Repsol Oil & Gas Canada 6K Interim Condensed Consolidated Financial Statements | TLM 13 Nov 15

Exhibit 99.2

TALISMAN ENERGY INC.

INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE PERIOD ENDED SEPTEMBER 30, 2015

Management’s Discussion and Analysis (MD&A)

(November 13, 2015)

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, 2015 and 2014, and the 2014 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.

All comparisons are between the three month periods ended September 30, 2015 and 2014, 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.

On May 8, 2015, the acquisition of Talisman by a wholly-owned subsidiary of Repsol S.A. (“Repsol”), by the way of an arrangement under the Canada Business Corporations Act, was completed. Repsol acquired all of the Company’s outstanding common and preferred shares. Upon the completion of the arrangement, the common shares were delisted from the Toronto Stock Exchange and the New York Stock Exchange, and the preferred shares were delisted from the Toronto Stock Exchange and converted into common shares on a 1:1 basis.

During the three month period ended September 30, 2015, Repsol Exploration Norge AS, a subsidiary of Repsol acquired substantially all of the assets and liabilities of Talisman’s Norwegian operations pursuant to a purchase and sale agreement dated April 14, 2015. The transaction closed on September 1, 2015. For further information, see the “Discontinued Operations” and “Transactions with Related Parties” section of the MD&A.

Use of “boe” and Change in Conversion Ratio

In conjunction with the acquisition of the Company by Repsol, the Company has adopted Repsol’s barrels of oil equivalent (boe) conversion ratio. The Company now applies a conversion factor of 1 barrel of oil equivalent (boe) equals 5,615 standard cubic feet of gas. The previous conversion ratio used was 6,000 standard cubic feet of gas. Comparative periods have been adjusted to reflect the change in conversion. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 5.615mcf:1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead.

Change of Norwegian functional currency

Subsequent to the sale of substantially all of the assets and liabilities of Talisman’s Norwegian operations on September 1, 2015, management has determined that the functional currency of the remaining Norwegian activities is more closely linked to the Norwegian Krone (NOK) than to the US$. Accordingly, effective September 1, 2015, these activities have been accounted for using a NOK functional currency. The impact of this change in functional currency during the third quarter of 2015 was to recognize a translation gain of $3 million included in other comprehensive income.

FINANCIAL AND OPERATING HIGHLIGHTS1,2

($ millions, unless otherwise	Nine Months Ended September 30				Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
stated)	2015		2014		2015		2015		2015		2014		2014		2014		2014		2013
Total revenue and other income from continuing operations	1,322		3,305		334		551		437		(71	)	995		1,134		1,176		779
Total revenue and other income from discontinued operations3	182		414		38		83		61		115		141		108		165		150
Total revenue and other income	1,504		3,719		372		634		498		44		1,136		1,242		1,341		929
Net income (loss) from continuing operations	(2,184	)	813		(899	)	(888	)	(397	)	(1,154	)	439		(207	)	581		(830	)
Net income (loss) from discontinued operations3	(294	)	(134	)	112		(364	)	(42	)	(436	)	(14	)	(30	)	(90	)	(175	)
Net income (loss)	(2,478	)	679		(787	)	(1,252	)	(439	)	(1,590	)	425		(237	)	491		(1,005	)
Per common share ($)
Net income (loss)4	(2.39	)	0.65		(0.75	)	(1.20	)	(0.43	)	(1.54	)	0.41		(0.23	)	0.47		(0.98	)
Diluted net income (loss)5	(2.42	)	0.57		(0.75	)	(1.24	)	(0.43	)	(1.54	)	0.38		(0.24	)	0.43		(0.98	)
Income (loss) from continuing operations per common share
Basic	(2.11	)	0.78		(0.86	)	(0.85	)	(0.39	)	(1.12	)	0.42		(0.20	)	0.56		(0.81	)
Diluted	(2.14	)	0.70		(0.86	)	(0.89	)	(0.39	)	(1.12	)	0.39		(0.21	)	0.52		(0.81	)
Production (Daily Average - Gross)
Oil and liquids (mbbls/d)	123		126		120		127		124		125		119		132		125		120
Natural gas (mmcf/d)	1,314		1,282		1,299		1,321		1,325		1,328		1,276		1,308		1,268		1,312
Continuing operations (mboe/d)	358		354		351		362		360		362		345		365		351		354
Assets sold or held for sale (mboe/d)6	15		32		13		16		16		18		23		27		50		50
Total mboe/d (5.615mcf = 1boe)	373		386		364		378		376		380		368		392		401		404

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

2. In the second quarter of 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

3. Discontinued Operations are the results associated with the Norway disposition.

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

5. 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.

6. Includes discontinued operations.

During the third quarter of 2015, the Company had a net loss of $787 million compared to net income of $425 million in the same quarter in 2014 due principally to lower commodity prices, slightly lower volumes, increased losses from joint ventures, asset impairments and no gains from held-for-trading financial instruments. These were partially offset by lower royalties, reduction in operating and general and administration expenses and the recognition of foreign exchange gains upon the completed sale of substantially all of the assets and liabilities of the Company’s Norwegian operations.

Production volumes from continuing operations remained relatively consistent in the third quarter of 2015 compared to the third quarter of 2014, with a small increase in natural gas production.

DAILY AVERAGE PRODUCTION

	Three months ended September 30
	Gross before royalties		Net of royalties
	2015	2014	2015	2014
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	40	41	34	33
Southeast Asia	33	43	22	28
North Sea	10	14	10	14
Other	14	16	8	8
	97	114	74	83
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK	20	12	20	12
Equion	13	9	11	7
	33	21	31	19
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	130	135	105	102
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	788	745	677	648
Southeast Asia	464	494	331	330
North Sea	18	21	18	21
	1,270	1,260	1,026	999
Natural gas from Joint Ventures (mmcf/d)
TSEUK	6	1	5	1
Equion	41	49	39	41
	47	50	44	42
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,317	1,310	1,070	1,041
Total Daily Production from Consolidated Subsidiaries (mboe/d)1
North America	180	173	154	148
Southeast Asia	116	131	81	87
North Sea	13	18	13	18
Other	14	16	8	8
	323	338	256	261
Total Daily Production from Joint Ventures (mboe/d)1
TSEUK	21	12	21	12
Equion	20	18	18	14
	41	30	39	26
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)1	364	368	295	287
Less production from assets sold or held for sale (mboe/d)1
North America	—	2	—	1
Southeast Asia	—	3	—	3
North Sea	13	18	13	18
	13	23	13	22
Total production from continuing operations (mboe/d)1	351	345	282	265

1. In the second quarter of 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

	Nine months ended September 30
	Gross before royalties		Net of royalties
	2015	2014	2015	2014
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	42	43	36	35
Southeast Asia	37	44	25	28
North Sea	12	13	12	13
Other	14	16	9	8
	105	116	82	84
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK	18	16	18	16
Equion	12	9	10	7
	30	25	28	23
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	135	141	110	107
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	788	801	683	696
Southeast Asia	481	510	345	344
North Sea	19	19	19	19
	1,288	1,330	1,047	1,059
Natural gas from Joint Ventures (mmcf/d)
TSEUK	4	2	4	2
Equion	41	47	34	38
	45	49	38	40
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,333	1,379	1,085	1,099
Total Daily Production from Consolidated Subsidiaries (mboe/d)1
North America	182	186	158	159
Southeast Asia	123	135	86	89
North Sea	15	16	15	16
Other	14	16	9	8
	334	353	268	272
Total Daily Production from Joint Ventures (mboe/d)1
TSEUK	19	16	19	16
Equion	20	17	16	14
	39	33	35	30
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)1	373	386	303	302
Less production from assets sold or held for sale (mboe/d)1
North America	—	13	—	12
Southeast Asia	—	3	—	1
North Sea	15	16	15	16
	15	32	15	29
Total production from continuing operations (mboe/d)1	358	354	288	273

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

Total production from continuing operations was 351 mboe/d, an increase of 2% compared to 2014 due principally to increased Joint Venture liquids production in TSEUK and Equion, partially offset by decreased production in Southeast Asia.

In North America, total production increased by 4% compared to 2014. Oil and liquids production decreased by 2% due principally to operational downtime and natural declines in the Eagle Ford, partially offset by development activity in Bigstone. Natural gas production increased by 6% due principally to development activity in Marcellus and Edson.

In Southeast Asia, total production decreased by 11% compared to 2014. Total oil and liquids production decreased by 23% and natural gas production decreased by 6% due principally to reduced demand in Indonesia, planned maintenance activities and the sale of its 7.48% interest in the Southeast Sumatra PSC in 2014.

Total production in TSEUK increased by 9 mboe/d due principally to production at Claymore, Tartan and Monarb which were shut down in the prior period, partially offset by maintenance work in Buchan and Auk North.

In the Other segment, including the Equion joint venture, total production remained consistent compared to 2014 due primarily to new wells and better well performance in Colombia, partially offset by uneconomic wells in Colombia being shut in, and production restrictions and operational issues in Algeria.

For details on production and netbacks related to the discontinued operations, see the “Discontinued Operations” section in this MD&A.

VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1,2

	Three months ended September 30				Nine months ended September 30
	2015		2014		2015		2014
North America - bbls/d	739		(652	)	(84	)	(235	)
Southeast Asia - bbls/d	(4,398	)	7,062		1,779		4,617
Other — bbls/d	2,218		6,549		597		2,379
Total produced into (sold out of) inventory — bbls/d	(1,441	)	12,959		2,292		6,761
Total produced into (sold out of) inventory — mmbbls	(0.1	)	1.2		0.6		1.8
Inventory at September 30 - mmbbls	2.0		2.8		2.0		2.8

1. Gross before royalties.

2. Excludes results of discontinued operations associated with the Norway disposition.

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 and title has transferred. 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.

During the three month period ended September 30, 2015, volumes in inventory decreased to 2.0 mmbbls from 2.1 mmbbls at the end of the second quarter due principally to decreased inventories in Malaysia and Colombia, partially offset by increased inventories in Algeria and Australia.

COMPANY NETBACKS1,2

	Three months ended September 30
	Gross before royalties		Net of royalties
Continuing Operations3	2015	2014	2015	2014
Oil and liquids ($/bbl)
Sales price	36.07	86.38	36.07	86.38
Royalties	10.19	27.89	—	—
Transportation	1.97	2.00	2.64	2.78
Operating costs	12.79	17.45	17.12	24.26
	11.12	39.04	16.31	59.34
Natural gas ($/mcf)
Sales price	3.47	5.85	3.47	5.85
Royalties	0.79	1.50	—	—
Transportation	0.25	0.26	0.32	0.35
Operating costs	0.96	1.15	1.23	1.54
	1.47	2.94	1.92	3.96
Total $/boe (5.615mcf=1boe)4
Sales price	24.14	49.52	24.14	49.52
Royalties	6.05	14.46	—	—
Transportation	1.56	1.64	2.04	2.24
Operating costs	7.44	9.88	9.81	13.63
	9.09	23.54	12.29	33.65

	Nine months ended September 30
	Gross before royalties		Net of royalties
Continuing Operations3	2015	2014	2015	2014
Oil and liquids ($/bbl)
Sales price	41.91	89.93	41.91	89.93
Royalties	11.23	30.00	—	—
Transportation	2.00	1.56	2.60	2.20
Operating costs	12.08	16.51	15.73	23.29
	16.60	41.86	23.58	64.44
Natural gas ($/mcf)
Sales price	3.72	6.17	3.72	6.17
Royalties	0.83	1.50	—	—
Transportation	0.25	0.24	0.33	0.31
Operating costs	1.05	1.11	1.35	1.49
	1.59	3.32	2.04	4.37
Total $/boe (5.615mcf=1boe)4
Sales price	26.97	51.44	26.97	51.44
Royalties	6.58	14.97	—	—
Transportation	1.59	1.41	2.06	1.92
Operating costs	7.69	9.35	10.03	12.78
	11.11	25.71	14.88	36.74

1. Netbacks do not include pipeline operations.

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

3. Excludes results of discontinued operations associated with the Norway disposition.

4. In the second quarter of 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

During the quarter, the Company’s average gross netback was $9.09/boe, 61% lower than 2014 due principally to lower realized prices, partially offset by lower royalties and lower operating costs.

Talisman’s realized net sales price of $24.14/boe was 51% lower than 2014, due principally to lower commodity prices. Oil and liquids realized prices decreased by 58% and natural gas realized prices decreased by 41% from 2014. The Company’s composite royalty rate was 25%, down from 29% in 2014 due principally to lower commodity prices.

COMMODITY PRICES AND EXCHANGE RATES1,2

		Three months ended September 30		Nine months ended September 30
Continuing Operations		2015	2014	2015	2014
Oil and liquids ($/bbl)
North America		27.82	67.90	29.00	67.32
Southeast Asia		44.44	102.24	53.85	107.91
Other		39.91	91.89	49.16	101.20
		36.07	86.38	41.91	89.93
Natural gas ($/mcf)
North America		2.22	3.72	2.34	4.34
Southeast Asia		5.61	9.07	5.97	9.05
		3.47	5.85	3.72	6.17
Company $/boe (5.615mcf=1boe)3		24.14	49.52	26.97	51.44
Benchmark prices and foreign exchange rates
WTI	(US$/bbl)	46.43	97.17	50.97	99.61
Dated Brent	(US$/bbl)	50.26	101.85	55.39	106.57
WCS	(US$/bbl)	33.16	77.20	37.80	78.59
LLS	(US$/bbl)	50.25	101.13	55.35	103.70
NYMEX	(US$/mmbtu)	2.77	4.07	2.80	4.51
AECO	(C$/gj)	2.65	4.00	2.66	4.32
C$/US$ exchange rate		1.31	1.09	1.26	1.09
UK£/US$ exchange rate		0.65	0.60	0.65	0.60

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

2. Excludes results of discontinued operations associated with the Norway disposition.

3. In the second quarter of 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

The Company’s overall realized oil and liquids price of $36.07/bbl decreased by 58% compared to 2014. In North America, realized oil and liquids prices decreased 59% due principally to decreases in benchmark crude prices. In Southeast Asia, realized oil and liquids prices decreased 57% due principally to decreases in Brent pricing.

The Company’s overall realized natural gas price of $3.47/mcf decreased by 41% compared to 2014. In North America, realized natural gas prices decreased 40% due principally to decreases in benchmark prices. In Southeast Asia, realized natural gas prices decreased by 38% where a portion of natural gas pricing is sold via fixed-price contracts.

EXPENSES

Unit Operating Expenses1,2

	Three months ended September 30
Continuing Operations	Gross before royalties		Net of royalties
($/boe)3	2015	2014	2015	2014
North America	6.09	7.54	7.12	8.84
Southeast Asia	8.71	12.15	12.40	18.40
Other	14.48	16.87	25.60	31.64
	7.44	9.88	9.81	13.63

	Nine months ended September 30
Continuing Operations	Gross before royalties		Net of royalties
($/boe)3	2015	2014	2015	2014
North America	6.76	7.68	7.81	9.01
Southeast Asia	8.35	11.36	11.84	17.18
Other	13.99	11.93	20.95	22.98
	7.69	9.35	10.03	12.78

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

2. Excludes results of discontinued operations associated with the Norway disposition.

3. In the second quarter of 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

Total Operating Expenses1,2


Continuing Operations	Three months ended September 30		Nine months ended September 30
($ millions)	2015	2014	2015	2014
North America	103	128	344	396
Southeast Asia	97	114	266	366
Other	15	21	49	44
	215	263	659	806

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

2. Excludes results of discontinued operations associated with the Norway disposition.

Total operating expenses decreased by 18% to $215 million due principally to cost reductions realized across the Company, favourable foreign exchange movements, the timing of liftings, and asset dispositions.

In North America, total operating expenses decreased by 20% to $103 million due principally to lower processing and operational costs in Eagle Ford and lower turnaround costs in Edson. Unit operating expenses in North America decreased by 19% due to lower costs and higher production.

In Southeast Asia, total operating expenses decreased by 15% to $97 million due principally to lower overall maintenance and operational costs, the renegotiation of contracts in Kitan resulting in reduced FPSO rates during shutdown periods, the sale of the Company’s 7.48% interest in the Southeast Sumatra PSC in 2014 and the completion of the jacket repair in Vietnam in 2014. Unit operating expenses decreased by 28% due to the reasons noted above which more than offset lower volumes.

In the Rest of the World, total operating expenses decreased by 29% to $15 million due principally to well shut-ins in Colombia, partially offset by the timing of liftings. Unit operating costs decreased by 14% due to the reasons noted above.

Unit Depreciation, Depletion and Amortization (DD&A) Expense1,2

	Three months ended September 30
Continuing Operations	Gross before royalties		Net of royalties
($/boe)3	2015	2014	2015	2014
North America	15.59	17.50	18.21	20.52
Southeast Asia	10.37	9.77	14.76	14.78
Other	11.98	8.98	21.19	16.85
	13.48	13.93	17.16	18.35

	Nine months ended September 30
Continuing Operations	Gross before royalties		Net of royalties
($/boe)3	2015	2014	2015	2014
North America	15.33	16.76	17.73	19.66
Southeast Asia	11.18	9.61	15.87	14.54
Other	11.73	10.12	17.57	19.49
	13.58	13.58	17.09	17.87

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

2. Excludes results of discontinued operations associated with the Norway disposition.

Total DD&A Expense1,2

Continuing Operations	Three months ended September 30		Nine months ended September 30
($ millions)	2015	2014	2015	2014
North America	258	282	767	844
Southeast Asia	122	111	372	341
Other	14	5	45	35
	394	398	1,184	1,220

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

2. Excludes results of discontinued operations associated with the Norway disposition.

Total DD&A expense in North America decreased by 9% due principally to a lower depletable base in Eagle Ford as a result of an impairment recognized in 2014, partially offset by an increase to the depletable base as a result of the change in discount rate used to measure the decommissioning liabilities, lower reserves in Edson and Chauvin and increased production in Marcellus, Edson and Duvernay. Unit DD&A expenses decreased 11% compared to 2014 due to the same reasons noted above.

In Southeast Asia, total DD&A expense increased 10% due principally to new well additions in Malaysia with higher DD&A rates, downward reserve revisions during 2014, increases to the depletable base in Indonesia as a result of the change in discount rate used to measure the decommissioning liabilities, partially offset by lower production in the current quarter and decreased production entitlement in HST/HSD. Unit DD&A expenses increased 6% compared to 2014 due to the same reasons noted above.

In the Rest of the World, total DD&A expense increased $9 million due principally to increases in the depletable base in Colombia, change in production mix in Algeria and timing of liftings. Unit DD&A expense increased by 33% due to the same reasons noted above.

Unit DD&A expense for the Company decreased by 3% to $13.48/boe due to the reasons noted above.

Impairment1,2

Continuing Operations	Three months ended September 30		Nine months ended September 30
($ millions)	2015	2014	2015	2014
Impairment losses
North America	325	—	325	—
Southeast Asia	—	—	48	—
	325	—	373	—
Impairment reversals
North America	—	—	—	(32	)
	—	—	—	(32	)
Net Impairment	325	—	373	(32	)

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

2. Excludes results of discontinued operations associated with the Norway disposition.

During 2014, the Company recorded a $614 million pre-tax ($614 million after-tax) impairment expense relating to Eagle Ford, of which $488 million was to PP&E assets and $126 million to E&E assets. The CGU consists of upstream properties and midstream assets. The impairment was taken mainly as a result of the overall lower commodity price environment leading to the decrease of the properties and asset valuation. The recoverable amount, as reflected by the fair value less cost to sell of the CGU, is $1.8 billion (using Level 2 fair value inputs). In developing its view of fair market value, management considered precedent Eagle Ford transactions. Precedent transactions from 2014 and 2013 were used to derive market metrics. A discount factor was applied to the historical 2014 and 2013 market metrics to reflect the lower liquids prices observed in the fourth quarter of 2014, the reduction determined by reference to comparable “pure play” companies operating in the CGU. During 2015, there was sustained decline in commodity prices and few precedent transactions. As a result, the Company applied a further discount to historical observed market metrics and recorded a $325 million pre-tax ($325 million after-tax) impairment expense of which $263 million was to PP&E assets and $62 million to E&E assets.

In conjunction with the acquisition of the Company by Repsol, Repsol has completed a preliminary allocation of the purchase price for purposes of its accounting subsequent to the acquisition date. As part of the purchase price allocation, Repsol estimated preliminary fair values of the Company’s assets and liabilities. Based on this preliminary assessment, certain of the Company’s assets could be impaired or subject to impairment reversals in future periods. Management has not recorded these potential impairments or reversals in the September 30, 2015 financial statements as the estimates are considered preliminary and subject to further review. The magnitude of any impairments or reversals to be recorded in future periods will be determined as the purchase price allocation is finalized.

Income (Loss) from Joint Ventures1

	Three months ended September 30				Nine months ended September 30
($ millions)	2015		2014		2015		2014
TSEUK	(208	)	(30	)	(529	)	(107	)
Equion	(23	)	17		(16	)	63
	(231	)	(13	)	(545	)	(44	)

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

The after-tax net loss in TSEUK is $178 million higher compared to 2014 due principally to lower realized commodity prices, increased DD&A expense from increased production, and deferred taxes, partially offset by lower operating costs and G&A.

The after-tax net loss in Equion of $23 million as compared to net income of $17 million in 2014 is due principally to lower realized commodity prices, increased DD&A expense from higher production and a higher depletable base, and increased deferred taxes, partially offset by lower operating costs and lower current tax.

Corporate and Other 1,2

	Three months ended September 30			Nine months ended September 30
($ millions)	2015	2014		2015		2014
General and administrative (G&A) expense	61	92		228		297
Dry hole expense	1	36		14		64
Exploration expense	20	44		142		127
Finance costs	83	79		246		245
Share-based payments expense (recovery)	—	(16	)	(24	)	(25	)
(Gain) loss on held-for-trading financial instruments	—	(428	)	(62	)	(197	)
(Gain) loss on asset disposals	—	(6	)	9		(560	)
Other income	24	35		105		112
Other expenses, net	34	(7	)	180		37

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

2. Excludes results of discontinued operations associated with the Norway disposition.

G&A expense decreased by $31 million compared to 2014 due principally to lower workforce expenses, reduced reliance on contractors in North America and Southeast Asia, and lower office expenses.

Exploration expense of $20 million consists primarily of seismic related costs in Southeast Asia and the Rest of the World.

Finance costs include interest on long-term debt (including current portion), other finance charges and accretion expense relating to decommissioning liabilities. Finance costs were relatively stable as compared to 2014.

Share-based payments recovery during the three month period ended September 30, 2015 was $nil due to the settlement of share-based payments in conjunction with the acquisition of the Company by Repsol in the second quarter of 2015.

There were no significant fair value changes to the Company’s held-for-trading financial instruments during the period ended September 30, 2015.

Other income of $24 million consists primarily of marketing and other income of $14 million and pipeline and customer treating tariffs of $6 million.

Other expense of $34 million includes a $14 million legal provision based on a proposed settlement agreement, a foreign exchange loss of $3 million and other miscellaneous expenses.

INCOME TAXES1,2

	Three months ended September 30				Nine months ended September 30
($ millions)	2015		2014		2015		2014
Income (loss) from continuing operations before taxes	(846	)	493		(1,764	)	1,195
Less: Petroleum Revenue Tax (PRT)
Current	2		(1	)	6		6
Deferred	2		3		(1	)	2
Total PRT	4		2		5		8
	(850	)	491		(1,769	)	1,187
Income tax expense (recovery)
Current income tax	(361	)	66		(230	)	324
Deferred income tax	410		(14	)	645		50
Total income tax expense	49		52		415		374
Effective income tax rate (%)	(6	)	11		(23	)	32

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

2. Excludes results of discontinued operations associated with the Norway disposition.

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 2015 was impacted by pre-tax losses of $474 million in North America where tax rates are between 27% and 39%, after-tax losses of $208 million in the TSEUK joint venture, partially offset by pre-tax income of $38 million in Southeast Asia where tax rates range from 30% to 58%.

For the three month period ended September 30, 2015, the current tax recovery was $361 million compared to current tax expense of $66 million in 2014 due principally to the sale of the Norwegian operations for a $419 million recovery and reduced operating income in Southeast Asia, partially offset by a recovery of $38 million from a settlement of an appeal with Canada Revenue Agency in 2014.

For the three month period ended September 30, 2015, the deferred tax expense was $410 million compared to a deferred tax recovery of $14 million in 2014 due principally to the sale of the Norwegian operations.

Impacts to the effective tax rate and the deferred tax expense are principally due to:

· Jurisdictional mix of income;

· Foreign exchange on foreign denominated tax pools;

· Completed sale of the Norwegian operations to Repsol Exploration Norge AS;

· The non-recognition of the tax benefit associated with losses in the United States and exploration blocks.

CAPITAL EXPENDITURES1

	Three months ended September 30			Nine months ended September 30
($ millions)	2015	2014		2015	2014
North America	224	348		555	949
Southeast Asia	55	125		163	308
Other	8	29		37	126
Exploration and development expenditure from subsidiaries2	287	502		755	1,383
Corporate, IS and Administrative	3	10		22	30
Acquisitions	3	—		11	36
Proceeds of dispositions	—	(102	)	—	(1,494	)
Net capital expenditure for subsidiaries	293	410		788	(45	)

TSEUK	80	121		290	454
Equion	11	30		32	64
Exploration and development expenditure from joint ventures3	91	151		322	518

Net capital expenditure for consolidated subsidiaries and joint ventures	384	561		1,110	473

1. Excludes results of discontinued operations associated with the Norway disposition.

2. Excludes exploration expense of $20 million (2014 - $44 million) for the three month period ended September 30, 2015 and $142 million (2014 - $127 million) for the nine month period ended September 30, 2015.

3. Represents the Company’s proportionate interest, excluding exploration expensed of $1 million net in TSEUK (2014 - $3 million) for the three month period ended September 30, 2015 and $2 million net in TSEUK (2014 - $5 million) for the nine month period ended September 30, 2015.

Capital expenditures, excluding exploration expense, decreased in the third quarter of 2015 compared to the same quarter in 2014 due principally to decreased spending across all regions.

North America capital expenditures during the quarter totalled $224 million, a decrease of 36% from 2014. Of this, $179 million related to development activity, with the majority spent in the Marcellus, Eagle Ford, Edson and Chauvin areas. The remaining capital was mainly invested in exploration drilling activities, primarily in the Duvernay.

In Southeast Asia, capital expenditures of $55 million included $46 million on development, with the majority spent in Vietnam and Indonesia. The majority of the remaining expenditures were exploration costs focused in Vietnam and Papua New Guinea.

In the Rest of the World, capital expenditures of $8 million consisted primarily of development spending on facilities in Colombia.

In the TSEUK joint venture, net capital expenditures of $80 million consisted primarily of development activities in the Montrose area and at Flyndre/Cawdor. In the Equion joint venture, net capital expenditures of $11 million related primarily to new development wells and facilities expansion in Piedemonte.

DISCONTINUED OPERATIONS

On September 1, 2015, Talisman completed the sale of substantially all of the assets and liabilities of Talisman’s Norwegian operations (the “Disposal Group”), to Repsol Exploration Norge AS, a subsidiary of Repsol, for proceeds of $47 million including working capital. Talisman retained a corporate income tax asset.

Operating results related to the Disposal Group have been included in net income (loss) from discontinued operations in the condensed Consolidated Statements of Income (Loss). Comparative period balances of the condensed Consolidated Statements of Income (Loss) and Cash Flows have been restated. During the three months ended June 30, 2015, the Disposal Group was remeasured to its recoverable amount of $47 million and as a result, a loss on remeasurement of discontinued operations of $472 million pre-tax ($292 million after-tax) was recorded in Norway. When the acquisition closed on September 1, 2015, an additional $10 million pre-tax loss on remeasurement of discontinued operations ($2 million after-tax) was recorded. Foreign exchange gains of $114 million relating to the Disposal Group previously recognized in accumulated other comprehensive income was included in the “Net income (loss) from discontinued operations” on the condensed Consolidated Statements of Income (Loss).

Net income (loss) from discontinued operations reported on the condensed Consolidated Statements of Income (Loss) is composed of the following:

Three months ended September 30	2015		2014
Revenue	38		141
Expenses	(28	)	(167	)
	10		(26	)
Loss on remeasurement of discontinued operations	(10	)	—
Realized accumulated translation adjustments on disposition of foreign operation	114		—
Income (loss) from discontinued operations before taxes	114		(26	)
Income taxes
Current income tax recovery	(1	)	(7	)
Deferred income tax expense (recovery)	3		(5	)
Net income (loss) from discontinued operations	112		(14	)

Nine months ended September 30	2015		2014
Revenue	182		414
Expenses	(429	)	(714	)
	(247	)	(300	)
Loss on remeasurement of discontinued operations	(482	)	—
Realized accumulated translation adjustments on disposition of foreign operation	114		—
Loss from discontinued operations before taxes	(615	)	(300	)
Income taxes
Current income tax recovery	(8	)	(12	)
Deferred income tax recovery	(313	)	(154	)
Net loss from discontinued operations	(294	)	(134	)

During the nine month period ended September 30, 2015, the Company recorded an impairment of $118 million in Norway E&E assets to fully impair costs associated with a license after a dry exploration well confirmed the license to be uneconomic. In addition, the Company recorded an impairment of $30 million in Norway, due to an increase in the

decommissioning obligation and asset caused by a 1.5% decrease in the credit-adjusted discount rate used to measure decommissioning liabilities.

During the nine month period ended September 30, 2014, the Company recorded an impairment of $60 million in Norway, due to an increase in the decommissioning obligation and asset caused by a 1% decrease in the credit-adjusted discount rate used to measure decommissioning liabilities. The Company also recorded $130 million of impairment expense in Norway as a result of the Company’s decision to withdraw from an exploration license following technical evaluation, representing the full book value of the license.

The cash flows from discontinued operations, including changes in related non-cash working capital items, are as follows:

	Three months ended September 30				Nine months ended September 30
	2015		2014		2015		2014
Operating	(5	)	7		(29	)	44
Investing	46		(35	)	9		(160	)
Cash flows from discontinued operations	41		(28	)	(20	)	(116	)

Netbacks for Discontinued Operations1,2

	Three months ended September 30			Nine months ended September 30
Discontinued Operations	2015	2014		2015		2014
Total $/boe (5.615mcf=1boe)
Sales price	37.05	80.79		48.19		89.58
Transportation	2.97	5.88		3.07		4.80
Operating costs	26.99	43.27		33.18		52.83
DD&A	—	35.70		21.56		41.52
	7.09	(4.06	)	(9.62	)	(9.57	)

2. Production before royalties and net of royalties are the same as Norway does not have any royalties. Thus, the netback table presented would be the same for both ‘gross before royalties’ and ‘net of royalties’ for the periods noted.

Commodity Pricing for Discontinued Operations

	Three months ended September 30		Nine months ended September 30
Discontinued Operations	2015	2014	2015	2014
Oil and liquids ($/bbl)	36.51	91.59	50.60	100.53
Natural gas ($/mcf)	6.90	7.22	7.04	8.11
Sales price ($/boe)1	37.05	80.79	48.19	89.58

LIQUIDITY AND CAPITAL RESOURCES

Talisman’s gross debt at September 30, 2015 was $4.9 billion, including loans from related parties of $959 million, compared to $5.1 billion at December 31, 2014.

During the quarter, the Company generated $169 million of cash provided by operating activities and incurred capital expenditures of $295 million.

Talisman’s capital structure consists of shareholder’s equity and debt. The Company makes adjustments to its capital structure based on changes in economic conditions and its planned requirements.

On May 8, 2015, TE Holdings SARL., a subsidiary of Talisman, entered into a $500 million revolving facility with Repsol Tesoreria Y Gestion Financiera, S.A. The facility matures on May 8, 2016 and bears an interest rate of LIBOR+0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. See the “Transactions with Related Parties” section.

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$1.0 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 and related parties credit facilities. The Company has in place committed bank facilities totaling $3.2 billion, all of which are committed through 2019.

At September 30, 2015, there were no drawings in the form of bankers’ acceptance or commercial paper, and there was $79 million in letters of credit support outstanding. Available borrowing capacity under committed bank facilities was $3.1 billion at September 30, 2015. In addition, the Company also has in place related party facilities from Repsol subsidiaries totaling $1.5 billion, all of which are committed through 2018. At September 30, 2015, $959 million were drawn under these facilities.

The authorized amount under the Company’s commercial paper program is $1.0 billion, but the amount available under this program is limited to the availability of backup funds under the Company’s Facility No. 1. For additional information regarding the Company’s Facilities, refer to note 18 to the Company’s 2014 audited Consolidated Financial Statements and note 14 in the Company’s interim condensed Consolidated Financial Statements.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At September 30, 2015, demand letters of credit guaranteed by the Company totaling $1.2 billion were issued, of which $1.1 billion were issued from uncommitted facilities. Of that total, $0.9 billion 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 Petroleum UK Limited (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 UK 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 by 50%. TSEUK has entered into a Decommissioning Relief Deed with the UK government and continues to negotiate with counterparties to amend all DSAs accordingly. Tax relief guaranteed by the UK government is limited to corporate tax paid since 2002. Under the limitation, TSEUK’s tax relief is capped at $2.1 billion, representing corporate income taxes paid and recoverable since 2002.

At September 30, 2015, TSEUK has $2.6 billion of demand shared facilities in place under which letters of credit of $1.8 billion have been issued. The Company guarantees 51% of all letters of credit issued under these shared facilities.

The Company also has obligations to fund, in proportion of its shareholding, the losses and net asset deficiency of TSEUK which arises from the Company’s past practice of funding TSEUK’s cash flow deficiencies, and the expectation that cash flow deficiencies will continue to be funded through 2016. In addition, the Company, in proportion of its shareholding, has provided certain guarantees to fund TSEUK’s decommissioning obligation if TSEUK is unable to, and the shareholders of TSEUK have provided equity funding facilities to TSEUK which include funding decommissioning liabilities. As such, the Company has recognized a negative investment value from the application of equity accounting. The Company’s obligation to fund TSEUK will increase to the extent future losses are generated within TSEUK. In addition, future contributions to the TSEUK joint venture could be impaired to the extent recoverability is not probable.

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.

Talisman monitors 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 and related parties facilities. The debt-to-cash flow ratio is calculated using debt (calculated by adding the gross debt and bank indebtedness, loans from related parties, 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, 2015, the debt-to-cash flow ratio was 1.7. Considering the current commodity price environment, Talisman may require support from Repsol to ensure continued compliance with its liquidity and covenant requirements.

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, 2015, approximately 80% of the Company’s trade accounts receivables were current and the largest single counterparty exposure, accounting for 5% of the total, was with a highly rated counterparty. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base consisting primarily of highly rated counterparties.

During the nine month period ended September 30, 2015, Talisman declared common share dividends of $0.1125 per common share for an aggregate dividend of $117 million. Subsequent to September 30, 2015, there was no movement in the number of common shares outstanding resulting in 1,044,166,028 common shares outstanding at November 10, 2015.

In the first quarter of 2015, Talisman declared preferred share dividends of C$0.2625 per share for an aggregate dividend of $2 million. On May 8, 2015, Repsol’s acquisition of Talisman was completed, whereby Repsol acquired all outstanding common and preferred shares of Talisman. The outstanding preferred shares were subsequently converted on a 1:1 basis into common shares. Consequently there were no preferred shares outstanding at September 30, 2015.

Subsequent to the acquisition of Talisman by Repsol on May 8, 2015, all share-based payment units have been settled and paid by May 29, 2015. At September 30, 2015 there were no stock options, RSUs, deferred share units (DSU) or long-term PSUs outstanding.

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.

For additional information regarding the Company’s liquidity and capital resources, refer to note 20 to the Company’s 2014 audited Consolidated Financial Statements and notes 14, 16 and 17 in the Company’s interim condensed Consolidated Financial Statements.

SENSITIVITIES1

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 2015 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $54.84/bbl, a NYMEX natural gas price of approximately $2.85/mmbtu and exchange rates of US$0.79=C$1 and UK£1=US$1.51.

(millions of $)	Net Income		Cash Provided by Operating Activities2
Volume changes
Oil — 10,000 bbls/d	22		102
Natural gas — 60 mmcf/d	4		42
Price changes
Oil — $1.00/bbl	26		31
Natural gas (North America)3 — $0.10/mcf	23		25
Exchange rate changes
US$/C$ decreased by US$0.01	(4	)	(6	)
US$/UK£ increased by US$0.02	(8	)	6

1. Excludes results of discontinued operations associated with the Norway disposition.

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

3. Price sensitivity on natural gas relates to North America natural gas only. The Company’s exposure to changes in the natural gas prices in 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.

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 audited 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 decommissioning liabilities, debt repayment obligations and significant commitments can be found in notes 8, 16, 18, 19 and 24 to the 2014 audited 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.

Except for the commitments at December 31, 2014 associated with Talisman’s Norwegian operations listed below, there have been no significant changes to Talisman’s expected future commitments, and the timing of those payments, since December 31, 2014. As a result of the sale of substantially all of the assets and liabilities of Talisman’s Norwegian operations, the following commitments are no longer those of the Company:

	2015	2016	2017	2018	2019	Subsequent to 2019	Total
Office leases	2	2	—	—	—	—	4
Vessel leases	5	2	2	2	—	—	11
Transportation and processing commitments	55	3	—	—	—	—	58
Decommissioning liabilities	73	134	174	230	132	567	1,310
Yme removal obligation	186	—	—	—	—	—	186
PP&E and E&E assets	61	—	—	—	—	—	61
Other service contracts	18	—	—	—	—	—	18
	400	141	176	232	132	567	1,648

TRANSACTIONS WITH RELATED PARTIES

Repsol

Repsol’s acquisition of Talisman closed on May 8, 2015. During the period from May 8, 2015 to September 30, 2015, Talisman has entered into the following transactions, with Repsol and/or subsidiaries of Repsol.

On September 1, 2015, Talisman and Repsol completed the purchase and sale agreement, whereby Repsol acquired substantially all of the assets and liabilities of Talisman’s Norwegian operations. For further information, see the “Discontinued Operations” section in this MD&A and note 4 in the Company’s interim condensed Consolidated Financial Statements.

On May 8, 2015, TE Holdings SARL., a subsidiary of Talisman, entered into a $500 million revolving facility with Repsol Tesoreria Y Gestion Financiera, S.A. The facility matures on May 8, 2016 and bears an interest rate of LIBOR+0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. As at September 30, 2015, $205 million has been drawn under this facility. Interest expense related to the facility recognized by Talisman during the quarter was $1 million.

On May 8, 2015, Talisman also entered into a $1.0 billion revolving facility with Repsol Energy Resources Canada, Inc. The facility matures on May 8, 2018 and bears an interest rate of LIBOR+1.20%. As at September 30, 2015, $754 million has been drawn under this facility. Interest expense related to the facility recognized by Talisman during the quarter was $3 million.

The nature and scope of related party transactions could increase in future periods as integration activities with Repsol continue. Specifically, changes for technical and administrative support as well as further asset transactions may occur.

Southeast Asia

Talisman entered into a commitment in 2001 to sell gas of 367.5 mmbtu daily in the Corridor Block in Indonesia to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings Limited (“Temasek”). The commitment matures in 2023. As a result of Repsol’s acquisition of Talisman on May 8, 2015, GSPL and Temasek became Talisman’s related parties. Since May 8, 2015, Talisman gas sales to GSPL totaled $93 million (net Talisman’s share). As at September 30, 2015, the amount included in accounts receivable as a result of this commitment was $20 million.

Other

In June and August 2015, Talisman (Algeria) B.V. (“TABV”) entered into Sale and Purchase Agreements with Repsol Trading S.A., a subsidiary of Repsol, under which TABV sold to Repsol approximately 615,000 barrels and 269,000 barrels of Saharan Blend Crude Oil for $38 million and $12 million, respectively. As at September 30, 2015, there were no outstanding receivable balances as a result of these transactions.

In July 2015, Talisman (Colombia) Oil and Gas Ltd. (“TCOG”) entered into a Sale and Purchase Agreement with Repsol Trading S.A., a subsidiary of Repsol, under which TCOG sold to Repsol approximately 229,000 barrels of Crude Oil for $11 million. As at September 30, 2015, there were no outstanding receivable balances as a result of this transaction.

TSEUK

The shareholders of TSEUK have provided an unsecured loan facility totaling $2.4 billion to TSEUK, of which Talisman is committed to $1.2 billion, for the purpose of funding capital expenditures of TSEUK. In January 2015, an agreement was reached by the shareholders of TSEUK, in which the quarterly principal and interest payments of the facility were deferred until July 31, 2015.

In July 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $1.1 billion, of which Talisman’s share was $541 million, which settled remaining shareholder loans of $1.0 billion and accrued interest of $52 million, of which Talisman’s share was $514 million and $27 million, respectively. There was no loan balance outstanding as at September 30, 2015.

In June 2015, the shareholders of TSEUK provided a new equity funding facility of $1.7 billion, of which Talisman is committed to $867 million, for the purpose of funding capital, decommissioning and operating expenditures of TSEUK. This facility is effective from July 1, 2015 and expires on December 31, 2016. During the three month period ended September 30, 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $190 million under this facility, of which Talisman’s share was $97 million.

In June 2014, the shareholders of TSEUK provided an equity funding facility totaling $1.2 billion to TSEUK, of which Talisman was committed to $612 million, for the purpose of funding capital, decommissioning and operating expenditures of TSEUK. In March 2015, the maximum available amount was increased to $1.5 billion. This facility expired on June 30, 2015. During the period from July 1, 2014 to December 31, 2014, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $625 million under this facility, of which Talisman’s share was $319 million. During the six month period ended June 30, 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $710 million under this facility, of which Talisman’s share was $362 million. For further information see note 6 and note 19 in the interim condensed Consolidated Financial Statements.

RISK MANAGEMENT

Talisman monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, Talisman may periodically enter 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.

During the nine month period ended September 30, 2015, the Company received proceeds of $1.3 billion for settlement of its oil and gas derivative contracts, which included proceeds related to the liquidation of outstanding instruments. As at September 30, 2015, there was less than $1 million of risk management liability associated with the Company’s outstanding fixed price power swaps.

Subsequent to September 30, 2015, the Company has not entered into any additional new commodity price risk management derivative contracts.

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.

As a result of Repsol’s acquisition of Talisman in May 2015, credit-adjusted rates specific to Repsol have been used to discount Talisman’s decommissioning liabilities. The provision has been calculated using the current estimated cost to retire the asset inflated to the estimated retirement date and then discounted using a weighted average credit-adjusted rate of 4.3% at September 30, 2015.

For additional information regarding the use of estimates and judgments refer to the notes to the Company’s audited Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2014.

SIGNIFICANT ACCOUNTING POLICIES

a) Changes in Accounting Policies

The interim condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the 2014 audited annual Consolidated Financial Statements, except for the following:

Foreign Currency Translation

b) Accounting Policies Used

The interim condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the Company’s audited annual Consolidated Financial Statements as at and for the year ended December 31, 2014, except for adoption of the following amendments to standards effective as of January 1, 2015:

Employee Benefits

· IAS 19 Employee Benefits - Amendments to IAS 19. The amended standard clarified the requirements that relate to how contributions from employees or third parties that are linked to service should be attributed to periods of service. In addition, it permits a practical expedient if the amount of the contributions is independent of the number of years of service, in that contributions can be, but are not required to be recognized as a reduction in the service cost in the period in which the related service is rendered. The amendment is effective for annual periods beginning on or after July 1, 2014. Application of the amended standard does not have an impact on the Company’s financial statements as it reflects current accounting policy of the Company.

Operating Segments

· IFRS 8 Operating Segments - Amendments to IFRS 8. The amended standard requires (i) disclosure of judgments made by management in aggregating segments, and (ii) a reconciliation of segmented assets to the Company’s assets when segment assets are reported. The amendment is effective for annual periods beginning on or after July 1, 2014. The amendment does not have an impact on the Company’s financial statements.

Fair Value Measurement

· IFRS 13 Fair Value Measurement - Amendments to IFRS 13. The amended standard clarifies that short-term receivables and payables with no stated interest rates can be measured at invoice amounts if the effect of discounting is immaterial. It also clarifies that the portfolio exception can be applied not only to financial assets and liabilities, but also to other contracts within scope of IAS 39 and IFRS 9. The amendment is effective for annual periods beginning on or after July 1, 2014. The application does not have a significant impact on the Company’s financial statements.

Related Parties

· IAS 24 Related Parties - Amendments to IAS 24. The amended standard (i) revises the definition of related party to include an entity that provides key management personnel services to the reporting entity or its parent, and (ii) clarifies related disclosure requirements. The amendment does not have an impact on the Company’s financial statements, as there is no entity performing key management services for the Company.

c) Accounting Pronouncements Not Yet Adopted

The Company continues to assess the impact of adopting the pronouncements from the IASB as described below:

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 from Contracts with Customers

· IFRS 15 Revenue from Contracts with Customers. IFRS 15 specifies that revenue should be recognized when an entity transfers control of goods or services at the amount the entity expects to be entitled to 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. Initially, IFRS 15 was effective for annual periods beginning on or after January 1, 2017. On September 11, 2015, the IASB issued an amendment to the standard deferring the effective date to January 1, 2018. Application of the standard is mandatory and early adoption is permitted. The Company continues to review the standard as it is updated and monitor its impact 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, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

LEGAL PROCEEDINGS AND CONTINGENCIES

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 currently expected to have a material impact on the Company’s financial position. A summary of specific legal proceedings and contingencies is as follows:

Galley Pipeline

In August 2012, a portion of the Galley pipeline, in which TSEUK has a 67.41% interest, suffered an upheaval buckle.

In September 2012, TSEUK, in which Talisman holds a 51% interest, claimed for the suffered losses as a consequence of the incidence to Oleum Insurance Company (“Oleum”), a wholly-owned Talisman subsidiary. TSEUK delivered a proof of loss seeking recovery under the insuring agreement of $315 million.

The information delivered by TSEUK in November 2014 purporting to substantiate its claim did not support a determination of coverage and Oleum sought additional information from TSEUK to facilitate final coverage

determination.

TSEUK has sent additional information to Oleum that is being reviewed by external counsel.

Addax Arbitration

On July 13, 2015, Addax Petroleum UK Limited and Sinopec International Petroleum Exploration and Production Corporation, filed a Notice of Arbitration against Talisman Energy Inc. (“TEI”) and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% shares of Talisman Energy (UK) Limited (now known as TSEUK). TEI and TCHL have filed their responses to the Notice of Arbitration on October 1, 2015. In the Company’s opinion, the claims included in the Notice of Arbitration are without merit.

Government and Legal Proceedings with Tax Implications

Specific tax claims which Talisman and its subsidiaries are parties to at September 30, 2015 are as follows:

Canada

The Canadian tax authorities, Canada Revenue Agency, (“CRA”) regularly inspect the tax matters of the Talisman Group companies based in Canada. In 2015, verification and investigation activities related to the years 2006-2010 have been made.

As part of these proceedings, the CRA has questioned certain restructuring transactions, although this line of questioning has not resulted in court proceedings to date.

Indonesia

Indonesian Corporate Tax Authorities have been questioning various aspects of the taxation of permanent establishments that Talisman Group has in the country. These proceedings are pending a court hearing.

Malaysia

Talisman Malaysia Ltd. and Talisman Malaysia (PM3) Ltd., the Talisman Group’s operating subsidiaries in Malaysia, have received notifications from the Inland Revenue Board (IRB) in respect of the years 2007, 2008 and 2011 questioning, primarily, the deductibility of certain costs. These proceedings are pending a court hearing.

Timor-Leste

The authorities of Timor-Leste, questioned the deduction by TLM Resources (JPDA 06-105) Pty Limited, the Talisman Group’s subsidiary in East Timor, of certain expenses for income tax purposes. This line of questioning is at a very preliminary stage of debate with the authorities.

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;

· Expected capital expenditures, timing and planned focus of such spending;

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

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

· Anticipated funding of the decommissioning liabilities;

· Expected future payment commitments and the estimated timing of such payments;

· Matters with respect to continued compliance with covenants of credit facilities; 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: commodity price and cost assumptions; 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; 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 2015 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:

· Fluctuations in oil and gas prices, foreign currency exchange rates, interest rates and tax or royalty rates;

· 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;

· 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 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. 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.

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.

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
FPSO		Floating production storage and offloading
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		million cubic feet per day
mmcfe/d		million cubic feet equivalent per day
MWh		megawatt hour
NGL		Natural Gas Liquids
NI		National Instrument
NOK		Norwegian krone
NYMEX		New York Mercantile Exchange
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

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

Repsol Oil & Gas Canada (TLM) Inactive 6-KInterim Condensed Consolidated Financial Statements