Repsol Oil & Gas Canada (TLM) 6-K Talisman Energy 6-K

Exhibit 99.2

 INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE PERIOD ENDED MARCH 31, 2015

Management’s Discussion and Analysis (MD&A)

(May 7, 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 month periods ended March 31, 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 March 31, 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 December 15, 2014, Talisman entered into an arrangement agreement (“Arrangement Agreement”) with Repsol S.A. and an indirect wholly-owned subsidiary of Repsol (collectively “Repsol”), providing for the acquisition of Talisman. Under the terms of the Arrangement Agreement, the acquisition is to be accomplished through a plan of arrangement (“Arrangement”) under the Canada Business Corporations Act. If the Arrangement is completed, common shareholders will receive US$8.00 for each common share that they own and preferred shareholders will receive C$25.00 plus accrued and unpaid dividends to the date of completion of the Arrangement for each preferred share that they own. The terms of the Arrangement Agreement contain certain restrictions on the Company’s activities without the approval of Repsol including, but not limited to, acquisitions and disposals of assets, certain actions related to employees, and the Company’s legal and organizational structures. The transaction was approved by the common shareholders on February 18, 2015 and regulatory approvals required under the arrangement agreement with Repsol have been obtained. The transaction is expected to close on May 8, 2015. Completion of the transaction remains subject to the satisfaction of customary closing deliverables.

Subsequent to March 31, 2015, Talisman and Repsol entered into a purchase and sale agreement whereby Repsol will acquire substantially all of the assets and liabilities of Talisman’s Norwegian operations. The transaction is subject to a number of conditions precedent, including the closing of Repsol’s acquisition of Talisman, a final determination of certain values in the purchase and sale agreement, and certain government approvals.

1

FIRST QUARTER 2015 PERFORMANCE HIGHLIGHTS

· Production from ongoing operations averaged 360,000 boe/d in the first quarter of 2015, up 2% from the first quarter of 2014. Liquids production was 137,000 bbl/d, down 4% from the first quarter of 2014.

· General and administrative (G&A) expense for the quarter was $86 million, down 18% from the first quarter of 2014.

· Operating expenses were $297 million, down 18% from the first quarter of 2014.

FINANCIAL AND OPERATING HIGHLIGHTS

	Q1		Q4		Q3	Q2		Q1	Q4		Q3		Q2
($ millions, unless otherwise stated)	2015		2014		2014	2014		2014	2013		2013		2013
Total revenue and other income1	498		44		1,136	1,242		1,341	929		1,244		1,190
Net income (loss)	(439	)	(1,590	)	425	(237	)	491	(1,005	)	(54	)	97
Per common share ($)
Net income (loss)2	(0.43	)	(1.54	)	0.41	(0.23	)	0.47	(0.98	)	(0.05	)	0.09
Diluted net income (loss)3	(0.43	)	(1.54	)	0.38	(0.24	)	0.43	(0.98	)	(0.08	)	0.06
Production4 (Daily Average - Gross)
Oil and liquids (mbbls/d)	137		140		135	145		142	137		134		126
Natural gas (mmcf/d)	1,342		1,347		1,310	1,380		1,452	1,505		1,423		1,414
Total mboe/d (6mcf = 1boe)	360		365		353	375		384	387		371		361

1. Includes other income and income (loss) from joint ventures and associates, after tax.

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 first quarter of 2015, the Company had a net loss of $439 million compared to net income of $491 million in the same quarter in 2014 principally due to lower gas, and oil and liquids prices in 2015, increased losses from joint ventures as well as higher gains on dispositions in 2014. This was partially offset by gains on held-for-trading instruments, lower impairment expenses and lower operating expenses.

Higher production volumes from ongoing operations in the first quarter of 2015 were primarily driven by increased volumes in North America, partially offset by decreased production from Southeast Asia.

2

DAILY AVERAGE PRODUCTION

	Three months ended March 31
	Gross before royalties				Net of royalties
	2015		2014		2015		2014
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America		45		42		38		34
Southeast Asia		39		44		27		28
North Sea		13		14		13		14
Other		14		15		9		7
		111		115		87		83
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK		15		18		15		18
Equion		11		9		9		7
		26		27		24		25
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)		137		142		111		108
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America		798		867		695		759
Southeast Asia		483		522		347		351
North Sea		17		15		17		15
Other		-		-		-		-
		1,298		1,404		1,059		1,125
Natural gas from Joint Ventures (mmcf/d)
TSEUK		2		2		2		2
Equion		42		46		32		38
		44		48		34		40
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)		1,342		1,452		1,093		1,165
Total Daily Production from Consolidated Subsidiaries (mboe/d)
North America		177		186		153		161
Southeast Asia		119		131		85		86
North Sea		16		17		16		17
Other		14		15		9		7
		326		349		263		271
Total Daily Production from Joint Ventures (mboe/d)
TSEUK		16		18		16		18
Equion		18		17		14		14
		34		35		30		32
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)		360		384		293		303
Less production from assets sold or held for sale (mboe/d)
North America		-		28		-		26
Southeast Asia		-		3		-		2
		-		31		-		28
Total production from ongoing operations (mboe/d)		360		353		293		275

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

Production from ongoing operations increased by 2% compared to 2014 due primarily to increased production in North America.

In North America, total production decreased by 5%, and production from ongoing operations increased by 12% compared to 2014. Oil and liquids production from ongoing operations increased by 7% due principally to increased production from the Edson area primarily as a result of new development wells in the Wildrich play. Natural gas production from ongoing operations increased by 14% primarily due to increased production from the Marcellus and Edson areas.

3

In Southeast Asia, total production decreased by 9%, and production from ongoing operations decreased by 7%. Oil and liquids production from ongoing operations decreased by 5% due principally to a reduction in the Company’s production entitlement at HST/HSD due to partner’s carrying costs being fully recouped in 2014. These declines were partially offset by higher production at Kinabalu following a multi-well infill program in 2014. Natural gas production from ongoing operations decreased by 7% due principally to reduced gas demand at Corridor and PM3.

Production in Norway decreased by 6% due principally to reduced production at Varg due to shutdown of the Armada platform, partially offset by increased production at Veslefrikk. In the TSEUK joint venture, production decreased by 11% due principally to shutdowns for a workover at Tweedsmuir and for repairs at Auk.

In the Rest of the World, including the Equion joint venture, production was stable compared to prior year.

VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1,2

	Three months ended March 31
	2015			2014
North America - bbls/d		278			533
Southeast Asia - bbls/d		(356	)		2,922
North Sea - bbls/d		1,907			(1,333	)
Other - bbls/d		402			3,694
Total produced into (sold out of) inventory - bbls/d		2,231			5,816
Total produced into (sold out of) inventory - mmbbls		0.2			0.5
Inventory at March 31 - mmbbls		1.7			1.7

1. Gross before royalties.

2. North Sea volumes only include Norway.

The Company's 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.

During the three month period ended March 31, 2015, volumes in inventory increased from 1.5 mmbbls at December 31, 2014 to 1.7 mmbbls at March 31, 2015 due principally to increased inventories in North America, Southeast Asia and Norway, partially offset by decreased inventories in the Rest of the World.

4

COMPANY NETBACKS1,2

	Three months ended March 31
	Gross before royalties				Net of royalties
	2015		2014		2015		2014
Oil and liquids ($/bbl)
Sales price		40.39		93.35		40.39		93.35
Royalties		9.50		26.95		-		-
Transportation		2.12		1.45		2.77		2.04
Operating costs		15.95		21.40		20.85		30.09
		12.82		43.55		16.77		61.22
Natural gas ($/mcf)
Sales price		4.00		6.50		4.00		6.50
Royalties		0.85		1.49		-		-
Transportation		0.28		0.27		0.35		0.35
Operating costs		1.21		1.15		1.54		1.50
		1.66		3.59		2.11		4.65
Total $/boe (6mcf=1boe)
Sales price		29.54		56.92		29.54		56.92
Royalties		6.61		14.86		-		-
Transportation		1.82		1.56		2.34		2.11
Operating costs		10.20		11.70		13.08		15.56
		10.91		28.80		14.12		39.25

1. Netbacks do not include pipeline operations.

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

During 2015, the Company’s average gross netback was $10.91/boe, 62% lower than 2014 due principally to lower realized prices, partially offset by lower royalties and lower operating costs.

Talisman’s realized net price of $29.54/boe was 48% lower than 2014, due principally to lower commodity prices. Oil and liquids realized prices decreased by 57% and natural gas realized prices decreased by 38% from 2014.

The Company’s realized net sales 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 22%, down from 26% in 2014 due principally to lower royalty rates in Southeast Asia.

5

COMMODITY PRICES AND EXCHANGE RATES

	Three months ended March 31
	2015		2014
Oil and liquids sales prices ($/bbl)1
North America		23.51		68.05
Southeast Asia		53.09		110.34
North Sea		50.39		103.82
Other		48.65		104.17
		40.39		93.35
Natural gas sales prices ($/mcf)1
North America		2.60		4.87
Southeast Asia		6.20		9.13
North Sea		7.57		9.79
Other		-		-
		4.00		6.50
Company $/boe (6mcf=1boe)		29.54		56.92
Quarterly average benchmark prices and foreign exchange rates
WTI                        (US$/bbl)		48.63		98.68
Dated Brent           (US$/bbl)		53.97		108.22
WCS                       (US$/bbl)		33.82		75.56
LLS                         (US$/bbl)		52.75		104.44
NYMEX                 (US$/mmbtu)		2.96		4.90
AECO                     (C$/gj)		2.80		4.51
C$/US$ exchange rate		1.24		1.10
UK£/US$ exchange rate		0.66		0.60

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

In North America, realized oil and liquids prices decreased by 65% in 2015, principally due to price declines and increased liquids production in the product mix. In Southeast Asia, North Sea and the Rest of the World realized oil and liquids prices decreased consistent with decreases in Brent pricing.

In North America, realized natural gas prices decreased by 47% in 2015 and in Southeast Asia, realized natural gas prices decreased by 32%. A significant portion of natural gas in Southeast Asia is sold via fixed-price contracts or linked to oil based indices. Because of volumes sold under fixed-price contracts the decline in gas prices was less than the decline in benchmark oil prices. Due to these reasons, Talisman’s overall realized natural gas price of $4.00/mcf decreased by 38% compared to 2014.

6

EXPENSES

Unit Operating Expenses1

	Three months ended March 31
	Gross before royalties				Net of royalties
($/boe)	2015		2014		2015		2014
North America		7.91		8.23		9.13		9.56
Southeast Asia		9.60		11.39		13.55		17.29
North Sea		36.35		55.02		36.35		55.02
Other		14.04		8.57		22.12		17.24
		10.20		11.70		13.08		15.56

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

Total Operating Expenses1

	Three months ended March 31
	2015		2014
($ millions)
North America		127		134
Southeast Asia		109		122
North Sea		46		98
Other		15		7
		297		361

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

Total operating expenses decreased by 18% to $297 million due principally to operating expense reductions being implemented across the Company, the timing of liftings, asset dispositions and favourable foreign exchange changes.

In North America, total operating expenses decreased by 5% to $127 million principally due to dispositions of non-core western Canadian properties in 2014, partially offset by increased production activity in remaining properties and the timing of liftings. Unit operating expenses in North America decreased by 4% due principally to a change in product mix as remaining assets have lower operating costs than assets disposed of in western Canada.

In Southeast Asia, total operating expenses decreased by 11% due primarily to the implementation of operating expense reductions, the disposition of Southeast Sumatra assets in 2014 and completion of the jacket repair in HST/HSD during 2014, partially offset by the timing of liftings. Unit operating expenses in Southeast Asia decreased by 16% due to the reasons noted above.

In the North Sea, total operating expenses in Norway decreased by 53% due principally to the timing of liftings, foreign exchange gains, and reduced costs associated with the cessation of production at Rev. Unit operating costs in Norway decreased by 34% due to the reasons noted above.

In the Rest of the World, total operating expenses increased by $8 million due principally to higher crude treatment costs in Colombia and the timing of liftings in Algeria. Unit operating costs rose by 64% due to the reasons above.

Unit operating expense for the Company decreased by 13% due to the reasons noted above.

7

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

	Three months ended March 31
	Gross before royalties				Net of royalties
($/boe)	2015		2014		2015		2014
North America		15.99		15.91		18.46		18.46
Southeast Asia		12.60		10.06		17.78		15.39
North Sea		32.18		46.87		32.18		46.87
Other		11.25		10.47		17.73		19.71
		15.35		15.20		19.06		19.46

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

Total DD&A Expense1

	Three months ended March 31
	2015		2014
($ millions)
North America		257		266
Southeast Asia		138		116
North Sea		43		77
Other		16		10
		454		469

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

Total DD&A expense decreased by 3% primarily due to decreased expense in the North Sea, partially offset by increased expense in Southeast Asia.

DD&A expense in North America decreased by 3% principally due to a lower depletable base in Eagle Ford as a result of impairment expenses recognized in 2014, partially offset by increased production from ongoing operations and higher DD&A rates in Canada. Unit DD&A expense was stable compared to 2014.

In Southeast Asia, DD&A expense increased by 19% principally due to 2014 well additions that have higher DD&A rates, as well as downward reserve revisions during 2014, partially offset by lower production and decreased production entitlement in HST/HSD. Unit DD&A expense increased by 25%, due principally to new wells with higher DD&A rates and downward reserve revisions as mentioned above.

In the North Sea, DD&A expense for Norway decreased by 44% due principally to 2014 impairment expenses at Gyda and Varg, which reduced the book value of those properties to $nil, as well as decreased production. Unit DD&A expense decreased by 31% due to the reasons noted above.

In the Rest of the World, DD&A expense increased by $6 million due principally to the timing of liftings in Algeria. Unit DD&A expense increased by 7% principally due to an increased depletable base in Colombia and change in production mix in Algeria.

Unit DD&A expense for the Company was stable compared to 2014 due to the reasons noted above.

8

Impairment1

	Three months ended March 31
	2015		2014
($ millions)
Impairment losses
Southeast Asia		48		-
North Sea		5		130
		53		130

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

During the three month period ended March 31, 2015, the Company fully impaired a property in Australia for $46 million.

During the three month period ended March 31, 2014 in Norway, the Company recorded $130 million of impairment expense 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.

Income (Loss) from Joint Ventures1

	Three months ended March 31
	2015			2014
($ millions)
TSEUK		(206	)		(17	)
Equion		(1	)		23
		(207	)		6

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

The net loss in TSEUK increased by $189 million due principally to decreased revenue from lower realized oil prices, decreased income tax recoveries, and increased DD&A expense as a result of capital expenditures during the three months ended March 31, 2015 being fully depleted on certain producing assets that have no proved reserves.

During the quarter, the UK government announced that effective January 1, 2015 the rate of supplementary charge on ring fence profits decreased from 32% to 20%. Consequently, there is now a combined UK corporation tax and supplementary charge rate of 50% (down from 62%) for oil and gas companies with fields not subject to Petroleum Revenue Tax (PRT). The UK government also announced that the PRT rate will decrease from 50% to 35%, effective for years ending after December 31, 2015. As a result of this legislative change, TSEUK recorded a recovery of deferred PRT of $98 million ($50 million net to Talisman).

The TSEUK deferred tax asset, which is recovered in UK pound sterling, decreased during the quarter by $160 million ($82 million net to Talisman), primarily as a result of the strengthening of the US dollar against the UK pound sterling during the three months ended March 31, 2015.

The net loss in Equion of $1 million after-tax as compared to income of $23 million in 2014 is principally due to lower commodity prices, partially offset by an income tax recovery of $1 million versus tax expense of $15 million in 2014.

9

Corporate and Other 1

	Three months ended March 31
	2015			2014
($ millions)
General and administrative (G&A) expense		86			105
Dry hole expense		13			16
Exploration expense		26			52
Finance costs		91			91
Share-based payments recovery		(3	)		(32	)
(Gain) loss on held-for-trading financial instruments		(193	)		60
(Gain) loss on asset disposals		5			(559	)
Other income		40			48
Other expenses, net		17			8

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

G&A expense decreased by $19 million relative to 2014, due principally to lower workforce costs.

In the first quarter of 2015, Talisman recorded dry hole expense of $13 million principally due to the write-off of exploration wells in Colombia.

Exploration expense decreased by $26 million due principally to reduced spending in North America, the North Sea 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 stable as compared to prior year.

Share-based payments recovery during the three month period ended March 31, 2015 decreased by $29 million principally due to Talisman’s share price declining by less in 2015 than in 2014.

Talisman recorded a gain on held-for-trading financial instruments of $193 million, due principally to decreases in oil and gas forward prices in comparison to the fourth quarter of 2014. See the ‘Risk Management’ section of this MD&A for further details concerning the Company’s financial instruments.

Other income of $40 million consists primarily of marketing and other income of $18 million and pipeline and customer treating tariffs of $15 million.

Other expense of $17 million includes restructuring costs of $12 million and other miscellaneous expenses of $28 million partially offset by foreign exchange gains of $23 million.

10

INCOME TAXES 1

	Three months ended March 31
	2015			2014
($ millions)
Income (loss) before taxes		(402	)		591
Less: PRT
Current		2			8
Deferred		(2	)		3
Total PRT		-			11
		(402	)		580
Income tax expense (recovery)
Current income tax		67			123
Deferred income tax		(30	)		(34	)
Total income tax expense		37			89
Effective income tax rate (%)		(9	)		15

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 first quarter of 2015 was impacted by pre-tax losses of $177 million in North America where tax rates are between 25% and 39% and pre-tax losses of $36 million in the North Sea where tax rates are principally 78%.

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

· Non-taxable portion of hedging gains;

· Foreign exchange on foreign denominated tax pools;

· Non-recognition of losses in the United States and exploration blocks.

The decrease of $56 million in current income taxes was primarily driven by lower net revenues in Southeast Asia.

The decrease of $4 million in deferred tax recovery was due principally to foreign exchange on tax pools, offset by deferred tax expense on the gains associated with the Company’s Montney disposition, and losses in Canada.

11

CAPITAL EXPENDITURES1,2

	Three months ended March 31
	2015		2014
($ millions)
North America		198		328
Southeast Asia		43		107
North Sea		23		52
Other		22		54
Exploration and development expenditure from subsidiaries2		286		541
Corporate, IS and Administrative		3		4
Proceeds of dispositions		-		(1,340	)
Net capital expenditure for subsidiaries		289		(795	)
TSEUK		109		164
Equion		10		7
Exploration and development expenditure from joint ventures3		119		171
Net capital expenditure for consolidated subsidiaries and joint ventures		408		(624	)

1. Capital expenditures in the North Sea only relate to Norway.

2. Excludes exploration expense of $26 million (2014 - $52 million).

3. Represents the Company’s proportionate interest, excluding exploration expensed of $1 million net in TSEUK (2014 - $1 million).

Capital expenditure, excluding exploration expense and after adjusting for proceeds of dispositions, decreased by $308 million or 43% in the first quarter of 2015 compared to the same quarter in 2014 due to decreased spending across all regions.

North America capital expenditures during the quarter totalled $198 million, a decrease of 40% from 2014. Of this, $172 million related to development activity, with the majority spent in the Eagle Ford, Marcellus and Edson areas. The remaining $26 million of capital was mainly invested in appraisal drilling activities in the Duvernay.

In Southeast Asia, capital expenditures of $43 million included $38 million on development, with the majority spent in Malaysia and Indonesia. The majority of the exploration spend was in Malaysia.

In Norway, capital expenditures of $23 million were for development activities, primarily related to Brynhild, Brage and Veslefrikk.

In the Rest of the World, capital expenditures of $22 million included $9 million of development spend in Colombia and $13 million of exploration spend in Colombia and the Kurdistan Region of Iraq.

In the TSEUK joint venture, net capital expenditures of $109 million consisted primarily of development activity at Montrose, Tweedsmuir and Flyndre/Cawdor. In the Equion joint venture, net capital expenditures of $10 million were principally for development wells.

12

ASSET DISPOSALS

North America Dispositions

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 $564 million ($493 million after tax).

LIQUIDITY AND CAPITAL RESOURCES

Talisman’s gross debt at March 31, 2015 was $5.1 billion ($5.0 billion, net of cash and cash equivalents and bank indebtedness), compared to $5.1 billion ($4.8 billion, net of cash and cash equivalents and bank indebtedness) at December 31, 2014.

During the quarter, the Company generated $556 million of cash provided by operating activities and incurred capital expenditures of $295 million.

Talisman’s capital structure consists of shareholders’ equity and debt. The Company makes adjustments to its capital structure based on changes in economic conditions and its planned requirements. Talisman has the ability to adjust its capital structure by issuing new equity or debt, selling assets to reduce debt, controlling the amount it returns to shareholders and making adjustments to its capital expenditure program, subject to restrictions in the Arrangement Agreement the Company entered into with Repsol on December 15, 2014, as filed on www.sedar.com.

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 March 31, 2015, 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 March 31, 2015, borrowings from bank lines totaled $775 million in the form of bankers’ acceptances. There was also $84 million in letters of credit support outstanding at March 31, 2015. In addition, $56 million of commercial paper was outstanding. 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. At March 31, 2015, available borrowing capacity under the bank credit facilities was $2.3 billion.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At March 31, 2015, demand letters guaranteed by the Company totaling $1.3 billion were issued of which $1.2 billion were issued from uncommitted facilities. Of that total, $0.9 billion is provided as security for the costs of decommissioning obligations in the United Kingdom (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.

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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 $2.2 billion, representing corporate income taxes paid and recoverable since 2002.

At March 31, 2015, TSEUK has $2.4 billion of demand shared facilities in place under which letters of credit of $1.9 billion have been issued. 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.

The Company also has obligations to fund 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 2015. In addition the Company has a guarantee to fund TSEUK’s decommissioning obligation if TSEUK is unable to. 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. During the second half of 2014, Talisman was downgraded by Moody’s, Standard & Poor’s, Fitch and Dominion Bond Rating Service to Baa3 (negative), BBB- (stable), BBB- (stable), and BBB under review with developing implications, 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.

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. The debt-to-cash flow ratio is calculated using debt (calculated by adding the gross debt and bank indebtedness, production payments and finance leases) 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 March 31, 2015, the debt-to-cash flow ratio was 2.2:1.

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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 March 31, 2015, approximately 90% of the Company's trade accounts receivable were aged less than 90 days and the largest single counterparty exposure, accounting for 3% 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.

At March 31, 2015, there were 1,036,166,028 common shares outstanding, of which 323,584 were held in trust by the Company resulting in 1,035,842,444 common shares outstanding for accounting purposes. During the three month period ended March 31, 2015, Talisman declared no common share dividends. Subsequent to March 31, 2015, no stock options were exercised for shares and 323,584 common shares previously held in trust for the long-term PSU plan were sold on the open market resulting in 1,036,166,028 common shares outstanding for accounting purposes. On April 8, 2015, the Company declared common share dividends of $0.1125 per common share for an aggregate dividend of $117 million.

On February 18, 2015 the Arrangement Agreement was approved by the common and preferred shareholders of the Company as described in this interim MD&A.

At March 31, 2015, 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 March 31, 2015, Talisman declared preferred share dividends of C$0.2625per share for an aggregate dividend of $2million.

At March 31, 2015, there were 29,316,331 stock options, 10,774,657 RSUs, 2,977,853 deferred share units (DSUs) and 2,243,000 long-term PSUs outstanding.

Subsequent to March 31, 2015, 4,075,446 RSUs were released, 95,975 were granted in lieu of payment of dividends and 18,705 were forfeited,  with 6,776,481 outstanding at May 4, 2015.

Upon closing of the transaction scheduled for May 8, 2015, all share-based payment units will be settled for cash. The payments will be paid within 60 days of closing.

To satisfy its obligation to deliver common shares to settle long-term PSUs, the Company may purchase shares on the open market, which are held in trust. The 2012 long-term PSU grant vested on December 31, 2014 and was settled in March 2015 based on the vesting of 100% of the PSUs granted, as approved by the Board of Directors.

During the three month period ended March 31, 2015, 3,793,939 common shares were purchased on the open market for $30 million and held in trust for the long-term PSU plan (During the same period in 2014 – no common shares were purchased). Between April 1 and May 4, 2015, no common shares were purchased on the open market.

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. Any acquisitions, investments, dispositions, or issuance of debt or equity are subject to restrictions in the Arrangement Agreement the Company entered into with Repsol on December 15, 2014, as filed on www.sedar.com.

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For additional information regarding the Company’s liquidity and capital resources, refer to note 20 to the 2014 audited Consolidated Financial Statements and notes 13, 15 and 16 to the interim condensed Consolidated Financial Statements.

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 2015 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $55/bbl, a NYMEX natural gas price of approximately $3.00/mmbtu and exchange rates of US$0.84=C$1 and UK£1=US$1.55.

(millions of $)	Net Income			Cash Provided by Operating Activities3
Volume changes
Oil – 10,000 bbls/d		25			100
Natural gas – 60 mmcf/d		(1	)		40
Price changes1
Oil – $1.00/bbl		25			30
Natural gas (North America)2 – $0.10/mcf		25			25
Exchange rate changes
US$/C$ decreased by US$0.01		(5	)		(5	)
US$/UK£ increased by US$0.02		(5	)		-

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 America natural gas only. The Company’s exposure to changes in the natural gas prices in Norway, 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 excludes 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 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.

There have been no additional significant changes in the Company’s expected future commitments, and the timing of those payments, since December 31, 2014.

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TRANSACTIONS WITH RELATED PARTIES

During the three months ended March 31, 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $320 million, of which Talisman’s share was $163 million.

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 2014 audited Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at March 31, 2015, including their respective fair values, are detailed in note 16 to the interim condensed Consolidated Financial Statements.

The Company has elected not to designate as hedges for accounting purposes any commodity price derivative contracts entered into. 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.

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Commodity Price Derivative Financial Instruments

The Company had the following commodity price derivative contracts outstanding at March 31, 2015, none of which are designated as hedges:

Two-way collars (Oil)	Term		bbls/d		Floor/ceiling $/bbl
Dated Brent oil index	2015 Apr - Dec			5,000		90.00/100.01
NYMEX WTI oil index	2015 Apr - Dec			5,000		80.00/95.02
Dated Brent oil index	2015 Apr - Dec			20,000		90.00/106.16
Dated Brent oil index	2016 Jan - Dec			1,000		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
Dated Brent oil index	2015 Apr - Dec			10,000		100.46
Dated Brent oil index	2015 Apr - Dec			1,000		104.00
Dated Brent oil index	2015 Apr - Dec			9,000		100.59
NYMEX WTI oil index	2015 Apr - Dec			5,000		96.36
Dated Brent oil index	2016 Jan - Dec			8,000		98.01
Dated Brent oil index	2016 Jan - Dec			2,000		100.29
Dated Brent oil index	2016 Jan - Dec			2,000		102.98
Two-way collars (Gas)	Term		mcf/d		Floor/ceiling $/mcf
NYMEX HH LD	2015 Apr - Dec			47,468		4.23/4.87
NYMEX HH LD	2015 Apr - Dec			94,936		4.21/5.06
NYMEX HH LD	2016 Jan - Dec			9,494		4.21/4.75
NYMEX HH LD	2016 Jan - Dec			18,987		4.21/4.87
Fixed priced swaps (Gas)	Term		mcf/d		$/mcf
NYMEX HH LD	2015 Apr - Dec			47,468		4.54
NYMEX HH LD	2015 Apr - Dec			47,468		4.39
NYMEX HH LD	2015 Apr - Dec			47,468		4.39
NYMEX HH LD	2015 Apr - Dec			47,468		4.48
NYMEX HH LD	2015 Apr - Dec			47,468		4.53
NYMEX HH LD	2015 Apr - Dec			47,468		4.55
NYMEX HH LD	2016 Jan - Dec			23,734		4.48
NYMEX HH LD	2016 Jan - Dec			18,897		4.55

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Fixed priced swaps (Power)	Term	MWh		C$/MWh
Alberta Power	2015 Apr - 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

In order to strengthen its balance sheet, the Company commenced monetization of its 2016 oil and gas derivative contracts, generating $251 million in proceeds during the quarter. Since the end of the quarter, the Company has monetized the remainder of its outstanding oil and gas derivative contracts for total proceeds of $818 million.

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. During the three month period ended March 31, 2015, no accounting items were impacted by changes in management’s estimates and judgments.

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, 2014.

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 2014 annual Consolidated Financial Statements except for the following:

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.

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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 position or performance.

Share-based Payments

· IFRS 2 Share-Based Payments - Amendments to IFRS 2. The standard amends the definitions of “vesting condition” and “market condition” and adds definitions for “performance condition” and “service condition”. The amendment is effective for annual periods beginning on or after July 1, 2014. The amendment does not have an impact on the Company as it reflects current accounting policy of the Company.

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 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.

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 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. 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.

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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 March 31, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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.

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 closing of the corporate transaction with Repsol;

· 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;

· Potential effects of the hedging program;

· 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, including share-based payments expense in future periods;

· 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.

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The factors or assumptions on which the forward-looking information is based include: 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 2015 assumes escalating commodity prices. Closing of the Repsol transaction is subject to satisfaction of customary closing deliverables.

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:

· 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;

· 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;

· Risks associated with the completion of the corporate transaction with Repsol;

· 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.

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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.

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.

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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
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
HH LD	Henry Hub Last Day
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 kroner
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

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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

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