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

Exhibit 99.2

INTERIM MANAGEMENT’S DISCUSSION
AND ANALYSIS
FOR THE PERIOD ENDED MARCH 31, 2016

REPSOL OIL & GAS CANADA INC.

Management’s Discussion and Analysis (MD&A)

(May 6, 2016)

General

This interim Management’s Discussion and Analysis (MD&A) should be read in conjunction with the unaudited interim condensed Consolidated Financial Statements of Repsol Oil & Gas Canada Inc. (“ROGCI” or “the Company”), formerly Talisman Energy Inc. as at and for the three month periods ended March 31, 2016 and 2015, and the 2015 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”).

The Company’s financial statements are prepared on a consolidated basis and include the accounts of the Company and its subsidiaries. Substantially all of the Company’s activities are conducted jointly with others, and the interim 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, 2016 and 2015, 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 the Company’s Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.

On January 1, 2016, the Articles of the Company were amended to change the name of the Company from Talisman Energy Inc. to Repsol Oil & Gas Canada Inc.

1

FINANCIAL AND OPERATING HIGHLIGHTS

	Three months ended
(millions of $, unless otherwise stated)	Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
	2016		2015		2015		2015		2015		2014		2014		2014
Total revenue and other income from continuing operations1	467		142		334		551		437		(71	)	995		1,134
Total revenue and other income from discontinued operations2	—		—		38		83		61		115		141		108
Total revenue and other income	467		142		372		634		498		44		1,136		1,242
Net income (loss) from continuing operations	(145	)	(628	)	(899	)	(888	)	(397	)	(1,154	)	439		(207	)
Net income (loss) from discontinued operations2	—		—		112		(364	)	(42	)	(436	)	(14	)	(30	)
Net income (loss)	(145	)	(628	)	(787	)	(1,252	)	(439	)	(1,590	)	425		(237	)
Per common share ($)
Net income (loss)3	(0.08	)	(0.59	)	(0.75	)	(1.20	)	(0.43	)	(1.54	)	0.41		(0.23	)
Diluted net income (loss)4	(0.08	)	(0.59	)	(0.75	)	(1.24	)	(0.43	)	(1.54	)	0.38		(0.24	)
Income (loss) from continuing operations per common share
Basic3	(0.08	)	(0.59	)	(0.86	)	(0.85	)	(0.39	)	(1.12	)	0.42		(0.20	)
Diluted4	(0.08	)	(0.59	)	(0.86	)	(0.89	)	(0.39	)	(1.12	)	0.39		(0.21	)
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	119		122		114		121		119		119		113		126
Natural gas (mmcf/d)	1,334		1,339		1,278		1,300		1,305		1,307		1,254		1,287
Ongoing operations (mboe/d)	357		360		342		353		351		352		336		355
Assets sold or held for sale (mboe/d)	—		9		22		25		25		28		32		36
Total mboe/d	357		369		364		378		376		380		368		391

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

(2)Discontinued operations are the results associated with the Norway disposition.

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

(4)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.

During the first quarter of 2016, the Company’s net loss decreased by $294 million to $145 million due principally to positive income from the TSEUK joint venture, reductions in operating, DD&A, G&A, and impairment expense as well as reductions in finance costs and income taxes. This was partially offset by reduced sales revenue due to lower commodity prices and a gain on held-for-trading instruments in the comparative period.

2

DAILY AVERAGE PRODUCTION

	Three months ended March 31
	Gross before royalties		Net of royalties
	2016	2015	2016	2015
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	39	45	33	38
Southeast Asia	32	39	23	27
North Sea	—	13	—	13
Other	11	14	6	9
	82	111	62	87
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK	23	15	23	15
Equion	14	11	11	9
	37	26	34	24
Total Oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	119	137	96	111
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	796	798	712	695
Southeast Asia	494	483	379	347
North Sea	—	17	—	17
	1,290	1,298	1,091	1,059
Natural gas from Joint Ventures (mmcf/d)
TSEUK	5	2	5	2
Equion	39	42	30	32
	44	44	35	34
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,334	1,342	1,126	1,093
Total Daily Production from Consolidated Subsidiaries (mboe/d)
North America	181	187	160	161
Southeast Asia	120	125	90	89
North Sea	—	16	—	16
Other	11	14	6	9
	312	342	256	275
Total Daily Production From Joint Ventures (mboe/d)
TSEUK	24	16	24	16
Equion	21	18	17	14
	45	34	41	30
Total Daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)	357	376	297	305
Less production from assets sold or held for sale (mboe/d)
North America	—	9	—	7
North Sea	—	16	—	16
	—	25	—	23
Total production from ongoing operations (mboe/d)	357	351	297	282

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

Total production from ongoing operations was 357 mboe/d in 2016, an increase of 2% compared to 2015 due principally to increased production in both the TSEUK and Equion joint ventures which was partially offset by decreased production in Southeast Asia and Other which is also referred to as Rest of World (“ROW”).

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In North America, total production decreased by 3% compared to 2015, and total production from ongoing operations increased by 2%. Total oil and liquids production decreased by 13% principally due to the Company’s sale of 26% of its 50% interest in the Eagle Ford area in late 2015, lower production as a result of well shut-ins due to lower commodity prices and natural declines. Total natural gas production decreased slightly primarily due to the reduction in Eagle Ford interest which was partially offset by new wells coming on stream in the Greater Edson area of Canada.

In Southeast Asia, total production decreased by 4% compared to 2015. Total oil and liquids production decreased by 18% principally due to production ceasing at Kitan in Australia/Timor-Leste in late 2015 due to operational issues and natural declines at HST/HSD in Vietnam. Natural gas production increased by 2% in 2016 due principally to increased demand at Corridor in Indonesia and at PM3 in Malaysia, partially offset by lower gas production at Kinabalu in Malaysia due to the relinquishment of associated gas rights back to Petronas effective April 1, 2015.

Total production in TSEUK increased by 8 mboe/d due principally to higher production at Monarb and Tartan which were shut down in the comparative period and partially due to improved performance at Claymore.

Total production in Equion increased by 3 mboe/d due primarily to new wells that started production during the second quarter of 2015.

In Rest of World, total production decreased by 21% compared to 2015. In Colombia, production decreased by 1 mboe/d principally due to the shut-in of wells due to the low commodity price environment. In Algeria, production was down by 2 mboe/d principally due to a temporary decline in the MLN field’s entitlement to production volumes, which is expected to be fully recovered in the second quarter of 2016.

VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1,2,3

	Three months ended March 31
	2016		2015
North America - bbls/d	(2,132	)	278
Southeast Asia - bbls/d	269		(356	)
Other - bbls/d	3,363		402
Total produced into inventory - bbls/d	1,500		324
Total produced into inventory - mmbbls	0.1		—
Inventory at March 31 - mmbbls	1.8		1.4

(1)Gross before royalties.

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

(3)Amounts shown only represent inventory from consolidated subsidiaries and exclude inventory from equity accounted entities.

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 and liquids volumes produced into inventory and exclude volumes sold out of inventory.

4

During the three month period ended March 31, 2016, volumes in inventory increased from 1.7 mmbbls at December 31, 2015 to 1.8 mmbbls at March 31, 2016 due principally to increased inventories in Indonesia and Algeria partially offset by decreased inventories in North America, Malaysia and Australia.

COMPANY NETBACKS1,2,3

	Three months ended March 31
	Gross before royalties		Net of royalties
	2016	2015	2016	2015
Oil and liquids ($/bbl)
Sales price	26.34	39.01	26.34	39.01
Royalties	7.08	10.81
Transportation	1.79	2.15	2.45	2.98
Operating costs	8.92	12.19	12.19	16.85
	8.55	13.86	11.70	19.18
Natural gas ($/mcf)
Sales price	2.70	3.95	2.70	3.95
Royalties	0.49	0.87
Transportation	0.26	0.27	0.32	0.34
Operating costs	0.86	1.22	1.05	1.56
	1.09	1.59	1.33	2.05
Total $/boe (5.615 mcf=1boe)
Sales price	18.09	27.22	18.09	27.22
Royalties	3.87	6.64
Transportation	1.55	1.69	1.97	2.23
Operating costs	5.92	8.44	7.21	10.61
	6.75	10.45	8.91	14.38

(1)Netbacks do not include pipeline operations.

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

(3)Amounts shown only represent netbacks from consolidated subsidiaries and exclude netbacks from equity accounted entities.

During the three month period ended March 31, 2016, the Company’s average gross netback was $6.75/boe, 35% lower than in 2015 due principally to lower realized prices, partially offset by lower royalties and lower operating costs.

The Company’s realized net price of $18.09/boe was 34% lower than 2015 due principally to lower commodity prices. Oil and liquids and natural gas prices both decreased by 32% compared to 2015.

The Company’s composite royalty rate was 21%, down from 24% in 2015 due principally to lower commodity prices.

5

COMMODITY PRICES AND EXCHANGE RATES1,2

	Three months ended March 31
	2016	2015
Oil and liquids ($/bbl)
North America	18.57	23.51
Southeast Asia	33.92	53.09
Other	31.67	48.65
	26.34	39.01
Natural gas ($/mcf)
North America	1.79	2.60
Southeast Asia	4.15	6.20
	2.70	3.95
Company $/boe (5.615mcf=1boe)	18.09	27.22
Benchmark prices and foreign exchange rates
WTI (US$/bbl)	33.45	48.63
Dated Brent (US$/bbl)	33.89	53.97
WCS (US$/bbl)	19.21	33.82
LLS (US$/bbl)	35.14	52.75
NYMEX ($/mmbtu)	2.05	2.96
AECO (C$/gj)	2.00	2.80
C$/US$ exchange rate	1.37	1.24
UK£/US$ exchange rate	0.70	0.66

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

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

In North America, realized oil and liquids prices decreased 21% in 2016 due principally to decreases in benchmark prices. In Southeast Asia, realized oil and liquids prices decreased 36%, consistent with decreases in Brent crude pricing. Due to these reasons, the Company’s overall realized oil and liquids price of $26.34/bbl decreased by 32% compared to 2015.

In North America, realized natural gas prices decreased by 31% in 2016, which is consistent with decreases in benchmark prices. In Southeast Asia, where a significant portion of gas sales are linked to oil prices, realized natural gas prices decreased by 33% which is in line with decreases in benchmark crude pricing. Due to these reasons, the Company’s overall realized natural gas price of $2.70/mcf decreased by 32% compared to 2015.

6

EXPENSES

Unit Operating Expenses1,2

	Three months ended March 31
	Gross before royalties		Net of royalties
($/boe)	2016	2015	2016	2015
North America	5.54	7.52	6.28	8.69
Southeast Asia	6.22	9.18	8.25	12.95
Other	8.95	14.03	16.33	22.12
	5.92	8.44	7.21	10.61

(1)Represents unit operating expenses from consolidated subsidiaries, excluding unit operating expenses from equity accounted entities.

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

Total Operating Expenses1,2

	Three months ended March 31
(millions of $)	2016	2015
North America	94	127
Southeast Asia	77	109
Other	9	15
	180	251

(1)Represents operating expenses from consolidated subsidiaries, excluding operating expenses from equity accounted entities.

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

Total operating expenses decreased by 28% to $180 million in 2016.

In North America, total operating expenses decreased by 26% to $94 million principally due to the reduction in Eagle Ford interest in late 2015, lower battery plant maintenance costs, reduced well workover costs, a recovery in severance tax, and a reduction in indirect opex due to smaller workforce numbers partially offset by higher processing expenses. Unit operating expenses in North America decreased by 26% due to the reasons noted above.

In Southeast Asia, total operating expenses decreased by 29% to $77 million due primarily to the Kitan field in Australia/Timor-Leste no longer producing, lower operation and maintenance activity at Corridor in Indonesia, re-phasing of maintenance activity to the later parts of 2016 and lower well intervention and wireline services for PM3 in Malaysia. Unit operating expenses decreased by 32% due principally to the reasons noted above.

In the Rest of World, total operating expenses decreased by 40% to $9 million primarily due to lower production in Colombia, reduced crude treatment costs, and the devaluation of the Colombian peso. Unit operating expenses decreased by 36% due principally to the reasons noted above.

Unit operating expense for the Company decreased by 30% to $5.92/boe due to the reasons noted above.

7

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

	Three months ended March 31
	Gross before royalties		Net of royalties
($/boe)	2016	2015	2016	2015
North America	13.98	15.21	15.84	17.55
Southeast Asia	6.71	12.05	8.90	16.99
Other	11.28	11.25	20.58	17.73
	11.08	13.82	13.49	17.37

(1)Represents unit DD&A expense from consolidated subsidiaries, excluding unit DD&A expense from equity accounted entities.

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

Total DD&A Expense1,2

	Three months ended March 31
(millions of $)	2016	2015
North America	231	257
Southeast Asia	73	138
Other	10	16
	314	411

(1)Represents DD&A expense from consolidated subsidiaries, excluding DD&A expense from equity accounted entities.

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

Total DD&A expense decreased by 24% compared to the same period in 2015 due principally to decreased DD&A expense in Southeast Asia and North America.

DD&A expense in North America decreased by 10% primarily due to asset impairments recorded at year end 2015, the partial sale of the Eagle Ford in late 2015, and reserve additions in the Marcellus, partially offset by lower reserves in the Bigstone, Wild River and Chauvin areas of Canada. Unit DD&A expense decreased by 8% due to the reasons noted above.

In Southeast Asia, DD&A expense decreased by 47% due principally to the Kitan field in Australia/Timor-Leste being fully impaired at the end of the first quarter of 2015 and lower depletable asset bases in Malaysia and Vietnam as a result of asset impairments recorded at year end 2015. Unit DD&A expense decreased by 44% due to the reasons noted above.

In the Rest of World, total DD&A expense decreased by 38% due principally to lower production during the quarter. Unit DD&A expense was consistent with 2015.

Unit DD&A expense for the Company decreased by 20% to $11.08/boe due to the reasons noted above.

8

Income (Loss) from Joint Ventures and Associates1

	Three months ended March 31
(millions of $)	2016		2015
TSEUK	20		(206	)
Equion	(2	)	(1	)
	18		(207	)

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

TSEUK Joint Venture

The after-tax net loss of $206 million in 2015 improved to an after-tax net income of $20 million in 2016 due principally to a deferred income tax recovery related to petroleum revenue tax (“PRT”) legislation enacted in March 2016 which reduced the PRT rate down to zero, lower operating costs, DD&A expense, G&A expense, and other expenses which were partially offset by reduced revenue due to lower commodity prices and an increase in finance costs.

Equion Joint Venture

The after-tax net loss in Equion of $2 million in 2016 as compared to an after-tax net loss of $1 million in 2015 is primarily a result of decreased sales revenue due to lower commodity prices, partially offset by higher production and lower royalties and operating expenses.

Corporate and Other1,2

	Three months ended March 31
(millions of $)	2016	2015
General and administrative (G&A) expense	63	84
Impairment	—	48
Dry hole expense	12	13
Exploration expense	29	24
Finance costs	54	84
Share-based payments recovery	—	(6	)
Gain on held-for-trading financial instruments	—	(193	)
Loss on disposals	—	5
Other expenses, net	23	17
Other income	45	40

(1)Represents corporate and other expense from consolidated subsidiaries, excluding corporate and other expense from equity accounted entities.

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

In 2016, G&A expense decreased by $21 million relative to 2015 principally due to lower workforce expenses and reduced reliance on temporary staff and consultants, lower office expenses and the departure of executives after the acquisition of the Company by Repsol.

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In the first quarter of 2016, the Company recorded dry hole expense of $12 million principally due to the write-off of an exploration well in North America.

Exploration expense increased by $5 million in 2016 due principally to increased spending in Southeast Asia and Colombia.

Finance costs include interest on long-term debt (including current portion), other finance charges and accretion expense relating to decommissioning liabilities, less interest capitalized. Finance costs decreased by $30 million in 2016 principally due to the reduction in long-term debt.

Other expenses of $23 million consists primarily of restructuring costs of $13 million, inventory writedowns of $7 million and $8 million in other miscellaneous expenses, partially offset by a foreign exchange gain of $5 million.

Other income of $45 million consists primarily of a $26 million net gain on repayment of long-term debt, marketing and other income of $15 million, and pipeline and customer treating tariffs of $4 million.

INCOME TAXES1,2

	Three months ended March 31
(millions of $)	2016		2015
Loss from continuing operations before taxes	(250	)	(351	)
Less: PRT
Current	2		2
Deferred	(4	)	(2	)
Total PRT	(2	)	—
	(248	)	(351	)
Income tax expense (recovery)
Current income tax expense	38		68
Deferred income tax recovery	(141	)	(22	)
Income tax expense (recovery) (excluding PRT)	(103	)	46
Effective income tax rate (%)	42	%	(13	)%

(1)Represents income taxes from consolidated subsidiaries, excluding income taxes from equity accounted entities.

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

The effective tax rate is expressed as a percentage of income from continuing operations before taxes adjusted for PRT, which is deductible in determining taxable income.

The effective tax rate in the first quarter of 2016 was impacted by pre-tax losses of $166 million in North America, where tax rates are between 27% and 39%, and pre-tax losses of $27 million in Rest of World, where tax rates range from 9% to 40%. This was partially offset by pre-tax income of $35 million in Southeast Asia, where tax rates range from 30% to 58%, and after-tax income of $20 million in the TSEUK joint venture.

10

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

·Foreign exchange movements on foreign denominated tax pools

·Non recognition of losses in exploration blocks

For the three month period ended March 31, 2016, the current tax expense decreased to $38 million compared to $68 million in 2015, due principally to lower net revenues in Indonesia.

For the three month period ended March 31, 2016, the deferred tax recovery increased to $141 million from $22 million in 2015, due principally to foreign exchange on tax pools and recognition of a US tax asset.

CAPITAL EXPENDITURES1

	Three months ended March 31
($ millions)	2016	2015
North America	137	198
Southeast Asia	21	43
Other	3	22
Exploration and development expenditure from consolidated subsidiaries2	161	263
Corporate, IS and Administrative	1	3
Net capital expenditure for consolidated subsidiaries	162	266
TSEUK	47	109
Equion	5	10
Exploration and development expenditure from Joint Ventures3	52	119
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures	214	385

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

(2)Excludes exploration expense of $29 million in 2016 (2015 - $24 million).

(3)Represents the Company’s proportionate interest, excluding exploration expensed of $1 million net in 2016 (2015 - $1 million).

North American capital expenditures during the quarter totalled $137 million, a decrease of 31% from 2015. Of this, $108 million related to development activity, with the majority spent in the Marcellus, Eagle Ford, and Greater Edson areas. The remaining capital was invested in exploration activities, largely in the Duvernay.

In Southeast Asia, capital expenditures of $21 million included $20 million on development, with the majority spent in Indonesia and Malaysia. The exploration expenditure of $1 million was invested in Indonesia and Vietnam.

In the Rest of World, capital expenditures of $3 million consisted primarily of exploration and evaluation activities in Colombia.

In the TSEUK joint venture, capital expenditures of $47 million consisted primarily of development activities in Montrose. In the Equion joint venture, net capital expenditures of $5 million related primarily to Piedemonte development wells.

11

LIQUIDITY AND CAPITAL RESOURCES

The Company’s gross debt and loans from related parties at March 31, 2016 was $3.1 billion compared to $3.3 billion at December 31, 2015.

During the quarter, the Company generated $137 million of cash provided by operating activities from continuing operations, incurred capital expenditures of $164 million, repaid long-term debt of $748 million and drew loans from related parties of $609 million.

The Company’s capital structure consists of shareholder’s equity and debt from capital markets and related parties. The Company makes adjustments to its capital structure based on changes in economic conditions and its planned requirements. The Company has the ability to adjust its capital structure by issuing new equity or debt, settle related party debt through the subscription agreement, sell assets to reduce debt, control the amount it returns to its shareholder and make adjustments to its capital expenditure program.

On May 8, 2015, TE Holding SARL. (“TEHS”), a subsidiary of the Company, entered into a $500 million revolving facility with Repsol Tesoreria Y Gestion Financiera, S.A. (“RTYGF”), a subsidiary of Repsol. Originally, the facility was to mature on May 8, 2016 and to bear an interest rate of LIBOR (1 month) plus 0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. On November 17, 2015, the interest rate in the facility agreement was amended to LIBOR (1 month) plus 1.20%. As at March 31, 2016, there were $193 million drawings outstanding under this facility. Interest expense related to the facility recognized by the Company during the three month period ended March 31, 2016 was less than $1 million.

On May 8, 2015, the Company also entered into a $1.0 billion revolving facility with Repsol Energy Resources Canada, Inc. (“RERCI”), a subsidiary of Repsol. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) plus 1.20%. The facility limit was increased to $2.8 billion on December 9, 2015. At March 31, 2016, the Company had $1.4 billion outstanding under this facility. Interest expense related to the facility recognized by the Company during the three month period ended March 31, 2016 was $3 million.

On December 22, 2015, the Company and RERCI entered into a subscription agreement which provides for the capitalization of the Company’s balances owing under this revolving facility. The Board of Directors of the Company authorized the issuance of up to an aggregate of $2.6 billion in common shares of the Company (1,361,256,544 common shares at $1.91 per share), to be settled by RERCI contributing receivables owing from the Company under this revolving facility. As at March 31, 2016, $1.1 billion drawings remained available under the subscription agreement.

On March 23, 2016, the Company announced a cash tender offer to purchase any and all of the principal amount of the Company’s outstanding 7.75% Senior Notes due 2019, 3.75% Senior Notes due 2021, 7.25% Debentures due 2027, 5.75% Senior Notes due 2035, 5.85% Senior Notes due 2037, 6.25% Senior Notes due 2038, and 5.50% Senior Notes due 2042 (collectively, the “Securities”). Holders of the Securities that were validly tendered received the relevant tender offer consideration plus accrued and unpaid interest up to but not including the payment date

12

March 31, 2016. The tender offer expired on March 29, 2016. The principal amount tendered and accepted was as follows:

Title of Security	Principal Prior to Tender Offer	Principal Amount Tendered & Accepted	Principal Amount Outstanding
7.75% Senior Notes due 2019	571	207	364
3.75% Senior Notes due 2021	576	335	241
7.25% Debentures due 2027	57	3	54
5.75% Senior Notes due 2035	98	8	90
5.85% Senior Notes due 2037	140	9	131
6.25% Senior Notes due 2038	132	13	119
5.50% Senior Notes due 2042	123	26	97
Total	1,697	601	1,096

On March 31, 2016, the Company paid the consenting note holders an aggregate of approximately $580 million in cash (including $572 million principal and $8 million accrued interest).

In addition, in January 2016, the Company also redeemed for retirement $24 million of the 3.75% Senior Notes due 2021, $2 million of the 7.75% Senior Notes due 2019, and $4 million of the 5.5% Senior Notes due 2042 for total payment of $27 million (including $26 million principal and $1 million accrued interest).

The above discussed tender offer and redemption of outstanding senior notes resulted in a net gain of $26 million, which was recognized in other income on the interim condensed Consolidated Statements of Loss.

The Company manages its liquidity requirements by use of both short-term and long-term cash forecasts and by integrating funding from subsidiaries of its ultimate parent, Repsol. The Company had undrawn capacity under committed bank credit facilities of $3.2 billion at March 31, 2016.

During 2015, the Company also entered into two revolving facilities with subsidiaries of its ultimate parent, Repsol, with a total borrowing limit of $3.3 billion. As at March 31, 2016, a total of $1.6 billion drawings were outstanding under these facilities. The subscription agreement underlying the revolving facility provides for the capitalization of the Company’s balances owing.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted.  At March 31, 2016, the Company had $0.2 billion letters of credit outstanding, primarily related to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations.  The Company also guaranteed $0.8 billion demand letters of credit issued under TSEUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK. In addition, there were also $45 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

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

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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 value 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. As of March 31, 2016, only two DSAs were still required to be negotiated on a post-tax basis. 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 $2.0 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At March 31, 2016, TSEUK had $3.1 billion of demand shared facilities in place under which letters of credit of $1.6 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. In addition the Company, in proportion of its shareholding, has a guarantee 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 required to be provided pursuant to DSAs. In addition, the extent to which shared facility capacity is available and the cost of that capacity are influenced by the Company’s investment-grade credit rating.

The Company 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 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

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basis as of the last day of each fiscal quarter. For the trailing 12-month period ended March 31, 2016, the debt-to-cash flow ratio was 1.7:1.

Considering the current commodity price environment and existing debt covenant, the Company will require continuing support from its parent company in the form of the committed credit facilities and subscription agreements.

A significant proportion of the Company’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At March 31, 2016, approximately 72% of the Company’s trade accounts receivable was current and the largest single counterparty exposure, accounting for 4% 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 primarily of highly rated counterparties.

Subsequent to December 31, 2015, there were no activities relating to the Company’s common shares. There were 1,829,506,342 common shares outstanding at May 5, 2016.

For additional information regarding the Company’s liquidity and capital resources, refer to note 18 to the Company’s 2015 audited Consolidated Financial Statements and notes 10, 12 and 13 to the Company’s interim condensed Consolidated Financial Statements.

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 7, 14, 16, 17 and 22 to the 2015 audited Consolidated Financial Statements.

There have been no significant changes in the Company’s expected future commitments, and the timing of those payments, since December 31, 2015.

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TRANSACTIONS WITH RELATED PARTIES

North America

During the three month period ended March 31, 2016, Repsol Canada Energy Partnership sold to Repsol Energy Canada Limited, a subsidiary of Repsol, approximately 11,500,000 gigajoules of natural gas for $13 million. As at March 31, 2016, the amount included in accounts receivable as a result of these transactions was $5 million.

Rest of World

During the three month period ended March 31, 2016, Talisman (Algeria) B.V. sold to Repsol Trading S.A., a subsidiary of Repsol, approximately 235,000 barrels of Saharan Blend Crude Oil for $7 million.  As at March 31, 2016, there were no amounts outstanding in accounts receivable as a result of these transactions.

Southeast Asia

The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek. Currently, ROGCI’s share of the sale on a daily basis is approximately 75 bbtu. The commitment matures in 2023.  As a result of the acquisition of the Company by Repsol, GSPL and Temasek became the Company’s related parties. During the three month period ended March 31, 2016, the Company’s gas sales to GSPL totaled $23 million (net the Company’s share). As at March 31, 2016, the amount included in accounts receivable as a result of this commitment was $14 million.

TSEUK

In June 2015, the shareholders of TSEUK provided an equity funding facility of $1.7 billion, of which the Company 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 March 31, 2016, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $115 million under this facility, of which the Company’s share was $59 million.

The shareholders of TSEUK have provided an unsecured loan facility totaling $2.4 billion to TSEUK, of which the Company is committed to $1.2 billion, for the purpose of funding capital expenditures of TSEUK. There was no loan balance outstanding as at March 31, 2016.

Equion

The Company has a loan due to Equion of $29 million (December 31, 2015 - $14 million) which is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.

RISK MANAGEMENT

In addition to the risks discussed in the liquidity and capital resources section of this MD&A, the Company monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, the Company 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

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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(r) to the Company’s 2015 audited Consolidated Financial Statements.

The Company had elected not to designate as hedges for accounting purposes any 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 quarterly. This can potentially increase the volatility of net income.

In 2015, the Company liquidated substantially all of its contracts related to commodity price risk management. The Company has not entered into any new commodity price risk management derivative contracts subsequently.

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 also 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.

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, 2015.

SIGNIFICANT ACCOUNTING POLICIES

The Company’s significant accounting policies and a summary of recently announced accounting standards are described in the Significant Accounting Policy section of the Company’s 2015 annual MD&A.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Throughout the three months ended March 31, 2016, the integration activities with the Company’s ultimate parent, Repsol, continued and changes to the Company’s organizational design, policies and individuals with significant roles in internal control over financial reporting have changed. In order to mitigate the potential effect associated with these changes, the Company has implemented additional controls intended to ensure responsibilities are clearly understood and information and communication controls are effective. Testing of the design and operating effectiveness of the Company’s controls will continue throughout 2016.

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LEGAL PROCEEDINGS

From time to time, the Company is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below 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 the Company 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. None of these claims are currently expected to have a material impact on the Company’s financial position. A summary of specific legal proceedings and contingencies is as follows:

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 submitted a notification of a claim to Oleum Insurance Company (‘‘Oleum’’), a wholly-owned subsidiary of the Company. TSEUK delivered a proof of loss seeking recovery under the insuring agreement of $315 million. The documentation delivered in November 2014 by TSEUK 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 provided additional information to Oleum that has been reviewed by external counsel; TSEUK has been advised that the information still does not support coverage.

On July 13, 2015, Addax Petroleum UK Limited and Sinopec International Petroleum Exploration and Production Corporation, filed a Notice of Arbitration (pursuant to the Rules of the Singapore International Arbitration Centre) against the Company and Talisman Colombia Holdco Limited (“TCHL”) in connection with Addax’s purchase of 49% of the shares of TSEUK. On October 1, 2015, the Company and TCHL filed a response to the Notice of Arbitration. The preliminary hearing before the Court of Arbitration took place on February 18, 2016, where it was decided, among other procedural matters, to schedule the hearing for January 29 to February 16, 2018. The Company believes the claims included in the Notice of Arbitration are without merit.

During the first quarter of 2016, the Alberta Energy Regulator (“AER”) informed the Company that certain permits to construct well sites and access roads were obtained without the Company following proper procedures.  The Company is responding to the issues raised by the AER and reviewing its permit applications back to 2010. At this time, the implications to the Company are not known.

Government and Legal Proceedings with Tax Implications

Specific tax claims which the Company and its subsidiaries are parties to at March 31, 2016 are as follows:

Canada

The Canadian tax authorities, Canada Revenue Agency, (“CRA”) regularly inspect the tax matters of the ROGCI Group companies based in Canada. To date, verification and investigation activities related to the years 2006-2012 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.

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Indonesia

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

Malaysia

Repsol Oil & Gas Malaysia Limited, formerly Talisman Malaysia Ltd. and Repsol Oil & Gas Malaysia (PM3) Limited, formerly Talisman Malaysia (PM3) Ltd., the Company’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 Talisman Resources (JPDA 06-105) Pty Limited, the Company’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 the Company’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;

·Anticipated timing and results of legal proceedings; and

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

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 2016 assumes escalating commodity prices.

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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 the Company 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 or strategy 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.

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ADVISORY — OIL AND GAS INFORMATION

Throughout this MD&A, the Company makes reference to production volumes. 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.

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

USE OF ‘BOE’

Throughout this MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of five thousand six hundred fifteen cubic feet (mcf) of natural gas to one barrel (bbl) 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 5.615 mcf: 1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead.

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
bbtu	billion British thermal units
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
G&A	General and administrative
GAAP	Generally Accepted Accounting Principles
gj	gigajoule
HH LD	Henry Hub Last Day
IFRIC	International Financial Reporting Interpretations Committee
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

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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
NGL	Natural Gas Liquids
NYMEX	New York Mercantile Exchange
PP&E	Property, plant and equipment
PSU	Performance 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 the Company 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 the Company’s interest in production volumes (through working interests and royalty interests) before the deduction of royalties. Net production means the Company’s interest in production volumes after deduction of royalties payable by the Company.

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.

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REPSOL OIL & GAS CANADA INC.

Suite 2000, 888 — 3rd Street SW

Calgary, Alberta, Canada T2P 5C5

P 403.237.1234  F 403.237.1902

E  infocanada@repsol.com

www.repsol.com/ca_en/