisition or investment, Talisman may incur debt or issue equity.

For additional information regarding the Company’s liquidity and capital resources, refer to notes 18 and 21 to the 2013 audited Consolidated Financial Statements and notes 13 and 15 to the interim condensed Consolidated Financial Statements.

19

SENSITIVITIES

Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated annualized impact of these factors for 2014 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $105/bbl, a NYMEX natural gas price of approximately $4.45/mmbtu and exchange rates of US$0.90=C$1 and UK£1=US$1.65.

(millions of $)	Net Income			Cash Provided by Operating Activities3
Volume changes
Oil – 10,000 bbls/d		80			180
Natural gas – 60 mmcf/d		20			70
Price changes1
Oil – $1.00/bbl		20			25
Natural gas (North America)2 – $0.10/mcf		15			25
Exchange rate changes
US$/C$ decreased by US$0.01		(5	)		(5	)
US$/UK£ increased by US$0.02		-			-

1. The impact of price changes excludes the effect of commodity derivatives.  See specific commodity derivative terms in the ‘Risk Management’ section of this MD&A, and note 16 to the interim condensed Consolidated Financial Statements.

2. Price sensitivity on natural gas relates to North American natural gas only.  The Company’s exposure to changes in the natural gas prices in Norway and Vietnam and Colombia is not material.  Most of the natural gas prices in Indonesia and Malaysia are based on the price of crude oil or high-sulphur fuel oil and, accordingly, have been included in the price sensitivity for oil. Most of the remaining part of Indonesia natural gas production is sold at a fixed price.

3. Changes in cash flow provided by operating activities exclude TSEUK and Equion due to the application of equity accounting.

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, decommissioning obligations, lease commitments relating to corporate offices and ocean-going vessels, firm commitments for gathering, processing and transmission services, minimum work commitments under various international agreements, other service contracts and fixed price commodity sales contracts.

Additional disclosure of the Company’s debt repayment obligations can be found in note 18 to the 2013 audited Consolidated Financial Statements and note 13 to the interim condensed Consolidated Financial Statements. A discussion of the Company’s derivative financial instruments and commodity sales contracts can be found in the “Risk Management” section of this MD&A.

During the nine month period ended September 30, 2014, as a result of the sale of the Company’s Montney acreage and non-core assets in western Canada, there was a total of $339 million decrease in the Company’s expected future commitments, including a $286 million decrease in transportation and processing commitments, a $50 million decrease in PP&E and E&E asset commitments, and a $3 million decrease in office lease commitments. There was a further $135 million decrease in the Company’s transportation and processing commitments in western Canada and Indonesia. There have been no additional significant changes in the Company’s expected future commitments, and the timing of those payments, since December 31, 2013.

20

TRANSACTIONS WITH RELATED PARTIES

During the three months ended September 30, 2014, Equion declared dividends payable to the shareholders in the amount of $570 million, of which Talisman’s share was $279 million. The Company has recorded dividends receivable of $279 million with a corresponding reduction in the equity investment in Equion.

During the three months ended September 30, 2014, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $365 million, of which Talisman’s share was $186 million.

In June 2014, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $1.26 billion, of which Talisman’s share was $643 million, which settled shareholder loans of $1.24 billion and accrued interest of $18 million, of which Talisman’s share was $634 million and $9 million, respectively.

In addition, the shareholders of TSEUK provided an equity funding facility totaling $1.2 billion to TSEUK in June 2014, of which Talisman is committed to $612 million, for the purpose of funding capital, decommissioning and operating expenditures of TSEUK. TSEUK may fund operating expenditures under this facility to a maximum amount of $150 million. This facility expires on June 30, 2015.

RISK MANAGEMENT

Talisman monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, Talisman periodically enters into physical delivery transactions for commodities of fixed or collared prices and into derivative financial instruments to reduce exposure to unfavourable movements in commodity prices, interest rates and foreign exchange rates. The terms of these contracts or instruments may limit the benefit of favourable changes in commodity prices, interest rates and currency values, and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with contracts.

The Company has established a system of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties.

The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 3(q) to the 2013 audited Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at September 30, 2014, including their respective fair values, are detailed in note 16 to the interim condensed Consolidated Financial Statements.

The Company has elected not to designate any commodity price derivative contracts entered into as hedges for accounting purposes. These derivatives are classified as held-for-trading financial instruments and are measured at fair value with changes in fair value recognized in net income. This can potentially increase the volatility of net income.

21

Commodity Price Derivative Financial Instruments

The Company had the following commodity price derivative contracts outstanding at September 30, 2014, none of which are designated as hedges:

Two-way collars (Oil)	Term	bbls/d		Floor/ceiling $/bbl
Dated Brent oil index	2014 Oct – Dec		10,000		95.00/110.07
Dated Brent oil index	2014 Oct – Dec		10,000		90.00/105.22
NYMEX WTI oil index	2014 Oct – Dec		5,000		80.00/95.00
Dated Brent oil index	2015 Jan – Dec		5,000		90.00/100.01
NYMEX WTI oil index	2015 Jan – Dec		5,000		80.00/95.02
Dated Brent oil index	2015 Jan – Dec		20,000		90.00/106.16
Dated Brent oil index	2016 Jan – Dec		5,000		90.00/108.00
NYMEX WTI oil index	2016 Jan – Dec		5,000		85.00/95.95

Fixed priced swaps (Oil)	Term	bbls/d		$/bbl
NYMEX WTI oil index	2014 Oct - Dec		2,500		91.91
Dated Brent oil index	2014 Oct - Dec		10,000		104.02
NYMEX WTI oil index	2014 Oct - Dec		10,000		94.28
Dated Brent oil index	2014 Oct - Dec		10,000		103.31
Dated Brent oil index	2014 Oct - Dec		8,000		111.79
WCS Diferential	2014 Oct - Dec		6,500		(21.55	)
Dated Brent oil index	2015 Jan - Dec		10,000		100.46
Dated Brent oil index	2015 Jan - Dec		1,000		104.00
Dated Brent oil index	2015 Jan - Dec		9,000		100.59
NYMEX WTI oil index	2015 Jan - Dec		5,000		96.36
WCS Differential	2015 Jan – Mar		6,500		(21.55	)
Dated Brent oil index	2016 Jan - Dec		10,000		98.01
Dated Brent oil index	2016 Jan - Dec		5,000		100.29
Dated Brent oil index	2016 Jan - Dec		10,000		102.98
Two-way collars (Gas)	Term	mcf/d		Floor/ceiling $/mcf
NYMEX HH LD	2014 Oct - Dec		94,936		4.21/4.71
NYMEX HH LD	2014 Oct - Dec		47,468		4.21/4.64
NYMEX HH LD	2014 Oct - Dec		47,468		4.21/4.99
NYMEX HH LD	2015 Jan - Dec		47,468		4.23/4.87
NYMEX HH LD	2015 Jan - Dec		94,936		4.21/5.06
NYMEX HH LD	2016 Jan - Dec		47,468		4.21/4.75
NYMEX HH LD	2016 Jan - Dec		47,468		4.21/4.87

22

Fixed priced swaps (Gas)	Term	mcf/d		$/mcf
NYMEX HH LD	2014 Oct - Dec		47,468		4.24
NYMEX HH LD	2014 Oct - Dec		47,468		4.25
NYMEX HH LD	2014 Oct - Dec		47,468		4.34
NYMEX HH LD	2014 Oct - Dec		47,468		4.42
NYMEX HH LD	2014 Oct - Dec		47,468		4.44
NYMEX HH LD	2014 Oct - Dec		47,468		4.29
NYMEX HH LD	2014 Oct - Dec		47,468		4.43
NYMEX HH LD	2015 Jan - Dec		47,468		4.54
NYMEX HH LD	2015 Jan - Dec		47,468		4.39
NYMEX HH LD	2015 Jan - Dec		47,468		4.39
NYMEX HH LD	2015 Jan - Dec		47,468		4.48
NYMEX HH LD	2015 Jan - Dec		47,468		4.53
NYMEX HH LD	2015 Jan - Dec		47,468		4.55
NYMEX HH LD	2016 Jan - Dec		47,468		4.48
NYMEX HH LD	2016 Jan - Dec		42,721		4.55
Fixed priced swaps (Power)	Term	MWh		$CAD/MWh
Alberta Power	2014 Oct - Dec		7		74.66
Alberta Power	2015 Jan - Dec		5		73.72
Alberta Power	2016 Jan - Dec		2		73.83
Alberta Power	2017 Jan - Dec		1		74.75
Alberta Power	2018 Jan - Dec		1		74.75

Subsequent to September 30, 2014, the Company did not enter into any derivative contracts as at October 30, 2014.

Interest Rate Swaps

In order to swap a portion of the $375 million 5.125% notes due 2015 to floating interest rates, the Company entered into fixed-to-floating interest rate swap contracts with a total notional amount of $300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three month US$ LIBOR plus 0.433% while receiving payments of 5.125% semi-annually.

USE OF ESTIMATES AND JUDGMENTS

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is required to adopt accounting policies that require the use of significant estimates and judgment. Actual results could differ materially from those estimates. Judgments and estimates are reviewed by management on a regular basis.

Decommissioning liabilities are measured based on the estimated cost of abandonment discounted to its net present value using a weighted average credit-adjusted risk free rate, which was 2.8% at September 30, 2014 (December 31, 2013 – 3.8%). Due to this rate decrease, the net present value of the decommissioning liability increased by $178 million during the nine months ended September 30, 2014.

23

For additional information regarding the use of estimates and judgments refer to the notes to the audited Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2013.

CHANGES IN ACCOUNTING POLICIES

a) Accounting Policies Used

The interim condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the 2013 annual Consolidated Financial Statements except for the following:

Offsetting Financial Assets and Financial Liabilities

· IAS 32 Offsetting Financial Assets and Financial Liabilities - Financial Instruments Presentation. The amended standard requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The scope includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements and securities borrowing and securities lending agreements. The amendments to IAS 32 are effective for annual periods beginning on or after January 1, 2014 and require retrospective application. As the Company is not netting any significant amounts related to financial instruments and does not have any significant offsetting arrangements, the amendment does not have an impact on the Company’s financial statements.

Impairment of Assets

· IAS 36 Impairment of Assets – Amendments to IAS 36. The amended standard requires entities to disclose the recoverable amount of an impaired Cash Generating Unit (CGU). The amendments to IAS 36 are effective for annual periods beginning on or after January 1, 2014 and require retrospective application. This standard did not have an impact on the Company’s financial position or performance.

Levies

· IFRIC 21 Levies - Interpretation of IAS 37 Provisions, contingent liabilities and assets: IAS 37 sets out criteria for the recognition of a liability, one of which is the requirement for the entity to have a present obligation as a result of a past event. The interpretation clarifies that the obligation that gives rise to the liability to pay a levy is the activity described in the relevant legislation that triggers the payment of the levy. The Company reviewed payments of levies and concluded that the application of the standard did not have a significant impact on the Company.

24

b) Accounting Pronouncements Not Yet Adopted

The Company continues to assess the impact of adopting the following pronouncements.

Financial Instruments

· IFRS 9 Financial Instruments: IFRS 9 (July 2014) replaces earlier versions of IFRS 9 that had not yet been adopted by the Company and supersedes IAS 39 Financial Instruments: Recognition and  Measurement. IFRS 9 introduces new models for classification and measurement of financial instruments, hedge accounting and impairment of financial assets and is mandatorily effective for periods beginning on or after January 1, 2018. The Company continues to review the standard as it is updated and monitor its impact on the Company’s financial statements.

Revenue

· IFRS 15 Revenue from Contracts with Customers: IFRS 15 specifies how and when to recognize revenue as well as requiring entities to provide users of financial statements with more informative, relevant disclosures. The standard supersedes IAS 18 Revenue, IAS 11 Construction Contracts, and a number of revenue-related interpretations. IFRS 15 will be effective for annual periods beginning on or after January 1, 2017. Application of the standard is mandatory and early adoption is permitted. The Company has not yet determined the impact of the standard on the Company’s financial statements.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no significant changes in Talisman’s internal control over financial reporting during the three month period ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Talisman utilizes the original Internal Control - Integrated Framework (1992) issued by the Committee of the Sponsoring Organizations of the Treadway Commission (COSO) to design and evaluate its internal control over financial reporting. In May 2013, COSO updated the Internal Control – Integrated Framework which will supersede the 1992 Framework on December 15, 2014.

LEGAL PROCEEDINGS

From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not expected to have a material impact on the Company's financial position.

REGULATORY DEVELOPMENT

Dodd-Frank Act

In 2010, the US Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act or the Act) was signed into law. The Dodd-Frank Act provides for numerous new substantive requirements in areas such as the disclosure of payments made to foreign governments, rules regarding the use of credit ratings, and corporate governance and executive compensation reforms, among others, some of which apply to Talisman as a foreign private issuer. Talisman will continue to assess the effect on the Company of the Dodd-Frank Act and related rules.  The SEC has yet to adopt the rules relating to pay-for-performance, pay parity, hedging and executive compensation clawbacks.

25

In August 2012, the SEC adopted rules to implement Section 1504 of the Dodd-Frank Act, requiring resource extraction issuers to disclose payments made to the US federal government or a foreign government (including a department, agent or instrumentality of a foreign government or a company owned by a foreign government) in their annual reports. On July 2, 2013, the US District Court for the District of Columbia vacated these rules, meaning that the rules are no longer in effect. As at October 30, 2014, the SEC had not issued new or revised rules in response to the Court’s ruling.

ADVISORIES

Forward-Looking Statements

This interim MD&A contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation.

This forward-looking information includes, but is not limited to, statements regarding:

· Business strategy, plans, and priorities;

· The estimated impact on Talisman’s financial performance from changes in production volumes, commodity prices and exchange rates;

· Potential effects of the hedging program;

· Expected sources of capital to fund the Company’s capital program and potential acquisitions, investments or dispositions;

· Expected future payment commitments;

· Expected timing of securing amendments to all DSAs pursuant to signing of the Decommissioning Relief Deed; and,

· Other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

Statements concerning oil and gas reserves contained in this interim MD&A may be deemed to be forward-looking information as they involve the implied assessment that the resources described can be profitably produced in the future.

The factors or assumptions on which the forward-looking information is based include: assumptions inherent in current guidance; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; ability to obtain regulatory and partner approval; commodity price and cost assumptions; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities.  The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 2014 assumes escalating commodity prices.

Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by Talisman and described in the forward-looking information contained in this MD&A. The material risk factors include, but are not limited to:

26

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

· Risks and uncertainties involving geology of oil and gas deposits;

· Risks associated with project management, project delays and / or cost overruns;

· Uncertainty related to securing sufficient egress and access to markets;

· The uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;

· The uncertainty of estimates and projections relating to production, costs and expenses, including decommissioning liabilities;

· Risks related to strategic and capital allocation decisions, including 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, interest rates and tax or royalty rates;

· Fluctuations in crude oil or natural gas prices could have a material adverse effect on the Company’s operations and financial condition, the value of its oil and natural gas reserves and its level of expenditure for oil and gas exploration and development. Downward trends in commodity prices could result in downward adjustments to the Company’s estimated reserves and asset values which could result in further impairment of assets;

· The outcome and effects of any future acquisitions and dispositions;

· Health, safety, security and environmental risks, including risks related to the possibility of major accidents;

· Environmental regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing;

· Uncertainties as to access to capital, including the availability and cost of credit and other financing, and changes in capital markets;

· Risks in conducting foreign operations (for example, civil, political and fiscal instability and corruption);

· Risks related to the attraction, retention and development of personnel;

· Changes in general economic and business conditions;

· The possibility that government policies, regulations or laws may change or governmental approvals may be delayed or withheld; and

· Results of the Company's risk mitigation strategies, including insurance and any hedging activities.

The foregoing list of risk factors 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 most recent AIF and Annual Report. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the SEC.

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

27

Advisory – Oil and Gas Information

Talisman makes reference to production volumes throughout this interim MD&A. 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 US, net production volumes are reported after the deduction of these amounts.

Talisman also discloses netbacks in this interim MD&A. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.

Non-Core Assets

In this MD&A, all references to “core” or “non-core” assets and properties align with the Company’s current public disclosures regarding its assets and properties.

Use of ‘boe’

Throughout this interim MD&A, the calculation of barrels of oil equivalent (boe) is 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. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf:1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

28

ABBREVIATIONS AND DEFINITIONS

The following abbreviations and definitions are used in this MD&A:

AIF	Annual Information Form
bbl	barrel
bbls	barrels
bbls/d	barrels per day
bcf	billion cubic feet
boe	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
COSO	Committee of the Sponsoring Organizations of the Treadway Commission
C$	Canadian dollar
DD&A	Depreciation, depletion and amortization
DSA	Decommissioning Security Agreements
DSU	Deferred share unit
E&E	Exploration and evaluation
EU	European Union
G&A	General and administrative
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gas emissions
gj	Gigajoule
IFRS	International Financial Reporting Standards
LIBOR	London Interbank Offered Rate
LLS	Light Louisiana Sweet
LNG	Liquefied Natural Gas
mbbls/d	thousand barrels per day
mboe/d	thousand barrels of oil equivalent per day
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmbbls	million barrels
mmboe	million barrels of oil equivalent
mmbtu	million British thermal units
mmcf/d	mllion cubic feet per day
mmcfe/d	million cubic feet equivalent per day
MWh	megawatt hour
NGL	Natural Gas Liquids
NI	National Instrument
NOK	Norwegian kroner
NYMEX	New York Mercantile Exchange
PGN	PT Perusahaan Gas Negara (Persero), Tbk
PP&E	Property, plant and equipment
PRT	Petroleum Revenue Tax
PSC	Production Sharing Contract
PSU	Performance share unit
RSU	Restricted share unit
SEC	US Securities and Exchange Commission
tcf	trillion cubic feet
UK	United Kingdom
UK£	Pound sterling
US	United States of America
US$ or $	United States dollar
WCS	Western Canadian Select
WTI	West Texas Intermediate

29

Gross acres means the total number of acres in which Talisman has a working interest.  Net acres means the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Gross production means Talisman’s interest in production volumes (through working interests and royalty interests) before the deduction of royalties. Net production means Talisman’s interest in production volumes after deduction of royalties payable by Talisman.

Gross wells means the total number of wells in which the Company has a working interest. Net wells means the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Conversion and equivalency factors

Imperial	Metric
1 ton	=   0.907 tonnes
1 acre	=   0.40 hectares
1 barrel	=   0.159 cubic metres
1 cubic foot	=   0.0282 cubic metres

30