EX-99.4 5 a17-12750_1ex99d4.htm EX-99.4

Exhibit 99.4

RESTATED MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE YEAR ENDED DECEMBER 31, 2016

REPSOL OIL & GAS CANADA INC.

Restated Management’s Discussion and Analysis (MD&A)

(May 12, 2017)

RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

Repsol Oil & Gas Canada Inc. (“ROGCI” or “the Company”) has restated its Consolidated Balance Sheet as at December 31, 2016, and its Consolidated Statement of Loss, Consolidated Statement of Comprehensive Loss, Consolidated Statement of Changes in Shareholder’s Equity and Consolidated Statement of Cash Flow for the year ended December 31, 2016.

On December 31, 2016, Repsol E&P USA Holdings Inc., a wholly owned subsidiary of ROGCI, sold 20% of its interest in Repsol Oil & Gas USA LLC. (“ROGUSA”) to Repsol USA Holdings Corporation (“RUSA”), a subsidiary of the Company’s ultimate parent Repsol S.A. (note 7 to the Restated Consolidated Financial Statements). During the first quarter of 2017, management determined that the accounting for this transaction should be adjusted. The adjustments impact shareholder’s equity, net loss, non-controlling interest, and deferred tax assets, as described below:

· The tax effect of the disposal was charged to the income tax expense in the Consolidated Statement of Loss and should have been recorded through equity;

· The deferred tax asset was not adjusted according to the new ownership interest in ROGUSA (80%) which is a flow through entity for tax purposes; and

· The non-controlling interest was recorded at the fair value of the consideration received and not the non-controlling interest holder’s share of the carrying value of the net assets disposed of, and the difference between fair value and carrying value should have been recorded to equity.

The net impact to the Company’s financial position is an increase in the deferred tax assets and a reclassification within the shareholder’s equity and non-controlling interest. The adjustments do not impact the Company’s reported cash flows.

Therefore, the restatement impacts the following accounts: deferred tax assets; non-controlling interest; retained earnings; and deferred tax recovery. The adjustments affected the Consolidated Balance Sheet and the Consolidated Statement of Loss, as presented in the following reconciliations:

Reconciliation of Consolidated Balance Sheet as at December 31, 2016

December 31, 2016 (millions of $)	December 31, 2016 Previously Reported	Adjustments		December 31, 2016 Restated

Assets
Current	1,159	—		1,159
Non-current excluding deferred tax assets	9,284	—		9,284
Deferred tax assets	1,195	120		1,315
Total assets	11,638	120		11,758

Liabilities
Current	1,380	—		1,380
Non-current	5,039	—		5,039

Shareholder’s equity
Common shares	3,501	—		3,501
Contributed surplus	86	—		86
Retained earnings	490	388		878
Accumulated other comprehensive income	700	—		700
Total shareholder’s equity	4,777	388		5,165
Non-controlling interest	442	(268	)	174
	5,219	120		5,339
Total liabilities and shareholder’s equity	11,638	120		11,758

Reconciliation of Consolidated Statement of Loss for the Year ended

Year ended December 31, 2016 (millions of $)	December 31, 2016 Previously Reported		Adjustments		December 31, 2016 Restated

Total revenue and other income	1,777		—		1,777
Total expenses	2,414		—		2,414
Loss before taxes	(637	)	—		(637	)
Income taxes
Current income tax	207		—		207
Deferred income tax recovery	(104	)	(228	)	(332	)
	103		(228	)	(125	)
Net loss	(740	)	228		(512	)

Net loss attributable to:
Shareholder	(740	)	228		(512	)
Non-controlling interest	—		—		—
	(740	)	228		(512	)
Per common share (US$):
Net loss and diluted net loss	(0.40	)	0.12		(0.28	)

GENERAL

This Restated Management’s Discussion and Analysis (“Restated MD&A”) should be read in conjunction with the Restated Consolidated Financial Statements of ROGCI, for the year ended December 31, 2016. The Company’s Restated Consolidated Financial Statements and the financial data included in this Restated 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 Restated 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, 2016 and 2015, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this Restated 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 Restated 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 Restated 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 Restated 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 Restated Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities, with the exception of the Company’s investments in Repsol Sinopec Resources United Kingdom Limited (“RSRUK”, formerly Talisman Sinopec Energy UK Limited) and Equion Energía Limited (“Equion”) which are accounted for using the equity method.

Note 31 to the 2016 audited Restated Consolidated Financial Statements provides segmented financial information that forms the basis for much of the following discussion and analysis. In 2016, 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 this Restated MD&A.

References in this Restated 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 RSRUK and Equion.

FINANCIAL AND OPERATING HIGHLIGHTS

(millions of $, unless otherwise stated)	2016		2015				2014
	Restated
Cash provided by operating activities from continuing operations	423		2,223				1,780
Net loss	(512	)	(3,106			)	(911			)
Loss from continuing operations	(512	)	(2,812			)	(341			)
Loss from discontinued operations1	—		(294			)	(570			)
Common share dividends	—		117				279
Preferred share dividends	—		2				8
Per share ($)
Net loss 2	(0.28	)	(2.97			)	(0.89			)
Diluted net loss 3	(0.28	)	(3.01			)	(0.96			)
Loss from continuing operations3	(0.28	)	(2.69			)	(0.34			)
Loss from discontinued operations1	—		(0.28			)	(0.55			)
Common share dividends	—		$	0.11			$	0.27
Preferred share dividends	—		C$		0.26		C$		1.05
Total Production (mboe/d)4	338		372				385
Production from continuing operations (mboe/d) 5	338		361				369
Average sales price ($/boe) 6	22.17		25.57				47.66
Total revenue and other income6	1,777		1,485				3,244
Operating costs ($/boe) 6	6.25		7.75				9.07
Depreciation, depletion and amortization (DD&A) expense, exploration and dry hole expense 6	1,435		1,724				1,970
Total exploration and development expenditures from Consolidated Subsidiaries and Joint Ventures6	724		1,399				2,624
Total assets	11,758		12,021				17,330
Loans from related parties	1,756		1,007				—
Total long-term debt (including current portion)	1,393		2,267				5,064
Cash and cash equivalents, net of bank indebtedness	47		91				253
Total long-term liabilities	5,039		4,775				6,748

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

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

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

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

(5) Production from continuing operations consists of total production less production from discontinued operations.

(6) From continuing operations.

2016 RESTATED NET LOSS VARIANCE

(millions of $)
2015 net loss from continuing operations	(2,812	)
Favourable (unfavourable) variances1:
Commodity prices2	(353	)
Production volumes2	(240	)
Royalties2	170
Other income	(167	)
Loss from joint ventures and associates, after tax	882
Operating & transportation expenses	222
General and administrative (“G&A”) expense	54
DD&A expense	320
Impairment	1,850
Dry hole expense	(101	)
Exploration expense	70
Finance costs	137
Share-based payments expense/recovery	(24	)
Gain on held-for-trading financial instruments	(61	)
Gain/Loss on disposals	75
Other	187
Current income tax recovery (including Petroleum Revenue Tax (PRT))	(384	)
Deferred income taxes (including PRT)	(337	)
Total variances	2,300
2016 net loss from continuing operations	(512	)

(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 2015, as summarized in the net loss variances table, are:

· Lower global commodity prices.

· Lower production from Southeast Asia and North America.

· Lower royalties due principally to lower global commodity prices and lower production.

· Other income decreased mainly due to lower net gain on repayment of long-term debt and lower pipeline income.

· Lower loss from joint ventures and associates, after tax from reduced operating expenses, impairment reversals, lower DD&A and gain from the revaluation of the Oleoducto de Colombia, S.A. (“ODC”) investment.

· Decrease in operating expenses due principally to a focused effort to reduce operating expenses in a low commodity price environment.

· 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 sale of 26% of the 50% working interest in Eagle Ford in 2015 and lower production and depletion rates in Southeast Asia.

· Decreased impairment expenses and increased impairment reversals due principally to reductions in cost assumptions as part of the focused effort to reduce costs across the Company’s operations.

· Increase in dry hole expense in Southeast Asia and North America.

· Decrease in exploration expense due principally to change of control provisions in certain third party contracts incurred in 2015 as a result of the acquisition of the Company by Repsol.

· No share-based payments since the settlement of plans in 2015 as result of 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 and have not entered into any significant derivative contracts since.

· Increase in gain on disposal due principally to the disposition of Talisman Wiriagar Overseas Limited (“TWOL”) in the fourth quarter of 2016.

· Decrease in other expense principally due to decreases in onerous contracts and other provisions, restructuring costs and increase in foreign exchange gains.

· Decrease in current income tax recovery from 2015 to a current income tax expense and a decrease in deferred income tax recovery.

· The decrease of deferred tax recovery due principally to the recognition of a large US deferred tax asset in 2015, compared to a much smaller recognition of a US deferred tax asset in 2016 combined with the derecognition of Southeast Asia deferred tax assets in 2016, partially offset by the sale of the Norwegian operations in 2015.

OPERATIONS REVIEW

Results Summary

Sales of oil, liquids and natural gas after royalties from continuing operations in 2016 were $1.8 billion, down 19% from 2015 due principally to lower commodity prices, and partially due to lower oil and liquids and natural gas production in Southeast Asia.

Oil and liquids sales decreased by $238 million compared to 2015 due principally to lower commodity prices, and partially due to lower oil and liquids production in Southeast Asia. The overall price for oil and liquids was 9% lower in 2016, compared to 2015.

Natural gas sales decreased by $183 million compared to 2015 due principally to lower commodity prices. The overall price for gas was 14% lower in 2016, compared to 2015.

In North America, sales of oil, liquids and natural gas was $815 million, a decrease of 13% from 2015 due to lower commodity prices and lower oil and liquids production. Operating expenses, transportation expense, and DD&A decreased by 13% compared to 2015.

In Southeast Asia, sales of oil, liquids and natural gas were $917 million, 21% lower than 2015. This was primarily due to lower commodity prices and partially as a result of lower oil and liquids and natural gas production. Production was lower due principally to shut-ins, natural declines, decreased demand and the sale of assets in Australia. Operating expenses, transportation expense and DD&A decreased by 31% compared to 2015.

In Rest of World, sales of oil, liquids and natural gas were $99 million, 35% lower than 2015 due to lower commodity prices and lower production. Operating expenses, transportation expense and DD&A decreased by 42% compared to 2015.

Daily Average Production

	Gross before royalties			Net of royalties
	2016	2015	2014	2016	2015	2014
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	38	42	43	32	36	34
Southeast Asia	28	36	43	19	24	28
North Sea	—	9	13	—	9	13
OtherE	13	14	16	6	9	8
	79	101	115	57	78	83
Oil and liquids from Joint Ventures (mbbls/d)
RSRUK	21	20	17	21	20	17
Equion	13	12	9	11	10	7
	34	32	26	32	30	24
Total Oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	113	133	141	89	108	107
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	783	797	794	678	693	690
Southeast Asia	443	483	510	338	347	348
North Sea	—	14	18	—	14	18
	1,226	1,294	1,322	1,016	1,054	1,056
Natural gas from Joint Ventures (mmcf/d)
RSRUK	3	4	1	3	4	1
Equion	31	42	48	31	34	36
	34	46	49	34	38	37
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,260	1,340	1,371	1,050	1,092	1,093
Total Daily Production from Consolidated Subsidiaries (mboe/d)1
North America	177	185	184	153	160	157
Southeast Asia	107	122	134	79	86	90
North Sea	—	11	16	—	11	16
Other	13	14	16	6	9	8
	297	332	350	238	266	271
Total Daily Production From Joint Ventures (mboe/d)1
RSRUK	22	21	17	22	20	17
Equion	19	19	18	17	16	13
	41	40	35	39	36	30
Total Daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)1	338	372	385	277	302	301
Less production from discontinued operations (mboe/d)1
North America	—	—	—	—	—	—
Southeast Asia	—	—	—	—	—	—
North Sea	—	11	16	—	11	16
	—	11	16	—	11	16
Total production from continuing operations (mboe/d)1	338	361	369	277	291	285

(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.

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

Total production from continuing operations was 338 mboe/d in 2016, a decrease of 6% compared to 2015 due principally to decreased production from Southeast Asia and North America.

In North America, total production decreased by 4%. Oil and liquids production decreased by 10% due principally to the Company’s sale of 26% of its 50% interest in the Eagle Ford area of the US in late 2015 (resulting in a reduction to the Company’s interest to 37%). Natural gas production decreased by 2% primarily due to lower natural gas volumes from the Company’s reduced interest in the Eagle Ford and natural declines in Canada, partially offset by new development wells coming onstream in the Greater Edson area of Canada.

In Southeast Asia, total production decreased by 12%. Oil and liquids production decreased by 22% due principally to well shut-ins and natural declines in Vietnam and Malaysia, the Kitan field in Australia/Timor-Leste no longer producing and the sale of Laminaria-Coralina in Australia/Timore-Leste in April 2016. Natural gas production decreased by 8% in 2016 due principally to shut-ins and lower demand in Malaysia, and increased competing LNG cargoes in Indonesia.

In Rest of World, production decreased to 13 mboe/d in 2016 compared to 14 mboe/d in 2015. Production in Colombia decreased from 2015 due to production from the Akacias field being shut-in from March to October of 2016. This was partially offset by an increased production in Algeria due principally to Algeria license extensions and increased production capacity approved by the government in 2016, and reduced shut-ins compared to 2015.

Total production in RSRUK increased by 5% due principally to reinstatement of a well and higher uptime at Bleoholm in 2016.

Total production in Equion was consistent at 19 mboe/d in 2016 compared to 2015.

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

	2016		2015		2014
North America - bbls/d	(675	)	227		82
Southeast Asia - bbls/d	(1,103	)	1,192		328
Other - bbls/d	(78	)	(504	)	791
Total produced into (sold out of) inventory - bbls/d	(1,856	)	915		1,201
Total produced into (sold out of) inventory - mmbbls	(0.7	)	0.3		0.4
Inventory at December 31 - mmbbls	1.0		1.7		1.4

(1) Gross before royalties.

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

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

The Company’s produced oil is frequently stored in tanks until there is sufficient volume to be lifted. The Company recognizes revenue and the related expenses on crude oil production, when liftings have occurred. Volumes presented in the “Daily Average Production” table represent production volumes in the period, which include oil and liquids volumes produced into inventory and exclude volumes sold out of inventory.

During the year ended December 31, 2016, volumes in inventory decreased from 1.7 mmbbls to 1.0 mmbbls due principally to decreased inventories in North America, Australia and Malaysia, partially offset by increased inventories in Indonesia.

Company Netbacks1,2,3

	Gross before royalties			Net of royalties
	2016	2015	2014	2016	2015	2014
Oil and liquids ($/bbl)
Sales price	36.00	39.57	81.31	36.00	39.57	81.31
Royalties	11.03	10.94	26.80	—	—	—
Transportation	1.56	1.89	1.62	2.25	2.62	2.42
Operating costs	9.24	11.93	15.52	13.32	16.49	23.15
	14.17	14.81	37.37	20.43	20.46	55.74
Natural gas ($/mcf)
Sales price	3.06	3.55	5.86	3.06	3.55	5.86
Royalties	0.59	0.79	1.40	—	—	—
Transportation	0.25	0.25	0.24	0.31	0.33	0.32
Operating costs	0.92	1.08	1.11	1.14	1.38	1.46
	1.30	1.43	3.11	1.61	1.84	4.08
Total $/boe (5.615 mcf= 1boe)4
Sales price	22.17	25.57	47.66	22.17	25.57	47.66
Royalties	5.36	6.30	13.62	—	—	—
Transportation	1.45	1.56	1.45	1.91	2.07	2.03
Operating costs	6.25	7.75	9.07	7.80	9.75	11.88
	9.11	9.96	23.52	12.46	13.75	33.75

(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 2016, the Company’s average gross netback was $9.11/boe, 9% lower than 2015 due principally to lower realized prices, partially offset by lower royalties and lower operating costs.

Commodity Prices and Exchange Rates1,2

	2016	2015	2014
Oil and liquids ($/bbl)
North America	26.22	27.93	61.49
Southeast Asia	45.69	50.76	98.31
Other	43.39	46.17	89.39
	36.00	39.57	81.31
Natural gas ($/mcf)
North America	2.04	2.24	4.12
Southeast Asia	4.85	5.72	8.58
	3.06	3.55	5.86
Company $/boe (5.615mcf=1boe)3	22.17	25.57	47.66
Benchmark prices and foreign exchange rates
WTI (US$/bbl)	43.32	48.78	92.97
Dated Brent (US$/bbl)	43.69	52.46	98.99
WCS (US$/bbl)	29.47	35.46	73.36
LLS (US$/bbl)	44.88	52.40	96.74
NYMEX ($/mmbtu)	2.46	2.67	4.37
AECO (C$/gj)	1.98	2.62	4.19
C$/US$ exchange rate	1.33	1.28	1.10
UK£/US$ exchange rate	0.74	0.65	0.61

(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 6% in 2016 due principally to decreases in benchmark prices. In Southeast Asia, realized oil and liquids prices decreased by 10% due to lower Brent pricing and timing of liftings in Malaysia and Indonesia. In Rest of World, realized oil and liquids prices decreased by 6% due principally to decreases in benchmark prices and timing of liftings in Algeria. Due to these reasons, the Company’s overall realized oil and liquids price of $36.00/bbl decreased by 9% compared to 2015.

In North America, realized natural gas prices decreased by 9% in 2016, which is consistent with decreases in benchmark prices. In Southeast Asia, where a significant portion of gas sales are linked to oil prices, realized natural gas prices decreased by 15% which is in line with decreases in benchmark crude pricing. Due to these reasons, the Company’s overall realized natural gas price of $3.06/mcf decreased by 14% compared to 2015.

Royalties1,2,3

	2016		2015		2014
	Rate (%)	$ million	Rate (%)	$ million	Rate (%)	$ million
North America	14	133	14	150	16	350
Southeast Asia	27	347	30	503	34	1,036
Other	50	101	39	99	46	233
	24	581	25	752	26	1,619

(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 was down $171 million from 2015. The decrease in royalty is principally due to lower overall commodity prices, partially offset by higher government entitlement in Algeria for 2016.

Unit Operating Expenses1,2,3

	Gross before royalties			Net of royalties
($/boe)	2016	2015	2014	2016	2015	2014
North America	5.67	6.85	7.69	6.57	7.90	9.03
Southeast Asia	7.06	8.39	10.69	9.59	11.92	16.02
Other	7.47	14.06	11.38	15.05	22.41	21.66
	6.25	7.75	9.07	7.80	9.75	11.88

(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 Expenses1,2

(millions of $)	2016	2015	2014
North America	379	470	527
Southeast Asia	291	367	494
Other	38	69	62
	708	906	1,083

(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 $198 million compared to 2015.

In North America, total operating expenses decreased 19% compared to 2015 due principally to a reduction in the Company’s interest in Eagle Ford in late 2015, severance tax credits and a focused effort to reduce operating expenses across the Company. Unit operating expenses in North America decreased by 17% due to the reasons noted above.

In Southeast Asia, total operating expenses decreased by 21% due primarily to the Kitan field in Australia/Timor-Leste no longer producing, the sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016 and a focused effort to reduce operating expenses across the Company. This was further driven by lower production in Southeast Asia. Unit operating expenses in Southeast Asia decreased by 16% due to the reasons noted above.

In Rest of World, total operating expenses decreased by 45% compared to 2015 primarily due to Akacias production

being shut-in in Colombia from March to October of 2016, as well as additional crude treatment charges recorded in 2015. Unit operating expenses decreased by 47% due to the reasons noted above.

Unit operating expense for the Company decreased by 19% to $6.25/boe due to the reasons noted above.

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

	Gross before royalties			Net of royalties
($/boe)	2016	2015	2014	2016	2015	2014
North America	13.74	14.86	16.53	15.93	17.15	19.40
Southeast Asia	6.99	10.53	9.82	9.50	14.96	14.71
Other	9.63	12.08	10.16	19.40	19.26	19.32
	11.13	13.09	13.55	13.89	16.48	17.75

(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 $)	2016	2015	2014
North America	894	1,004	1,109
Southeast Asia	276	466	473
Other	44	64	52
	1,214	1,534	1,634

(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 21% compared to 2015 due principally to decreased DD&A expense in Southeast Asia and North America.

In North America, DD&A expense decreased by 11% due principally to the partial sale of the Eagle Ford in late 2015, partially offset by an increase in Canada due to impairment reversals recorded at the end of 2015. Unit DD&A expense decreased by 8% due to the reasons noted above.

In Southeast Asia, DD&A expense decreased by 41% due principally to a lower depletable base in Malaysia and Vietnam as a result of asset impairments recorded at year-end 2015, lower production in Vietnam, the Kitan field in Australia/Timor-Leste no longer producing and the sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016. Unit DD&A expense decreased by 34% due to the reasons noted above.

In Rest of World, DD&A expense decreased by 31% due principally to Akacias production being shut-in from March to October of 2016 in Colombia, timing of liftings and increase in depletable base in Algeria. Unit DD&A expense decreased by 20% due to the reasons noted above.

Unit DD&A expense for the Company decreased by 15% to $11.13/boe due to the reasons noted above.

Impairment1,2

(millions of $)	2016		2015		2014
Impairment losses
North America	2		734		625
Southeast Asia	75		610		60
North Sea3	—		—		287
Other4	8		338		374
	85		1,682		1,346
Impairment reversals
North America	(242	)	(155	)	(32	)
Southeast Asia	(161	)	(4	)	—
Other4	(9	)	—		—
	(412	)	(159	)	(32	)
Net impairment	(327	)	1,523		1,314

(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 in 2014 relate entirely to the impairment of goodwill.

(4) Included in the impairment expense (reversals) of “Other” is a non-taxable impairment reversal of $9 million for 2016 (impairment expense of $47 million and $133 million in 2015 and 2014 respectively) relating to the Company’s investment in the Equion joint venture.

North American Impairments

During 2016, the Company recorded a PP&E asset impairment reversal of $58 million relating to Edson ($42 million after-tax), in part as a result of reduced cost assumptions as part of the focused effort to reduce costs across the Company’s operations.

During 2016, the Company recorded a $183 million pre-tax ($112 million after-tax) impairment reversal in the Eagle Ford CGU to its PP&E assets ($148 million) and E&E assets ($35 million). The impairment reversal was taken as a result of the increase in the recoverable amount due to an improvement in the outlook of the assets.

Southeast Asia Impairments

During 2016, the Company recorded a pre-tax PP&E impairment reversal of $84 million ($52 million after-tax) related to PM3 in Malaysia primarily as a result of reduced operating cost assumptions as part of the focused effort to reduce costs across the Company’s operations.

During 2016, the Company recorded a pre-tax PP&E impairment reversal of $60 million ($30 million after-tax) for Block 15-2 in Vietnam due to increased reserves from improved technical performance on oil wells and reduced operating cost assumptions as part of the focused effort to reduce costs across the Company’s operations.

During 2016, the Company recorded a pre-tax PP&E impairment expense of $47 million ($35 million after-tax) in Southeast Asia due to the delay in the timing of production and certain assets no longer expected to be used. The Company also fully impaired $28 million of E&E assets ($22 million after-tax) as a result of unfavorable drilling results.

Dry Hole Expense1,2

(millions of $)	2016	2015	2014
North America	14	—	11
Southeast Asia	91	1	92
Other	11	14	38
	116	15	141

(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.

Dry hole expense relates to the write-off of costs for unsuccessful exploration wells.

In North America, dry hole expense of $14 million consists primarily of Duvernay well costs in Canada.

In Southeast Asia, dry hole expense of $91 million consists primarily of $46 million for well costs in Papua New Guinea, $35 million for well costs in Malaysia, and $10 million for well costs in Indonesia.

In Rest of World, dry hole expense consists of write-off of an unsuccessful exploration well in Colombia.

Exploration Expense1,2

(millions of $)	2016	2015	2014
North America	5	51	21
Southeast Asia	64	68	108
North Sea	—	16	—
Other	36	40	66
	105	175	195

(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, exploration expense decreased by $46 million due principally to change of control provisions in certain third party contracts incurred in 2015 as a result of the acquisition of the Company by Repsol.

In Southeast Asia, exploration expense decreased by $4 million due principally to reduced seismic, geological and geophysical activities in Vietnam and Papua New Guinea, partially offset by increased activities in Indonesia.

In North Sea, exploration expense decreased by $16 million due to change of control provisions in certain third party contracts incurred in 2015 as a result of the acquisition of the Company by Repsol.

In Rest of World, exploration expense decreased by $4 million due principally to the farm-out of block CPE6 in Colombia.

Income (Loss) from Joint Ventures and Associates1

(millions of $)	2016		2015		2014
RSRUK	(266	)	(1,021	)	(1,055	)
Equion	62		(65	)	15
	(204	)	(1,086	)	(1,040	)

(1) Includes the Company’s proportionate interest in joint ventures and associates as disclosed in note 8 of the 2016 audited Restated Consolidated Financial Statements.

RSRUK Joint Venture

The Company’s share of net loss from RSRUK decreased from $1.0 billion in 2015 down to $266 million in 2016 due principally to net impairment reversals compared to net impairment expense in 2015, lower operating expenses as part of operational transformation initiatives in 2016, lower DD&A, and decrease in income taxes.

Effective January 1, 2016, the UK government decreased the rate of supplementary charge on ring fence profits from 20% to 10%. Consequently, there is now a combined UK corporation tax and supplementary charge rate of 40% (down from 50%) for oil and gas companies. The UK government also decreased the Petroleum Revenue Tax (PRT) rate decreased from 35% to 0%, effective January 1, 2016. As a result of this legislative change, RSRUK recorded a recovery of deferred PRT of $85 million ($43 million net to the Company) in 2016.

In 2015, the UK government decreased the supplemental charge on ring fence profits from 32% to 20% and the PRT rate from 50% to 35%. RSRUK recorded a recovery of deferred PRT of $98 million ($50 million net to the Company) in 2015.

Equion Joint Venture

The net income of $62 million after-tax represents the Company’s 49% interest in the Equion joint venture in Colombia. In 2016, Equion had net income of $62 million compared to a loss of $65 million in 2015 due principally to lower impairment expense, lower DD&A as a result of impairments taken in 2015 and timing of liftings and recognizing a gain on revaluation of the ODC investment, partially offset with reduced revenue as a result of lower commodity prices.

Corporate and Other1,2

(millions of $)	2016		2015		2014
G&A expense	244		298		396
Finance costs	190		327		327
Share-based payments expense (recovery)	—		(24	)	25
Gain on held-for-trading financial instruments	—		(61	)	(1,427	)
(Gain) Loss on disposals	(73	)	2		(550	)
Other expenses, net	79		266		48
Other income	150		317		158

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

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

In 2016, G&A expense decreased by $54 million relative to 2015 due principally to lower workforce expenses and reduced reliance on temporary staff and consultants.

Finance costs include interest on long-term debt, other finance charges and accretion expense relating to decommissioning liabilities, less interest capitalized. Finance costs decreased by $137 million as compared to 2015 by reducing overall long-term debt and with the increased reliance on related party financing, which carries lower financing costs.

The Company recorded a gain on disposals of $73 million in 2016. This is due principally to the disposition of TWOL in the fourth quarter of 2016.

Other expenses consists primarily of onerous lease contracts and other provisions of $68 million, restructuring costs of $17 million, inventory write-downs of $10 million, $50 million in other miscellaneous expenses and a foreign exchange gain of $67 million.

Other income of $150 million includes $13 million of pipeline income, $99 million of marketing and other miscellaneous income, $12 million of investment income and $26 million from a net gain as a result of repayment of long-term debt.

Income Taxes1,2

(millions of $)	2016		2015		2014
	Restated
Loss from continuing operations before taxes	(637	)	(3,658	)	(119	)
Less: PRT
Current	6		7		15
Deferred	(13	)	(1	)	(18	)
Total PRT	(7	)	6		(3	)
	(630	)	(3,664	)	(116	)
Income tax expense (recovery)
Current income tax (recovery)	201		(184	)	414
Deferred income tax (recovery)	(319	)	(668	)	(189	)
Income tax expense (recovery) (excluding PRT)	(118	)	(852	)	225
Effective income tax rate (%)	19	%	23	%	(194	)%

(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 2016 effective tax rate was impacted by pre-tax losses of $308 million in North America where tax rates are between 27% and 39% and pre-tax income of $213 million in Southeast Asia where tax rates range from 30% to 58%.

In addition to the jurisdictional mix of income, the effective tax rate in 2016 was impacted by:

· Derecognition of deferred tax assets in Malaysia and Vietnam;

· Earnings from joint ventures;

· Rate decrease in Colombia;

· Disposals in Southeast Asia;

· Recognition of previously unrecognized deferred tax asset in the US.

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%.

In addition to the jurisdictional mix of income, the effective tax rate in 2015 was also 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 increase of $385 million in current tax expense from a current income tax recovery of $184 million in 2015 to a current income tax expense of $201 million in 2016 is due principally to the sale of the Norwegian operations in 2015.

The decrease of deferred tax recovery of $349 million in 2016 to $319 million from $668 million in 2015 was due principally to the recognition of a large US deferred tax asset in 2015, compared to a much smaller recognition of a US deferred tax asset in 2016 combined with the derecognition of Southeast Asia deferred tax assets in 2016, partially offset by the sale of the Norwegian operations in 2015.

Capital Expenditures1

($ millions)	2016		2015		2014
North America	315		763		1,322
Southeast Asia	177		210		439
Other	20		46		161
Exploration and development expenditure from consolidated subsidiaries2	512		1,019		1,922
Corporate, IS and Administrative	3		24		47
Acquisitions and extension	113		31		35
Proceeds of dispositions	(325	)	(396	)	(1,517	)
Net capital expenditure for consolidated subsidiaries	303		678		487
RSRUK	199		337		599
Equion	13		43		103
Exploration and development expenditure from Joint Ventures3	212		380		702
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures	515		1,058		1,189

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

(2) Excludes exploration expense of $105 million in 2016 (2015 - $175 million; 2014 - $195 million).

(3) Represents the Company’s proportionate interest, excluding exploration expensed of $3 million net in 2016 (2015 - $3 million; 2014 - $5 million).

North American capital expenditures were $315 million in 2016, a decrease of 59% from 2015. This was as a result of the decreased development spending in Marcellus, Eagle Ford, Edson and Chauvin areas and decreased exploration spending in Duvernay due to reduced cash flows and less attractive investment economics from lower commodity prices. Of the total, $259 million related to development activity, with the remaining capital invested in exploration activities.

In Southeast Asia, capital expenditures of $177 million included $101 million on development, with the majority spent in Indonesia and Malaysia. The exploration expenditure of $76 million was invested in Malaysia, Indonesia, and Papua New Guinea.

In Rest of World, capital expenditures of $20 million consisted primarily of exploration and evaluation activities in Colombia.

In the RSRUK joint venture, capital expenditures of $199 million consisted primarily of development activities in the Monarb, Claymore, Clyde and Fulmar areas. In the Equion joint venture, net capital expenditures of $13 million related primarily to Piedemonte development wells.

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.

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

Years ended December 31,	2015		2014
Revenue	182		529
Expenses	(429	)	(1,190	)
	(247	)	(661	)
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	)
Income taxes
Current income tax recovery	(8	)	(11	)
Deferred income tax recovery	(313	)	(80	)
Net loss from discontinued operations	(294	)	(570	)

DISPOSALS

North America

On December 31, 2016, Repsol E&P USA Holdings Inc., sold 20% of its interest in ROGUSA to RUSA. The preliminary purchase price of $502 million supported by a preliminary evaluation by an independent third party valuator, was settled in exchange for a note receivable from RUSA and was included in the amount due from related party. Subsequently, based upon the Company’s internal evaluations of the purchase price, supported by the assessment of the external valuator, the Company reduced the purchase price to $442 million. The $60 million adjustment was recorded as a payable to RUSA at December 31, 2016. In April 2017, the purchase price was confirmed and finalized, and the note receivable from RUSA was amended to $442 million.

No gain or loss was recognized on this transaction through the Restated Consolidated Statement of Loss. The after-tax amount of $160 million representing the difference between the fair value of the consideration received and the non-controlling interest holder’s share of the carrying amount of the interest sold was recognized through equity. ROGCI will continue to consolidate 100% of ROGUSA’s results with an offsetting amount representing the 20% non-controlling interest.

Southeast Asia

In December 2016, the Company sold all of its shares in TWOL for total cash proceeds of $306 million, resulting in a pre-tax gain on disposal of $79 million ($27 million after-tax).

In April 2016, the Company paid $8 million to dispose of net assets in Australia/Timor-Leste which resulted in a loss of $7 million.

ACQUISITIONS AND EXTENSION

During the second quarter, the Company was successful in extending a Production Sharing Contract (“PSC”) in Malaysia until December 31, 2027. As a result, the Company committed to pay a lease extension payment of $60 million in various tranches until 2020 of which $29 million and $25 million, were included in accounts payable and accrued liabilities and other long-term obligations, respectively.

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 23, 2017.

The Company’s gross before royalties proved and probable reserves at December 31, 2016 (including the reserves attributable to its investments in RSRUK 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 basis1	Light Oil (mmbbls)	Heavy Oil (mmbbls)	Tight Oil (mmbbls)	Shale Gas (bcf)	Conventional Natural Gas (bcf)	Natural Gas Liquids (mmbbls)
Proved Developed Producing	31.3	22.8	3.7	1,266.5	1,047.3	49.6
Proved Developed Non-Producing	1.1	3.5	—	17.6	106.8	2.4
Proved Undeveloped	3.4	3.6	3.9	611.9	266.8	25.1
Total Proved	35.8	29.9	7.6	1,896.0	1,420.9	77.1
Total Probable	57.9	11.9	1.8	781.1	628.8	37.7
Total Proved Plus Probable Reserves for Consolidated Subsidiaries	93.7	41.8	9.4	2,677.1	2,049.7	114.8
Summary of working interest reserves for Joint Ventures on gross basis
Proved Developed Producing	40.6	—	—	—	29.0	1.2
Proved Developed Non-Producing	0.4	—	—	—	—	—
Proved Undeveloped	3.8	—	—	—	26.3	—
Total Proved	44.8	—	—	—	55.3	1.2
Total Probable	26.0	—	—	—	19.5	0.1
Total Proved Plus Probable Reserves for Joint Ventures	70.8	—	—	—	74.8	1.3
Total Proved Plus Probable Reserves for Consolidated Subsidiaries and Joint Ventures	164.5	41.8	9.4	2,677.1	2,124.5	116.1

(1) In accordance with NI 51-101, the table above includes 100% of the reserves attributed to ROGUSA properties, without reduction to reflect the 20% non-controlling interest.

Reconciliation of proved plus probable reserves:

Continuity of working interest reserves for Consolidated Subsidiaries on gross basis1	Light Oil (mmbbls)		Heavy Oil (mmbbls)		Tight Oil (mmbbls)		Shale Gas (bcf)		Conventional Natural Gas (bcf)		Natural Gas Liquids (mmbbls)
At December 31, 2015	108.0		56.4		11.6		2,755.5		2,441.1		108.1
Discoveries	—		—		—		—		—		—
Additions and extensions	3.3		0.4		0.3		280.6		187.6		24.3
Acquisitions	—		0.9		—		7.3		7.1		0.6
Divestment	—		—		—		—		(274.8	)	(1.6	)
Technical revisions	(6.5	)	(4.9	)	(1.0	)	27.6		(28.0	)	1.1
Economic revisions	1.7		(7.6	)	(0.8	)	(191.5	)	(37.5	)	(5.8	)
Production	(12.8	)	(3.4	)	(0.7	)	(202.4	)	(245.8	)	(11.9	)
At December 31, 2016 for Consolidated Subsidiaries	93.7		41.8		9.4		2,677.1		2,049.7		114.8
Continuity of working interest reserves for Joint Ventures on gross basis
At December 31, 2015	70.4		—		—		—		89.5		1.7
Discoveries	—		—		—		—		—		—
Additions and extensions	0.3		—		—		—		2.3		—
Acquisitions	—		—		—		—		—		—
Divestment	—		—		—		—		—		—
Technical revisions	3.5		—		—		—		(14.9	)	(0.3	)
Economic revisions	8.6		—		—		—		10.1		0.2
Production	(12.0	)	—		—		—		(12.2	)	(0.3	)
At December 31, 2016 for Joint Ventures	70.8		—		—		—		74.8		1.3
Total at December 31, 2016 for Consolidated Subsidiaries and Joint Ventures	164.5		41.8		9.4		2,677.1		2,124.5		116.1

(1) In accordance with NI 51-101, the table above includes 100% of the reserves attributed to ROGUSA properties, without reduction to reflect the 20% non-controlling interest.

At the end of 2016, the Company’s proved plus probable reserves totaled 1.19 billion boe. The Company added (discoveries, additions & extensions, acquisitions) approximately 116.5 million boe, with negative technical revisions of 10.8 million boe, negative economic revisions of 42.7 million boe, and divestments of 50.5 million boe.

LIQUIDITY AND CAPITAL RESOURCES

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

During 2016, the Company generated $423 million of cash provided by operating activities from continuing operations, incurred capital expenditures of $528 million, and received proceeds of $325 million from the disposition of assets and investments.

The Company’s capital structure consists of shareholder’s equity, debenture and notes, and debt from 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.

During 2016 and 2015, the Company entered into three revolving facilities with subsidiaries of its ultimate parent, Repsol, with total borrowing limit of $3.5 billion. As at December 31, 2016, $1.8 billion drawings were outstanding under these facilities. In May 2017, amendments were made to the facility agreements (Refer to “Transactions with Related Parties” section).

On March 23, 2016, the Company announced a cash tender offer to purchase any and all principal amount of the Company’s outstanding 7.75% Senior Notes due 2019, 3.75% Senior Notes due 2021, 7.25% Debentures due 2027, 5.75% Senior Notes due 2035, 5.85% Senior Notes due 2037, 6.25% Senior Notes due 2038, and 5.50% Senior Notes due 2042. The principal amount tendered and accepted was $601 million.

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

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

The above discussed tender offer and redemption of outstanding senior notes in 2016 resulted in a net gain of $26 million, which was recognized in other income on the Restated Consolidated Statement of Loss.

In 2015, the Company announced a cash tender offer to purchase up to $750 million (subsequently raised to $2.0 billion) 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. As at December 31, 2015, the principal amount tendered and accepted was $1.5 billion. The Company paid the consenting note holders an aggregate of approximately $1.4 billion in cash (including $1.4 billion principal and $23 million accrued interest).

In 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 in 2015 resulted in a net gain of $149 million, which was recognized in other income on the Restated 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 related party credit facilities.

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

debt-to-cash flow ratio of less than 3.5:1.

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At December 31, 2016, the Company had $155 million letters of credit outstanding, primarily related to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations. In addition, there were $127 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

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

The UK government passed legislation in 2013 which provides for a contractual instrument, known as a Decommissioning Relief Deed, for the government to guarantee tax relief on decommissioning costs at 50%, allowing security under DSAs to be posted on an after-tax basis and reducing the value of letters of credit required to be posted by 50%. RSRUK has entered into a Decommissioning Relief Deed with the UK Government and continues to negotiate with counterparties to amend all DSAs accordingly. As of December 31, 2016, only two DSAs were still required to be negotiated on a post-tax basis. Tax relief guaranteed by the UK government is limited to corporate tax paid since 2002. Under the limitation, RSRUK’s tax relief is capped at $1.5 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At December 31, 2016, RSRUK has $2.6 billion of demand shared facilities in place under which letters of credit of $1.2 billion have been issued. The Company also guaranteed $0.6 billion demand letters of credit issued under RSRUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK.

The Company has also granted guarantees to various beneficiaries in respect of decommissioning obligations of RSRUK.

At December 31, 2016, the Company’s share of RSRUK’s total recorded decommissioning liabilities was $2.6 billion. Decommissioning estimates are subject to a significant amount of management judgment given the long dated nature of the assets and the timing of remediation upon cessation of production. The Company reviews its assessment of decommissioning liabilities annually, or where a triggering event causes a review, taking into account new information and industry experience.

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.

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

The Company’s obligation to fund RSRUK, in proportion of its shareholding, arises from the Company’s past practice of funding RSRUK’s cash flow deficiencies, and the expectation that cash flow deficiencies will continue to be funded. In addition the Company, in proportion of its shareholding, has a guarantee to fund RSRUK’s decommissioning and pension obligation if RSRUK is unable to, and the shareholders of RSRUK have provided equity funding facilities to RSRUK which include funding decommissioning liabilities. As such, the Company has recognized a negative investment value from the application of equity accounting. The Company’s obligation to fund RSRUK will increase to the extent future losses are generated within RSRUK.

The Company had an interest in the Tangguh LNG Project and was a participant in two series of project financing facilities. As a result of the Company’s sale of all of its shares in TWOL in December 2016, the Company is no longer a participant of the above mentioned series of financing facilities.

The Company monitors its balance sheet with reference to its liquidity. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from equity accounted entities, cash provided by and used in investing activities and available related party facilities.

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. Collateral received from customers at December 31, 2016 included $92 million of letters of credit. At December 31, 2016, an allowance of $21 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, 2016, approximately 86% of the Company’s accounts receivable was current and the largest single counterparty exposure, accounting for 5% of the total, was with a highly rated counterparty. In addition, 18% of the Company’s accounts receivable was with subsidiaries of the Company’s ultimate parent, Repsol, as a result of the related party transactions disclosed in “Transactions with Related Parties” section. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base primarily of entities with acceptable risk based on internal analysis.

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 based on internal analysis of creditworthiness.

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

On December 22, 2016, the Company issued 4,869,110 common shares at $1.91 per share to Repsol Energy Resources Canada Inc. (“RERCI”), a subsidiary of the Company’s ultimate parent Repsol, for proceeds of $9 million. There were 1,834,375,452 common shares outstanding at December 31, 2016.

On April 18, 2017 RERCI, subscribed for $1.5 billion in the Company’s common shares (786,125,654 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. On May 12, 2017 there were 2,620,501,106 common shares outstanding.

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 with related parties.

For additional information regarding the Company’s liquidity and capital resources, refer to notes 17, 19 and 21 to the 2016 audited Restated Consolidated Financial Statements.

SENSITIVITIES

The Company’s financial performance is affected by factors such as changes in production volumes and commodity prices. The estimated annualized impact of these factors for 2017 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $55/bbl, a NYMEX natural gas price of approximately $3.20/mmbtu.

		Cash Provided by
		Operating Activities
		from continuing
(millions of $)	Net Loss	operations2
Volume changes
Oil – 10,000 bbls/d	50	65
Natural gas – 60 mmcf/d	20	55
Price changes
Oil – $1.00/bbl	25	20
Natural gas (North America)1 – $0. 10/mcf	15	25

(1) 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.

(2) Changes in cash flow provided by operating activities exclude RSRUK 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 2016 audited Restated Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, decommissioning obligations, lease commitments relating to corporate offices and ocean-going vessels, firm commitments for gathering, processing and transmission services, minimum work commitments under various international agreements, other service contracts and fixed price commodity sales contracts.

Additional disclosure of the Company’s decommissioning liabilities, debt repayment obligations and significant commitments can be found in notes 8, 15, 17, 18 and 22 to the 2016 audited Restated 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, 2016 and estimated timing of such payments:

			Payments due by period1,2 (millions of $)
Commitments	Recognized in balance sheet	Total	2017	2018- 2019	2020- 2021	2021+
Long-term debt	Yes – Liability	1,393	308	363	239	483
Loans from related parties	Yes – Liability	1,756	—	1,756	—	—
Bank indebtedness	Yes – Liability	5	5	—	—	—
Accounts payable and accrued liabilities	Yes – Liability	835	835	—	—	—
Loans from joint ventures	Yes – Liability	10	10	—	—	—
Finance leases	Yes – Partially accrued	33	12	14	2	5
Investment commitments3	No	801	345	304	143	9
Service commitments	No	484	103	149	92	140
Transportation commitments4	No	679	110	193	159	217
Operating leases	No	217	41	65	57	54
Total		6,213	1,769	2,844	692	908

(1) Future payments denominated in foreign currencies have been translated into US$ at the December 31, 2016 exchange rate.

(2) Payments exclude interest on long-term debt and loans from related parties.

(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 RSRUK and Equion commitments as at December 31, 2016.

		Payments due by period1,2 (millions of $)
Commitments	Total	2017	2018- 2019	2020- 2021	2021+
Purchase commitments	69	19	25	25	—
Investment commitments3	17	17	—	—	—
Service commitments	69	24	36	2	7
Transportation commitments4	19	12	7	—	—
Operating leases	12	2	3	2	5
Total	186	74	71	29	12

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

(2) Future payments denominated in foreign currencies have been translated into US$ based on the December 31, 2016 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, 2016. 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	60	251	799	1,110
Decommissioning liabilities for Joint Ventures1	128	785	1,670	2,583

(1) Represents the Company’s share of the RSRUK 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 btu. 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 160 bcf over the remaining seven-year life of the agreement.

The Company is subject to natural gas volume delivery requirements for approximately 90-110 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 and Vietnam, which is currently scheduled to expire in 2018. Negotiations to extend the long-term gas sales agreement beyond 2018 are well underway under which the gas delivery commitments are expected to be extended to 2027 to coincide with the extension of the PM3 Commercial Arrangement Area which was awarded in 2016. Payment reference for the gas price beyond 2018 will remain the same and volume delivery requirements will be adjusted to match the forward reserves profile and will follow a step down approach. In the event these delivery requirements are not met in a contract year, volumes delivered in the subsequent contract year may be subject to a 25% price discount for the equivalent volume of unexcused shortage that was not delivered in the prior contract year. The long-term gas sales agreement

contains provisions which allow for relief from these penalties due to allowable shut-down days, force majeure and other events.

Currently, the Company anticipates having sufficient production to meet all of these future delivery requirements.

There have been no significant changes in the Company’s expected future payment commitments, and the timing of those payments, since December 31, 2016.

TRANSACTIONS WITH RELATED PARTIES

Repsol

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

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 plus 0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. On November 17, 2015, the interest rate in the facility agreement was amended to LIBOR plus 1.20%. Effective June 13, 2016, the credit limit on this facility was increased to $550 million. As at December 31, 2016, there were $261 million drawings under this facility. Interest expense related to the facility recognized by the Company during 2016 was $6 million. In 2015, RTYGF had a balance of $334 million payable to TEHS, which was recorded as amount due from related party on the Restated Consolidated Balance Sheets. In January 2016, RTYGF repaid the outstanding balance to TEHS. In May 2017, the facility agreement was modified to extend the maturity date to June 30, 2020.

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 plus 1.20%. The facility limit was increased to $2.8 billion on December 9, 2015. At December 31, 2016, the Company had $1.5 billion outstanding under this facility. Interest expense related to the facility recognized by the Company during 2016 was $23 million. In May 2017, the facility agreement was modified to extend the maturity date to May 8, 2020.

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

During 2016, the Company incurred $14 million reinsurance expense with Gaviota RE S.A., a subsidiary of Repsol. As at December 31, 2016, there was no payable outstanding as a result of this transaction.

During 2016, a subsidiary of ROGCI’s ultimate parent, Repsol, provided exploration services to various subsidiaries of ROGCI for total cost of $17 million. As at December 31, 2016, the amount included in accounts payable as a result of these transactions was $10 million.

During 2016, a subsidiary of ROGCI’s ultimate Parent, Repsol, paid $9 million for the use of income tax losses in a ROGCI subsidiary. Accordingly, ROGCI recorded a current income tax asset and a current income tax recovery of $9 million.

As at December 31, 2016, there were $127 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

North America

On June 8, 2016, ROGUSA entered into a $125 million revolving facility with RUSA, a subsidiary of Repsol. The facility matures on June 8, 2017 and bears an interest rate of LIBOR (6 month) plus 1.70%. ROGUSA also provides RUSA with an $85 million supplementary revolving facility, with interest rate of LIBOR (1 month). As at December 31, 2016, there were no drawings outstanding under the primary facility. Instead, RUSA had a balance of $67 million payable to ROGUSA under the supplemental facility. Interest income related to the facility recognized by the Company during 2016 was less than one million.

The sale of 20% of the interest in ROGUSA, Repsol E&P USA Holdings Inc., an indirect subsidiary of the Company is further discussed in the “Disposals” section of this Restated MD&A.

During 2016, Repsol Canada Energy Partnership sold to Repsol Energy Canada Limited, a subsidiary of Repsol, approximately 65 trillion btu of natural gas for $103 million. As at December 31, 2016, the amount included in accounts receivable as a result of these transactions was $16 million.

During 2016, ROGUSA sold to Repsol Energy North America Corporation, a subsidiary of Repsol, approximately 49 trillion btu of natural gas for $115 million and additional transport capacity income of $28 million. As at December 31, 2016, the amount included in accounts receivable as a result of these transactions was $41 million.

Rest of World

During 2016, Talisman (Algeria) B.V. sold to Repsol Trading S.A., a subsidiary of Repsol, approximately 1.8 million barrels of Saharan Blend Crude Oil for $81 million. As at December 31, 2016, the amount included in accounts receivable as a result of these transactions was $19 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 billion btu. The commitment matures in 2023. As a result of the

acquisition of the Company by Repsol, GSPL and Temasek became the Company’s related parties. During 2016, the Company’s gas sales to GSPL totaled $132 million, (net of royalties and the Company’s share). As at December 31, 2016, the amount included in accounts receivable as a result of this commitment was $31 million.

RSRUK

As at December 31, 2016, the investment balance in the RSRUK joint venture was negative $628 million. Based on anticipated funding requirements in 2017, the Company has recorded $143 million as a current obligation.

In June 2015, the shareholders of RSRUK provided an equity funding facility of $1.7 billion, of which the Company is committed to $867 million, for the purpose of funding capital, decommissioning and operating expenditures of RSRUK. This facility is effective from July 1, 2015 and had a maturity date of December 31, 2016. In September 2016, this agreement was modified to extend the maturity date to December 31, 2017. During the year ended December 31, 2016, the shareholders of RSRUK agreed to subscribe for common shares of RSRUK in the amount of $595 million under this facility, of which the Company’s share was $303 million.

The shareholders of RSRUK provided an unsecured non-revolving loan facility totaling $2.4 billion to RSRUK ($1.2 billion net to the Company), for the purpose of funding capital expenditures of RSRUK. There was no loan balance outstanding as at December 31, 2016.

The Company has also granted guarantees to various beneficiaries in respect of decommissioning obligations of RSRUK.

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

Equion

The loan due to Equion of $10 million is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.

During the year ended December 31, 2016, Equion declared dividends payable to the shareholders in the amount of $318 million (2015 - $190 million) of which the Company’s share was $156 million (2015 - $93 million). In 2016, the dividends declared were settled through reduction of the loan due to Equion ($74 million), through cash receipts ($41 million), and through transfer of Equion’s ownership in the shares of ODC to the Company ($41 million).

Key Management Personnel Compensation

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

(millions of $)	2016	2015	2014
Short-term benefits	3	4	14
Pension and other post-employment benefits	—	3	5
Termination benefits	1	23	3
Share-based payments1	—	11	3
Change of control payments	—	24	—
	4	65	25

(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 Restated 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 4(q) to the 2016 audited Restated Consolidated Financial Statements.

For accounting purposes the Company had elected not to designate any derivative contracts entered into as hedges. These derivatives are classified as held-for-trading financial instruments and are measured at fair value with changes in fair value recognized in net income quarterly. This can potentially increase the volatility of net income.

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

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 $, unless otherwise stated)	Annual		Dec. 31		Sep. 30		Jun. 30		Mar. 31
	Restated		Restated
2016
Total revenue and other income from continuing operations1	1,777		679		313		316		469
Total revenue and other income from discontinued operations2	—		—		—		—		—
Total revenue and other income	1,777		679		313		316		469
Net income (loss) from continuing operations	(512	)	262		(323	)	(306	)	(145	)
Net income (loss) from discontinued operations2	—		—		—		—		—
Net income (loss)	(512	)	262		(323	)	(306	)	(145	)
Per common share ($)
Net income (loss) 3	(0.28	)	0.14		(0.18	)	(0.17	)	(0.08	)
Diluted net income (loss) 4	(0.28	)	0.14		(0.18	)	(0.17	)	(0.08	)
Income (loss) from continuing operations per common share
Basic	(0.28	)	0.14		(0.18	)	(0.17	)	(0.08	)
Diluted	(0.28	)	0.14		(0.18	)	(0.17	)	(0.08	)
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	113		106		116		112		119
Natural gas (mmcf/d)	1,260		1,230		1,223		1,252		1,334
Total production from continuing operations (mboe/d)	338		325		334		335		357
Total production from discontinued operations (mboe/d)2	—		—		—		—		—
Total mboe/d	338		325		334		335		357
2015
Total revenue and other income from continuing operations1	1,485		145		345		556		439
Total revenue and other income from discontinued operations2	182		—		38		83		61
Total revenue and other income	1,667		145		383		639		500
Net loss from continuing operations	(2,812	)	(628	)	(899	)	(888	)	(397	)
Net income (loss) from discontinued operations2	(294	)	—		112		(364	)	(42	)
Net loss	(3,106	)	(628	)	(787	)	(1,252	)	(439	)
Per common share ($)
Net loss3	(2.97	)	(0.59	)	(0.75	)	(1.20	)	(0.43	)
Diluted net loss 4	(3.01	)	(0.59	)	(0.75	)	(1.24	)	(0.43	)
Loss from continuing operations per common share
Basic3	(2.69	)	(0.59	)	(0.86	)	(0.85	)	(0.39	)
Diluted4	(2.73	)	(0.59	)	(0.86	)	(0.89	)	(0.39	)
Daily average production from Consolidated Subsidiaries and Joint Ventures
Oil and liquids (mbbls/d)	124		127		120		127		124
Natural gas (mmcf/d)	1,326		1,359		1,299		1,321		1,325
Total production from continuing operations (mboe/d)	361		369		351		362		360
Total production from discontinued operations (mboe/d) 2	11		—		13		16		16
Total mboe/d	372		369		364		378		376

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

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

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

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

During the three-month period ended December 31, 2016, total revenue and other income from continuing operations increased by $534 million over the same period in 2015 due principally to income from the RSRUK joint venture compared to loss from RSRUK joint venture in the prior year quarter which is partially offset by a decrease in other income due to the recognition of a net gain on repayment of long-term debt in the fourth quarter of 2015.

Net loss from continuing operations of $628 million for the three-month period ended December 31, 2015 increased to a net income of $262 million for the three-month period ended December 31, 2016 due principally to impairment reversals in RSRUK and lower impairment expenses in Equion, the recognition of a gain on revaluation of the ODC investment, impairment reversals in North America and Southeast Asia, the decrease in operating expense and DD&A and gain on disposal due principally to the disposition of TWOL, partially offset by increase in income taxes.

Also, during the three-month period ended December 31, 2016, the Company:

· Recorded total production of 325 mboe/d, down 12% from the same period in 2015.

· Sold 20% of its 100% interest of ROGUSA to RUSA as described in the “Disposals” section of this Restated MD&A.

· Sold all of its shares in TWOL for total cash proceeds of $306 million, resulting in a pre-tax gain on disposal of $79 million ($27 million after-tax).

· Recorded a net impairment reversals of $341 million.

· Recorded dry holes in Papua New Guinea, Indonesia and Colombia of $62 million.

INTERNAL CONTROL OVER FINANCIAL REPORTING AND DISLCLOSURE CONTROLS AND PROCEDURES

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (“ICFR”), 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”). A material weakness in the Company’s ICFR exists if a deficiency or a combination of deficiencies in our ICFR is such that there is a reasonable possibility that a material misstatement of our annual financial statements or interim financial reports will not be prevented or detected on a timely basis.

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

During the year ended December 31, 2016, the integration activities with the Company’s ultimate parent, Repsol, continued and the Company’s organizational design, policies and individuals with significant roles in ICFR have changed. In order to mitigate the potential effect associated with these changes, the Company continues to implement additional controls intended to ensure responsibilities are clearly understood and information and communication controls are effective.

Integration with Repsol will continue to impact ICFR over time and the changes will be monitored and managed.

The results of management’s original assessment of the Company’s ICFR were reviewed with the Audit Committee of the Company’s Board of Directors on February 21, 2017. Based on this assessment as at December 31, 2016, management had concluded that the Company’s ICFR was effective. However, subsequent to 2016, management determined that a restatement of its previously issued financial statements is necessary. As a result of the financial statement restatement, management has reassessed the effectiveness of the Company’s ICFR and has concluded that a material weakness exists in its ICFR, as discussed below. The Company’s ICFR was therefore not operating effectively as at December 31, 2016.

Identification and remediation of material weakness in ICFR

Subsequent to year-end, management determined that a related party transaction resulting in a non-controlling interest was not accounted for correctly, as described in the Restatement of Previously Issued Financial Statements section of this Restated MD&A. This resulted in a review by management, which indicated a material weakness in the Company’s ICFR relating to the review of the accounting treatment of this non-controlling interest transaction. Through analysis, management concluded that the material weakness of the Company’s ICFR was isolated to the aforementioned non-controlling interest transaction. Management’s review and conclusions were discussed with the Audit Committee.

This material weakness did not impact the controls relating to the preparation of the financial information for the purposes of consolidation with the Company’s ultimate parent and did not affect its ICFR.

Management has implemented appropriate remedial actions to address the material weakness identified in the Company’s ICFR. The remediation includes the strengthening of specific controls over the analysis and review of the impact in the financial statements of significant non-routine transactions, including non-controlling interest transactions. These measures will reinforce the responsibilities for review by individuals with specialized knowledge.

Management has discussed the aforementioned material weakness and remedial actions already implemented with the Audit Committee and the Board. Management will continue to review and report, to the Audit Committee, the progress on additional enhancements throughout 2017.

Because of its inherent limitations, ICFR is not intended to provide absolute assurance that a misstatement of the Company’s financial statements would be prevented or detected, even with the remediation measures implemented to address the material weakness and further enhancements to be implemented. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving the stated goals under all potential scenarios. 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 ineffective.

Disclosure Controls and Procedures

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.

At the end of the period covered by this Restated 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 not effective due to the material weakness described above.

Notwithstanding the material weakness described above, based upon the work performed during the restatement process, management has concluded that the Restated Consolidated Financial Statements for the year ended December 31, 2016, are fairly stated in all material respects in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

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 RSRUK has a 67.41% interest, suffered an upheaval buckle. In September 2012, RSRUK submitted a notification of a claim to Oleum Insurance Company (‘‘Oleum’’), a

wholly-owned subsidiary of the Company. RSRUK delivered a proof of loss seeking recovery under the insuring agreement of $350 million. To date, the documentation delivered by RSRUK purporting to substantiate its claim does not support coverage. On August 8, 2016, RSRUK served its Request for Arbitration and on September 7, 2016, Oleum served its response. The seat of the arbitration is London, while the law of New York governs the claim for damages and business interruption. The arbitration is currently in the pleadings stage, after which the tribunal will decide on the trial dates, among other procedural matters.

On July 13, 2015, Addax and Sinopec International Petroleum Exploration and Production Corporation (“Sinopec”) filed a “Notice of Arbitration” against ROGCI and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% shares of RSRUK. ROGCI and TCHL filed their response to the Notice of Arbitration on October 1, 2015. On May 25, 2016, Addax and Sinopec filed the Statement of Claim, in which they seek, in the event that their claims were confirmed in their entirety, repayment of their initial investment in RSRUK, which was executed in 2012 through the purchase of 49% of RSRUK from TCHL, a wholly-owned subsidiary of ROGCI, together with any additional investment, past or future, in such company, and further for any loss of opportunity, which they estimate in a total approximate amount of US$5.5 billion. The Arbitral Tribunal has decided, among other procedural matters, the bifurcation of the proceedings; the hearing related to liability issues has been scheduled for January 29 to February 20, 2018, and, if necessary, the hearing related to damages will take place at a later date still undecided, although it is likely to be fixed for the beginning of 2019. The Company maintains its opinion that the claims included in the Statement of Claim are without merit.

During 2016, the Alberta Energy Regulator (“AER”) informed the Company that certain permits to construct well sites and access roads were obtained without the Company following proper procedures. The Company has worked closely with the AER to close this matter. At this time, the Company does not expect any enforcement actions that the AER may issue to have a material impact on the Company’s operations.

Government and Legal Proceedings with Tax Implications

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

Canada

Pursuant to administrative proceedings by the Canada Revenue Agency (“CRA”) on the situation of the ROGCI Group of companies based in Canada for the years 2006-2010, a Notice of Reassessment resulting in adjustments to the 2006 tax return under several items was received. The Company does not expect this claim to have a significant impact for the Group. The Company will file the appropriate appeals as it considers some of the item adjustments to be incorrect.

Indonesia

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

Malaysia

The Company’s branches in Malaysia of Repsol Oil & Gas Malaysia Limited, formerly Talisman Malaysia Ltd. and Repsol Oil & Gas Malaysia (PM3) Limited, formerly Talisman Malaysia (PM3) Ltd., had received notifications of additional assessment from the Inland Revenue Board in respect of the years of assessment 2007, 2008 and 2011, disallowing the deduction of certain costs. The appeal was submitted to the Special

Commissioners of Petroleum Income Tax (“SCPIT”). Currently the Dispute Resolution Panel of the SCPIT is working with the Company’s external legal consultants for an out of court settlement while the case is waiting to be heard.

Timor-Leste

With respect to administrative proceedings by the authorities of Timor-Leste on the deductibility of certain expenses in income tax by Repsol Oil & Gas Australia (JPDA 06-105) Pty Limited, the authorities have recently withdrawn the pre-assessment questioning.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

The preparation of audited Restated 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 4 to the 2016 audited Restated 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 and resources. 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.

Contingent resources are those quantities of oil and gas estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to contingencies. Contingencies may include factors such as economic, legal, political, environmental and regulatory matters or a lack of markets. The estimate of contingent resources are included as part of the recoverable amount of certain assets in the impairment test.

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. These values are further impacted by estimates of contingent resources, commodity prices, and capital and operating costs required to develop and produce those reserves. By their nature, estimates of reserves and resources and the related future cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the Restated Consolidated Financial Statements of future periods could be material.

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, 2016 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 investment is written down to its recoverable amount when its carrying amount exceeds the recoverable amount. During 2016, the Company recorded an impairment reversal of $9 million pre-tax ($9 million after-tax) related to its investment in Equion.

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, 2016, the net present value of the Company’s decommissioning liability was $1,110 million (2015 — $796 million) and is recorded as liabilities on the Company’s restated balance sheet.

At December 31, 2016, the estimated undiscounted inflation adjusted decommissioning liabilities associated with oil and gas properties and facilities were $3.4 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 4.5%.

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 $43 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 Restated 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 4(o) to the 2016 audited Restated 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 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

Accounting Policies Adopted on January 1, 2016

Effective January 1, 2016, the Company adopted new and amended accounting standards as described below:

· IAS 1 Presentation of Financial Statements — Amendments to IAS 1. The amendments clarify guidance on materiality and aggregation, use of disaggregation and subtotals, the order of the notes to the financial statements and other comprehensive income arising from investments accounted for under the equity method. The adoption of this amended standard did not have a significant impact on the Company’s restated financial statements.

· IFRS 11 Joint Arrangements — Amendments to IFRS 11. The amendments clarify the accounting for the acquisition of an interest in a joint operation where the activities of the operation constitute a business. They require an investor to apply the principles of business combination accounting when it acquires an interest in a joint operation that constitutes a business. The adoption of this amended standard did not have a significant impact on the Company’s restated financial statements as the Company did not acquire an interest in joint operation during the year.

· IAS 16 Property, Plant and Equipment and IAS 38 Intangible Assets — Amendments to IAS 16 and IAS 38. The amendments clarify under IAS 16 that a revenue-based method should not be used to calculate the depreciation of items of property, plant and equipment and under IAS 38 that the amortization of intangible assets based on revenue is inappropriate. The adoption of these amended standards has no impact on the Company’s restated financial results as revenue-based amortization method is not allowed under the Company’s accounting policy.

· IFRS 10 Consolidated Financial Statements and IAS 28 Investments in Associates and Joint Ventures — Amendments to IFRS 10 and IAS 28. The amendments clarify that the accounting treatment for sales or contribution of assets between an investor and its associates or joint ventures depends on whether the non- monetary assets sold or contributed to an associate or joint venture constitute a business. The adoption of this amended standard did not have a significant impact on the Company’s restated financial statements.

· IFRS 7 Financial Instruments: Disclosures — Amendments to IFRS 7. The amendments clarify derecognition rules for service contracts associated with a transferred asset; and the applicability of the

amendments to IFRS 7 on offsetting disclosures to condensed interim financial statements. The adoption of this amended standard did not have a significant impact on the Company’s restated financial statements.

· IAS 19 Employee Benefits — Amendments to IAS 19. The amendment clarifies the proper currency denominations for post-employment benefit obligations. The adoption of this amended standard did not have a significant impact on the Company’s restated financial results.

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, 2017:

Effective January 1, 2017

· IAS 7 Statement of Cash Flows — Amendments to IAS 7. The amendments require entities to provide disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities, including non-cash changes and changes arising from cash flows. The Company believes the disclosure requirement has already been fulfilled through detailed disclosures in the Restated Consolidated Statements of Cash Flows and additional disclosures in the Long-Term Debt note.

· IAS 12 Income Taxes — Amendments to IAS 12. The amendments clarify the accounting for deferred tax assets for unrealized losses on debt instruments measured at fair value, and the application of some current IAS 12 principles on deferred tax assets recognition and the estimation of probable future taxable profit. The amendments are not expected to have an impact on the Company as there are no debt financial instruments which are measured at fair value and the deferred tax assets recognition principles are already adopted by the Company.

Effective January 1, 2018 and after

· 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. The Company continues to review the standard as it is updated and monitor its impact on the Consolidated Financial Statements. IFRS 9 will be effective for annual periods beginning on or after January 1, 2018. The Company does not expect the application of IFRS 9 will have significant impact on its 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, relevant disclosures. The standard supersedes IAS 18 Revenue, IAS 11 Construction Contracts, and a number of revenue-related interpretations. Early adoption of this standard is permitted. IFRS 15 will be effective for annual periods beginning on or after January 1, 2018. The Company will not be early adopting IFRS 15.

The Company has elected to adopt IFRS 15 using the modified retrospective approach. The Company does not expect the application of IFRS 15 will have significant impact on its 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 Restated Consolidated Financial Statements and the related notes.

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 2016, the Company also carried out drilling operations in 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.

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.

If legal restrictions are adopted in 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 the Company is 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 relatively low, they raise stakeholder and regulatory concerns. Due to seismic activity reported in the Fox Creek area of Alberta, the AER announced 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 regulatory 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, including 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.

In November 2016, the Alberta Provincial Government issued regulations regarding carbon emissions that include a carbon levy across all industry sectors. This levy is payable at the time when hydrocarbons are removed or purchased from a transmission pipeline. The regulations contain exemptions for upstream producers and processors of raw materials until 2023 with some exceptions. The Company has applied for and received exemption certificates where available. The Company’s preliminary estimate is that the amount of carbon levy payable where an exemption is not allowed is not significant. The Canadian Federal Government has also announced the possibility of a Federal carbon levy. The Company is currently assessing the implication of these changes and will continue to do so as the new Canadian legislative frameworks evolve.

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 Restated Consolidated Financial Statements in accordance with IFRS. Additional information regarding decommissioning liabilities is set forth in the notes to the annual Restated 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. Due to the economic climate, there is an additional risk that the Company may be asked to assume an active role in the decommissioning, remediation and reclamation of an asset if the operator goes bankrupt.

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.

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, 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 or security holders.

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.

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 RSRUK and the projects RSRUK 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”.

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”. 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.

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. The UK’s vote in favour of leaving the European Union creates uncertainties that affect the stock, commodities and foreign exchange markets which may affect the Company. The Climate Leadership Act recently proclaimed in Alberta institutes a carbon levy on consumers of carbon-emitting fuels throughout the fuel supply chain, with a number of exemptions provided. The impact of the levy to the Company has not yet been fully evaluated. See also “Risk Factors - Greenhouse Gas Emissions” for further information concerning the environmental impact of the Climate Leadership Act on the Company.

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.

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 various regulations, such as the Canadian Extractive Sector Transparency Measure Act. 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. 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.

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, availability of alternative fuel sources, technological advances affecting energy production and consumption, and weather conditions. Natural gas prices realized by the Company in North America are affected primarily by market supply and demand, weather conditions and prices of alternative sources of energy. The Company is also affected by markets outside of North America, primarily in Southeast Asia. Natural gas prices realized in these markets are largely determined by 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 has 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 would 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.

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 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 the inability to perform some business processes in a timely manner.

The increasing concern of cyber security threats across the industry, with the intention to disrupt business by attacks such as the use of Ransomware, phishing emails, and other more sophisticated attempts often referred to as advanced persistent threats, requires the Company to continually improve its ability to detect and prevent such occurrences. The Company actively monitors the security and resilience of its IT systems globally and works with private and government agencies, such as private cyber threat intelligence services, Canadian Cyber Incident Response Centre, and the Federal Bureau of Investigation, in order to be apprised of potential risks across the globe. 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.

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 under the heading “Legal Proceedings and Contingencies” in this MD&A.

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. 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. 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”.

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.

Exchange Rate Fluctuations

Results of operations are affected primarily by the exchange rates among 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 Restated 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.

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. Approximately 40% of the Company’s debt has a fixed interest rate while 60% is floating rate debt borrowed from related parties. Therefore, the Company’s main exposure to changes in interest rates would occur with respect to short-term borrowings.

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.

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 of the Company’s production. Another associated risk is 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.

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.

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 comply with the Code of Ethics and Business Conduct as well as other Company policies against giving or accepting money or gifts in certain circumstances. Despite these requirements, 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.

Forward-Looking Statements

This Restated MD&A contains or incorporates by reference 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 Restated MD&A, including among other places, under the headings “General Development of the Business,” “Description of the Business,” “Social and Environmental Policies,” “Legal Proceedings” and “Risk Factors”. This forward-looking information includes, but is not limited to, statements regarding:

· business strategy, priorities and plans;

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

· expected capital sources to fund the Company’s capital program;

· expected production and timing of such production;

· planned drilling and development;

· expected results from the Company’s portfolio of oil and gas assets;

· expected abandonment and reclamation timing and costs;

· anticipated funding of decommissioning liabilities;

· anticipated timing and results of legal proceedings;

· anticipated closing and timing of closing of planned dispositions; and

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

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

The factors or assumptions on which the forward-looking information is based include: commodity price and cost assumptions; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; the ability to obtain regulatory and partner approval; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 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 Restated 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;

· 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);

· uncertainties related to the UK’s vote in favour of leaving the European Union;

· risks related to cybersecurity;

· 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 under the heading “Risk Factors” and elsewhere in this Restated MD&A. 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 Restated MD&A reflects the Company’s internally-generated estimates of its reserves.

Gross Production

Throughout this Restated 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 Restated MD&A. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.

Financial Outlook

Included in this Restated 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 Restated MD&A:

AIF		Annual Information Form
bbl		barrel
bbls		barrels
bbls/d		barrels per day
btu		British thermal units
bcf		billion cubic feet
boe		barrels of oil equivalent
boe/d		barrels of oil equivalent per day
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
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
NYMEX		New York Mercantile Exchange
PP&E		Property, plant and equipment
PRT		Petroleum Revenue Tax
PSC		Production Sharing Contract
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 mean 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 mean 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 acre		= 0.40 hectares
1 barrel		= 0.159 cubic metres
1 cubic foot		= 0.0282 cubic metres

REPSOL OIL & GAS CANADA INC.

Suite 2000, 888 — 3rd Street SW

Calgary, Alberta, Canada T2P 5C5

P 403.237.1234 F 403.237.1902

E infocanada@repsol.com

www.repsol.com/ca_en/