EX-99.5 6 a16-4350_1ex99d5.htm EX-99.5 MANAGEMENT'S DISCUSSION AND ANALYSIS

Exhibit 99.5

MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2015


REPSOL OIL & GAS CANADA INC.

Management’s Discussion and Analysis (MD&A)

(February 26, 2016)

General

This Management’s Discussion and Analysis (MD&A) should be read in conjunction with the Consolidated Financial Statements of Repsol Oil & Gas Canada Inc. (“ROGCI” or “the Company”), formerly Talisman Energy Inc. for the year ended December 31, 2015. The Company’s Consolidated Financial Statements and the financial data included in this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”), unless otherwise noted.

Unless otherwise stated, references to production and reserves represent the Company’s working interest share (including the Company’s share of volumes of royalty interest) before deduction of royalties. 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. Prior to the acquisition of the Company by Repsol S.A. (“Repsol”), the Company’s previous conversion ratio was six thousand cubic feet (mcf) of natural gas to one barrel (bbl) of oil. Comparative periods have been adjusted to reflect the change in conversion from 6 mcf: 1 bbl to 5:615 mcf:1 bbl. 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.

All comparisons are between the years ended December 31, 2015 and 2014, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this MD&A are listed in the section “Abbreviations and Definitions”.

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. The Company’s Annual Report on Form 40-F may be found in the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database at www.sec.gov.

COMPANY OVERVIEW

Repsol Oil & Gas Canada Inc. is a global upstream oil and gas company. The Company’s main business activities include exploration, development, production, transportation and marketing of crude oil, natural gas and natural gas liquids. The Company is committed to conducting business safely, in a socially and environmentally responsible manner.

On December 15, 2014, the Company entered into an arrangement agreement with Repsol and an indirectly wholly owned subsidiary of Repsol (the “Arrangement Agreement”), providing for Repsol’s acquisition of the Company (the “Repsol Transaction”). Under the terms of the Arrangement Agreement, the acquisition was to be accomplished through a plan of arrangement under the Canada Business Corporations Act. On May 8, 2015, the Repsol Transaction was completed.

Repsol acquired all of the Company’s outstanding common shares and preferred shares. Upon the completion of the Repsol Transaction, the common shares were delisted from the Toronto Stock Exchange and the New York Stock Exchange, and the preferred shares were delisted from the Toronto Stock Exchange and subsequently converted into common shares on a 1:1 basis.

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.

Unless the context indicates otherwise, references in this MD&A to “ROGCI” or “the Company” include, for reporting purposes only, the direct or indirect subsidiaries of Repsol Oil & Gas Canada Inc. and partnership interests held by Repsol Oil & Gas Canada Inc. and its subsidiaries. Such use of “ROGCI” or “the Company” to refer to these other legal entities and partnership interests does not constitute a waiver by Repsol Oil & Gas Canada Inc. or such entities or partnerships of their separate legal status, for any purpose.

The Company’s audited Consolidated 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 audited 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.

Note 30 to the 2015 audited Consolidated Financial Statements provides segmented financial information that forms the basis for much of the following discussion and analysis. In 2015, the Company’s activities were conducted in four geographic segments for the purposes of financial reporting: North America, Southeast Asia, the North Sea and Other. The North America segment includes operations and exploration activities in Canada and the US. The Southeast Asia segment includes operations and exploration activities in Indonesia, Malaysia, Vietnam, Papua New Guinea and operations in Australia/Timor-Leste. The North Sea segment includes operations and exploration activities in the UK. The Company also has operations in Algeria, operations and exploration activities in Colombia, and exploration activities in the Kurdistan Region of Iraq. Furthermore, the Company is in the process of exiting Peru. For ease of reference, all of the activities in Algeria, Colombia, Peru and the Kurdistan Region of Iraq are referred to collectively as the “Other” geographic segment or “Rest of World”, except where otherwise noted.

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

Subsequent to the sale of substantially all of the assets and liabilities of the Company’s Norwegian operations on September 1, 2015, management determined that the functional currency of the remaining Norwegian activities is more closely linked to the Norwegian Krone (“NOK”) than to the US$. Accordingly, effective September 1, 2015,

these activities have been accounted for using a NOK functional currency. The impact of this change in functional currency during the remainder of 2015 was to recognize a translation gain of $3 million included in other comprehensive income.

References in this MD&A to “Consolidated Subsidiaries” refer to Repsol Oil & Gas Canada Inc. together with its subsidiaries which are consolidated for financial reporting purposes. References to “Joint Ventures” are to TSEUK and Equion.

FINANCIAL AND OPERATING HIGHLIGHTS1

(millions of $, unless otherwise stated)	2015				2014				2013
Cash provided by operating activities	2,194				1,899				1,767
Cash provided by operating activities from continuing operations	2,223				1,780				1,466
Net loss	(3,106			)	(911			)	(1,175			)
Loss from continuing operations	(2,812			)	(341			)	(864			)
Loss from discontinued operations2	(294			)	(570			)	(311			)
Common share dividends	117				279				277
Preferred share dividends	2				8				8
Per share ($)
Net loss 3	(2.97			)	(0.89			)	(1.15			)
Diluted net loss 4	(3.01			)	(0.96			)	(1.21			)
Loss from continuing operations3	(2.69			)	(0.34			)	(0.85			)
Loss from discontinued operations2	(0.28			)	(0.55			)	(0.30			)
Common share dividends	$	0.11			$	0.27			$	0.27
Preferred share dividends	C$		0.26		C$		1.05		C$		1.05
Total Production (mboe/d)5	372				385				390
Production from ongoing operations (mboe/d) 6	354				349				332
Average sales price ($/boe) 7	25.57				47.66				47.97
Total revenue and other income7	1,464				3,234				3,909
Operating costs ($/boe) 7	7.57				8.98				8.91
Depreciation, depletion and amortization (DD&A) expense, exploration and dry hole expense 7	1,724				1,970				2,019
Total exploration and development expenditures from Consolidated Subsidiaries and Joint Ventures7	1,399				2,624				2,504
Total assets	12,021				17,330				19,161
Loans from related parties	1,007				—				—
Total long-term debt (including current portion)	2,267				5,064				5,239
Cash and cash equivalents, net of bank indebtedness	91				253				351
Total long-term liabilities	4,775				6,748				7,051

(1) For the year ended December 31, 2015, the Company changed the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

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

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

(4) Diluted net 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.

(5) Includes production from consolidated subsidiaries and joint ventures.

(6) Production from ongoing operations consists of total production less production from assets sold or held for sale.

(7) From continuing operations.

2015 NET LOSS VARIANCES

(millions of $)
2014 net loss from continuing operations	(341	)
Favourable (unfavourable) variances1:
Commodity prices2	(2,404	)
Production volumes2	(335	)
Royalties2	867
Other income	148
Loss from joint ventures and associates, after tax	(46	)
Operating & transportation expenses	183
General and administrative (“G&A”) expense	98
DD&A expense	100
Impairment	(209	)
Dry hole expense	126
Exploration expense	20
Share-based payments expense/recovery	49
Gain on held-for-trading financial instruments	(1,366	)
Gain/Loss on disposals	(552	)
Other	(218	)
Current income tax recovery (including Petroleum Revenue Tax (PRT))	606
Deferred income taxes (including PRT)	462
Total variances	(2,471	)
2015 net loss from continuing operations	(2,812	)

(1) Variances are before tax except for current and deferred taxes, unless otherwise noted.

(2) In the commentary that follows, the term “sales” refers to the net impact of commodity prices, production volumes and royalties.

The significant variances from 2014, as summarized in the net loss variances table, are:

· Lower global commodity prices.

· Lower oil and liquids production in Southeast Asia.

· Reduction in royalties due principally to lower global commodity prices.

· Other income increased mainly due to a $149 million net gain on repayment of long-term debt.

· Decrease in operating expenses in Southeast Asia and North America.

· G&A expense decreased primarily due to lower workforce expenses and reduced reliance on temporary staff and consultants.

· DD&A expense decreased principally due to the impairment of Eagle Ford in the fourth quarter of 2014.

· Increased impairment expense principally due to lower commodity prices.

· Reduction in dry hole expense in Southeast Asia.

· Decrease in gain on held-for-trading financial instruments due principally to the monetization of remaining hedges in early 2015.

· Reduced disposal activity in 2015 compared to the prior year.

· Increase in other expense principally due to onerous lease contracts and other provisions of $118 million, transaction costs incurred in relation to the acquisition of the Company by Repsol of $41 million, foreign exchange of $30 million, restructuring costs of $20 million and bad debts of $20 million.

· Increase in current income tax recovery principally due to the sale of the Norwegian operations and reduced operating income in Southeast Asia.

· Increase in deferred income tax recovery due principally to the recognition of US net operating losses offset by the sale of the Norwegian operations.

OPERATIONS REVIEW

Results Summary

Sales of oil, liquids and natural gas after royalties from continuing operations in 2015 were $2.3 billion, down 45% from 2014 due principally to lower commodity prices and partially due to lower oil and liquids production in Southeast Asia.

Oil and liquids sales decreased by $1.0 billion compared to 2014 principally due to lower commodity prices and partially due to lower oil and liquids production in Southeast Asia. The overall price for oil and liquids was 51% lower in 2015, compared to 2014.

Natural gas sales decreased by $835 million compared to 2014 due principally to lower commodity prices. The overall price for gas was 39% lower in 2015, compared to 2014.

In North America, sales of oil, liquids and natural gas were $938 million, a decrease of 48% from 2014 due primarily to lower commodity prices. Operating expenses, transportation expense, and DD&A decreased by 9% year-over-year.

In Southeast Asia, sales of oil, liquids and natural gas were $1.2 billion, 43% lower than 2014. This was primarily due to lower commodity prices and partially as a result of lower oil and liquids production due principally to the payout of the carry recovery volumes at HST/HSD in Vietnam in the third quarter of 2014 and because of the sale of a 7.48% interest in the Southeast Sumatra PSC in the fourth quarter of 2014. Operating expenses, transportation expense and DD&A decreased by 13% year-over-year.

In the Rest of World, sales of oil, liquids and natural gas were $153 million, 44% lower than 2014 due principally to lower commodity prices.

Daily Average Production

	Gross before royalties			Net of royalties
	2015	2014	2013	2015	2014	2013
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	42	43	35	36	34	27
Southeast Asia	36	43	44	24	28	24
North Sea	9	13	14	9	13	14
Other	14	16	12	9	8	6
	101	115	105	78	83	71
Oil and liquids from Joint Ventures (mbbls/d)
TSEUK	20	17	18	20	17	18
Equion	12	9	9	10	7	8
	32	26	27	30	24	26
Total Oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	133	141	132	108	107	97
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	797	794	883	693	690	774
Southeast Asia	483	510	516	347	348	346
North Sea	14	18	7	14	18	7
	1,294	1,322	1,406	1,054	1,056	1,127
Natural gas from Joint Ventures (mmcf/d)
TSEUK	4	1	2	4	1	2
Equion	42	48	43	34	36	34
	46	49	45	38	37	36
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,340	1,371	1,451	1,092	1,093	1,163
Total Daily Production from Consolidated Subsidiaries (mboe/d)1
North America	185	184	192	160	157	165
Southeast Asia	122	134	136	86	90	86
North Sea	11	16	15	11	16	15
Other	14	16	12	9	8	6
	332	350	355	266	271	272
Total Daily Production From Joint Ventures (mboe/d)1
TSEUK	21	17	18	20	17	18
Equion	19	18	17	16	13	14
	40	35	35	36	30	32
Total Daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)1	372	385	390	302	301	304
Less production from assets sold or held for sale (mboe/d)1,2
North America	7	17	39	6	15	37
Southeast Asia	—	3	4	—	1	3
North Sea	11	16	15	11	16	15
	18	36	58	17	32	55
Total production from ongoing operations (mboe/d)1	354	349	332	285	269	249

(2) Includes assets sold through December 31, 2015.

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

Total production from ongoing operations was 354 mboe/d in 2015, an increase of 1% compared to 2014 due principally to increased production from North American operations and the TSEUK joint venture which was partially offset by a decrease in production from Southeast Asia.

In North America, total production was consistent with 2015 and production from ongoing operations increased by 7% compared to 2014. Oil and liquids production decreased slightly principally due to natural declines partially offset by development activity in Edson and Duvernay. Natural gas production increased slightly primarily due to increased production from development activity in Edson, Marcellus, and Duvernay which was partially offset by dispositions of non-core Canadian assets in 2014 and natural declines.

In Southeast Asia, total production decreased by 9% and production from ongoing operations decreased by 7%. The total oil and liquids production decreased by 16% due principally to the payout of the carry recovery volumes at HST/HSD in Vietnam in the third quarter of 2014 and the sale of a 7.48% interest in the Southeast Sumatra PSC in the fourth quarter of 2014. Natural gas production decreased by 5% in 2015 due principally to reduced overall demand for gas in Indonesia and South Sumatra.

Total production in TSEUK increased by 4 mboe/d due principally to recommencement of production at Monarb and Tartan (which were shut down in the prior year) and improved performance at Claymore due to a new compression unit.

In the Other segment, including the Equion joint venture, production was 33 mboe/d in 2015 compared to 34 mboe/d in 2014. Production in Colombia was consistent with 2014 and there was a reduction of 1 mboe/d in Algeria due principally to operational issues.

Volumes Produced Into (Sold Out of) Inventory1,2,3

	2015		2014	2013
North America - bbls/d	227		82	—
Southeast Asia - bbls/d	1,192		328	(2,630	)
Other - bbls/d	(504	)	791	(410	)
Total produced into (sold out of) inventory - bbls/d	915		1,201	(3,040	)
Total produced into (sold out of) inventory - mmbbls	0.3		0.4	(1.1	)
Inventory at December 31 - mmbbls	1.7		1.4	1.0

(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 year ended December 31, 2015, volumes in inventory increased from 1.4 mmbbls to 1.7 mmbbls due principally to increased inventories in Malaysia, Indonesia, Vietnam, Australia, Colombia and North America partially offset by decreased inventories in Algeria.

Company Netbacks1,2,3

	Gross before royalties			Net of royalties
	2015	2014	2013	2015	2014	2013
Oil and liquids ($/bbl)
Sales price	39.57	81.31	92.31	39.57	81.31	92.31
Royalties	10.94	26.80	36.29	—	—	—
Transportation	1.89	1.62	1.05	2.62	2.42	1.72
Operating costs	11.86	15.52	16.16	16.39	23.15	26.62
	14.88	37.37	38.81	20.56	55.74	63.97
Natural gas ($/mcf)
Sales price	3.55	5.86	5.69	3.55	5.86	5.69
Royalties	0.79	1.40	1.42	—	—	—
Transportation	0.25	0.24	0.26	0.33	0.32	0.35
Operating costs	1.04	1.09	1.12	1.34	1.43	1.49
	1.47	3.13	2.89	1.88	4.11	3.85
Total $/boe (5.615 mcf= 1boe)4
Sales price	25.57	47.66	47.97	25.57	47.66	47.97
Royalties	6.30	13.62	15.50	—	—	—
Transportation	1.56	1.45	1.35	2.07	2.03	1.99
Operating costs	7.57	8.98	8.91	9.53	11.77	11.78
	10.14	23.61	22.21	13.97	33.86	34.20

(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.

(4) For the year ended December 31, 2015, the Company adjusted the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

During 2015, the Company’s average gross netback was $10.14/boe, 57% lower than 2014 due principally to lower realized prices, partially offset by lower royalties and lower operating costs.

The Company’s net price of $25.57/boe was 46% lower than 2014 due principally to a 51% decline in realized oil and liquids prices due to lower global oil and liquids prices and a 39% decrease in realized prices on natural gas.

Commodity Prices and Exchange Rates1,2

	2015	2014	2013
Oil and liquids ($/bbl)
North America	27.93	61.49	66.70
Southeast Asia	50.76	98.31	108.56
Other	46.17	89.39	107.32
	39.57	81.31	92.31
Natural gas ($/mcf)
North America	2.24	4.12	3.49
Southeast Asia	5.72	8.58	9.44
	3.55	5.86	5.69
Company $/boe (5.615mcf=1boe)3	25.57	47.66	47.97
Benchmark prices and foreign exchange rates
WTI (US$/bbl)	48.78	92.97	97.97
Dated Brent (US$/bbl)	52.46	98.99	108.66
WCS (US$/bbl)	35.46	73.36	72.96
LLS (US$/bbl)	52.40	96.74	107.31
NYMEX ($/mmbtu)	2.67	4.37	3.67
AECO (C$/gj)	2.62	4.19	3.00
C$/US$ exchange rate	1.28	1.10	1.03
UK£/US$ exchange rate	0.65	0.61	0.64

(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.

(3) For the year ended December 31, 2015, the Company adjusted the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

In North America, realized oil and liquids prices decreased by 55% in 2015 due principally to decreases in benchmark prices. In Southeast Asia, realized oil and liquids prices decreased 48%, consistent with decreases in Brent crude pricing. Due to these reasons, the Company’s overall realized oil and liquids price of $39.57/bbl decreased by 51% compared to 2014.

In North America, realized natural gas prices decreased by 46% in 2015, which is consistent with decreases in benchmark prices. In Southeast Asia, realized natural gas prices decreased by 33% where a portion of natural gas pricing is sold via higher offsetting fixed-price contracts. Due to these reasons, the Company’s overall realized natural gas price of $3.55/mcf decreased by 39% compared to 2014.

Royalties1,2,3

	2015		2014		2013
	Rate (%)	$ million	Rate (%)	$ million	Rate (%)	$ million
North America	14	150	16	350	16	321
Southeast Asia	30	503	34	1,036	39	1,413
Other	39	99	46	233	54	270
	25	752	26	1,619	30	2,004

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

(2) Includes impact of royalties related to sales volumes.

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

The overall royalty rate was 25%, down from 26% in 2014. The decrease in royalty rate is principally due to lower commodity prices.

Unit Operating Expenses1,2,3

	Gross before royalties			Net of royalties
($/boe)	2015	2014	2013	2015	2014	2013
North America	6.54	7.54	7.97	7.55	8.85	9.27
Southeast Asia	8.39	10.69	10.44	11.92	16.02	16.46
Other	14.06	11.38	6.48	22.41	21.66	13.84
	7.57	8.98	8.91	9.53	11.77	11.78

(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.

(3) For the year ended December 31, 2015, the Company adjusted the conversion ratio of barrels of oil equivalent (boe) to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

Total Operating Expenses1

(millions of $)	2015	2014	2013
North America	449	517	568
Southeast Asia	367	494	532
Other	69	62	30
	885	1,073	1,130

(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 were down by $188 million compared to 2014.

In North America, total operating expenses decreased 13% compared to 2014 due primarily to a weakening of the Canadian dollar, Canadian non-core asset dispositions, Edson gas plant turn-around in 2014 and lower severance taxes in the US due to lower prices. Unit operating expenses in North America decreased by 13% due to the reasons noted above.

In Southeast Asia, total operating expenses decreased by 26% due primarily to lower floating production storage and offloading (“FPSO”) operating costs in Kitan, lower marine vessel costs in PM3, lower wireline and well intervention costs in Kinabalu, and lower jacket repair costs in HSD/HST as major jacket repair projects were completed in 2014. Unit operating expenses decreased by 22% due principally to the reasons noted above.

In the Rest of World, total operating expenses increased by 11% compared to 2014 due primarily to an increase in the number of well work-overs and plant turnaround work in Algeria. Unit operating expenses increased by 24% due principally to the reasons noted above and decreased production.

Unit operating expense for the Company decreased by 16% to $7.57/boe due to the reasons noted above.

Unit Depreciation, Depletion and Amortization (DD&A) Expense1,2,3

	Gross before royalties			Net of royalties
($/boe)	2015	2014	2013	2015	2014	2013
North America	14.86	16.53	17.38	17.15	19.40	20.22
Southeast Asia	10.53	9.82	9.53	14.96	14.71	15.02
Other	12.08	10.16	6.93	19.26	19.32	14.80
	13.09	13.55	13.88	16.48	17.75	18.36

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

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

Total DD&A Expense1,2

(millions of $)	2015	2014	2013
North America	1,004	1,109	1,211
Southeast Asia	466	473	486
Other	64	52	30
	1,534	1,634	1,727

(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 6% compared to 2014 due principally to decreased DD&A expense in North America.

DD&A expense in North America decreased by 9% primarily due to the impairment of Eagle Ford in late 2014 and an increase in reserve additions in Marcellus, partially offset by increased production in Marcellus, Edson, and Duvernay and an increase in the depletable base in Duvernay. Unit DD&A expense decreased by 10% due to the reasons noted above.

In Southeast Asia, DD&A expense decreased by 1% due principally to lower production in the year. This was partially offset by an increase in the depletable base from a K3 sidetrack well in Australia (with minimal reserves) and downward reserve revisions in late 2014 in both Malaysia and Vietnam which increased their respective 2015 DD&A rates. Unit DD&A expense increased by 7% due to the reasons noted above.

In the Rest of World, total DD&A expense increased by 23% due principally to a higher depletable base from Akacias wells and facilities in Colombia and also from increased volumes from higher DD&A rate properties in Algeria. Unit DD&A expense increased by 19% due to the reasons noted above.

Unit DD&A expense for the Company decreased by 3% to $13.09/boe due to the reasons noted above.

Impairment1,2

(millions of $)	2015		2014		2013
Impairment losses
North America	734		625		332
Southeast Asia	610		60		55
North Sea3	—		287		185
Other4	338		374		16
	1,682		1,346		588
Impairment reversals
North America	(155	)	(32	)	—
Southeast Asia	(4	)	—		—
	(159	)	(32	)	—
Net impairment	1,523		1,314		588

(1) Represents impairment losses and reversals from consolidated subsidiaries, excluding impairment losses and reversals from equity accounted entities.

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

(3) The impairment losses in the North Sea for years 2013 & 2014 relate entirely to the impairment of Goodwill

(4) Included in the impairment expense of “Other” is a non-taxable impairment expense of $47 million for 2015 ($133 million in 2014) relating to the Company’s investment in the Equion joint venture.

North American Impairments

During 2015, the Company recorded a PP&E asset impairment reversal of $120 million relating to Edson ($88 million after-tax), in part as a result of the aggregation of the Wild River/Bigstone CGU into the Edson CGU. In 2015, the Company aggregated these CGUs as they are in the same geographical area and now managed on a portfolio basis due to a change in the management team. The CGU consists of both upstream properties and midstream assets.

During 2015, the Company fully impaired the Groundbirch CGU and recorded a pre-tax impairment expense of $252 million ($185 million after-tax), of which $84 million was to PP&E assets and $168 million was to E&E assets, primarily as a result of the lack of capital committed to the project. The Groundbirch CGU consists of upstream properties.

During 2015, as a result of sustained declines in commodity prices, the Company recorded a $481 million pre-tax ($293 million after-tax) impairment expense in the Eagle Ford CGU of which $389 million was to PP&E assets and $92 million to E&E assets.

Southeast Asia Impairments

During 2015, the Company recorded a pre-tax PP&E impairment expense of $154 million ($96 million after-tax) for PM3 in Malaysia due to the cancellation of development activity and drilling of fewer wells in light of the lower commodity prices. In addition, the Company also recorded a pre-tax E&E impairment expense of $49 million ($30 million after-tax) due to the limited commercial viability of an exploration well in Malaysia.

During 2015, the Company recorded a pre-tax PP&E impairment expense of $17 million ($11 million after-tax) related to Kinabalu in Malaysia and $100 million ($50 million after-tax) related to HST/HSD in Vietnam and fully

impaired a property in Australia (PP&E impairment) for $46 million ($46 million after-tax) primarily as a result of lower commodity prices.

During 2015, the Company recorded a pre-tax E&E impairment expense of $244 million ($244 million after-tax) for Papua New Guinea due to lower gas prices and the higher discount rate due to country risk.

Other Impairments

During 2015, the Company fully impaired its E&E assets in the Kurdistan Region of Iraq and recorded a pre-tax impairment expense of $197 million ($197 million after-tax) as the Company has no specific plan to develop. However, the Company is discussing possible development options with the Kurdistan Regional Government.

During 2015, the Company recorded a pre-tax E&E impairment expense of $94 million ($94 million after-tax) for Block CPE-6 in Colombia relating to E&E assets as the Company reached an agreement in the fourth quarter of 2015 to sell the Block for nominal proceeds.

During 2015, the Company recorded a pre-tax impairment expense of $47 million ($47 million after-tax) related to its investment in Equion, due principally to the lower commodity price environment.

Dry Hole Expense1,2

(millions of $)	2015	2014	2013
North America	—	11	—
Southeast Asia	1	92	60
Other	14	38	11
	15	141	71

(1) Represents dry hole expense from consolidated subsidiaries, excluding dry hole expense from equity accounted entities.

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

In 2015, dry hole expense principally relates to the write-off of unsuccessful exploration wells in Colombia.

Exploration Expense1,2

(millions of $)	2015	2014	2013
North America	51	21	39
Southeast Asia	68	108	59
North Sea	16	—	—
Other	40	66	123
	175	195	221

(1) Represents exploration expense from consolidated subsidiaries, excluding exploration expense from equity accounted entities.

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

Exploration expense consists of geological and geophysical costs, seismic, non-producing land lease rentals and indirect exploration expense. These costs are expensed as incurred.

In North America and the North Sea, exploration expense increased by $46 million due principally to change of

control provisions in certain third party contracts as a result of the acquisition of the Company by Repsol.

In Southeast Asia, exploration expense decreased by $40 million due principally to reduced exploration activity in PNG, Indonesia, Vietnam, and Malaysia.

In the Rest of World, exploration expense decreased by $26 million due principally to reduced exploration activity in Colombia.

Income (Loss) from Joint Ventures and Associates1

(millions of $)	2015		2014		2013
TSEUK	(1,021	)	(1,055	)	(450	)
Equion	(65	)	15		116
Ocensa2	—		—		59
	(1,086	)	(1,040	)	(275	)

(1) Includes the Company’s proportionate interest in joint ventures and associates as disclosed in note 7 of the 2015 audited Consolidated Financial Statements.

(2) In December 2013, the Company sold its 12.152% equity interest in the Ocensa pipeline. Refer to the “Asset Disposals” section of this MD&A for more details.

TSEUK Joint Venture

The Company’s share of net loss from TSEUK decreased from $1,055 million in 2014 down to $1,021 million in 2015 due principally to lower asset impairments and operating expenses in 2015 partially offset by an increase in deferred income tax expense and reduced revenue due to lower commodity prices.

The factors noted above resulted in a negative investment balance in the TSEUK joint venture of $627 million as at December 31, 2015. Based on the anticipated funding requirements in 2016, the Company has recorded $571 million as a current obligation. The obligation to fund TSEUK, in proportion of its shareholding, 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.

Equion Joint Venture

The net loss of $65 million after-tax represents the Company’s 49% interest in the Equion joint venture in Colombia. The 2015 net loss was due primarily to asset impairments and reduced revenue as a result of lower commodity prices which was partially offset by reduced income tax.

Corporate and Other1,2

(millions of $)	2015		2014		2013
G&A expense	298		396		427
Finance costs	327		327		318
Share-based payments expense (recovery)	(24	)	25		49
(Gain) Loss on held-for-trading financial instruments	(61	)	(1,427	)	140
(Gain) Loss on disposals	2		(550	)	(96	)
Other expenses, net	266		48		117
Other income	296		148		109

(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 2015, G&A expense decreased by $98 million relative to 2014 principally due to lower workforce expenses and reduced reliance on temporary staff and consultants, lower office expenses and departure of executives after completion of the Repsol Transaction.

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 were relatively stable as compared to 2014.

Share-based payments recovery in 2015 was $24 million, due principally to the settlement of share-based payments in conjunction with the Repsol Transaction.

The Company recorded a gain on held-for-trading financial instruments of $61 million in 2015 in connection with the monetization of all its hedges in early 2015.

Other expenses consists primarily of onerous lease contracts and other provisions of $121 million, transaction costs of $41 million associated with the Repsol Transaction, restructuring costs of $38 million, bad debts of $20 million, inventory writedowns of $17 million and $29 million in other miscellaneous expenses.

Other income of $296 million includes pipeline, processing, marketing, and investment income which was relatively consistent with 2014. Other income also includes a $149 million net gain on repayment of long-term debt in 2015 and $10 million of interest on the loan to TSEUK.

Income Taxes1,2

(millions of $)	2015		2014		2013
Loss from continuing operations before taxes	(3,658	)	(119	)	(950	)
Less: PRT
Current	8		15		33
Deferred	(1	)	(18	)	5
Total PRT	7		(3	)	38
	(3,665	)	(116	)	(988	)
Income tax expense (recovery)
Current income tax (recovery)	(185	)	414		641
Deferred income tax recovery	(668	)	(189	)	(765	)
Income tax expense (recovery) (excluding PRT)	(853	)	225		(124	)
Effective income tax rate (%)	23	%	(194	)%	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 before taxes adjusted for PRT, which is deductible in determining taxable income.

The 2015 effective tax rate was impacted by pre-tax losses of $1.2 billion in North America where tax rates are between 27% and 39% and pre-tax losses of $429 million in Southeast Asia where tax rates range from 30% to 58%.

The effective tax rate in 2015 was impacted by:

· The recognition of a deferred tax asset relating to net operating losses in the US in the amount of $967 million;

· Not recognizing tax benefits associated with impairments and losses in Papua New Guinea, Kurdistan Region of Iraq, Colombia and Australia;

· Non-taxable hedging gains;

· Foreign exchange on foreign denominated tax pools.

The Company’s 2014 effective tax rate was impacted by pre-tax losses of $530 million in North America where tax rates are between 25% and 39%, partially offset by pre-tax income of $751 million in Southeast Asia where tax rates range from 30% to 50%.

In addition to the jurisdictional mix of income, the effective tax rate in 2014 was also impacted by:

· Not recording $349 million of tax benefit associated with book losses in the US;

· Not recognizing tax benefits associated with operations in Southeast Asia;

· Non-taxable corporate hedging gains;

· Foreign exchange on foreign denominated tax pools; and

· Non-taxable impairments.

The reduction of $599 million in current tax from current income tax of $414 million in 2014 to a current income tax recovery of $185 million in 2015 is due principally to the sale of the Norwegian operations for a $419 million recovery and reduced operating income in Southeast Asia.

The deferred tax recovery of $668 million in 2015 compared to a deferred tax recovery of $189 million in 2014 was due principally to the recognition of US net operating losses offset by the sale of the Norwegian operations.

Capital Expenditures1

($ millions)	2015		2014		2013
North America	763		1,322		1,283
Southeast Asia	210		439		482
Other	46		161		161
Exploration and development expenditure from consolidated subsidiaries2	1,019		1,922		1,926
Corporate, IS and Administrative	24		47		41
Acquisitions	31		35		111
Proceeds of dispositions3	(396	)	(1,517	)	(146	)
Net capital expenditure for consolidated subsidiaries	678		487		1,932
TSEUK	337		599		460
Equion	43		103		118
Exploration and development expenditure from Joint Ventures4	380		702		578
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures	1,058		1,189		2,510

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

(2) Excludes exploration expense of $175 million in 2015 (2014 - $195 million; 2013 - $221 million).

(3) Excludes proceeds, net of disposition costs, of approximately $590 million from the disposal of the Company’s 12.152% equity interest in the Ocensa pipeline in Colombia in December 2013.

(4) Represents the Company’s proportionate interest, excluding exploration expensed of $3 million net in 2015 (2014 - $5 million; 2013 - $19 million).

North American capital expenditures were $763 million in 2015, a decrease of 42% from 2014. Of this, $633 million related to development activity, with the majority spent in the Marcellus, Eagle Ford, and Edson areas. The remaining capital was invested in exploration activities, largely in the Duvernay.

In Southeast Asia, capital expenditures of $210 million included $138 million on development, with the majority spent in Indonesia, Malaysia, and Vietnam. The exploration expenditure of $72 million was invested in Malaysia, Indonesia, Vietnam, and PNG.

In the Rest of World, capital expenditures of $46 million consisted primarily of exploration and evaluation activities in Colombia including the construction of the Akacias facilities.

In the TSEUK joint venture, capital expenditures of $337 million consisted primarily of development activities in the Montrose, Tweedsmuir, and Flyndre/Cawdor areas. In the Equion joint venture, net capital expenditures of $43 million related primarily to Piedemonte development wells and facilities expansion.

DISCONTINUED OPERATIONS

On September 1, 2015, the Company completed the sale of substantially all of the assets and liabilities of its Norwegian operations (the “Disposal Group”), to Repsol Exploration Norge AS, a subsidiary of Repsol, for proceeds of $47 million including working capital.

Operating results related to the Disposal Group have been included in net loss from discontinued operations on the Consolidated Statement of Loss for the period of ownership. During 2015, the Disposal Group was remeasured to its recoverable amount of $47 million and as a result, a loss on remeasurement of discontinued operations of $472 million pre-tax ($292 million after-tax) was recorded in Norway. When the acquisition closed on September 1, 2015, an additional $10 million pre-tax loss on remeasurement of discontinued operations ($2 million after-tax) was recorded. Exchange gains of $114 million relating to the Disposal Group previously recognized in accumulated other comprehensive income were included in the net loss from discontinued operations on the Consolidated Statement of Loss.

Net loss from discontinued operations reported on the Consolidated Statement of Loss is composed of the following:

Years ended December 31,	2015		2014		2013
Revenue	182		529		577
Expenses	(429	)	(1,190	)	(949	)
	(247	)	(661	)	(372	)
Loss on remeasurement of discontinued operations	(482	)	—		—
Realized accumulated translation adjustments on disposition of foreign operations	114		—		—
Loss from discontinued operations before taxes	(615	)	(661	)	(372	)
Income taxes
Current income tax recovery	(8	)	(11	)	(51	)
Deferred income tax recovery	(313	)	(80	)	(10	)
Net loss from discontinued operations	(294	)	(570	)	(311	)

During the year ended December 31, 2015, the Company recorded a pre-tax impairment of $118 million ($85 million after-tax) in Norway E&E assets to fully impair costs associated with a license after a dry exploration well confirmed the license to be uneconomic. In addition, the Company recorded a pre-tax impairment of $30 million ($7 million after-tax) in Norway, due to an increase in the decommissioning obligation and asset caused by a 1.5% decrease in the credit-adjusted discount rate used to measure decommissioning liabilities.

During the year ended December 31, 2014, the Company recorded impairment expenses of $288 million pre-tax ($142 million after-tax) related to E&E assets in Norway. Of the $288 million, $158 million pre-tax expense ($35 million after-tax) was recorded due to uncertainties in future development plans as a result of lower prices and a further $130 million of pre-tax impairment expense ($107 million after-tax) as a result of the Company’s decision to withdraw from an exploration licence following technical evaluation, representing the full book value of the licence.

In addition, the Company also recorded a $166 million pre-tax impairment ($36 million after-tax) related to PP&E assets as a result of lower commodity prices, capital overruns, high operating costs and lower than expected results which resulted in downward reserves revisions.

During 2013 in Norway, the Company recorded a net impairment expense of $358 million pre-tax ($79 million after-tax). The impairments are primarily as a result of increased decommissioning costs and negative reserves revisions.

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

Years ended December 31,	2015		2014		2013
Operating	(29	)	119		301
Investing	9		(193	)	(392	)
Cash flows from discontinued operations	(20	)	(74	)	(91	)

ASSET DISPOSALS

North America Dispositions

On December 30, 2015, the Company completed the sale of 26% of its 50% interest (a net 13% working interest; retaining a 37% working interest post-sale) in its Eagle Ford area to certain subsidiaries of Statoil ASA (“Statoil”) for net proceeds of $393 million after $7 million working capital adjustments, resulting in a pre-tax gain of $6 million ($4 million after-tax). As part of this transaction, the Company also agreed to amend the South Texas Joint Venture Development Agreement with Statoil and transfer operatorship of the western portion of the Eagle Ford to Statoil.

In 2014, the Company completed the sale of its Montney acreage in northeast British Columbia for proceeds of $1.3 billion, resulting in a pre-tax gain of $564 million ($493 million after-tax).

In 2014, the Company sold non-core assets in western Canada for net proceeds of $141 million, after $3 million in working capital adjustments, resulting in a pre-tax loss on disposal of $6 million ($7 million after-tax).

In 2013, the Company completed sales of non-core assets in western Canada for proceeds of $98 million, resulting in a pre-tax gain of $49 million ($37 million after-tax).

North Sea Disposition

On September 1, 2015, the Company completed the sale of substantially all of the assets and liabilities of its Norwegian operations, to Repsol Exploration Norge AS, a subsidiary of Repsol, for proceeds of $47 million including working capital.

Southeast Asia Disposition

In 2014, the Company completed the sale of its 7.48% interest in the Southeast Sumatra PSC in Indonesia for proceeds of $34 million, net of withholding tax, resulting in a pre-tax loss of $3 million ($nil million after-tax). In 2013, the Company completed the sale of its 5.03% interest in the Offshore Northwest Java PSC in Indonesia for net proceeds of $36 million, resulting in a pre-tax gain of $9 million ($3 million after-tax).

Sale of Colombian Pipeline Interest

In 2013, the Company sold its 12.152% equity interest in the Ocensa pipeline in Colombia for proceeds, net of disposition costs, of approximately $590 million, resulting in a pre-tax gain of $34 million. The Company retained its crude oil transportation rights in the Ocensa pipeline and retained its option to market any unused capacity to third parties.

ACQUISITIONS

Vietnam Acquisition

In 2013, the Company acquired a 55% working interest and operatorship of exploration and evaluation assets in Block 07/03 offshore Vietnam via two separate transactions with a total acquisition cost of $95 million. The block is adjacent to the Company’s existing position in the Nam Con Son Basin.

RESERVES AT DECEMBER 31

Disclosure Requirements

As a Canadian public company, the Company is subject to the oil and gas disclosure requirements of National Instrument 51-101 (NI 51-101) of the Canadian Securities Administrators. Information regarding the pricing assumptions used in the preparation of the estimates of NI 51-101 reserves is set forth in Schedule A of the Company’s AIF dated February 26, 2016.

The Company’s gross before royalties proved and probable reserves at December 31, 2015 (including the reserves attributable to its investments in TSEUK and Equion), compiled in accordance with NI 51-101 disclosure requirements using forecast prices, are estimated as follows:

Summary of working interest reserves for Consolidated Subsidiaries on gross basis	Light Oil (mmbbls)	Heavy Oil (mmbbls)	Tight Oil (mmbbls)	Shale Gas (bcf)	Conventional Natural Gas (bcf)	Natural Gas Liquids (mmbbls)
Proved Developed Producing	30.4	31.4	4.4	1,253.6	1,264.5	55.3
Proved Developed Non-Producing	0.1	—	—	26.0	68.6	0.4
Proved Undeveloped	1.4	4.4	5.0	698.7	244.6	21.9
Total Proved	31.9	35.8	9.4	1,978.3	1,577.7	77.6
Total Probable	76.0	20.5	2.1	777.2	863.5	30.5
Total Proved Plus Probable Reserves for Consolidated Subsidiaries	107.9	56.3	11.5	2,755.5	2,441.2	108.1
Summary of working interest reserves for Joint Ventures on gross basis
Proved Developed Producing	30.3	—	—	—	42.9	1.5
Proved Developed Non-Producing	—	—	—	—	—	—
Proved Undeveloped	8.0	—	—	—	27.2	—
Total Proved	38.3	—	—	—	70.1	1.5
Total Probable	32.1	—	—	—	19.4	0.2
Total Proved Plus Probable Reserves for Joint Ventures	70.4	—	—	—	89.5	1.7
Total Proved Plus Probable Reserves for Consolidated Subsidiaries and Joint Ventures	178.3	56.3	11.5	2,755.5	2,530.7	109.8

Reconciliation of proved plus probable reserves:

Continuity of working interest reserves for Consolidated Subsidiaries on gross basis	Light Oil (mmbbls)		Heavy Oil (mmbbls)		Tight Oil (mmbbls)		Shale Gas (bcf)		Conventional Natural Gas (bcf)		Natural Gas Liquids (mmbbls)
At December 31, 2014	139.1		58.2		14.3		2,909.1		2,669.6		127.2
Discoveries	1.1		—		—		—		83.9		—
Additions and extensions	0.4		1.2		2.4		439.1		98.0		23.4
Acquisitions	0.2		—		—		30.5		5.8		—
Divestment	(6.9	)	—		(4.2	)	(80.3	)	(19.2	)	(19.5	)
Technical revisions	3.8		0.9		0.9		82.8		(77.0	)	(7.1	)
Economic revisions	(11.5	)	0.5		(0.4	)	(412.6	)	(58.4	)	(3.3	)
Production	(18.3	)	(4.5	)	(1.5	)	(213.1	)	(261.5	)	(12.6	)
At December 31, 2015 for Consolidated Subsidiaries	107.9		56.3		11.5		2,755.5		2,441.2		108.1
Continuity of working interest reserves for Joint Ventures on gross basis
At December 31, 2014	91.2		—		—		—		115.3		2.2
Discoveries	—		—		—		—		—		—
Additions and extensions	—		—		—		—		2.5		—
Acquisitions	—		—		—		—		—		—
Divestment	—		—		—		—		—		—
Technical revisions	9.4		—		—		—		(4.4	)	—
Economic revisions	(19.0	)	—		—		—		(7.5	)	—
Production	(11.2	)	—		—		—		(16.4	)	(0.5	)
At December 31, 2015 for Joint Ventures	70.4		—		—		—		89.5		1.7
Total at December 31, 2015 for Consolidated Subsidiaries and Joint Ventures	178.3		56.3		11.5		2,755.5		2,530.7		109.8

At the end of 2015, the Company’s proved plus probable reserves totaled 1,297 billion boe. The Company added discoveries, additions, and extensions of approximately 140 million boe (97 million boe proved) offset by positive technical revisions of 8 million boe, negative economic revisions of 119 million boe, acquisitions of 7 million boe and divestments of 48 million boe.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s gross debt and loans from related parties at December 31, 2015 was $3.3 billion compared to $5.1 billion at December 31, 2014.

During 2015, the Company generated $2.2 billion of cash provided by operating activities from continuing operations, incurred capital expenditures of $1.1 billion, and received proceeds of $396 million from the disposition of assets.

The Company’s capital structure consists of shareholder’s equity and debt from banks 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, selling assets to reduce debt, controlling the amount it returns to its shareholder and making 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”). Originally, the facility was to mature on May 8, 2016 and to bear an interest rate of LIBOR (1 month) +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) +1.20%. As at December 31, 2015, there were no drawings under this facility. Instead, RTYGF has a balance of $334 million payable to TEHS, which was recorded as amount due from related party on the Consolidated Balance Sheets. Subsequently in January 2016, the outstanding balance was repaid by RTYGF to TEHS. Interest expense related to the facility recognized by the Company during 2015 was $2 million.

On May 8, 2015, the Company also entered into a $1.0 billion revolving facility with Repsol Energy Resources Canada, Inc. (“RERCI”). The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) +1.20%. The facility limit was increased to $2.0 billion on November 18, 2015 and further increased to $2.8 billion on December 9, 2015. At December 31, 2015, the Company had $1.0 billion outstanding under this facility.

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 the revolving facility. On December 29, 2015, RERCI contributed $1.5 billion of the receivable owing under the revolving facility to the Company in consideration for 785,340,314 common shares in the Company at $1.91 per share, which constituted a repayment of $1.5 billion of the balance owing from the Company to RERCI under the revolving facility. As at December 31, 2015, an aggregate principal amount of $1.1 billion remained available under the subscription agreement. Interest expense related to the facility recognized by the Company during 2015 was $8 million.

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

During the second quarter of 2015, $375 million of 5.125% notes matured and were repaid.

On November 24, 2015, the Company announced a cash tender offer to purchase up to $750 million aggregate principal amount of the Company’s outstanding 5.85% Senior Notes due 2037, 5.50% Senior Notes due 2042, 6.25% Senior Notes due 2038, 7.25% Debentures due 2027 and 5.75% Senior Notes due 2035 (collectively, the “Securities”). Holders of the Securities that were validly tendered, not withdrawn on the early tender date, December 8, 2015, and accepted for purchase received an additional $50 dollars early tender premium per $1,000 dollars principal amount of the Securities accepted for purchase. On December 9, 2015, the Company announced that it had raised the maximum tender amount to $1.5 billion, which was subsequently amended on December 23, 2015 to $2.0 billion. The tender offer expired on January 7, 2016. As at December 31, 2015, the principal amount tendered and accepted was as follows:

Title of Security	Principal	Principal Amount Tendered & Accepted	Principal Amount Outstanding
5.85% Senior Notes due 2037	500	360	140
5.50% Senior Notes due 2042	600	474	126
6.25% Senior Notes due 2038	600	468	132
7.25% Debentures due 2027	300	243	57
5.75% Senior Notes due 2035	125	27	98
Total	2,125	1,572	553

On December 11, 2015, the Company paid the consenting note holders who tendered before December 9, 2015 an aggregate of approximately $1.4 billion in cash (including the early tender premium). On December 24, 2015, the Company paid the consenting note holders who tendered after December 9, 2015 and before December 22, 2015 an aggregate of approximately $48 million in cash.

In addition, on December 23, 2015, the Company also redeemed for retirement $127 million of the 7.75% notes due 2019 for total payment of $139 million (including $138 million principal and $1 million accrued interest).

The above discussed tender offer and redemption of outstanding senior notes resulted in a net gain of $149 million on the Consolidated Statement of Loss.

The Company manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by maintaining appropriate undrawn capacity under committed bank credit facilities. At December 31, 2015, the Company had unsecured credit facilities totaling $3.2 billion, consisting of facilities of $3.0 billion (Facility No. 1),

maturing March 19, 2019 and $200 million (Facility No. 2), maturing October 21, 2019.

At December 31, 2015, there were no drawings on the Company’s bank lines and no commercial paper was outstanding. The authorized amount under the Company’s commercial paper program is $1.0 billion, but the amount available under this program is limited to the availability of backup funds under the Company’s Facility No. 1.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At December 31, 2015, 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 $0.9 billion demand letters of credit issued under TSEUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK.

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

The 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 December 31, 2015, 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 $1.9 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At December 31, 2015, TSEUK has $3.2 billion of demand shared facilities in place under which letters of credit of $1.8 billion have been issued. The Company guarantees 51% of all letters of credit issued under these shared facilities.

The Company 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, is influenced by the Company’s investment-grade credit rating.

The current portion of long-term debt of $156 million consists of $150 million of 8.50% notes, and $6 million in Tangguh project financing.

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 basis as of the last day of each fiscal quarter. For the trailing 12-month period ended December 31, 2015, the debt-to-cash flow ratio was 1.4:1.

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 and subscription facilities as described above.

The Company is exposed to credit risk, which is the risk that a customer or counterparty will fail to perform an obligation or settle a liability, resulting in financial loss to the Company. The Company manages exposure to credit risk by adopting credit risk guidelines approved by the Board of Directors that limit transactions according to counterparty creditworthiness. The Company routinely assesses the financial strength of its joint participants and customers, in accordance with the credit risk guidelines. The Company’s credit policy requires collateral to be obtained from counterparties considered to present a material risk of non-payment, which would include entities internally assessed as high risk or those with ratings below investment grade. Collateral received from customers at December 31, 2015 included $53 million of letters of credit. At December 31, 2015, an allowance of $30 million was recorded in respect of specifically identified doubtful accounts.

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 December 31, 2015, approximately 72% of the Company’s accounts receivable were current and the largest single counterparty exposure, accounting for 4% of the total, was with a highly rated counterparty. Concentration of credit risk is managed by having a broad domestic and international customer base of primarily highly rated counterparties.

The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions.

The Company’s policy allows it to deposit cash balances at financial institutions subject to a sliding scale limit, depending on creditworthiness.

The maximum credit exposure associated with financial assets is the carrying values.

During the year ended December 31, 2015, the Company declared common share dividends of $0.1125 per common share for an aggregate dividend of $117 million. During the year ended December 31, 2015, the Company declared preferred share dividends of C$0.2625 per share for an aggregate dividend of $2 million.

On May 8, 2015, the Repsol Transaction was completed, whereby Repsol acquired all outstanding common and preferred shares of the Company. The outstanding preferred shares were subsequently converted into common shares on a 1:1 basis. Consequently there were no preferred shares outstanding at December 31, 2015. Subsequent to the acquisition of the Company by Repsol on May 8, 2015, all remaining share-based payment units were settled and paid in May 2015. At December 31, 2015 there were no stock options, RSUs, DSUs or PSUs outstanding.

On December 29, 2015, RERCI, a subsidiary of the Company’s parent Repsol, subscribed for $1.5 billion of the Company’s common shares (785,340,314 common shares at $1.91 per share), which settled $1.5 billion of the balance owing from the Company to RERCI under the revolving facility. Subsequent to December 31, 2015 there was no movement in the number of common shares outstanding resulting in 1,829,506,342 common shares outstanding at February 25, 2016.

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

For additional information regarding the Company’s liquidity and capital resources, refer to notes 16, 18, 19 and 21 to the 2015 audited Consolidated Financial Statements.

SENSITIVITIES1

The Company’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated annualized impact of these factors for 2016 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $38/bbl, a NYMEX natural gas price of approximately $2.28/mmbtu and exchange rates of US$0.72=C$1 and UK£1=US$1.48.

(millions of $)	Net Loss		Cash Provided by Operating Activities from continuing operations3
Volume changes
Oil — 10,000 bbls/d	25		80
Natural gas — 60 mmcf/d	—		35
Price changes
Oil — $1.00/bbl	25		25
Natural gas (North America)2 — $0.10/mcf	25		25
Exchange rate changes
US$/C$ decreased by US$0.01	—		(5	)
US$/UK£ increased by US$0.02	(10	)	—

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

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

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

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the 2015 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.

The following table includes the Company’s gross long-term debt, operating and finance leases, PP&E and E&E spend commitments and other expected future payment commitments as at December 31, 2015 and estimated timing of such payments:

			Payments due by period1,2 (millions of $)
Commitments	Recognized in balance sheet	Total	2016	2017- 2018	2019- 2020	2020+
Long-term debt	Yes — Liability	2,267	156	384	585	1,142
Loans from related parties	Yes — Liability	1,007	—	1,007	—	—
Bank indebtedness	Yes — Liability	7	7	—	—	—
Accounts payable and accrued liabilities	Yes — Liability	884	884	—	—	—
Loans from joint ventures	Yes — Liability	14	14	—	—	—
Obligation to fund equity investee	Yes — Liability	627	571	56	—	—
Finance leases	Yes — Partially accrued	55	16	27	5	7
Purchase commitments	No	25	25	—	—	—
Investment commitments3	No	506	260	187	39	20
Service commitments	No	632	130	201	129	172
Transportation commitments4	No	854	119	231	192	312
Operating leases	No	417	62	105	95	155
Total		7,295	2,244	2,198	1,045	1,808

(1) Future payments denominated in foreign currencies have been translated into US$ at the December 31, 2015 exchange rate.

(2) Payments exclude interest on long-term debt.

(3) Investment commitments include drilling rig commitments to meet a portion of the Company’s future drilling requirements, as well as minimum work commitments.

(4) Certain of the Company’s transportation commitments are tied to firm gas sales contracts.

The following summary of commitments summarizes the Company’s share of TSEUK and Equion commitments as at December 31, 2015.

		Payments due by period1,2 (millions of $)
Commitments	Total	2016	2017- 2018	2019- 2020	2020+
Purchase commitments	32	16	16	—	—
Investment commitments3	97	97	—	—	—
Service commitments	189	138	26	17	8
Transportation commitments4	23	11	12	—	—
Operating leases	21	4	4	4	9
Total	362	266	58	21	17

(1) Payments exclude interest on long-term debt and payments made to settle derivative contracts.

(2) Future payments denominated in foreign currencies have been translated into US$ based on the December 31, 2015 exchange rate.

(3) Investment commitments include drilling rig commitments to meet a portion of the Company’s future drilling requirements, as well as minimum work commitments.

(4) Certain of the Company’s transportation commitments are tied to firm gas sales contracts.

The following table provides a summary of the estimated settlement timing of the Company’s decommissioning liabilities as at December 31, 2015. However, due to the nature of the risks provisioned, these timing assessments are subject to uncertainty and changes that are beyond the Company’s control. As a result, the schedule could change in the future accordingly to the circumstances inherent in the estimates.

	Less than one year	Between 1 to 5 years	More than 5 years	Total
Decommissioning liabilities for consolidated subsidiaries	41	320	435	796
Decommissioning liabilities for Joint Ventures1	84	620	1,915	2,619

(1) Represents the Company’s share of the TSEUK and Equion decommissioning liabilities.

Estimated Future Sales Commitments

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 Limited (“Temasek”). Currently ROGCI’s share of the sale on a daily basis is approximately 75 billion British thermal units (“bbtu”). The contract matures in 2023.

Under the sales agreement with GSPL, which is currently due to expire in 2023, delivered gas sales to Singapore from the Corridor Block are priced at approximately 115% of the spot price of high-sulphur fuel oil in Singapore. The Company’s share of the minimum volume commitment is approximately 232 bcf over the remaining eight-year life of the agreement.

The Company is subject to natural gas volume delivery requirements for approximately 70-90 mmcf/d at a price that is referenced to the spot price of high-sulphur fuel oil in Singapore in relation to a long-term gas sales agreement from the PM-3 Commercial Arrangement Area in Malaysia/Vietnam, which is currently scheduled to expire in 2018. In the event these delivery requirements are not met in a contract year, volumes delivered in the subsequent contract year are subject to a 25% price discount for the equivalent volume of unexcused shortage that was not delivered in the prior contract year.

The Company also entered into sales contracts to sell natural gas produced in North America. These contracts mature before the end of 2017. The Company’s volume commitment in Canada is approximately 50% of the portfolio to March 2016 and 20% to October 2016. The Company’s volume commitment from the Marcellus asset is approximately 90% of the portfolio to March 2016, 80% to October 2016, 30% to March 2017, and 10% to October 2017.

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

TRANSACTIONS WITH RELATED PARTIES

Repsol

Repsol’s acquisition of the Company closed on May 8, 2015. During the period from May 8, 2015 to December 31, 2015, the Company entered into the following transactions with subsidiaries of Repsol, its ultimate parent.

On May 8, 2015, TEHS, a subsidiary of the Company, entered into a $500 million revolving facility with RTYGF. Originally, the facility was to mature on May 8, 2016 and to bear an interest rate of LIBOR (1 month) +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) +1.20%. For further information, see the “Liquidity and Capital Resources” section of this MD&A.

On May 8, 2015, the Company also entered into a $1.0 billion revolving facility with RERCI. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) +1.20%. For further information, see the “Liquidity and Capital Resources” section of this MD&A.

During the second quarter of 2015, the Company and a subsidiary of Repsol entered into a purchase and sale agreement whereby the Repsol subsidiary acquired substantially all of the assets and liabilities of the Company’s Norwegian operations. In the Company’s opinion, the consideration for this transaction represents fair value. The transaction closed on September 1, 2015. For further information, see the “Discontinued Operations” section in this MD&A and note 4 in the Company’s 2015 audited Consolidated Financial Statements.

Other

From May 8, 2015 to December 31, 2015, Talisman (Algeria) B.V. (“TABV”) entered into Sale and Purchase Agreements with Repsol Trading S.A., a subsidiary of Repsol, under which TABV sold to Repsol approximately 1,452,000 barrels of Saharan Blend Crude Oil for a total of $75 million. As at December 31, 2015, the amount included in accounts receivable of the Company’s Consolidated Balance Sheet as a result of these transactions was $11 million.

In July and December 2015, Talisman (Colombia) Oil and Gas Ltd. (“TCOG”) entered into Sale and Purchase Agreements with Repsol Trading S.A., a subsidiary of Repsol, under which TCOG sold to Repsol approximately 309,000 barrels of crude oil for $13 million. As at December 31, 2015, the amount included in accounts receivable of the Company’s Consolidated Balance Sheet as a result of these transactions was $2 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 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 Repsol Transaction, GSPL and Temasek became the Company’s related parties. Since May 8, 2015, the Company’s gas sales to GSPL totaled $97 million (net the Company’s share). As at December 31, 2015, the amount included in accounts receivable as a result of this commitment was $18 million.

TSEUK

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

In June 2015, the shareholders of TSEUK provided a new 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 six month period ended December 31, 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $375 million under this facility, of which the Company’s share was $191 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. In January 2015, an agreement was reached by the shareholders of TSEUK, in which the quarterly principal and interest payments of the facility were deferred until July 31, 2015. In July 2015, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $1.1 billion, of which the Company’s share was $541 million, which settled remaining shareholder loans of $1.0 billion and accrued interest of $52 million, of which the Company’s share was $514 million and $27 million, respectively.

The Company has a loan due to Equion of $14 million (2014 - $15 million) which is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.

Key Management Personnel Compensation

The compensation of key management personnel, consisting of the Company’s directors and members of the executive committee, is as follows:

(millions of $)	2015	2014	2013
Short-term benefits	4	14	15
Pension and other post-employment benefits	3	5	5
Termination benefits	23	3	6
Share-based payments1	11	3	9
Change of control payments	24	—	—
	65	25	35

(1) The amount reported represents the cost to the Company of key management’s participation in share-based payment plans, as measured by the fair value that the individual received based on the value of the shares exercised in the current period.

RISK MANAGEMENT

In addition to the risks discussed in the liquidity and capital resources section in 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 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.

During the year the Company received proceeds of $1.3 billion for settlement of its oil and gas derivative contracts, which included proceeds related to the liquidation of substantially all of its contracts relating to commodity price risk management. The Company has not entered into any new commodity price risk management derivative contracts subsequently.

SUMMARY OF QUARTERLY RESULTS1

The following is a summary of quarterly results of the Company for the eight most recently completed quarters.

			Three months ended
(millions of $, unless otherwise stated)	Annual		Dec. 31		Sep. 30		Jun. 30		Mar. 31
2015
Total revenue and other income from continuing operations2	1,464		142		334		551		437
Total revenue and other income from discontinued operations3	182		—		38		83		61
Total revenue and other income	1,646		142		372		634		498
Net loss from continuing operations	(2,812	)	(628	)	(899	)	(888	)	(397	)
Net income (loss) from discontinued operations3	(294	)	—		112		(364	)	(42	)
Net loss	(3,106	)	(628	)	(787	)	(1,252	)	(439	)
Per common share ($)
Net loss 4	(2.97	)	(0.59	)	(0.75	)	(1.20	)	(0.43	)
Diluted net loss 5	(3.01	)	(0.59	)	(0.75	)	(1.24	)	(0.43	)
Loss from continuing operations per common share
Basic4	(2.69	)	(0.59	)	(0.86	)	(0.85	)	(0.39	)
Diluted5	(2.73	)	(0.59	)	(0.86	)	(0.89	)	(0.39	)
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	119		122		116		122		120
Natural gas (mmcf/d)	1,310		1,344		1,283		1,305		1,309
Ongoing operations (mboe/d)	354		361		344		354		353
Assets sold or held for sale (mboe/d)6	18		8		20		24		23
Total mboe/d	372		369		364		378		376
2014
Total revenue and other income from continuing operations2	3,234		(71	)	995		1,134		1,176
Total revenue and other income from discontinued operations3	529		115		141		108		165
Total revenue and other income	3,763		44		1,136		1,242		1,341
Net income (loss) from continuing operations	(341	)	(1,154	)	439		(207	)	581
Net Loss from discontinued operations3	(570	)	(436	)	(14	)	(30	)	(90	)
Net income (loss)	(911	)	(1,590	)	425		(237	)	491
Per common share ($)
Net income (loss)4	(0.89	)	(1.54	)	0.41		(0.23	)	0.47
Diluted net income (loss) 5	(0.96	)	(1.54	)	0.38		(0.24	)	0.43
Income (loss) from continuing operations per common share
Basic4	(0.34	)	(1.12	)	0.42		(0.20	)	0.56
Diluted5	(0.41	)	(1.12	)	0.39		(0.21	)	0.52
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	121		120		115		126		121
Natural gas (mmcf/d)	1,280		1,313		1,260		1,291		1,255
Ongoing operations (mboe/d)	349		354		338		357		344
Assets sold or held for sale (mboe/d) 6	36		26		30		34		57
Total mboe/d	385		380		368		391		401

(1) For the year ended December 31, 2015, the Company adjusted the conversion ratio of barrels of oil equivalent (boe) of natural gas for one barrel of oil to a ratio of 5.615:1 from 6:1. Comparative periods have been adjusted to reflect the change in conversion.

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

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

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

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

(6) Includes assets sold through December 31, 2015.

During the three-month period ended December 31, 2015, total revenue and other income from continuing operations increased by $213 million over the same period in 2014 due principally to reduced losses from the TSEUK joint venture in the current quarter compared to the prior year quarter and partially due to an increase in other income due to the recognition of a net gain on repayment of long-term debt which is partially offset by reduced sales in the current quarter due principally to lower commodity prices and lower production in Southeast

Asia.

Net loss from continuing operations of $1.2 billion for the three-month period ended December 31, 2014 decreased to a net loss of $628 million for the three-month period ended December 31, 2015 due principally to an increase in deferred income tax recovery and partially due to an increase in total revenue and other income. This was partially offset by an overall increase in total expenses due to having recognized a gain on held-for-trading financial instruments of $1.2 billion in the fourth quarter of 2014 compared to recognizing a $nil gain or loss on held-for-trading financial instruments in the current quarter which was partially offset by reductions in impairments, DD&A, dry hole expense, and share-based payments in the current quarter.

Also, during the three-month period ended December 31, 2015, the Company:

· Recorded total production from ongoing operations of 361 mboe/d, up 2% from the same period in 2014.

· On December 30, 2015, the Company completed the sale of 26% of its 50% interest (a net 13% working interest; retaining a 37% working interest post-sale) in its Eagle Ford area to certain subsidiaries of Statoil ASA (“Statoil”) for net proceeds of $393 million after $7 million working capital adjustments, resulting in a pre-tax gain of $6 million ($4 million after-tax).

· Repaid $1.7 billion in long-term debt and recorded a pre-tax gain of $149 million ($109 million post-tax).

· On December 29, 2015, RERCI, a subsidiary of the Company’s parent Repsol, subscribed $1.5 billion in the Company’s common shares (785,340,314 common shares at $1.91 per share), which settled $1.5 billion of balance owing from the Company to RERCI under the revolving facility.

· The recognition of a deferred tax asset relating to net operating losses in the US in the amount of $967 million.

INTERNAL CONTROL OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS AND PROCEDURES

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in rules 13a-15(f) and 15d-15(f) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act).

Management, including the Company’s Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the Company’s internal control over financial reporting based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework).

Based on management’s assessment as at December 31, 2015, management has concluded that the Company’s internal control over financial reporting is effective. The results of management’s assessment were reviewed with the Audit Committee of the Company’s Board of Directors.

Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company’s financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

There have been no changes in the Company’s internal control over financial reporting during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. During the year, the Company was acquired by Repsol which did not result in a material change to internal control over financial reporting as of December 31, 2015. Integration with Repsol will continue to impact internal control over financial reporting over time and the changes will be monitored and managed. As the internal control over financial reporting of both companies is based on the criteria established in COSO 2013, it is not expected that these changes will materially affect internal control over financial reporting.

Disclosure Controls and Procedures

At the end of the period covered by this MD&A, an evaluation was carried out under the supervision of, and with the participation of, the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective.

The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is (a) accumulated and communicated to

the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure; and (b) reported within the time periods specified in the rules and forms of the SEC and the Canadian Securities Administrators.

LEGAL PROCEEDINGS AND CONTINGENCIES

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

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 parties have agreed to a hearing, expected to commence in 2018. The Company believes the claims included in the Notice of Arbitration are without merit.

Subsequent to December 31, 2015, 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 2011. 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 December 31, 2015 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. In 2015, verification and investigation activities related to the years 2006-2010 have been made.

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

Indonesia

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

Malaysia

Talisman Malaysia Ltd. and 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.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

The preparation of audited Consolidated 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. A summary of significant accounting policies adopted by the Company can be found in note 3 to the 2015 audited Consolidated Financial Statements. In assisting the Company’s Audit Committee to fulfil its financial statement oversight role, management regularly meets with the Committee to review the Company’s significant accounting policies, estimates and any significant changes thereto, including those discussed below.

Management believes the most critical accounting policies, including judgments in their application, which may have an impact on the Company’s financial results, relate to the accounting for PP&E, E&E assets, impairments, income taxes, decommissioning liabilities, the recognition of assets acquired and liabilities assumed upon a business combination and goodwill. The rate at which the Company’s assets are depleted, depreciated or otherwise written off and the decommissioning liabilities provided for, with the associated accretion expensed to the income statement, are subject to a number of estimates about future events, many of which are beyond management’s control. Reserves recognition is central to much of an oil and gas company’s accounting, as described below.

Reserves Recognition

Underpinning the Company’s estimates and judgments regarding oil and gas assets and goodwill are its oil and gas reserves. Detailed rules and industry practice, to which the Company adheres, have been developed to provide uniform reserves recognition criteria. However, the process of estimating oil and gas reserves is inherently judgmental. There are two principal sources of uncertainty: technical and commercial. Technical reserves estimates are made using available geological and reservoir data as well as production performance data. As new data becomes available, including actual reservoir performance, reserves estimates may change. Reserves can also be classified as proved or probable with decreasing levels of certainty as to the likelihood that the reserves will be ultimately produced.

Reserves recognition is also impacted by economic considerations. In order for reserves to be recognized, they must be reasonably certain of being produced under existing economic and operating conditions, which is viewed as being annual forecast prices and cost assumptions (NI 51-101 requirements). Any anticipated changes in conditions must have reasonable certainty of occurrence. In particular, in international operations, consideration includes the status of field development planning and gas sales contracts. As economic conditions change, primarily as a result of changes in commodity prices and, to a lesser extent, operating and capital costs, marginally profitable production, typically experienced in the later years of a field’s life cycle, may be added to reserves or, conversely, may no longer qualify for reserves recognition.

The Company’s reserves and revisions to those reserves, although not separately reported on the Company’s balance sheet or statement of income, impact the Company’s reported assets, liabilities and net income through the DD&A of the Company’s PP&E, impairments and the provision for decommissioning liabilities.

The Company’s Board of Directors reviews the Company’s reserves booking process and related public disclosures and the report of the internal qualified reserves evaluator (IQRE). The primary responsibilities of the Board of Directors related to reserves include, among other things, reviewing the Company’s reserves booking process and approving the Company’s annual disclosure of reserves data and other oil and gas information contained in the Company’s AIF. The IQRE reports the Company’s annual reserves data to the Board of Directors and delivers a regulatory certificate regarding proved and probable reserves and their related future net revenue, disclosed pursuant to NI 51-101 requirements.

Depreciation, Depletion and Amortization Expense (DD&A)

A significant portion of the Company’s PP&E is amortized based on the unit of production method with other assets being depreciated on a straight-line basis over their expected useful lives. The unit of production method attempts to amortize the asset’s cost over its proved oil and gas reserves base. Accordingly, revisions to reserves or changes to management’s view as to the operational lifespan of an asset will impact the Company’s future DD&A expense. Depletion and depreciation rates are updated in each reporting period that a significant change in circumstances, including reserves revisions, occurs.

Exploration and Evaluation (E&E) Assets

Exploration well costs are initially capitalized and, if subsequently determined to have not found sufficient reserves to justify commercial production, are charged to dry hole expense. Exploration well costs that have found sufficient reserves to justify commercial production, but those reserves cannot be classified as proved, continue to be capitalized as long as sufficient progress is being made to assess the reserves and economic viability of the well and/or related project. All such carried costs are subject to technical, commercial and management review at each reporting date to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is tested for potential impairment and then transferred to PP&E. If a project no longer meets these criteria, it is tested for impairment and transferred back from PP&E to E&E assets.

Undeveloped land costs are classified initially as E&E assets and transferred to PP&E as proved reserves are assigned. E&E assets are not subject to DD&A.

Impairment of Assets

The Company tests PP&E and E&E assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, for example, changes in assumptions relating to future prices, future costs, reserves and contingent resources. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets, known as a cash-generating unit (CGU). The measurement of impairment charges and reversals is also dependent upon management’s judgment in determining CGUs. If any such indication of impairment exists, an estimate of the CGU’s recoverable amount is made. A CGU’s recoverable amount is the higher of its fair value less costs to sell and its value in use. These assessments require the use of estimates and assumptions regarding production volumes, discount rates, long-term commodity prices, reserve and contingent resource quantities, operating costs, royalty rates, future capital cost estimates, foreign exchange rates, income taxes and life of field. E&E assets are also tested for impairment when transferred to PP&E.

A previously recognized impairment loss is reversed only if there has been a change in the estimates or assumptions used to determine the CGU’s recoverable amount since the impairment loss was recognized. If that is the case, the carrying amount of the CGU is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depletion, had no impairment loss been recognized for the CGU in prior periods. Such a reversal is recognized in net income, following which the depletion charge is adjusted in future periods to allocate the CGU’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Goodwill Impairments

Goodwill represents the excess of the consideration transferred over the fair value of the identifiable assets acquired and liabilities assumed in a business combination. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. The impairment test requires that goodwill be allocated to CGUs, which the Company has determined by aggregating locations having similar economic characteristics and/or which are in similar geographic locations, and which correspond with the operating segments, except for locations within the Other segment, which are allocated to the relevant countries. Impairment is determined for goodwill by assessing the recoverable amount (based on value in use) of each segment to which the goodwill relates. Where the recoverable amount of the segment is less than the carrying amount, an impairment loss is recognized. Goodwill impairment losses cannot be reversed.

Goodwill was assessed for impairment as at December 31, 2015 using value in use. Value in use was estimated for each CGU, with allocated goodwill, based on the assumptions used in the asset impairment test.

Impairment of Investments

The Company assesses investments for impairment whenever changes in circumstances or events indicate that the carrying value may not be recoverable. If such impairment indicators exist, the carrying amount of the investment is compared to its recoverable amount. The recoverable amount is the higher of the investment’s fair value less costs to sell and its value in use. The investment is written down to its recoverable amount when its carrying amount exceeds the recoverable amount.

During 2015, the Company recorded an impairment expense of $47 million pre-tax ($47 million after-tax) related to its investment in Equion, due principally to lower commodity prices.

Decommissioning Liabilities

Decommissioning liabilities are measured based on the estimated cost of abandonment discounted to its net present value using a weighted average credit-adjusted nominal rate. At December 31, 2015, the net present value of the Company’s decommissioning liability was $796 million (2014 — $1.9 billion) and is recorded as liabilities on the Company’s balance sheet.

At December 31, 2015, the estimated undiscounted inflation adjusted decommissioning liabilities associated with oil and gas properties and facilities were $2.6 billion. The majority of the payments to settle this provision will occur over a period of 35 years and will be funded from the general resources of the Company as they arise. The provision for the costs of decommissioning production facilities and pipelines at the end of their economic lives has been

estimated using existing technology, at current prices or long-term assumptions and based upon the expected timing of the activity. The provision has been discounted using a weighted average credit-adjusted nominal rate of 4.8%.

While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs. As an indication of possible future changes in estimated decommissioning liabilities, if all of the Company’s decommissioning obligations could be deferred by one year, the net present value of the liabilities would decrease by approximately $37 million.

Income Taxes

Current tax is based on estimated taxable income and tax rates, which are determined pursuant to the tax laws that are enacted or substantively enacted at the balance sheet date.

Deferred tax is determined using the liability method. Under the liability method, deferred tax is calculated based on the differences between assets and liabilities reported for financial accounting purposes and those reported for income tax purposes. Deferred tax assets and liabilities are measured using substantively enacted tax rates. The impact of a change in tax rate is recognized in net income in the period in which the tax rate is substantively enacted. The Company recognizes in its audited Consolidated Financial Statements the best estimate of the impact of a tax position by determining if the available evidence indicates whether it is more likely than not, based solely on technical merits, that the position will be sustained on audit. The Company estimates the amount to be recorded by weighting all possible outcomes by their associated probabilities.

Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction and relate to the same taxable entity. The Company assesses the available positive and negative evidence of both an objective and subjective nature to estimate if sufficient future taxable income will be generated to realize the existing deferred tax assets.

The determination of the income tax provision is an inherently complex process, requiring management to interpret continually changing regulations and to make certain judgments. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the jurisdictions in which the Company operates around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible that such changes could be significant when compared with the Company’s total unrecognized tax benefits. However, the amount of change cannot be quantified.

Foreign Exchange Accounting

The Company’s worldwide operations expose the Company to transactions denominated in a number of different currencies, which are required to be translated into one currency for financial statement reporting purposes. The Company’s foreign currency translation policy, as detailed in note 3(p) to the 2015 audited Consolidated Financial Statements, is designed to reflect the economic exposure of the Company’s operations to the various currencies. The functional currency of all of the Company’s operations (other than its Norwegian operations) is US$, a reflection of the Company’s overall exposure to US$ denominated transactions, assets and liabilities; oil prices are

largely denominated in US$ as is much of the Company’s corporate debt and international capital spending and operating costs.

The foreign operations are translated as follows: monetary assets and liabilities at exchange rates in effect at the balance sheet date, non-monetary assets and liabilities at rates in effect on the dates the assets were acquired or liabilities were assumed, and revenues and expenses at rates of exchange prevailing on the transaction dates. Gains and losses on translation are reflected in income when incurred.

Production Sharing Contract (PSC) Arrangements

A significant portion of the Company’s operations outside of North America are governed by PSCs. Under PSCs, the Company, along with other working interest holders, typically bears all risks and costs for exploration, development and production. In return, if exploration is successful, the Company recovers the sum of its investment and operating costs (cost oil) from a percentage of the production and sale of the associated hydrocarbons. The Company is also entitled to receive a share of the production in excess of cost oil (profit oil). The sharing of profit oil varies between the working interest holders and the government from contract to contract. The cost oil, together with the Company’s share of profit oil, represents the Company’s hydrocarbon entitlement (working interest less royalties). The Company records gross production, sales and reserves based on its working interest ownership with sales disclosed net of royalties. In addition, certain of the Company’s contractual arrangements in foreign jurisdictions stipulate that income tax payments are to be withheld from the Company and paid to the government out of the respective national oil company’s entitlement share of production. The Company includes such amounts in income tax expense at the statutory tax rate in effect at the time of production.

The amount of cost oil required to recover the Company’s investment and costs in a PSC is dependent on commodity prices and, consequently, the Company’s share of profit oil is also impacted. Accordingly, the amount of royalty paid by the Company over the term of a PSC and the corresponding net after royalty reserves booked by the Company are dependent on the amount of initial investment and past costs yet to be recovered and anticipated future costs, commodity prices and production. As a result, when year-end prices increase, the amount of net reserves after royalty the Company books may decrease and vice versa.

SIGNIFICANT ACCOUNTING POLICIES

a) Changes in Accounting Policies

Foreign Currency Translation

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

b) Accounting Policies Adopted on January 1, 2015

Effective January 1, 2015, the Company adopted new and amended accounting standards as described below:

Employee Benefits

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

Operating Segments

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

Fair Value Measurement

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

Related Parties

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

b) Accounting Standards and Interpretations Issued but Not Yet Effective

The following pronouncements from the IASB are applicable to the Company and will become effective for future reporting periods, but have not yet been adopted. The Company intends to adopt these standards, if applicable, when they become effective on, or after, January 1, 2016:

Effective January 1, 2016 and thereafter

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

· IFRS 15 Revenue from Contracts with Customers. IFRS 15 specifies that revenue should be recognized when an entity transfers control of goods or services at the amount the entity expects to be entitled to as well as requiring entities to provide users of financial statements with more informative and relevant disclosures. The standard supersedes IAS 18 Revenue, IAS 11 Construction Contracts, and a number of revenue-related interpretations. IFRS 15 will be effective for annual periods beginning on or after January 1, 2017. In an exposure draft in May 2015, the effective date of IFRS 15 was proposed to be deferred to January 1, 2018. Application of the standard is mandatory and early adoption is permitted. The Company has not yet determined the impact of the standard on the Company’s audited Consolidated Financial Statements.

· IFRS 16 Leases requires lessees to recognize nearly all leases— with an exemption for short-term and low-value asset leases — on the balance sheet, which will reflect their right to use an asset for a period of time and the associated liability to pay rentals, whereas under the existing rules, lessees generally account for lease transactions either off balance sheet or on balance sheet for finance leases. The lessor’s accounting model largely remains unchanged. The Company has not yet determined the impact of the standard on the Company’s financial statements. IFRS 16 will be effective for annual periods beginning on or after January 1, 2019.

RISK FACTORS

The Company is exposed to a number of risks inherent in exploring for, developing and producing crude oil, natural gas liquids and natural gas. This section describes the important risks and other matters that could cause actual results of the Company to differ materially from those reflected in forward-looking statements and that could affect the trading price of the Company’s outstanding securities. The risks described below may not be the only risks the Company faces, as the Company’s business and operations may also be subject to risks that the Company does not yet know of, or that the Company currently believes are immaterial. Events or circumstances described below could materially and adversely affect the Company’s business, financial condition, results of operations or cash flow and

the trading price of the Company’s securities could decline. The risks described below are interconnected, and more than one of these risks could materialize simultaneously or in short sequence if certain events or circumstances described below actually occur. The following risk factors should be read in conjunction with the other information contained herein and in the Consolidated Financial Statements and the related notes.

Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices

The Company’s financial performance is highly sensitive to the prevailing prices of crude oil, natural gas liquids and natural gas. Fluctuations in these prices could have a material effect on the Company’s operations and financial condition, the value of its liquids and natural gas reserves and its level of expenditure for liquids and gas exploration and development. Prices for liquids and natural gas fluctuate in response to changes in the supply of and demand for liquids and natural gas, market uncertainty and a variety of additional factors that are largely beyond the Company’s control. The Company does not currently use derivative instruments to hedge the Company’s expected production so as to manage the impact of fluctuations in crude oil and natural gas prices. Fluctuations in crude oil and gas prices could have a material effect on the volatility of the Company’s earnings. Oil prices are largely determined by international supply and demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, world economic conditions, government regulation, political stability throughout the world, the availability of alternative fuel sources, technological advances affecting energy production and consumption, and weather conditions. Approximately 59% of the natural gas prices realized by the Company are affected primarily by North American supply and demand, weather conditions and prices of alternative sources of energy. The remaining 41% of natural gas prices realized by the Company are in markets outside of North America, primarily in Southeast Asia. These other prices are largely sold under long-term contracts most of which are linked to international oil and/or oil equivalent prices. The development of crude oil and natural gas discoveries in offshore areas and the development of shale gas plays are particularly dependent on the outlook for liquids and natural gas prices because of the large amount of capital expenditure required for development prior to commencing production.

A substantial and extended decline in the prices of crude oil, natural gas liquids and/or natural gas have resulted in delay or cancellation of drilling, development or construction programs, and curtailment in production and/or unutilized long-term transportation commitments, all of which could have a material adverse impact on the Company. Poor economics for developing assets have resulted in a reduction of drilling activity which may lead to loss of leases and skilled employees. The amount of cost oil required to recover the Company’s investment and costs in various PSCs is dependent on commodity prices, with higher commodity prices resulting in the booking of lower oil and gas reserves net of royalties. Moreover, changes in commodity prices may result in the Company making downward adjustments to the Company’s estimated reserves. If this occurs, or if the Company’s estimates of production or economic factors change, accounting rules may require the Company to impair, as a non-cash charge to earnings, the carrying value of the Company’s oil and gas properties. The Company is required to perform impairment tests on oil and gas properties whenever events or changes in circumstances indicate that the carrying value of properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company’s oil and gas properties, the carrying value may not be recoverable and, therefore, an

impairment charge will be required to reduce the carrying value of the properties to their estimated fair value. The Company may incur impairment charges in the future, which could materially affect the Company’s results of operations, and its balance sheet, in the period incurred.

Credit and Liquidity

The Company’s financial performance and cash flow is highly sensitive to the prevailing prices of crude oil, natural gas liquids and natural gas, which fluctuate in response to a variety of factors beyond the Company’s control. A substantial and extended decline in the prices of crude oil, natural gas liquids or natural gas could negatively impact the Company’s liquidity and/or credit ratings and adversely affect the Company’s ability to comply with covenants under denominated long-term notes and credit facilities. See also “Risk Factors — Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices.”

The volatility of credit markets can result in market conditions that may restrict timely access and limit the Company’s ability to secure and maintain cost-effective financing on acceptable terms and conditions. In addition, if any lender under the Company’s syndicated bank credit facility does not fund its commitment, the Company’s liquidity may be reduced by an amount up to the aggregate amount of such lender’s commitment. See also “Risk Factors — Counterparty Credit Risk.”

The credit rating agencies regularly evaluate the Company, and their ratings of the Company’s securities are based on a number of factors not entirely within the Company’s control, including the credit rating of the Company’s parent, Repsol, conditions affecting the oil and gas industry generally, and the wider state of the economy. There can be no assurance that one or more of the Company’s credit ratings will not be downgraded. A reduction in any of the Company’s current investment-grade credit ratings to below investment grade could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. In addition, the Company relies on access to letters of credit in the normal course of business in order to support some of its operations. For example, with respect to the Company’s North Sea operations, the Company relies on access to letters of credit facilities which entitle a bank to demand cash at any time to cover the full amount of any letter of credit issued with respect to UK decommissioning obligations. There can be no assurance that the Company will be able to obtain the necessary letters of credit or repay the full amount of a letter of credit upon demand. See also “Risk Factors — Capital Allocation and Project Decisions.”

Capital Allocation and Project Decisions

The Company’s long-term financial performance is sensitive to the capital allocation decisions taken and the underlying performance of the projects undertaken. Capital allocation and project decisions are undertaken after assessing reserve and production projections, capital and operating cost estimates and applicable fiscal regimes that govern the respective government take from any project. All of these factors are evaluated against common commodity pricing assumptions and the relative risks of projects. These factors are used to establish a relative ranking of projects and capital allocation, which is then calibrated to ensure the debt and liquidity of the Company

is not compromised. However, material changes to project outcomes and deviation from forecasted assumptions, such as production volumes and rates, realized commodity price, cost or tax and/or royalties, could have a material impact on the Company’s cash flow and financial performance as well as assessed impacts of impairments on the Company’s assets. Adverse economic and/or fiscal conditions could impact the prioritization of projects and capital allocation to these projects, which in turn could lead to adverse effects such as asset under investment, asset performance impairments or land access expiries.

Uncertainties around some of the Company’s projects, including, but not limited to its equity interest in TSEUK and the projects TSEUK undertakes, could result in changes to the Company’s capital allocation or its spend target being exceeded. The Company cannot be certain that funding, if needed, will be available to the extent required or on acceptable terms. To the extent that asset sales are necessary to fund capital requirements, the Company’s ability to sell assets is subject to market interest. If the Company is unable to access funding when needed on acceptable terms, the Company may not be able to fully implement its business plans, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s business, financial condition, cash flows, and results of operations. See also “Risk Factors — Credit and Liquidity” and “Risk Factors — Interest Rates.”

Counterparty Credit Risk

In the normal course of business, the Company enters into contractual relationships with counterparties in the energy industry and other industries, including suppliers and co-venturers and counterparties to commodity sale/purchase agreements. If such counterparties do not fulfil their contractual obligations or settle their liabilities to the Company, the Company may suffer losses, may have to proceed on a sole risk basis, may have to forgo opportunities or may have to relinquish leases or blocks. Fluctuations in prevailing prices of crude oil, natural gas liquids and natural gas could have a material adverse effect on the operations and financial condition of such counterparties. The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions. While the Company maintains a risk management system that limits exposures to any one counterparty, losses due to the failure by counterparties to fulfil their contractual obligations may adversely affect the Company’s financial condition.

Project Delivery

The Company manages a variety of projects, including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may impact expected revenues and project cost overruns could make projects uneconomic. The Company’s ability to complete projects depends upon numerous factors, many of which are beyond the Company’s control. These factors include the level of direct control by the Company, since many of the projects in which the Company is involved are not operated by the Company, and timing and project management control are the responsibility of the operator. See also “Risk Factors — Non-Operatorship and Partner Relations.” The global demand for project resources can impact the access to appropriately competent contractors and construction yards as well as to raw products, such as steel. Typical execution risks include the availability of seismic data, the availability of processing capacity, the availability and proximity of pipeline

capacity, the availability of drilling and other equipment, the ability to access lands, weather, unexpected cost increases, accidents, the availability of skilled labour, including engineering and project planning personnel, the need for government approvals and permits, and regulatory matters. Subsurface challenges can also result in additional risk of cost overruns and scheduling delays if conditions are not typical of historical experiences. The Company utilizes materials and services which are subject to general industry-wide conditions. Cost escalation for materials and services may be unrelated to commodity price changes and may continue to have a significant impact on project planning and economics. The Company operates in challenging, environmentally hostile climates, such as Papua New Guinea, where logistical costs can be materially impacted by seasonal and occasionally unanticipated weather patterns. Contracts where work has been placed under a lump sum arrangement are subject to additional challenges related to scheduling, reputation and relationship management with the Company’s coventurers.

Ability to Find, Develop or Acquire Additional Reserves

The Company’s future success depends largely on its ability to find and develop, or acquire, additional oil and gas reserves that are economically recoverable. Hydrocarbons are a limited resource, and the Company is subject to increasing competition from other companies, including national oil companies. Exploration and development drilling may not result in commercially productive reserves and, if production begins, reservoir performance may be less than projected. Successful acquisitions require an assessment of a number of factors, many of which are uncertain. These factors include recoverable reserves, development potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. If a high impact prospect identified by the Company fails to materialize in a given year, the Company’s multi-year exploration and/or development portfolio may be compromised. See also “Risk Factors — Volatility of Crude Oil, Natural Gas Liquids and Natural Gas Prices”. The recent decline in commodity prices, if sustained, may result in promising exploration and development projects being deemed uneconomic. Continued failure to achieve anticipated reserve and resource addition targets may result in the Company’s withdrawal from an area, which in turn may result in a write-down of any associated reserves and/or resources for that area.

Uncertainty of Reserves Estimates

The process of estimating oil and gas reserves is complex and involves a significant number of assumptions in evaluating available geological, geophysical, engineering and economic data. In addition, the process requires future projections of reservoir performance and economic conditions; therefore, reserves estimates are inherently uncertain. Since all reserves estimates are, to some degree, uncertain, reserves classification attempts to qualify the degree of uncertainty involved.

Since the evaluation of reserves involves the evaluator’s interpretation of available data and projections of price and other economic factors, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on estimated uncertainty, and the estimates of future net revenue or future net cash flows prepared by different evaluators or by the same evaluators at different times may vary substantially.

Each year, the Company prepares evaluations of all of its reserves internally. Initial estimates of reserves are often based upon volumetric calculations and analogy to similar types of reservoirs, rather than actual well data and performance history. Estimates based on these methods generally are less certain than those based on actual performance. The Company may adjust its estimates and classification of reserves and future net revenues or cash flows based on results of exploration and development drilling and testing, additional performance history, prevailing oil and gas prices, and other factors, many of which are beyond the Company’s control. As new information becomes available, subsequent evaluations of the same reserves may continue to have variations in the estimated reserves, some of which may be material. In addition, the Company’s actual production, taxes, and development and operating expenditures with respect to its reserves will likely vary from such estimates and such variances could be material.

Operational Risks

Major Incident, Major Spill / Loss of Well Control

Oil and gas drilling and producing operations are subject to many risks, including the risk of fire, explosions, mechanical failure, pipe or well cement failure, well casing collapse, pressure or irregularities in formations, chemical and other spills, unauthorized access to hydrocarbons, illegal tapping of pipelines, accidental flows of oil, natural gas or well fluids, sour gas releases, contamination, vessel collision, structural failure, loss of buoyancy, storms or other adverse weather conditions and other occurrences. If any of these should occur, the Company could incur legal defence costs and remedial costs and could suffer substantial losses due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, unplanned production outage, cleanup responsibilities, regulatory investigation and penalties, increased public interest in the Company’s operational performance and suspension of operations. The Company’s horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

The Company maintains insurance that contemplates both first and third party exposures for the Company’s onshore and offshore operations globally. There is no assurance that this insurance will be adequate to cover all losses or exposures to liability. The Company believes that its coverage is aligned with customary industry practices and in amounts and at costs that the Company believes to be prudent and commercially practicable. While the Company believes these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, the Company’s insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on the Company’s financial position, results of operations and cash flows. The insurance coverage that the Company maintains may not be sufficient to cover every claim made against the Company in the future. In addition, a major incident could impact the Company in such a way that it could lead to a prolonged shutdown of an asset which may have a material adverse effect on the Company’s business and affect the Company’s reputation as a competent operator.

The Company operates and drills wells in both mature producing areas such as the UK and North America and in several remote areas in multiple countries. In 2015, the Company also carried out drilling and seismic operations in the emerging areas of Papua New Guinea and Colombia. The Company may seek new leases and/or drill in similar environments in the future.

Health Hazards and Personal Safety Incidents

The employee and contractor personnel involved in exploration and production activities and operations of the Company are subject to many inherent health and safety risks and hazards, which could result in occupational illness or health issues, personal injury, and loss of life, facility quarantine and/or facility and personnel evacuation. For example, employees and contractors are subject to the possibility of loss of containment. This could lead to exposure to the release of high pressure materials as well as collateral shrapnel from piping or vessels which could result in personal injury and loss of life.

Security Incidents

The Company’s operations may be adversely affected by security-related incidents which are not within the control of the Company, such as war (external and internal conflicts) and remnants of war, sectarian violence, civil unrest, criminal acts, terrorism and abductions in locations where the Company operates. Security-related incidents may include allegations of human rights abuse associated with the provision of security to the Company operations. In particular, the Company faces increased security risks in the Kurdistan Region of Iraq, Colombia, Papua New Guinea and Algeria within the Company’s current portfolio. A significant security incident could result in the deferral of or termination of Company activity within the impacted areas of operations, thus adversely impacting execution of the Company’s business strategy (e.g., delaying exploration and development, causing a halt to production or forcing exit strategy processes), which could adversely affect the Company’s financial condition.

Regulatory Approvals/Compliance and Changes to Laws and Regulations

The Company’s exploration and production operations are subject to extensive regulation at many levels of government, including municipal, state, provincial and federal governments, in the countries where the Company operates, and operations are subject to interruption or termination by governmental and regulatory authorities based on environmental or other considerations. Moreover, the Company has incurred and will continue to incur costs in the Company’s efforts to comply with the requirements of environmental, safety and other regulations, such as the recently introduced Canadian Extractive Sector Transparency Measure Act and the recently re-proposed rules to implement Section 1504 of the U.S. Dodd-Frank Act, when enacted. Further, the regulatory environment in the oil and gas industry could change in ways that the Company cannot predict and that might substantially increase the Company’s costs of compliance and, in turn, materially and adversely affect the Company’s business, results of operations and financial condition.

Failure to comply with the applicable laws or regulations may result in significant increases in costs, fines or penalties and even shutdowns or losses of operating licences or criminal sanctions. If regulatory approvals or permits required for operations are delayed or not obtained, the Company could experience delays or abandonment of projects, decreases in production and increases in costs. This could result in an inability of the Company to fully

execute its strategy and adverse impacts on its financial condition. See also “Risk Factors — Fiscal Stability” and “Risk Factors — Socio-Political Risks.”

Changes to existing laws and regulations or new laws could have an adverse effect on the Company’s business by increasing costs, impacting development schedules, reducing revenue and cash flow from natural gas and oil sales, reducing liquidity or otherwise altering the way the Company conducts business. There have been various proposals to enact new, or amend existing, laws and regulations relating to greenhouse gas emissions, hydraulic fracturing (including associated additives, water use, induced seismicity, and disposal) and shale gas development generally. For example, in Colombia, the high level of oil and gas activity in the country has resulted in significant delays in the granting of the required environmental licences. These delays may result in reduced near-term production. See also “Risk Factors — Environmental Risks.”

The Company continues to monitor and assess any new policies, legislation, regulations and treaties in the areas where the Company operates to determine the impact on the Company’s operations. Governmental organizations unilaterally control the timing, scope and effect of any currently proposed or future laws, regulations or treaties, and such enactments are subject to a myriad of factors, including political, monetary and social pressures. The Company acknowledges that the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect the Company’s business, results of operations and financial condition.

Fiscal Stability

Governments may amend or create new legislation that could impact the Company’s operations and that could result in increased capital, operating and compliance costs. Moreover, the Company’s operations are subject to various levels of taxation in the countries where the Company operates. Federal, provincial, and state income tax rates or incentive programs relating to the oil and gas industry in the jurisdictions where the Company operates may in the future be changed or interpreted in a manner that could materially affect the economic value of the respective assets. For example, the US Congress has been considering a revision of the immediate deduction currently available for drilling costs. The Government of Alberta has recently announced the results of a royalty review. While many details of the implementation of this new regime have yet to be determined, royalties on existing wells remain unchanged for 10 years, and the new royalties will apply only to wells drilled in 2017 and onwards. Furthermore, the Government has pledged that the new system will be, in aggregate, “rate of return neutral” relative to the existing system, although individual assets may see higher or lower royalties. The impact of the new royalty regime to the Company has not yet been fully evaluated.

Stakeholder Opposition

The Company’s planned activities may be adversely affected if there is strong community opposition to its operations. For example, local community concerns in parts of Colombia, the Kurdistan Region of Iraq and Papua New Guinea could potentially result in development and production delays in those operations. There is also heightened public concern regarding hydraulic fracturing in parts of North America, which could materially affect the Company’s shale operations. In some circumstances, this risk of community opposition may be higher in areas

where the Company operates alongside indigenous communities who may have additional concerns regarding land ownership, usage or claim compensation.

Socio-Political Risks

The Company’s operations may be adversely affected by political or economic developments or social instability in the jurisdictions in which it operates, which are not within the control of the Company, including, among other things, a change in crude oil, natural gas liquids or natural gas pricing policy and/or related regulatory delays, the risks of war, terrorism, abduction, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, difficulties in enforcing contractual terms, a change in taxation policies, economic sanctions, the imposition of specific drilling obligations, the imposition of rules relating to development and abandonment of fields, access to or development of infrastructure, jurisdictional boundary disputes, and currency controls. As a result of the continuing evolution of an international framework for corporate responsibility and accountability for international crimes, the Company could also be exposed to potential claims for alleged breaches of international law, health, safety and environmental regulations, and other human rights-based litigation risk. Numerous countries in which the Company has interests, including, but not limited to, the Kurdistan Region of Iraq, Colombia, Vietnam, Algeria and Indonesia, have been subject to recent economic or political instability, disputes and social unrest, and military or rebel hostilities. The potential deterioration of socio-political security situations (i.e. political instability and/or disputes) poses increased risk, which may result in the cessation of operations as well as the delay in payment or exports such as, in the Kurdistan Region of Iraq with respect to the regularity and predictability of export payment arrangements during a state of conflict, and in Vietnam and Malaysia with respect to China’s claim over disputed waters in the East Sea. In addition, the Company regularly evaluates opportunities worldwide, and may in the future engage in projects or acquire properties in other nations that are experiencing economic or political instability, social unrest, military hostilities or United Nations, US or other international sanctions. Some of the foregoing government actions may lead to political or reputational pressures on the Company from non-governmental organizations, home governments and security holders.

Non-Operatorship and Partner Relations

Some of the Company’s projects are conducted in joint venture environments where the Company has a limited ability to influence or control operations or future development, safety and environmental standards, and amount of capital expenditures. Companies which operate these properties may not necessarily share the Company’s health, safety and environmental standards or strategic or operational goals or approach to partner relationships, which may result in accidents, regulatory noncompliance, project delays or unexpected future costs, all of which may affect the viability of these projects and the Company’s standing in the external market.

The Company is also dependent on other working interest co-participants of these projects to fund their contractual share of the capital expenditures. If these co-participants are unable to fund their contractual share of, or do not approve, the capital expenditures, the co-participants may seek to defer programs, resulting in strategic misalignments and a delay of a portion of development of the Company’s programs, or the co-participants may default, such that projects may be delayed and/or the Company may be partially or totally liable for their share.

Some of the Company’s projects involve transition of operatorship as part of a joint venture, which requires a significant amount of effort and coordination.

Litigation

From time to time, the Company is the subject of litigation arising out of the Company’s operations. Specific disclosure of current legal proceedings, and the risks associated with current proceedings and litigation generally, are disclosed in this MD&A under the heading “Legal Proceedings and Contingencies”.

Exchange Rate Fluctuations

Results of operations are affected primarily by the exchange rates between the US$, the C$ and UK£. These exchange rates may vary substantially. Most of the Company’s revenue is received in or is referenced to US$ denominated prices (including the Company’s Consolidated Financial Statements, which are presented in US$), while the majority of the Company’s expenditures are denominated in US$, C$ and UK£. A change in the relative value of the US$ against the C$ or the UK£ would also result in an increase or decrease in the Company’s UK£ denominated debt, as expressed in US$, and the related interest expense. The Company is also exposed to fluctuations in other foreign currencies.

Environmental Risks

General

All phases of the Company’s oil and natural gas business are subject to environmental regulation pursuant to a variety of laws and regulations in the countries where the Company does business. These laws and regulations may require the acquisition of a permit before operations commence, restrict the types, quantities and concentration of substances that can be released into the environment in connection with the Company’s drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from the Company’s operations. The Company’s business is subject to the trend toward increased rigour in regulatory compliance and civil or criminal liability for environmental matters in certain regions (e.g., Canada, the United States and the European Union). Compliance with environmental legislation can require significant expenditures, and failure to comply with environmental legislation may result in the assessment of administrative, civil and criminal penalties, the cancellation or suspension of regulatory permits, the imposition of investigatory or remedial obligations or the issuance of injunctions restricting or prohibiting certain activities. Under existing environmental laws and regulations, the Company could be held strictly liable for the remediation of previously released materials or property contamination resulting from its operations, regardless of whether those operations were in compliance with all applicable laws at the time they were performed. Regulatory delays, legal proceedings and reputational impacts from an environmental incident could result in a material adverse effect on the Company’s business. Increased stakeholder concerns and regulatory actions regarding shale gas development could lead to third party or governmental claims, and could adversely affect the Company’s business and financial condition. Although the Company currently believes that the costs of complying with environmental legislation and dealing with environmental civil liabilities will not have a material adverse effect on the Company’s financial condition or results of operations, there can be no assurance that such costs will not have such an effect in the future.

Hydraulic Fracturing

The Company utilizes horizontal drilling, multi-stage hydraulic fracturing, specially formulated drilling fluids and other technologies in its drilling and completion activities. Hydraulic fracturing is a method of increasing well production by injecting fluid under high pressure down a well, which causes the surrounding rock to crack or fracture. The fluid typically consists of water, sand, chemicals and other additives and flows into the cracks where the sand remains to keep the cracks open and enable natural gas or liquids to be recovered. Fracturing fluids flow back to the surface through the wellbore and are stored for reuse or future disposal in accordance with regional regulations, which may include injection into underground wells. The design of the well bores protects groundwater aquifers from the fracturing process.

Hydraulic fracturing has been in use for some time in the oil and gas industry, however, the proliferation of fracturing in recent years to access hydrocarbons in unconventional reservoirs, such as shale formations, has given rise to public concerns about the environmental impacts of this technology. Public concern over the environmental impacts of the hydraulic fracturing process has focused on a number of issues, including water aquifer contamination; other qualitative and quantitative effects on water resources as large quantities of water are used and

injected fluids either remain underground or flow back to the surface to be collected, treated and disposed; and the potential for fracturing activities to induce seismic events. Regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns. Federal, provincial, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect the Company’s production. Public perception of environmental risks associated with hydraulic fracturing can further increase pressure to adopt new laws, regulation or permitting requirements, or lead to regulatory delays, legal proceedings and/or reputational impacts. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delay, increased operating costs, and third party or governmental claims. They could also increase the Company’s costs of compliance and doing business as well as delay the development of hydrocarbon (natural gas and oil) resources from shale formations, which may not be commercial without the use of hydraulic fracturing.

Due to the adoption of legal restrictions in New York, or if legal restrictions are adopted in other areas where the Company is currently conducting or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. In addition, if hydraulic fracturing becomes more regulated, the Company’s fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves. It is anticipated that federal, provincial and state regulatory frameworks to address concerns related to hydraulic fracturing will continue to emerge. While we are unable to predict the impact of any potential regulations upon our business, the implementation of new regulations with respect to water usage or hydraulic fracturing generally could increase the Company’s costs of compliance, operating costs, the risk of litigation and environmental liability, or negatively impact the Company’s prospects, any of which may have a material adverse effect on our business, financial condition and results of operations.

Seismicity

Seismicity events have been recorded as occurring at the same time that the Company has been conducting hydraulic fracturing and related operations. Although the size of these events is considered light, they raise stakeholder and regulatory concerns. Due to recent seismic activity reported in the Fox Creek area of Alberta, the Alberta Energy Regulator (“AER”) has announced new seismic monitoring and reporting requirements for hydraulic fracturing operators in the Duvernay zone in the Fox Creek area. These requirements include, among others, an assessment of the potential for seismicity prior to operations, real time monitoring of seismic activity, the implementation of a response plan to address potential events, and the suspension of operations when a seismic event above a particular threshold occurs. The AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province, or introduce more stringent measures, if deemed appropriate. This could impact the Company’s future development plans as operations may be under more regulatory scrutiny. The foregoing or any future AER requirements could lead to additional costs, delays or curtailment of exploration, development, or production activities, and perhaps preclude the use of hydraulic fracturing programs in the area. In addition, if monitoring seismicity becomes more regulated, the Company’s fracturing activities could

become subject to additional permitting requirements and result in delays as well as potential increases in costs. Restrictions on hydraulic fracturing due to a perceived correlation to seismicity could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves in the affected areas.

Greenhouse Gas Emissions

The Company is subject to various greenhouse gas (“GHG”) emissions-related legislation. Current GHG emissions legislation does not result in material compliance costs, but compliance costs may increase in the future and may impact the Company’s operations and financial results. The Company operates in jurisdictions with existing GHG legislation (e.g., UK, United States and Canada, notably Alberta and British Columbia) as well as in regions which currently do not have GHG emissions legislation and jurisdictions where GHG emissions legislation is emerging or is subject to change. The Company monitors GHG legislative developments in all areas in which the Company operates. Potential new or additional GHG legislation and associated compliance costs, in particular in association with the adoption of the Paris Agreement under the United Nations Framework Convention on Climate Change, may have a material impact on the Company.

Environmental and Decommissioning Liabilities

The Company is involved in the operation and maintenance of facilities and infrastructure in difficult and challenging areas, including offshore, deepwater, jungle and desert environments. Despite the Company’s implementation of health, safety and environmental standards, there is a risk that accidents or regulatory non-compliance can occur, the outcomes of which, including remedial work or regulatory intervention, cannot be foreseen or planned for. The Company expects to incur site restoration costs over a prolonged period as existing fields are depleted. The Company provides for decommissioning liabilities in its annual Consolidated Financial Statements in accordance with IFRS. Additional information regarding decommissioning liabilities is set forth in the notes to the annual Consolidated Financial Statements. The process of estimating decommissioning liabilities is complex and involves significant uncertainties concerning the timing of the decommissioning activity; legislative changes; technological advancement; regulatory, environmental and political changes; and the appropriate discount rate used in estimating the liability. Any change to these assumptions could result in a change to the decommissioning liabilities to which the Company is subject. In the Company’s North Sea operations, changes in these assumptions would potentially have a significant impact on the Company’s decommissioning liabilities because of the assessed size of these future costs. Any changes to decommissioning estimates influence the value of letters of credit to be provided pursuant to the decommissioning security agreements. There can be no assurances that the cost estimates and decommissioning liabilities are materially correct and that the liabilities will occur when predicted. In addition, with respect to some operations, the Company is not the operator and may not determine the cost estimates or timing of decommissioning such that cost overruns are possible, the Company is often jointly and severally liable for the decommissioning costs associated with the Company’s various operations and could, therefore, be required to pay more than its net share.

Attraction, Retention and Development of Personnel

Successful execution of the Company’s plans is dependent on the Company’s ability to attract and retain talented personnel who have the skills necessary to deliver on the Company’s strategy and maintain safe operations. This includes not only key talent at a senior level, but also individuals with the professional and technical skill sets

critical for the Company’s business, particularly geologists, geophysicists, engineers, accountants and other specialists.

Information Systems

Many of the Company’s business processes depend on the availability, capacity, reliability and security of the Company’s information technology (“IT”) infrastructure and the Company’s ability to expand and continually update this infrastructure in response to the Company’s changing needs. The Company’s IT systems are increasingly integrated in terms of geography, number of systems, and key resources supporting the delivery of IT systems. Further, as a result of the completion of the Repsol Transaction, the Company’s IT systems require integration with, or possibly replacement by, Repsol IT systems. The performance of the Company’s key suppliers is critical to ensure appropriate delivery of key services. Any failure to manage, expand and update the Company’s IT infrastructure, any failure in the extension or operation of this infrastructure, or any failure by the Company’s key resources or service providers in the performance of their services could materially and adversely harm the Company’s business.

The ability of the IT function to support the Company’s business in the event of a disaster such as fire, flood or loss/denial of any of the Company’s data centres or major office locations and the Company’s ability to recover key systems from unexpected interruptions cannot be fully tested. There is a risk that, if such an event actually occurs, the business continuity plan may not be adequate to immediately address all repercussions of the disaster. In the event of a disaster affecting a data centre or key office location, key systems may be unavailable for a number of days, leading to inability to perform some business processes in a timely manner.

In addition, the increasing risk of information security breaches, including more sophisticated attempts often referred to as advanced persistent threats, requires the Company to continually improve its ability to detect and prevent such occurrences. Disruption of critical IT services, or breaches of information security, could have a negative effect on the Company’s operational performance and earnings, as well as on the Company’s reputation.

Egress and Gas & Liquids Buyers

As increasing volumes of natural gas and liquids are brought on-stream by the Company and others, transportation and processing infrastructure capacity may, at times, be exceeded before capacity additions become available. In such an event, there is a risk that the transportation and/or processing of some of the Company’s production may be restricted or delayed until pipeline connection or infrastructure additions are complete. In Canada and in the Eagle Ford area in the US, the Company has secured sufficient access to infrastructure for both liquids and gas for the near and medium term, and it is expected that any restrictions on production due to lack of infrastructure capacity would be relatively short-term (more operational in nature) and would not impact a material quantity of production. Ensuring that the Company holds sufficient transportation capacity to take gas supplies from the Marcellus area, which has seen a significant growth in industry production over the past few years, to market is critical to ensuring the ability to flow production on an unrestricted basis as well as to maximize the value for the Company’s production. Another associated risk will be the availability and diversity of contract and credit-enabled buyers. Should the Company be unable to secure access to infrastructure and qualified buyers for its production, the

Company could face reduced production and/or materially lower prices on some portion of production, which in turn could adversely affect the Company’s operating results.

Interest Rates

The Company is exposed to interest rate risk principally by virtue of its borrowings. Borrowing at floating rates exposes the Company to short-term movements in interest rates. Borrowing at fixed rates exposes the Company to reset risk associated with debt maturity. Most of the Company’s debt is issued at fixed interest rates; therefore, the Company’s main exposure to changes in interest rates would occur in respect of short-term investments or borrowings in the event that substantial cash balances are invested in or owed to the Company.

Competitive Risk

The global oil and gas industry is highly competitive. The Company faces significant competition and many of the Company’s competitors have resources in excess of the Company’s available resources. The Company actively competes for the acquisition and divestment of properties, the exploration for and development of new sources of supply, the contractual services for oil and gas drilling and production equipment and services, the transportation and marketing of current production, and industry personnel, including, but not limited to, geologists, geophysicists, engineers and other specialists that enable the business. Many of the Company’s competitors have the ability to pay more for seismic and lease rights in crude oil and natural gas properties and exploratory prospects. They can define, evaluate, bid for and purchase a greater number of properties and prospects than the Company’s financial or human resources permit. If the Company is not successful in the competition for oil and gas reserves or in the marketing of production, the Company’s financial condition and results of operations may be adversely affected. Many of the Company’s competitors have resources substantially greater than the Company’s and, as a consequence, the Company may be at a competitive disadvantage.

Corruption & Fraud

The Company’s operations are governed by the laws of many jurisdictions, which generally prohibit bribery and other forms of corruption. The Company requires all employees to participate in ethics awareness training, which includes the Company’s policies against giving or accepting money or gifts in certain circumstances. Despite the training and policies, it is possible that the Company, or some of its employees or contractors, could be charged with bribery or corruption. If the Company is found guilty of such a violation, which could include a failure to take effective steps to prevent or address corruption by its employees or contractors, the Company could be subject to onerous penalties. Depending on its nature and scope, a mere investigation itself could lead to significant corporate disruption, high legal costs and forced settlements (such as the imposition of an internal monitor). In addition, bribery allegations or bribery or corruption convictions could impair the Company’s ability to work with governments or non-governmental organizations. Such convictions or allegations could result in the formal exclusion of the Company from a country or area, national or international lawsuits, government sanctions or fines, project suspension or delays, reduced market capitalization, reputational impacts and increased investor concern.

ADVISORIES

Forward-Looking Statements

This MD&A contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation. Forward-looking information is included throughout this MD&A, including under the heading “Risk Factors”. 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;

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

· Anticipated timing and results of legal proceedings;

· Expected spending and allocation of spending; and

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

The Company’s priorities and goals disclosed in this MD&A are objectives only and their achievement cannot be guaranteed.

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

The factors or assumptions on which the forward-looking information is based include: 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.

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;

· Fluctuations in crude oil or natural gas prices could have a material adverse effect on the Company’s operations and financial condition, the value of its oil and natural gas reserves and its level of expenditure for oil and gas exploration and development.

· 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.

Reserves Data and Other Oil and Gas Information

An exemption granted to the Company permits it to disclose internally evaluated reserves data. Any reserves data contained in this MD&A reflects the Company’s internally-generated estimates of its reserves.

Gross Production

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.

Netbacks

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

Financial Outlook

Included in this MD&A is the Company’s financial outlook. Its purpose is to enrich management’s discussion and analysis. This information may not be appropriate for other purposes.

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
COSO		Committee of the Sponsoring Organizations of the Treadway Commission
CGU		Cash generating unit
COSO		Committee of the Sponsoring Organizations of the Treadway Commission
C$		Canadian dollar
DD&A		Depreciation, depletion and amortization
DSA		Decommissioning Security Agreements
DSU		Deferred share unit
E&E		Exploration and evaluation
EU		European Union
FPSO		Floating production storage and offloading
G&A		General and administrative
GAAP		Generally Accepted Accounting Principles
GHG		Greenhouse gas emissions
gj		gigajoule
HH LD		Henry Hub Last Day
IFRIC		International Financial Reporting Interpretations Committee
IFRS		International Financial Reporting Standards
IQRE		Internal Qualified Reserves Evaluator
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
NI		National Instrument
NOK		Norwegian krone
NYMEX		New York Mercantile Exchange
PGN		PT Perusahaan Gas Negara (Persero), Tbk
PP&E		Property, plant and equipment
PRT		Petroleum Revenue Tax
PSC		Production Sharing Contract
PSU		Performance share unit
RSU		Restricted share unit
SEC		US Securities and Exchange Commission
tcf		trillion cubic feet
UK		United Kingdom
UK£		Pound sterling
US		United States of America
US$ or $		United States dollar
WCS		Western Canadian Select
WTI		West Texas Intermediate

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.

Conversion and equivalency factors

Imperial				Metric
1 ton		=		0.907 tonnes

1 acre	=	0.40 hectares
1 barrel	=	0.159 cubic metres
1 cubic foot	=	0.0282 cubic metres