EX-99.2 3 a16-19760_1ex99d2.htm EX-99.2 INTERIM MANAGEMENT'S DISCUSSION AND ANALYSIS

Exhibit 99.2

Management’s Discussion and Analysis (MD&A)

(November 8, 2016)

General

This interim 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 and nine month periods ended September 30, 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 Repsol Sinopec Resources UK Limited (“RSRUK”, formerly Talisman Sinopec Energy UK Limited) and Equion Energía Limited (“Equion”) which are accounted for using the equity method.

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

FINANCIAL AND OPERATING HIGHLIGHTS

(millions of $, unless otherwise stated)	Nine Months Ended September 30,				Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
	2016		2015		2016		2016		2016		2015		2015		2015		2015		2014
Total revenue and other income from continuing operations1	1,098		1,340		313		316		469		145		345		555		439		(69	)
Total revenue and other income from discontinued operations2	—		182		—		—		—		—		38		83		61		115
Total revenue and other income	1,098		1,522		313		316		469		145		384		638		500		46
Net income (loss) from continuing operations	(774	)	(2,184	)	(323	)	(306	)	(145	)	(628	)	(899	)	(888	)	(397	)	(1,154	)
Net income (loss) from discontinued operations2	—		(294	)	—		—		—		—		112		(364	)	(42	)	(436	)
Net income (loss)	(774	)	(2,478	)	(323	)	(306	)	(145	)	(628	)	(787	)	(1,252	)	(439	)	(1,590	)
Per common share ($)
Net income (loss)3	(0.42	)	(2.39	)	(0.18	)	(0.17	)	(0.08	)	(0.59	)	(0.75	)	(1.20	)	(0.43	)	(1.54	)
Diluted net income (loss)4	(0.42	)	(2.42	)	(0.18	)	(0.17	)	(0.08	)	(0.59	)	(0.75	)	(1.24	)	(0.43	)	(1.54	)
Income (loss) from continuing operations per common share
Basic3	(0.42	)	(2.11	)	(0.18	)	(0.17	)	(0.08	)	(0.59	)	(0.86	)	(0.85	)	(0.39	)	(1.12	)
Diluted4	(0.42	)	(2.14	)	(0.18	)	(0.17	)	(0.08	)	(0.59	)	(0.86	)	(0.89	)	(0.39	)	(1.12	)
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	115		123		116		112		119		127		120		127		124		125
Natural gas (mmcf/d)	1,270		1,314		1,223		1,252		1,334		1,359		1,299		1,321		1,325		1,328
Continuing operations (mboe/d)	342		358		334		335		357		369		351		362		360		362
Discontinued operations (mboe/d)2	—		15		—		—		—		—		13		16		16		18
Total mboe/d	342		373		334		335		357		369		364		378		376		380

(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 third quarter of 2016, the Company’s net loss from continuing operations decreased by $576 million to $323 million. This was principally due to reductions in impairment expense, DD&A expense, operating expense, income taxes and equity earnings. This was partially offset by reduced sales revenue due to both lower production and commodity prices and increased dry hole expense.

DAILY AVERAGE PRODUCTION

	Three months ended September 30				Nine months ended September 30
	Gross before royalties		Net of royalties		Gross before royalties		Net of royalties
	2016	2015	2016	2015	2016	2015	2016	2015
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	39	40	33	34	39	42	34	36
Southeast Asia	26	33	17	22	29	37	20	25
North Sea	—	10	—	10	—	12	—	12
Other1	16	14	8	8	12	14	6	9
	81	97	58	74	80	105	60	82
Oil and liquids from Joint Ventures (mbbls/d)
RSRUK	22	20	22	20	22	18	22	18
Equion	13	13	10	11	13	12	11	10
	35	33	32	31	35	30	33	28
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	116	130	90	105	115	135	93	110
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	775	788	667	677	789	788	687	683
Southeast Asia	423	464	316	331	445	481	340	345
North Sea	—	18	—	18	—	19	—	19
	1,198	1,270	983	1,026	1,234	1,288	1,027	1,047
Natural gas from Joint Ventures (mmcf/d)
RSRUK	2	6	2	5	3	4	3	4
Equion	23	41	20	39	33	41	26	34
	25	47	22	44	36	45	29	38
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,223	1,317	1,005	1,070	1,270	1,333	1,056	1,085
Total daily production from Consolidated Subsidiaries (mboe/d)
North America	177	180	152	154	180	182	156	158
Southeast Asia	101	116	73	81	108	123	80	86
North Sea	—	13	—	13	—	15	—	15
Other	16	14	8	8	12	14	6	9
	294	323	233	256	300	334	242	268
Total daily production from Joint Ventures (mboe/d)
RSRUK	23	21	23	21	23	19	23	19
Equion	17	20	14	18	19	20	15	16
	40	41	37	39	42	39	38	35
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)	334	364	270	295	342	373	280	303
Less production from discontinued operations (mboe/d)
North Sea	—	13	—	13	—	15	—	15

Total production from continuing operations (mboe/d)	334	351	270	282	342	358	280	288

(1) Other is also referred to as Rest of World.

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

Total production from continuing operations was 334 mboe/d in 2016, a decrease of 5% compared to 2015 due principally to decreased production in Southeast Asia, the Equion joint venture and North America which was partially offset by increased production in Algeria.

In North America, total production decreased by 2% compared to 2015. Total oil and liquids production decreased by 3% principally due to the Company’s sale of 26% of its 50% interest in the Eagle Ford area of the US in late 2015 (resulting in a reduction to the Company’s interest to 37%), partially offset by increased production due to the development of Duvernay and Bigstone/Wild River. Total natural gas production decreased by 2% due to lower natural gas volumes from the Company’s reduced interest in the Eagle Ford, which was slightly offset by new wells coming on stream in the Greater Edson area of Canada.

In Southeast Asia, total production decreased by 13% compared to 2015. Total oil and liquids production decreased by 21% due principally to well shut-ins and natural declines in Vietnam and Malaysia. Natural gas production decreased by 9% due principally to lower Corridor demand as impacted from increased competing LNG cargoes from Tangguh.

In Rest of World, total production increased by 14% compared to 2015, principally due to Algeria license extensions that were granted effective January 1, 2016 now recorded entirely in the third quarter of 2016, partially offset by production from the Akacias field in Colombia being shut-in.

In the RSRUK joint venture, total production increased by 10% principally due to production from several fields which were shut-in and platform outages in the prior period.

In the Equion joint venture, total production decreased by 15%. This was principally due to the decrease in natural gas production as a result of a license relinquishment in 2016.

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

	Three months ended September 30				Nine months ended September 30
	2016		2015		2016		2015
North America - bbls/d	(583	)	739		(677	)	(84	)
Southeast Asia - bbls/d	(600	)	(4,398	)	(341	)	1,779
Other - bbls/d	1,777		2,218		749		597
Total produced into (sold out of) inventory - bbls/d	594		(1,441	)	(269	)	2,292
Total produced into (sold out of) inventory - mmbbls	0.1		(0.1	)	(0.1	)	0.6
Inventory at September 30 - mmbbls	1.6		2.0		1.6		2.0

(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.

During the three month period ended September 30, 2016, volumes in inventory remained consistent from June 30, 2016 at 1.6 mmbbls. This was due principally to decreased inventories in Southeast Asia and North America which was partially offset by increased inventory in Algeria.

COMPANY NETBACKS1,2,3

	Three months ended September 30				Nine months ended September 30
	Gross before royalties		Net of royalties		Gross before royalties		Net of royalties
	2016	2015	2016	2015	2016	2015	2016	2015
Oil and liquids ($/bbl)
Sales price	36.19	36.07	36.19	36.07	33.69	41.91	33.69	41.91
Royalties	11.66	10.19	—	—	9.76	11.23	—	—
Transportation	1.54	1.97	2.28	2.75	1.63	2.00	2.30	2.73
Operating costs	9.79	13.06	14.44	18.20	9.55	12.18	13.45	16.63
	13.20	10.85	19.47	15.12	12.75	16.50	17.94	22.55
Natural gas ($/mcf)
Sales price	3.30	3.47	3.30	3.47	2.89	3.72	2.89	3.72
Royalties	0.67	0.79	—	—	0.55	0.83	—	—
Transportation	0.24	0.25	0.30	0.32	0.25	0.25	0.31	0.33
Operating costs	0.90	1.04	1.12	1.33	0.91	1.09	1.12	1.40
	1.49	1.39	1.88	1.82	1.18	1.55	1.46	1.99
Total $/boe (5.615 mcf:1boe)
Sales price	23.39	24.14	23.39	24.14	20.90	26.97	20.90	26.97
Royalties	5.93	6.05	—	—	4.88	6.58	—	—
Transportation	1.39	1.56	1.86	2.08	1.47	1.59	1.91	2.11
Operating costs	6.34	7.85	8.02	9.98	6.29	7.89	7.78	9.93
	9.73	8.68	13.51	12.08	8.26	10.91	11.21	14.93

(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 September 30, 2016, the Company’s average gross netback was $9.73/boe, 12% higher than in 2015 due principally to lower operating costs.

The Company’s composite royalty rate was consistent at 25% from 2015.

COMMODITY PRICES AND EXCHANGE RATES1,2

	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015
Oil and liquids ($/bbl)
North America	25.86	27.82	24.38	29.00
Southeast Asia	46.80	44.44	43.08	53.85
Other	44.21	39.91	41.61	49.16
	36.19	36.07	33.69	41.91
Natural gas ($/mcf)
North America	2.25	2.22	1.89	2.34
Southeast Asia	5.23	5.61	4.67	5.97
	3.30	3.47	2.89	3.72
Company $/boe (5.615mcf:1boe)	23.39	24.14	20.90	26.97
Benchmark prices and foreign exchange rates
WTI (US$/bbl)	44.94	46.43	41.33	50.97
Dated Brent (US$/bbl)	45.85	50.26	41.77	55.39
WCS (US$/bbl)	31.40	33.16	27.63	37.80
LLS (US$/bbl)	46.53	50.25	43.00	55.35
NYMEX (US$/mmbtu)	2.81	2.77	2.29	2.80
AECO (C$/gj)	2.09	2.65	1.76	2.66
C$/US$ exchange rate	1.30	1.31	1.32	1.26
UK£/US$ exchange rate	0.76	0.65	0.72	0.65

(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 7% in 2016 due principally to decreases in benchmark prices. In Southeast Asia, realized oil and liquids prices increased 5% while Brent crude pricing has decreased due to timing of liftings in Malaysia. Due to these reasons, the Company’s overall realized oil and liquids price has remained consistent compared to 2015.

In North America, realized natural gas prices increased by 1% in 2016. This was due to the 10% increase in the US, which is consistent with increase in benchmark prices offset with Canada’s decrease of 18% as a result of the decrease in the AECO benchmark price. In Southeast Asia, where a significant portion of gas sales are linked to oil prices, realized natural gas prices decreased by 7% which is in line with decreases in benchmark crude pricing. Due to these reasons, the Company’s overall realized natural gas price of $3.30/mcf decreased by 5% compared to 2015.

In Rest of World, realized oil and liquids prices have increased 11% while benchmark prices have decreased due to timing of liftings in Algeria.

EXPENSES

Unit Operating Expenses1,2

Three months ended September 30

Nine months ended September 30

Gross before
royalties

Net of royalties

Gross before
royalties

Net of royalties

($/boe)

2016

2015

2016

2015

2016

2015

2016

2015

North America

5.13

6.79

5.96

7.93

5.54

7.11

6.38

8.23

Southeast Asia

8.49

8.71

11.77

12.40

7.43

8.35

9.99

11.84

Other

6.29

14.48

13.08

25.60

7.17

13.99

14.38

20.95

6.34

7.85

8.02

9.98

6.29

7.89

7.78

9.93

(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 September 30		Nine months ended September 30
(millions of $)	2016	2015	2016	2015

North America	86	114	280	362
Southeast Asia	80	97	222	266
Other	9	15	27	49
	175	226	529	677

(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 23% to $175 million in 2016.

In North America, total operating expenses decreased by $28 million principally due to a reduction in the Company’s interest in Eagle Ford in late 2015 and due to a focused effort to reduce operating expenses in a low commodity price environment in both Canada and the US. Unit operating expenses in North America decreased by 24% due to the reasons noted above.

In Southeast Asia, total operating expenses decreased by $17 million due primarily to lower inspection, processing and lifting costs in Vietnam, lower insurance expense and maintenance activities in Indonesia, and timing of liftings in Malaysia. Operating costs were also lower as a result of the Kitan field in Australia/Timor-Leste which is no longer producing, and the sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016. The decrease was also as a result of lower production and focused effort to reduce costs in a low commodity price environment. Unit operating expenses decreased by 3% due to the reasons noted above.

In Rest of World, total operating expenses decreased by $6 million primarily due to Akacias production being shut-in in Colombia, partially offset with increase in Algeria due to timing of liftings. Unit operating expenses decreased by 57% due principally to the reasons noted above.

Unit operating expense for the Company decreased by 19% to $6.34/boe due to the reasons noted above.

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

Three months ended September 30

Nine months ended September 30

Gross before
royalties

Net of royalties

Gross before
royalties

Net of royalties

($/boe)

2016

2015

2016

2015

2016

2015

2016

2015

North America

13.80

15.59

16.04

18.21

13.88

15.33

15.99

17.73

Southeast Asia

7.09

10.37

9.82

14.76

7.03

11.18

9.46

15.87

Other

9.19

11.98

19.11

21.19

10.34

11.73

20.74

17.57

11.24

13.48

14.20

17.16

11.27

13.58

13.95

17.09

(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 September 30		Nine months ended September 30
(millions of $)	2016	2015	2016	2015

North America	226	258	685	767
Southeast Asia	64	122	208	372
Other	11	14	31	45
	301	394	924	1,184

(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 North America and Southeast Asia.

DD&A expense in North America decreased by 12% due principally to the partial sale of the Eagle Ford in late 2015 and lower production in Marcellus and Eagle Ford, partially offset by higher production in Canada. Unit DD&A expense decreased by 11% due to the reasons noted above.

In Southeast Asia, DD&A expense decreased by 48% due principally to a lower depletable base in Malaysia and Vietnam as a result of asset impairments recorded at year-end 2015, lower production in Vietnam and timing of liftings in Malaysia. Unit DD&A expense decreased by 32% due to the reasons noted above.

In Rest of World, total DD&A expense decreased by 21% primarily due to Akacias production being shut-in in Colombia, partially offset by increase in Algeria due to increased production and timing of liftings. Unit DD&A expense decreased by 23% due to the reasons noted above.

Unit DD&A expense for the Company decreased by 17% to $11.24/boe due to the reasons noted above.

Income (Loss) from Joint Ventures and Associates1

	Three months ended September 30				Nine months ended September 30
(millions of $)	2016		2015		2016		2015
RSRUK	(200	)	(208	)	(335	)	(529	)
Equion	10		(23	)	23		(16	)
	(190	)	(231	)	(312	)	(545	)

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

RSRUK Joint Venture

The after-tax net loss in RSRUK decreased by $8 million compared to 2015 due principally to lower operating cost as a result of operational initiatives and cost-saving measures and lower DD&A as a result of an increase in reserves partially offset with an increase in the depletable base. This was partially offset by an impairment expense recorded on the Seagull exploration well and lower sales revenues as a result of the timing of liftings.

Equion Joint Venture

The after-tax net income in Equion of $10 million in 2016 as compared to an after-tax net loss of $23 million in 2015 was primarily a result of lower DD&A due to impairments in late 2015 and lower production, as well as a decrease in income tax expense. This was partially offset by decreased revenue from lower gas prices and a decrease in gas production.

Corporate and Other1,2

	Three months ended September 30			Nine months ended September 30
(millions of $)	2016		2015	2016	2015
General and administrative (G&A) expense	56		61	177	228
Impairment	14		325	14	373
Dry hole expense	41		1	54	14
Exploration expense	19		20	81	142
Finance costs	44		83	145	246
Share-based payments recovery	—		—	—	(24	)
Gain on held-for-trading financial instruments	—		—	—	(62	)
(Gain) loss on disposals	(1	)	—	6	9
Other expenses, net	5		34	32	180
Other income	30		35	103	123

(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 $5 million relative to 2015 principally due to lower workforce expenses in Southeast Asia and sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016.

Dry hole expense of $41 million is related to the write-off of well costs in Malaysia.

Exploration expense of $19 million consists primarily of seismic related costs in Southeast Asia and the Rest of the World.

Finance costs include interest on long-term debt (including current portion), interest on loans from related parties, other finance charges and accretion expense relating to decommissioning liabilities. Finance costs decreased by $39 million in 2016 by reducing overall long-term debt and by replacing the remaining portion with related party financing, which carries lower financing costs.

Other expenses of $5 million is primarily made up of $11 million from an onerous contract provision related to the company’s office lease and other miscellaneous expenses of $12 million, partially offset by an unrealized foreign exchange gain of $19 million.

Other income of $30 million consists primarily of marketing and other miscellaneous income of $22 million, investment income of $4 million and pipeline and customer treating tariffs of $4 million.

INCOME TAXES1,2

	Three months ended September 30				Nine months ended September 30
(millions of $)	2016		2015		2016		2015
Loss from continuing operations before taxes	(379	)	(846	)	(985	)	(1,764	)
Less: PRT
Current	1		2		4		6
Deferred	(8	)	2		(13	)	(1	)
Total PRT	(7	)	4		(9	)	5
	(372	)	(850	)	(976	)	(1,769	)
Income tax expense (recovery)
Current income tax	39		(361	)	111		(230	)
Deferred income tax	(88	)	410		(313	)	645
Income tax expense (recovery) (excluding PRT)	(49	)	49		(202	)	415
Effective income tax rate (%)	13	%	(6	)%	21	%	(23	)%

(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 third quarter of 2016 was impacted by pre-tax losses of $107 million in North America, where tax rates are between 27% and 39%, after-tax net loss of $190 million from joint ventures, and pre-tax loss of $6 million in Southeast Asia, where tax rates range from 30% to 58%.

In addition to the jurisdictional mix of income, the effective tax rate was also impacted by non-recognition of tax benefits associated with losses in exploration blocks.

For the three month period ended September 30, 2016, the current tax expense was $39 million compared to a $361 million recovery in 2015, due principally to reclassification of deferred income tax to current income tax in 2015 as a result of the Norway disposition.

For the three month period ended September 30, 2016, the deferred income tax recovery was $88 million compared to a deferred income tax expense of $410 million in 2015 due principally to:

· Completed sale of the Norwegian operations to Repsol Exploration Norge AS in 2015;

· Impact of tax depreciation differences;

· Foreign exchange on foreign denominated tax pools;

· Recovery from the Malaysia dry hole expensed in 2016.

CAPITAL EXPENDITURES1

	Three months ended September 30		Nine months ended September 30
($ millions)	2016	2015	2016	2015

North America	49	224	217	555
Southeast Asia	71	55	112	163
Other	6	8	16	37
Exploration and development expenditure from Consolidated Subsidiaries2	126	287	345	755
Corporate, IS and Administrative	—	3	3	22
Acquisitions and extensions	2	3	69	11
Net capital expenditure for Consolidated Subsidiaries	128	293	417	788
RSRUK	48	80	168	290
Equion	3	11	12	32
Exploration and development expenditure from Joint Ventures3	51	91	180	322
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures	179	384	597	1,110

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

(2) Excludes exploration expense of $19 million (2015 - $20 million) for the three month period ended September 30, 2016 and $81 million (2015 - $142 million) for the nine month period ended September 30, 2016.

(3) Represents the Company’s proportionate interest, excluding exploration expensed of $1 million (2015 - $1 million) net for the three month period ended September 30, 2016 and $3 million (2015 - $2 million) for the nine month period ended September 30, 2016.

North American capital expenditures during the quarter totalled $49 million, a decrease of 78%. This was as a result of the decreased development spending in Marcellus, Eagle Ford, Edson and Chauvin areas and decreased exploration spending in Duvernay due to reduced cash flows and less attractive investment economics from lower commodity prices. The majority of the 2016 capital expenditures relate to development drilling and completion costs in Greater Edson, Marcellus and Eagle Ford.

In Southeast Asia, capital expenditures during the quarter totalled $71 million. This expenditure included $23 million on development with the majority spent in Indonesia and Malaysia and $48 million on exploration with the majority spent in Malaysia.

In the Rest of World, capital expenditures of $6 million consisted of mainly exploration and evaluation activities in Colombia.

During the nine month period ending September 30, 2016, the Company was successful in extending a Production Sharing Contract (“PSC”) in Malaysia until December 31, 2027. As a result, the Company recorded a lease extension payment which is recognized in acquisition and extensions.

In the RSRUK joint venture, net capital expenditures of $48 million consisted primarily of development activities in Monarb and Scapa. In the Equion joint venture, net capital expenditures of $3 million were principally for development activities in Piedemonte.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s gross debt and loans from related parties at September 30, 2016 was $3.4 billion compared to $3.3 billion at December 31, 2015.

During the quarter, the Company generated $154 million of cash in operating activities from continuing operations, incurred capital expenditures of $128 million and drew loans from related parties of $19 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.

During the nine month period ended September 30, 2016, an LNG expansion project in Indonesia was approved. As a result, the Company became a participant in a second series of project financing facilities, the Company’s share of which is up to $114 million. Draws under these facilities bear interest at LIBOR plus 1.75% to LIBOR plus 3.45% per annum. These facilities are to mature on July 20, 2029.

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%. Effective June 13, 2016, the credit limit of this facility was increased to $550 million. As at September 30, 2016, there were $446 million drawings outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine months ended September 30, 2016 was $2 million and $4 million, respectively.

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 September 30, 2016, the Company had $1.5 billion outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine month periods ended September 30, 2016 was $6 million and $16 million, respectively.

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 September 30, 2016, $1.1 billion drawings remained available under the subscription agreement.

On June 8, 2016, Talisman Energy USA Inc. (“TEUSA”), a subsidiary of the Company, entered into a $125 million revolving facility with Repsol USA Holdings Corporation (“RUSA”), a subsidiary of Repsol. The facility matures on June 8, 2017 and bears an interest rate of LIBOR (6 month) plus 1.70%. TEUSA also provides RUSA an $85 million supplementary revolving facility, with interest rate of LIBOR (1 month). As at September 30, 2016, there were no drawings outstanding under the primary facility. Instead, RUSA had a balance of $76 million payable to TEUSA under the supplemental facility. Interest income related to the facility recognized by the Company during the three and nine month periods ended September 30, 2016 was less than $1 million.

During the nine month period ended September 30, 2016, the Company announced the cash tender offer to purchase any and all principal amount of the following:

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 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.

On May 25, 2016, the Company cancelled unsecured credit facilities of $3 billion (Facility No. 1), maturing March 19, 2019 and $200 million (Facility No. 2), maturing October 21, 2019, both of which the Company had not drawn on since May 2015. As a result of the cancellation, the Company no longer has the principal financial covenant of a debt-to-cash flow ratio of less than 3.5:1.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At September 30, 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 RSRUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK. In addition, there were $87 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

RSRUK is required to provide demand 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 RSRUK. Addax’s parent company, China Petrochemical Corporation, 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%. RSRUK has entered into a Decommissioning Relief Deed with the UK Government and continues to negotiate with counterparties to amend all DSAs accordingly. As of September 30, 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, RSRUK’s tax relief is capped at $1.7 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At September 30, 2016, RSRUK has $2.9 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 RSRUK.

Subsequent to September 30, 2016, the Company granted a guarantee of £46 million in respect of RSRUK’s pension scheme liabilities.

The Company also has obligations to fund the losses and net asset deficiency of RSRUK, which arises from the Company’s past practice of funding RSRUK’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 RSRUK’s decommissioning and pension obligation if RSRUK is unable to, and the shareholders of RSRUK have provided equity funding facilities to RSRUK 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 RSRUK will increase to the extent future losses are generated within RSRUK.

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. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from equity accounted entities (defined 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 related party credit facilities.

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 September 30, 2016, approximately 84% of the Company’s accounts receivable was current and the largest single counterparty exposure, accounting for 5% of the total, was with a highly rated counterparty. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base 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 Nov 7, 2016.

For additional information regarding the Company’s liquidity and capital resources, refer to notes 7, 16, 18, 19 and 21 to the Company’s 2015 audited Consolidated Financial Statements and notes 5, 11, 12, 13 and 14 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 and related party loan repayment obligations and significant commitments can be found in notes 7, 14, 16, 17 and 22 to the 2015 audited Consolidated Financial Statements.

During the nine month period ended September 30, 2016, a Tangguh LNG expansion project in Indonesia was approved. As a result, the Company agreed to fund its share of future capital expenditures of $261 million through the approval of a development plan, and entered into project financing arrangements of $114 million.

As a result of the PSC extension in Malaysia in April 2016 (note 7 to the Company’s interim condensed Consolidated Financial Statements), the Company agreed to $180 million in additional minimum work commitments.

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

TRANSACTIONS WITH RELATED PARTIES

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

During the three and nine month periods ended September 30, 2016, the Company incurred $nil and $14 million reinsurance expense, respectively with Gaviota RE S.A., a subsidiary of Repsol. As at September 30, 2016, there was no payable outstanding as a result of this transaction.

North America

During the three and nine month periods ended September 30, 2016, Repsol Canada Energy Partnership sold to Repsol Energy Canada Limited, a subsidiary of Repsol, approximately 16 and 48 trillion British thermal units (“btu”) of natural gas for $29 million and $63 million, respectively. As at September 30, 2016, the amount included in accounts receivable as a result of these transactions was $9 million.

During the three and nine month periods ended September 30, 2016, TEUSA sold to Repsol Energy North America Corporation, a subsidiary of Repsol, approximately 10 and 22 trillion btu of natural gas for $32 million and $57 million, respectively. As at September 30, 2016, the amount included in accounts receivable as a result of these transactions was $11 million.

Rest of World

During the three and nine month periods ended September 30, 2016, Talisman (Algeria) B.V. sold to Repsol Trading S.A., a subsidiary of Repsol, approximately 580,000 and 1,280,000 barrels of Saharan Blend Crude Oil for $27 million and $55 million, respectively. As at September 30, 2016, the amount included in accounts receivable as a result of these transactions was $16 million.

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 Holdings (Private) Limited (“Temasek”). Currently, ROGCI’s share of the sale on a daily basis is approximately 75 billion btu. 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 and nine month periods ended September 30, 2016, the Company’s gas sales to GSPL totaled $37 million and $87 million, respectively (net the Company’s share). As at September 30, 2016, the amount included in accounts receivable as a result of this commitment was $22 million.

RSRUK

In June 2015, the shareholders of RSRUK 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 RSRUK. This facility is effective from July 1, 2015 and had a maturity date of December 31, 2016. In September 2016, this agreement was modified to extend the maturity date to December 31, 2017. During the three and nine month periods ended September 30, 2016, the shareholders of RSRUK agreed to subscribe for common shares of RSRUK in the amount of $105 million and $465 million under this facility, respectively, of which the Company’s share was $54 million and $237 million, respectively.

The shareholders of RSRUK have provided an unsecured loan facility totaling $2.4 billion to RSRUK, of which the Company is committed to $1.2 billion, for the purpose of funding capital expenditures of RSRUK. There was no loan balance outstanding as at September 30, 2016.

Equion

The loan due to Equion of $25 million (December 31, 2015 - $14 million) is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.

During the three months ended September 30, 2016, Equion declared dividends payable to the shareholders in the amount of $100 million of which the Company’s share was $49 million. The Company has recorded a reduction in the equity investment in Equion. The dividends were settled through reduction of the loan due to Equion.

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 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.

For accounting purposes the Company had elected not to designate any derivative contracts entered into as hedges. 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

During the three and nine month periods ended September 30, 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.

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 RSRUK has a 67.41% interest, suffered an upheaval buckle. In September 2012, RSRUK submitted a notification of a claim to Oleum Insurance Company (‘‘Oleum’’), a wholly-owned subsidiary of the Company. RSRUK delivered a proof of loss seeking recovery under the insuring agreement of $350 million. To date, the documentation delivered by RSRUK purporting to substantiate its claim does not support coverage. On August 8, 2016, RSRUK served its Request for Arbitration and on September 7, 2016 Oleum served its Response. The seat of the arbitration is London, while the law of New York governs the claim for damages and business interruption.

On July 13, 2015, Addax and Sinopec International Petroleum Exploration and Production Corporation (“Sinopec”), filed a “Notice of Arbitration” against ROGCI and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% of the shares of RSRUK. ROGCI and TCHL filed their response to the Notice of Arbitration on October 1, 2015. On May 25, 2016, Addax and Sinopec filed their Statement of Claim, in which they seek, in the event that their claims were confirmed in their entirety, repayment of their initial investment in RSRUK, together with any additional investment, past or future, in such company, and further for any loss of opportunity, which they estimate in a total approximate amount of $5.5 billion. The Court of Arbitration has decided, among other procedural matters, to schedule the hearing for January 29 to February 16, 2018. The Company believes the claims included in their Statement of Claim 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 continues to investigate its permit applications and work with the AER in this matter. 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 September 30, 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.

Indonesia

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

Malaysia

The Company’s branches in Malaysia of Repsol Oil & Gas Malaysia Limited, formerly Talisman Malaysia Ltd. and Repsol Oil & Gas Malaysia (PM3) Limited, formerly Talisman Malaysia (PM3) Ltd., had received notifications of additional assessment from the Inland Revenue Board in respect of the years of assessment 2007, 2008 and 2011, disallowing the deduction of certain costs. The appeal was submitted to the Special Commissioners of Petroleum Income Tax (“SCPIT”). Currently the Dispute Resolution Panel of the SCPIT is working with the Company’s external legal consultants for an out of court settlement while the case is waiting to be heard.

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;

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

· Potential future related party transactions and asset transactions.

The factors or assumptions on which the forward-looking information is based include: projected capital investment levels; the flexibility of capital spending plans; 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.

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);

· The UK’s vote in favour of leaving the EU and the expected use of the Article 50 of the Treaty of Lisbon implies an end to the irreversibility of participation in the EU. While the British case is very particular, in the short-term, it creates uncertainty about potential referendums in other countries. In addition, the UK’s vote to leave the EU is a relevant volatility factor. In the short-term, it creates uncertainty that affects the stock, commodities and foreign exchange markets. While the central banks’ reaction is expected to cushion such negative effects to some extent, in the long term, the possibility that other member states could also leave the EU threatens economic stability and the existence of the Euro. Further details about the process of the UK leaving the EU are needed to better assess the impact on the Company;

· 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.

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. 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:1 bbl 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
btu	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
E&E	Exploration and evaluation
EU	European Union
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
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
PRT	Petroleum Revenue Tax
PSU	Performance share unit
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 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.

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/