Exhibit 99.5

RESTATED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2016 REPSOL OIL & GAS CANADA INC.

Report of Management

Management is responsible for the Restated Consolidated Financial Statements.

Management has prepared the Restated Consolidated Financial Statements in accordance with International Financial Reporting Standards. If alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has ensured that the Restated Consolidated Financial Statements are presented fairly in all material respects.

The Board of Directors is responsible for reviewing and approving the Restated Consolidated Financial Statements and Restated Management’s Discussion and Analysis and, primarily through its Audit Committee, ensures that management fulfils its responsibilities for financial reporting.

The Audit Committee is appointed by the Board of Directors and is composed entirely of unrelated, independent directors. The Audit Committee meets regularly with management, and with the internal and external auditors, to discuss internal controls and reporting issues and to satisfy itself that each party is properly discharging its responsibilities. It reviews the Restated Consolidated Financial Statements and the external auditors’ report. The Audit Committee also considers, for review by the Board of Directors and approval by the shareholder, the engagement or reappointment of the external auditors.

Ernst & Young LLP, the external auditors, have audited the Restated Consolidated Financial Statements in accordance with auditing standards generally accepted in Canada and the standards of the Public Company Accounting Oversight Board (United States) on behalf of the shareholder. Ernst & Young LLP have full and free access to the Audit Committee.

Management Report on Internal Control over Financial Reporting

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

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

The results of management’s original assessment of the Company’s internal control over financial reporting 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 internal control over financial reporting was effective. However, subsequent to 2016, management determined that a restatement of its previously issued financial statements is necessary, as described in note 2. As a result of the financial statement restatement, management has reassessed the effectiveness of the Company’s internal control over financial reporting and has concluded that a material weakness exists in its internal control over financial reporting as result of  a non-controlling interest transaction not accounted for correctly. The Company’s internal control over financial reporting was therefore not operating effectively as at December 31, 2016.

(signed) “Luis Cabra Dueñas”	(signed) “David Charlton”
Luis Cabra Dueñas	David Charlton
Vice-Chairman and Chief Executive Officer	Vice-President Finance, Treasurer and Chief Financial Officer

May 11, 2017

1

Independent Auditors’ Report of Registered Public Accounting Firm

To the Shareholder of Repsol Oil & Gas Canada Inc.

We have audited the accompanying Consolidated Financial Statements of Repsol Oil & Gas Canada Inc., which comprise the Consolidated Balance Sheets as at December 31, 2016 and 2015 and the Consolidated Statements of Loss, Comprehensive Loss, Changes in Shareholders’ Equity and Cash Flows for each of the years in the three-year period ended December 31, 2016 and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits.  We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.  We were not engaged to perform an audit of the Company’s internal control over financial reporting under Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements.  The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of Repsol Oil & Gas Canada Inc. as at December 31, 2016 and 2015 and its financial performance and its cash flows for each of the years in the three-year period ended December 31, 2016 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Restatement of Consolidated Financial Statements

Without modifying our opinion, we draw attention to Note 2 to the consolidated financial statements for the year ended December 31, 2016 which explains that the consolidated financial statements have been restated from those on which we originally reported on February 21, 2017.

(Signed) “Ernst & Young LLP”

Chartered Professional Accountants

Calgary, Canada

May 11, 2017

2

Repsol Oil & Gas Canada Inc.

Restated Consolidated Balance Sheets

December 31 (millions of US$)	2016	2015
	(Restated - note 2)
Assets
Current
Cash and cash equivalents (note 27)	52	98
Accounts receivable (note 10)	412	372
Income and other taxes receivable	31	67
Amount due from related party (note 17)	569	334
Inventories (note 11)	78	103
Prepaid expenses	17	25
	1,159	999
Other assets (note 12)	185	184
Investments (note 8)	353	392
Goodwill (note 9)	257	274
Property, plant and equipment (note 13)	6,933	7,289
Exploration and evaluation assets (note 13)	1,537	1,664
Long-term income tax receivable	19	—
Deferred tax assets (note 25)	1,315	1,219
	10,599	11,022
Total assets	11,758	12,021
Liabilities
Current
Bank indebtedness	5	7
Accounts payable and accrued liabilities	835	884
Obligation to fund equity investee (note 8)	143	571
Income and other taxes payable	79	65
Loans from joint ventures (note 8)	10	14
Current portion of long-term debt (note 17)	308	156
	1,380	1,697
Decommissioning liabilities (note 15)	1,050	755
Other long-term obligations (note 18)	291	233
Loans from related parties (note 17)	1,756	1,007
Obligation to fund equity investee (note 8)	485	56
Long-term debt (note 17)	1,085	2,111
Deferred tax liabilities (note 25)	372	613
	5,039	4,775
Contingencies and commitments (note 22)
Shareholder’s equity
Common shares (note 19)	3,501	3,492
Contributed surplus	86	86
Retained earnings	878	1,271
Accumulated other comprehensive income (note 20)	700	700
Total shareholder’s equity	5,165	5,549
Non-controlling interest (note 7)	174	—
	5,339	5,549
Total liabilities and shareholder’s equity	11,778	12,021

See accompanying notes.

On behalf of the Board

(signed) “Josu Jon Imaz San Miguel”	(signed) “Michael T. Waites”
Josu Jon Imaz San Miguel	Michael T. Waites
Chairman of the Board	Director

3

Repsol Oil & Gas Canada Inc.

Restated Consolidated Statements of Loss

Years ended December 31 (millions of US$)	2016		2015		2014
	(Restated - note 2)				(Restated - note 6)
Revenue
Sales	1,831		2,254		4,126
Other income (note 23)	150		317		158
Loss from joint ventures and associates, after tax (note 8)	(204	)	(1,086	)	(1,040	)
Total revenue and other income	1,777		1,485		3,244
Expenses
Operating	708		906		1,083
Transportation	158		182		177
General and administrative	244		298		396
Depreciation, depletion and amortization	1,214		1,534		1,634
Impairment, net of reversals (note 14)	(327	)	1,523		1,314
Dry hole	116		15		141
Exploration	105		175		195
Finance costs (note 16)	190		327		327
Share-based payments expense (recovery) (note 19)	—		(24	)	25
Gain on held-for-trading financial instruments (note 21)	—		(61	)	(1,427	)
(Gain) Loss on disposals (note 7)	(73	)	2		(550	)
Other, net (note 24)	79		266		48
Total expenses	2,414		5,143		3,363
Loss from continuing operations before taxes	(637	)	(3,658	)	(119	)
Income taxes (note 25)
Current income tax (recovery)	207		(177	)	429
Deferred income recovery	(332	)	(669	)	(207	)
	(125	)	(846	)	222
Net loss from continuing operations	(512	)	(2,812	)	(341	)
Discontinued operations
Net loss from discontinued operations (note 6)	—		(294	)	(570	)
Net loss	(512	)	(3,106	)	(911	)
Net loss attributable to:
Shareholder	(512	)	(3,106	)	(911	)
Non-controlling interest (note 7)	—		—		—
	(512	)	(3,106	)	(911	)
Per common share (US$):
Net loss from continuing operations	(0.28	)	(2.69	)	(0.34	)
Net loss from discontinued operations	—		(0.28	)	(0.55	)
Net loss	(0.28	)	(2.97	)	(0.89	)
Diluted net loss from continuing operations	(0.28	)	(2.73	)	(0.41	)
Diluted net loss from discontinued operations	—		(0.28	)	(0.55	)
Diluted net loss	(0.28	)	(3.01	)	(0.96	)
Weighted average number of common shares outstanding (millions)
Basic (note 28)	1,830		1,047		1,033
Diluted (note 28)	1,830		1,047		1,033

See accompanying notes.

4

Repsol Oil & Gas Canada Inc.

Restated Consolidated Statements of Comprehensive Loss

Years ended December 31 (millions of US$)	2016		2015		2014
	(Restated - note 2)
Net loss	512		(3,106	)	(911	)
Items to be reclassified to net income or loss in subsequent periods:
Foreign currency translation	—		3		—
Transfer of accumulated comprehensive income on disposition of foreign operations (note 6)	—		(114	)	—
Items not to be reclassified to net income or loss in subsequent periods:
Remeasurements relating to pension and other post-employment benefit plans1	(3	)	7		(8	)
Share of remeasurements relating to pension and other post-employment benefit plans from joint ventures2 (note 8)	(38	)	—		—
Other comprehensive loss	(41	)	(104	)	(8	)
Comprehensive loss	(553	)	(3,210	)	(919	)
Comprehensive loss attributable to:
Shareholder	(553	)	(3,210	)	(919	)
Non-controlling interest (note 7)	—		—		—
	(553	)	(3,210	)	(919	)

(1)  Net of tax of $nil (2015 - $2 million; 2014 - $13 million).

(2)  Net of tax of $nil (2015 - $nil; 2014 - $nil).

See accompanying notes.

5

Repsol Oil & Gas Canada Inc.

Restated Consolidated Statements of Changes in Shareholder’s Equity

Years ended December 31 (millions of US$)	2016		2015		2014
	(Restated - note 2)
Common shares (note 19)
Balance at beginning of year	3,492		1,738		1,723
Issued to parent	9		—		—
Issued on exercise of stock options	—		—		5
Issued as payment of loan from related parties (notes 17 and 19)	—		1,500		—
Converted from preferred shares	—		195		—
Shares purchased and held in trust for long-term PSU plan	—		(30	)	(21	)
Shares in trust sold on open market	—		3		—
Shares released from trust for long-term PSU plan	—		86		31
Balance at end of year	3,501		3,492		1,738
Preferred shares (note 19)
Balance at beginning of year	—		191		191
Converted to common shares	—		(191	)	—
Balance at end of year	—		—		191
Contributed surplus
Balance at beginning of year	86		176		135
Preferred shares conversion difference	—		(4	)	—
Settlement of long-term PSU plan grant (note 19)	—		(104	)	(31	)
Share-based payments (note 19)	—		18		72
Balance at end of year	86		86		176
Retained earnings
Balance at beginning of year	1,271		4,489		5,695
Net loss	(512	)	(3,106	)	(911	)
Gain on sale of investment to non-controlling interest (note 2)1	160		—		—
Remeasurements of employee benefit plans transferred to retained earnings	(3	)	7		(8	)
Share of remeasurements of employee benefit plans from joint ventures transferred to retained earnings	(38	)	—		—
Common share dividends (note 19)	—		(117	)	(279	)
Preferred share dividends (note 19)	—		(2	)	(8	)
Balance at end of year	878		1,271		4,489

(1)  Net of tax of $108 million.

Accumulated other comprehensive income (note 20)
Balance at beginning of year	700		811		811
Other comprehensive loss	(41	)	(104	)	(8	)
Remeasurements of employee benefit plans transferred to retained earnings	3		(7	)	8
Share of remeasurements of employee benefit plans from joint ventures transferred to retained earnings	38		—		—
Balance at end of year	700		700		811
Non-controlling interest
Balance at beginning of year	—		—		—
Non-controlling interest through disposal (note 7)	174		—		—
Income (loss) attributable to non-controlling interest	—		—		—
Balance at end of year	174		—		—

See accompanying notes.

6

Repsol Oil & Gas Canada Inc.

Restated Consolidated Statements of Cash Flows

Years ended December 31 (millions of US$)	2016		2015		2014
	(Restated - note 2)				(Restated - note 6)
Operating activities
Net loss from continuing operations	(512	)	(2,812	)	(341	)
Add: Finance costs (cash and non-cash) (note 16)	190		327		327
Dividends from joint ventures (note 8)	41		—		—
Items not involving cash (note 26)	753		4,638		2,046
	472		2,153		2,032
Changes in non-cash working capital (note 26)	(49	)	70		(252	)
Cash provided by operating activities from continuing operations	423		2,223		1,780
Investing activities
Capital expenditures
Exploration, development and other	(528	)	(1,059	)	(1,967	)
Property acquisitions and extension	(94	)	(31	)	(23	)
Proceeds of resource property dispositions (note 7)	325		396		1,517
Proceeds from sale of investment net of payments	(9	)	17		—
Investment in joint ventures (note 8)	(303	)	(553	)	(319	)
Loan to joint venture, net of repayments (note 8)	—		—		(337	)
Changes in non-cash working capital	(45	)	(259	)	93
Cash used in investing activities from continuing operations	(654	)	(1,489	)	(1,036	)
Financing activities
Long-term debt repaid (note 17)	(754	)	(3,085	)	(1,264	)
Long-term debt issued (note 17)	10		452		1,110
Loans from joint ventures, net of repayments (note 8)	70		92		6
Loans from related parties (note 17)	749		2,507		—
Amount due from related party (note 17)	267		(334	)	—
Common shares issued (note 19)	9		—		4
Common shares purchased (note 19)	—		(30	)	(21	)
Common shares held in trust sold (note 19)	—		3		—
Finance costs (note 16)	(150	)	(293	)	(301	)
Common share dividends	—		(117	)	(279	)
Preferred share dividends	—		(2	)	(8	)
Deferred credits and other	(16	)	(41	)	(16	)
Changes in non-cash working capital	2		(29	)	(3	)
Cash provided by (used in) financing activities from continuing operations	187		(877	)	(772	)
Effect of translation on foreign currency cash and cash equivalents	—		1		4
Cash provided by (used in) operating activities from discontinued operations (note 6)	—		(29	)	119
Cash provided by (used in) investing activities from discontinued operations (note 6)	—		9		(193	)
Net decrease in cash and cash equivalents	(44	)	(162	)	(98	)
Cash and cash equivalents net of bank indebtedness, beginning of year	91		253		351
Cash and cash equivalents net of bank indebtedness, end of year	47		91		253
Cash and cash equivalents	52		98		262
Bank indebtedness	(5	)	(7	)	(9	)
Cash and cash equivalents net of bank indebtedness, end of year	47		91		253

See accompanying notes.

7

Repsol Oil & Gas Canada Inc.

Restated Notes to the 2016 Consolidated Financial Statements

(tabular amounts in millions of US dollars, except as noted)

1. GENERAL INFORMATION

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 (“ROGCI” or “the Company”).

ROGCI is a company incorporated under the Canada Business Corporations Act and domiciled in Alberta, Canada. The Company’s common shares are wholly owned by a subsidiary of its ultimate parent Repsol S.A (“Repsol”). Its registered office is located at Suite 2000, 888 – 3rdStreet SW, Calgary, Alberta, Canada, T2P 5C5.

The Company is in the business of exploration, development, production, transportation, and marketing of crude oil, natural gas and natural gas liquids (NGLs).

The Restated Consolidated Financial Statements as at and for the year ended December 31, 2016 were authorized for issuance by the Board of Directors on May 11, 2017.

Repsol Acquisition of Talisman

On December 15, 2014, the Company entered into an arrangement agreement with Repsol and an indirectly wholly owned subsidiary of Repsol, providing for Repsol’s acquisition of the Company by a way of arrangement under the Canada Business Corporations Act (the “Repsol Transaction”).

On May 8, 2015, the Repsol Transaction was completed. Repsol acquired all of the Company’s outstanding common and preferred shares. Upon the completion of the arrangement, 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.

2. RESTATEMENT OF THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2016

ROGCI 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). 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 Financial Statements, as presented in the following reconciliations:

8

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		5,165
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	)

Reconciliation of Consolidated Statement of Comprehensive Loss for the Year ended

Year ended December 31, 2016 (millions of $)	December 31, 2016 Previously Reported		Adjustments	December 31, 2016 Restated
Net loss	(740	)	228	(512	)
Items not to be reclassified to net income or loss in subsequent periods:
Remeasurements relating to pension and other post-employment benefit plans1	(3	)	—	(3	)
Share of remeasurements relating to pension and other post-employment benefit plans from joint ventures2	(38	)	—	(38	)
Other comprehensive loss	(41	)	—	(41	)
Comprehensive loss	(781	)	228	(553	)
Comprehensive loss attributable to:
Shareholder	(781	)	228	(553	)
Non-controlling interest	—		—	—
	(781	)	228	(553	)

(1)     Net of tax of $nil (2015 - $2 million; 2014 - $13 million).

(2)     Net of tax of $nil (2015 - $nil; 2014 - $nil).

9

Reconciliation of Consolidated Statement of Changes in Shareholder’s Equity for the Year ended

Years ended December 31 (millions of US$)	December 31, 2016 Previously Reported		Adjustments	December 31, 2016 Restated
Common shares
Balance at end of year	3,501		—	3,501
Contributed surplus
Balance at end of year	86		—	86
Retained earnings
Balance at beginning of year	1,271		—	1,271
Net loss	(740	)	228	(512	)
Gain on sale of investment to non-controlling interest1	—		160	160
Remeasurements of employee benefit plans transferred to retained earnings	(3	)	—	(3	)
Share of remeasurements of employee benefit plans from joint ventures transferred to retained earnings	(38	)	—	(38	)
Balance at end of year	490		388	878

(1)  Net of tax of $108 million.

Accumulated other comprehensive income
Balance at end of year	700	—		700
Non-controlling interest
Balance at beginning of year	—	—		—
Non-controlling interest through disposal	442	(268	)	174
Balance at end of year	442	(268	)	174

Reconciliation of Consolidated Statement of Cash Flows for the Year ended

Years ended December 31 (millions of US$)	December 31, 2016 Previously Reported		Adjustments		December 31, 2016 Restated
Operating activities
Net loss	(740	)	228		(512	)
Add: Finance costs (cash and non-cash)	190		—		190
Dividends from joint ventures	41		—		41
Items not involving cash	981		(228	)	753
	472		—		472
Changes in non-cash working capital	(49	)	—		(49	)
Cash provided by operating activities from continuing operations	423		—		423
Investing activities
Cash used in investing activities	(654	)	—		(654	)
Financing activities
Cash provided by financing activities	187		—		187
Net decrease in cash and cash equivalents	(44	)	—		(44	)
Cash and cash equivalents net of bank indebtedness, beginning of year	91		—		91
Cash and cash equivalents net of bank indebtedness, end of year	47		—		47

3. BASIS OF PREPARATION

The Restated Consolidated Financial Statements of ROGCI and its subsidiaries have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC).

The Restated Consolidated Financial Statements have been prepared on a going concern basis using the historical cost convention, except for available-for-sale financial assets that have been measured at fair value.

The Restated Consolidated Financial Statements are prepared in United States dollars (US$), which is the Company’s functional currency.

The preparation of the Restated Consolidated Financial Statements in accordance with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise judgment in applying the Company’s accounting policies. The areas of accounting that require a high degree of judgment or which are based upon significant estimates are disclosed in note 5.

10

Comparative period balances of the Consolidated Statements of Loss and Cash Flows have been restated as a result of the sale of substantially all assets and liabilities of the Norwegian operations on September 1, 2015.

Certain prior period amounts have been reclassified to conform to the current presentation.

4. SIGNIFICANT ACCOUNTING POLICIES

a) 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 did not have an 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.

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b) Consolidation

The Restated Consolidated Financial Statements include the accounts of the Company and its subsidiaries, being those investees over which the Company, either directly or indirectly, has control. Control is achieved when the Company is exposed, or has the rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Specifically, the Company controls an investee if, and only if, the Company has:

·Power over the investee, through existing rights that give the Company the current ability to direct the relevant activities;

·      Exposure, or rights to variable returns from its involvement with the investee; and

·      The ability to use its power over the investee to affect its returns.

Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases, using consistent accounting policies. For non-wholly owned subsidiaries, interests held by external parties that the Company consolidates are shown as non-controlling interest. All intercompany balances and transactions, including unrealized profits arising from such transactions, are eliminated upon consolidation. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

c) Joint Arrangements and Investments

A joint arrangement represents an arrangement where two or more parties hold joint control. Joint control is deemed to exist under contractual agreement where decisions regarding relevant activities of the arrangement require the unanimous consent of those parties sharing control.

A joint venture is a joint arrangement and represents a company or other entity in which each venturer has an interest, holds joint control and holds rights to the net assets of the entity. Interests in joint ventures are accounted for using the equity method of accounting.

A joint operation is a joint arrangement and represents a company, partnership or other entity in which each venturer has an interest, holds joint control and holds rights to the assets and obligations for the liabilities of the entity. Interests in joint operations are accounted for by recognizing the Company’s share of the assets, liabilities, revenue and expenses.

An associate is an entity, including an unincorporated entity such as a partnership, over which the Company has significant influence and that is neither a subsidiary nor an interest in a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.

Investments in associates and joint ventures are accounted for using the equity method. Investments of this nature are recorded at original cost and adjusted periodically. The Company’s share of the income of equity investments is recorded in the Restated Consolidated Statements of Loss. Dividends from equity investments are included in cash provided by operating activities. Interests in entities over which the Company does not have significant influence are accounted for as available-for-sale financial assets. Both equity investments and investments classified as available- for-sale assets are tested for possible impairment whenever events or changes in circumstances indicate that the

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carrying value of the investment may not be recoverable. If, and when, an equity accounted investment balance becomes negative by the application of equity method accounting, the Company assesses whether the Company has an obligation to fund the operations of the equity investment. If so, the Company presents the amount as an obligation to fund equity investee.

d) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method when control is transferred to the Company. The cost of an acquisition is the aggregate of the consideration transferred, measured at acquisition date fair value. Acquisition costs incurred are expensed. When the Company acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts acquired.

Contingent consideration to be transferred by the Company is recognized at fair value at the acquisition date. Subsequent changes to the fair value of contingent consideration recorded as a financial asset or liability are recognized in net income in accordance with IAS 39 Financial Instruments: Recognition and Measurement.

Goodwill represents the excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed in business combinations. Goodwill is not amortized but is subject to impairment reviews annually, or more frequently as economic events dictate, as described in note 4(j).

Where goodwill forms part of an operating segment and part of the operation within that segment is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the segment retained.

e) Accounts Receivable

Accounts receivable are recorded based on the Company’s revenue recognition policy. The allowance for doubtful accounts is management’s best estimate of accounts receivable balances that may not be collectible, and is reviewed monthly.

f) Inventories

Inventories are valued at the lower of cost and net realizable value. Cost comprises direct purchase costs, cost of production and taxes, and is determined using the first-in first-out method for product inventories and by the average cost method for materials and supplies. Net realizable value is determined by reference to prices existing at the balance sheet date less any costs expected to be incurred to completion and disposal.

g) Property, Plant and Equipment (PP&E)

PP&E, comprising oil and gas development and production properties and corporate assets, is stated at cost less accumulated depreciation, depletion and amortization and accumulated impairment losses.

Oil and gas development and production expenditure is generally accounted for using the principles of the successful efforts method of accounting. Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells is capitalized within PP&E.

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The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning liability and capitalized borrowing costs for qualifying assets. The capitalized value of a finance lease is also included within PP&E.

Expenditure on turnarounds comprises the cost of replacement assets or parts of assets and inspection and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits will flow to the Company from the replacement, the expenditure is capitalized and the replaced part is derecognized. Inspection and overhaul costs relating to turnarounds, which generally occur annually, and all other repairs and maintenance costs are expensed when incurred.

Well injection costs incurred to stimulate depleted wells are charged as an expense when incurred. Certain stimulation costs which increase production and reserves, extending beyond one year, are deferred in PP&E and depleted using the unit of production method.

Exchanges of development and production assets are measured at fair value unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset exchanged is reliably measurable. The cost of the acquired asset is measured at the fair value of the asset exchanged, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset exchanged. Any gain or loss arising is recognized in net income.

The Company assesses at each reporting date whether there is an indication that its PP&E may be impaired or subject to impairment reversals. If any indication exists, the Company estimates the asset’s recoverable amount using the methodology described in note 4(i).

h) 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, and that the carrying amount is likely to be recovered in full from successful development or sale. When this is no longer the case, the costs are written off to their estimated recoverable amount. 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 (see note 4(i) for details of the impairment methodology). 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.

All other exploration costs, including geological and geophysical costs and annual lease rentals, are charged to exploration expense when incurred.

For exchanges or parts of exchanges that involve principally E&E assets, the exchange is generally accounted for at the carrying amount of the asset exchanged.

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i) 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 amount 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”). 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 on a systematic basis over its remaining useful life.

j) Goodwill

Goodwill is tested for impairment annually and when circumstances indicate that the carrying amount 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 described in note 31, except for locations within the Other segment, which are generally grouped by country. Impairment is determined for goodwill by assessing the recoverable amount (based on value in use) of each segment or country, as appropriate, to which the goodwill relates.  Where the recoverable amount of the segment or country, as appropriate, is less than the carrying amount, an impairment loss is recognized. Goodwill impairment losses cannot be reversed.

k) Depreciation, Depletion and Amortization (DD&A)

Capitalized costs of proved oil and gas properties are depleted using the unit of production method. For purposes of these calculations, production and reserves of natural gas are converted to barrels (bbls) on an energy equivalent basis at a ratio of approximately five thousand six hundred fifteen cubic feet (mcf) of natural gas for one barrel (bbl) of oil. Depletion and depreciation rates are updated in each reporting period that a significant change in circumstances, including reserves revisions, occurs.

Successful exploratory wells and development costs are depleted over proved developed reserves. Significant development costs incurred in connection with proved undeveloped reserves are excluded from depletion until the reserves are developed.

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Acquired resource properties with proved reserves, including offshore platform costs, are depleted over total proved reserves. Acquisition costs of probable reserves are not depleted or amortized while under active evaluation for commercial reserves. Costs are transferred to depletable costs as proved reserves are recognized.

Costs associated with significant development projects are not depleted until the asset is substantially complete and ready for its intended use. Unproved land acquisition costs that are individually material are not amortized, but are assessed for impairment and transferred to depletable costs as proved reserves are recognized. Unproved land acquisition costs that are individually immaterial are amortized on a straight-line basis over the average lease term. Gas plants are depreciated on a straight-line basis over their estimated remaining useful lives, not to exceed the estimated remaining productive lives of related fields. Pipelines and corporate assets are depreciated using the straight-line method at annual rates of 4% and 5-33%, respectively.

The transportation rights owned with respect to the Ocensa pipeline are recorded in other assets (note 12), and are being depreciated using the straight-line method at an annual rate of 8%.

l) Non-Current Assets Held for Sale and Discontinued Operations

Non-current assets classified as held for sale and associated liabilities are measured at the lower of carrying amount and fair value less costs to sell, and are presented as current on the Restated Consolidated Balance Sheets.

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

Non-current assets and disposal groups are classified and presented as discontinued operations if the assets or disposal groups are disposed of or classified as held for sale and the assets and disposal groups are:

·      A major line of business or geographical area of operations;

·A part of a single coordinated plan of dispose of a separate major line of business or geographical area of operations; or

·      A subsidiary acquired solely for the purpose of resale.

The assets or disposal groups that meet these criteria are measured at the lower of the carrying amount and fair value less costs of disposal, with impairments recognized in the Restated Consolidated Statement of Comprehensive Loss. Non- current assets held for sale are presented in current assets and liabilities within the Restated Consolidated Balance Sheets. Assets held for sale are not depreciated, depleted or amortized. Comparative period of the Restated Consolidated Balance Sheets are not restated.

m) Decommissioning and Environmental Liabilities

Decommissioning liabilities are recognized when the Company has a legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate of the amount of the obligation can be made. A corresponding amount equivalent to the liability is recognized as part of the cost of the related PP&E or E&E asset.

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Decommissioning liabilities are carried on the Restated Consolidated Balance Sheets at their discounted present value. The liabilities are calculated using a weighted average credit-adjusted nominal rate, and are accreted over time for the change in their present value, with this accretion expense included in finance costs on the Restated Consolidated Statements of Loss. Actual expenditures incurred are charged against the accumulated obligation. Any difference between the recorded decommissioning liability and the actual retirement costs incurred is recorded as a gain or loss.

The increase in capitalized costs is amortized to income on a basis consistent with DD&A of the underlying assets. Subsequent changes in the estimated decommissioning liabilities are capitalized and amortized over the remaining useful life of the underlying asset.

Liabilities for environmental costs are recognized when an obligation exists and the associated costs can be reliably estimated. Generally, the timing of recognition of these liabilities coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. These estimates are included in decommissioning liabilities.

n) Finance Costs and Long-Term Debt

Finance costs include interest and other costs that the Company incurs in connection with the borrowing of funds, as well as accretion expense relating to the Company’s decommissioning liabilities.

Finance costs associated with major development projects are capitalized and included in the carrying amounts of the related assets until they are completed and ready for use. These costs are subsequently amortized to income with the related assets. The amount of borrowing costs capitalized for the period is determined by applying the weighted average interest rate applicable to appropriate borrowings outstanding during the period to the average amount of capitalized expenditure for the qualifying assets.

All other finance costs are recognized on the Restated Consolidated Statements of Loss in the period in which they are incurred.

o) Foreign and Reporting Currency

The functional currency of all of the Company’s operations is the US$.

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.

p) Employee Benefit Plans

The cost of providing benefits under the Company’s defined benefit pension plans and non-pension post- employment benefit plans is determined using the projected benefit method pro-rated on service and management’s best estimate of expected plan investment performance, pensionable earnings escalation, inflation and mortality rates. There is uncertainty relating to the assumptions used to calculate the net benefit expense and accrued benefit obligation, due to their long-term nature.

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The discount rate used to determine the accrued benefit obligation is determined by reference to market interest rates at the measurement date on high quality debt instruments with cash flows that match the timing and amount of expected benefit payments. The effects of changes in demographic and financial assumptions, experience adjustments, as well as other plan remeasurements such as the return on plan assets are recognized in other comprehensive loss and transferred to retained earnings in the year recorded.

Payments to defined contribution plans are expensed as incurred, which is as the related service is rendered.

The pension benefits of key management personnel represent the attributable amount of the net benefit expense of the plans in which they participate.

q) Financial Instruments

The Company classifies its financial instruments into one of the following categories: held-for-trading assets and liabilities, assets available-for-sale, loans and receivables, assets held-to-maturity and other financial liabilities. All financial assets and liabilities are recognized on the Restated Consolidated Balance Sheets when the Company becomes a party to the contractual requirements of the instrument. All financial instruments are measured at fair value on initial recognition. Transaction costs are included in the initial carrying amount of financial instruments except for held-for-trading items, in which case they are expensed as incurred. Measurement in subsequent periods depends on the classification of the financial instrument.

In conducting its business, the Company may use derivative financial instruments in order to manage risks associated with fluctuations in commodity prices, interest rates and foreign currency exchange rates.

Non-Hedge Financial Instruments

Held-for-trading financial assets and liabilities are subsequently measured at fair value, with changes in fair value recognized in net income. Financial assets available-for-sale are subsequently measured at fair value, with changes in fair value recognized in other comprehensive loss, net of tax. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are subsequently measured at amortized cost using the effective interest rate method.

Cash equivalents are classified as loans and receivables and are measured at carrying value, which approximates fair value, due to the short-term nature of these instruments. Accounts receivable and certain other assets that are financial instruments are classified as loans and receivables. Bank indebtedness, accounts payable and accrued liabilities, certain other long-term obligations and current and long-term debt are classified as other financial liabilities. Financial liabilities are derecognized when the obligation under the liability is discharged, cancelled or expires. Financial instruments that are derivative contracts are considered held-for-trading.

Derivatives embedded in other financial instruments and non-financial host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contract. Contracts are assessed for embedded derivatives when the Company becomes a party to them, including at the date of a business combination. Embedded derivatives requiring separation are measured at fair value at each balance sheet date and any gains or losses arising from changes in fair value are recognized in net income.

Own Use Exemption

Contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Company’s expected purchase, sale or usage requirements fall within the exemption from

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IAS 32 and IAS 39, which is known as the “own use” exemption. The Company enters into physical commodity contracts in the normal course of business, including contracts with fixed terms. The Company’s production is expected to be sufficient to deliver all required volumes under these contracts. No amounts are recognized in the Restated Consolidated Financial Statements related to these contracts until such time as the associated volumes are delivered.

r) Income Taxes

Income taxes comprise current tax, deferred tax and Petroleum Revenue Tax (PRT) and are recognized on the Restated Consolidated Statement of Loss except to the extent they relate to items recognized in other comprehensive income (loss) or directly in equity. PRT is treated as an income tax and deferred PRT is accounted for on a temporary difference basis.

Interest and penalties assessed by taxing authorities on any underpayment of income tax are accrued and classified as a component of income taxes on the Restated Consolidated Statement of Loss.

Certain of the Company’s contractual arrangements in foreign jurisdictions stipulate that income taxes be paid by the respective national oil company out of its entitlement share of production. Such amounts are included in income taxes at the statutory tax rate in effect at the time of production.

The Company recognizes in its 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.

Current Tax

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

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.

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.

s) Revenue Recognition

Revenues associated with the sale of crude oil, natural gas and NGLs are recognized at the fair value of the consideration received or receivable when the significant risks and rewards of ownership have been transferred, which is when title passes from the Company to the customer. For the Company’s international operations, generally, customers take title when the crude oil is loaded onto a tanker. The Company employs the entitlement method in accounting for crude oil and natural gas sales and records a receivable from a joint interest participant if a participant sells more than its proportionate share of crude oil or natural gas production. Crude oil and natural gas produced and sold, below or above the Company’s working interest share in the related resource properties, results

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in production underliftings, or overliftings. Underliftings are recorded as inventory at the cost to produce and transport the product to storage tanks, and overliftings are recorded in accounts payable and accrued at the sales value. Underliftings are reversed from inventory when the crude oil is lifted and sold, with the sales proceeds recorded as revenue and the cost of the inventory expensed. Overliftings are reversed from accounts payable when sufficient volumes are produced to make up the overlifted volume. Amounts received under take-or-pay gas sales contracts in respect of undelivered volumes are accounted for as deferred income in deferred credits and recognized as revenue when volumes are delivered. Transportation expenses are reported as a separate expense and are not netted against revenue.

A significant portion of the Company’s operations outside North America and the North Sea are governed by Production Sharing Contracts (“PSCs”). Under PSCs, revenues are derived from cost recovery oil and gas and profit oil and gas. Generally, cost recovery oil and gas allows the Company to recover its capital and production costs and, as appropriate, the costs carried by the Company on behalf of state oil companies from production. Profit oil and gas is allocated to the host government and contract parties in accordance with their respective equity interests.

All taxes collected from customers that are remitted to governments are excluded from revenues.

Certain of the Company’s foreign operations are conducted jointly with the respective national oil companies. These operations are reflected in the Restated Consolidated Financial Statements based on the Company’s working interest in such activities. All other government takes, other than income taxes, are considered to be royalty interests. Royalties on production from these joint foreign operations represent the entitlement of the respective governments to a portion of the Company’s share of crude oil, natural gas and NGLs production and are recorded using rates in effect under the terms of contracts at the time of production.

Sales as reported represent the Company’s share of revenues from the sale of crude oil, natural gas and NGLs and is presented after deduction of royalty payments to governments and other mineral interest owners.

t) Leases

Leases that transfer substantially all of the benefits and risks of ownership to the Company are accounted for at the commencement of the lease term as finance leases and recorded as PP&E at the fair value of the leased asset, or, if lower, at the present value of the minimum lease payments, together with an offsetting liability. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and are recognized in net income. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.

All other leases are accounted for as operating leases and the lease costs are expensed as incurred.

u) Net Income and Diluted Net Income Per Share

Net income per share is calculated by dividing net income less after-tax cumulative preferred share dividends by the weighted average number of common shares outstanding. Diluted net income per share is calculated giving effect to the potential dilution that could occur if stock options were exercised in exchange for common shares.

v) Cash and Cash Equivalents

Cash and cash equivalents include cash on deposit with banks and interest-bearing short-term investments with an original maturity of three months or less. Cash and cash equivalents are stated at cost, which approximates fair value.

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For the purpose of the Restated Consolidated Statements of Cash Flows, cash and cash equivalents consist of cash and cash equivalents as defined above, net of bank indebtedness.

w) Segmented Information

The Company’s reporting segments are established on the basis of having similar economic characteristics and/or which are in similar geographic locations and those components of the Company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance.

x) Accounting Standards Issued but Not Yet Effective

At the date of issuance of these Restated Consolidated Financial Statements, the standards that have been issued by the IASB but not yet been adopted by the Company are as follows.  The Company is currently assessing the impact their application may have on the Restated Consolidated Financial Statements:

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 a 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 a significant impact on its financial statements.

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·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.

5. SIGNIFICANT ACCOUNTING JUDGMENTS AND ESTIMATES

The preparation of the Restated Consolidated Financial Statements in accordance with IFRS makes it necessary to make assumptions and estimates that affect the valuation of the amounts of assets and liabilities recognized, the income and expenses reported during the year and the presentation of contingent assets and liabilities. Actual results may differ from estimated amounts.

Oil and gas reserves and contingent resources

Underpinning the Company’s estimates and judgments regarding oil and gas assets and goodwill are its oil and gas reserves and resources. The process of estimating oil and gas reserves and resources 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. 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.

Although not separately reported on the Company’s Restated Consolidated Balance Sheets or Restated Consolidated Statements of Loss, the Company’s reserves and revisions to those reserves impact the Company’s reported assets, liabilities and net income through their impact on DD&A, the fair value and/or the value in use of PP&E and E&E assets, goodwill, investment in equity accounted entities, amounts recognized for impairment charges and reversals and the recognition of assets acquired and liabilities assumed upon a business combination.  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

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Financial Statements of future periods could be material. The measurement of impairment charges and reversals is also dependent upon management’s judgment in determining CGUs (see note (4(i)).

Decommissioning liabilities

Inherent in the calculation of decommissioning liabilities are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, foreign exchange rates, and changes in the legal, regulatory, environmental and political environments. 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.  To the extent future revisions to assumptions impact the amount of decommissioning liabilities, a corresponding adjustment is made to the PP&E and/or E&E assets balance.

Pension plans

The values of pension assets and obligations and the amount of the net benefit expense charged to net income depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty.

Income taxes

The measurement of income tax expense, the related provisions and deferred tax assets on the Restated Consolidated Balance Sheets is subject to uncertainty associated with future recoverability of oil and natural gas reserves and contingent resources, commodity prices, the timing of future events and changes in legislation, tax rates and interpretations by tax authorities.

Functional currency

The designation of the Company’s functional currency is a management judgment based on the composition of revenue and costs in the locations in which it operates.

Provisions and contingent liabilities

Provisions are recorded when the Company has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, future cash flow estimates are adjusted to reflect risks specific to the liability.

Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the Company. Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote. The evaluation of the likelihood of the contingent events requires management judgment as to the probability of exposure to potential loss.

Investments

Once the Company’s interest in an equity investee is reduced to zero, additional losses are provided for and an obligation to fund equity investee is recognized, to the extent that the Company has incurred legal or constructive obligations.

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6. DISCONTINUED OPERATIONS

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

Operating results related to the Disposal Group have been included in net loss from discontinued operations in the Restated Consolidated Statements of Loss for the period of ownership. Comparative period balances of the Restated Consolidated Statements of Loss and Cash Flows have been restated.

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

Years ended December 31,	2015		2014
Revenue	182		529
Expenses1	(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	)

(1)Includes $129 million E&E impairment expense and $24 million PP&E impairment expense for the year 2015 and $288 million E&E impairment expense for the year 2014.

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

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

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7. 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.

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

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

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

Southeast Asia

In December 2016, the Company sold all of its common shares in Talisman Wiriagar Overseas Limited (“TWOL”) for total 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.

In 2014, the Company completed the sale of its 7.48% interest in the Southeast Sumatra PSC in Indonesia for proceeds of $34 million, net of withholding tax, resulting in a pre-tax loss on disposal of $3 million ($nil after-tax).

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8. INVESTMENTS

December 31,	2016	2015
Investments in Joint Ventures
Equity investment in Equion Energía Limited (“Equion”)	233	318
Available-for-sale investment
Transasia Pipeline Company Pvt. Ltd. (“Transasia”)	34	34
Oleoducto de Colombia, S.A. (“ODC”)	41	—
Other	45	40
	120	74
Total	353	392

December 31,	2016		2015
Obligation to Fund Equity Investee1
Equity investment in Repsol Sinopec Resources United Kingdom (“RSRUK”)2	(628	)	(627	)

(1)The Company’s planned equity funding for 2017 is $143 million net. The remaining $485 million is classified as a long-term obligation.

(2)Formerly Talisman Sinopec Energy (UK) Limited (“TSEUK”).

Investments in Joint Ventures

Equion Joint Venture

The Company has a 49% interest in the ownership and voting rights of Equion whose principal place of operations is Colombia. The Company is one of two shareholders in this corporate joint venture engaged in the exploration for, and development and production of crude oil and natural gas. The corporate joint venture is governed by a heads of agreement amongst the shareholders, which requires that unanimous consent be obtained from the shareholders for all significant operating and financing decisions.

Movement in the investment in Equion joint venture during the year is as follows:

Years ended December 31,	2016		2015
Balance, beginning of year	318		523
Share of comprehensive income (loss)	62		(65	)
Dividends declared by Equion	(156	)	(93	)
Impairment (expense) reversals (note 14)	9		(47	)
Balance, end of year	233		318

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).

The ODC investment was recorded at its fair value of $41 million, using Level 3 inputs, as described in note 21. The fair value of the ODC investment, which is based on the discounted cash flow approach and is modelled through a third party independent evaluator using observable inputs and unobservable inputs such as expected pipeline utilization, tariff rates, operating costs and discount rate. The pro forma impact of varying any of these inputs by 10% individually and in the aggregate, is not material to the fair value of the ODC investment, nor the financial results of the Equion joint venture for the year ended December 31, 2016.

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The loan due to Equion of $10 million (December 31, 2015 - $14 million) is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.

RSRUK Joint Venture

The Company has a 51% interest in the ownership and voting rights of RSRUK (formerly Talisman Sinopec Energy UK Limited) whose principal place of operations is the United Kingdom (UK) and is incorporated in England and Wales. The Company is one of two shareholders in this corporate joint venture, the other being Addax Petroleum UK Limited (Addax), a subsidiary of China Petrochemical Corporation.  The joint venture is engaged in the exploration for and development and production of crude oil and natural gas. The corporate joint venture is governed by a shareholders’ agreement, which requires that unanimous consent be obtained from the shareholders for all significant operating and financing decisions.

Movement in the investment in the RSRUK joint venture during the year is as follows:

Years ended December 31,	2016		2015
Balance, beginning of year	(627	)	(186	)
Investment in RSRUK	303		1,094
Loan to RSRUK, net of repayments and settlements	—		(514	)
Share of comprehensive loss	(304	)	(1,021	)
Balance, end of year	(628	)	(627	)

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. The 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. In addition, future contributions to the RSRUK joint venture could be impaired to the extent recoverability is not probable.

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 (2015 - $375 million), of which the Company’s share was $303 million (2015 - $191 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. Any loans under this facility bear interest at the UK interest rate swap rate plus 2.5%, and are repayable quarterly in equal installments based upon a five year repayment period calculated

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from the date each loan is advanced. Any outstanding loans will mature December 31, 2017, although the maturity date may be extended from time to time upon agreement between the shareholders and RSRUK.  Prior to the maturity date, RSRUK may repay, in full or in part, the balance outstanding on any loan under this facility. Remaining borrowing capacity under this facility1:

Years ended December 31,	2016	2015
Borrowing capacity, beginning of year	742	742
Advances	—	—
Borrowing capacity, end of year	742	742
ROGCI’s share	378	378

(1)Due to the non-revolving nature of the facility, the borrowing capacity decreases when the funds are drawn and does not increase for any repayments.

RSRUK is required to provide demand letters of credit as security in relation to certain decommissioning obligations in the UK pursuant to contractual arrangements under Decommissioning Security Agreements (DSAs). Refer to “Liquidity Risk” in note 21.

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 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.

Summarized Financial Information of Joint Ventures

The summarized financial information presented below represents the amounts included in the financial statements of the joint venture entities adjusted for fair value adjustments made at the time of acquisition, as appropriate, reconciled to the carrying amount of the Company’s interests in joint ventures, which are accounted for using the equity method. The fair value adjustments related to the Company’s jointly controlled equity interest in Equion principally relate to property, plant and equipment, provisions and the related indemnification asset, goodwill, and asset impairments. In addition, the financial statements of RSRUK have been adjusted with respect to asset impairments and depletion, depreciation and amortization.

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Summarized Balance Sheets

	2016						2015
December 31,	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Cash and cash equivalents	5		100		105		20		108		128
Current assets	298		104		402		275		140		415
Loans receivable from shareholders	—		20		20		—		29		29
Non-current assets	3,811		550		4,361		3,957		836		4,793
Total assets	4,114		774		4,888		4,252		1,113		5,365
Current liabilities	619		134		753		655		184		839
Decommissioning liabilities	4,804		10		4,814		4,952		19		4,971
Other non-current liabilities	74		137		211		26		224		250
Total liabilities	5,497		281		5,778		5,633		427		6,060
Net assets (liabilities)	(1,383	)	493		(890	)	(1,381	)	686		(695	)
ROGCI’s interest	51	%	49	%			51	%	49	%
ROGCI’s share of net assets (liabilities)	(705	)	242		(463	)	(704	)	336		(368	)
Goodwill	77		162		239		77		162		239
	(628	)	404		(224	)	(627	)	498		(129	)
Accumulated impairment	—		(171	)	(171	)	—		(180	)	(180	)
ROGCI’s investment (obligation to fund)	(628	)	233		(395	)	(627	)	318		(309	)

(1)Balances represent respective entity’s 100% share.

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Summarized Statements of Income (Loss)

	2016						2015
Years ended December 31,	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Revenue	848		379		1,227		791		480		1,271
Operating expenses	742		53		795		937		74		1,011
Transportation	26		37		63		17		41		58
General and administrative	(9	)	—		(9	)	49		—		49
Restructuring costs	—		—		—		5		—		5
Depreciation, depletion and amortization	238		229		467		450		324		774
Exploration expense	6		—		6		5		—		5
Finance costs	229		2		231		189		2		191
Impairment, net of reversals	(47	)	47		—		687		150		837
Gain on revaluation of investment	—		(66	)	(66	)	—		—		—
Other	25		15		40		211		50		261
Income (loss) before tax	(362	)	62		(300	)	(1,759	)	(161	)	(1,920	)
Current income tax expense (recovery)	(113	)	27		(86	)	(97	)	48		(49	)
Deferred income tax expense (recovery)	272		(91	)	181		340		(76	)	264
Net income (loss)	(521	)	126		(395	)	(2,002	)	(133	)	(2,135	)
Other comprehensive loss	(75	)	—		(75	)	—		—		—
ROGCI’s interest	51	%	49	%			51	%	49	%
ROGCI’s share of income (loss)	(266	)	62		(204	)	(1,021	)	(65	)	(1,086	)
ROGCI’s share of other comprehensive loss	(38	)	—		(38	)	—		—		—
ROGCI’s share of comprehensive income (loss)	(304	)	62		(242	)	(1,021	)	(65	)	(1,086	)

(1)Balances represent respective entity’s 100% share.

Commitments of Joint Ventures

The following table summarizes the Company’s share of RSRUK and Equion commitments as at December 31, 20161,2:

	2017	2018	2019	2020	2021	Subsequent to 2021	Total
Purchase commitments	19	13	12	13	12	—	69
Investment commitments4	17	—	—	—	—	—	17
Service commitments	24	19	17	1	1	7	69
Transportation commmitments3	12	5	2	—	—	—	19
Operating leases	2	2	1	1	1	5	12
	74	39	32	15	14	12	186

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

(4)Investment commitments include drilling rig commitments and minimum work commitments.

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The following table provides a summary of the estimated settlement timing of the Company’s share of RSRUK and Equion discounted decommissioning liabilities as at December 31, 2016.  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 according to the circumstances inherent in the estimates.

	Less than one year1	Between 1 to 5 years	More than 5 years	Total
RSRUK decommissioning liabilities	120	781	1,669	2,570
Equion decommissioning liabilities	8	4	1	13
	128	785	1,670	2,583

(1)Included in accounts payable and accrued liabilities of the balance sheets of the joint ventures.

9. GOODWILL

Changes in the carrying amount of the Company’s goodwill, which has no tax basis, are as follows:

Continuity of goodwill	2016		2015
Balance, beginning of year	274		279
Disposals (note 7)	(17	)	(5	)
Balance, end of year	257		274

10. ACCOUNTS RECEIVABLE

December 31,	2016		2015
Accounts receivable	433		402
Allowance for doubtful accounts	(21	)	(30	)
	412		372

The fair value of accounts receivable approximates the carrying amount due to their short term to maturity. Trade receivables are non-interest bearing and are generally on 30-90 day terms.

At December 31, the analysis of accounts receivables that were due or past due, but not impaired, was as follows:

Due date	2016	2015
Not due	355	268
Past due 0-30 days	21	34
Past due 31-180 days	6	35
Past due for more than 180 days	30	35
	412	372

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11. INVENTORIES

December 31,	2016	2015
Materials and supplies	46	47
Product	32	56
	78	103

12. OTHER ASSETS

December 31,	2016	2015
Accrued pension asset (note 29)	—	4
Decommissioning sinking fund (note 15)	98	85
Transportation rights1	75	84
Other	12	11
	185	184

(1)Net of $33 million accumulated depreciation (2015 - $24 million).

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13. OIL AND GAS ASSETS

The cost and accumulated DD&A of the Company’s PP&E (including corporate assets) and E&E assets are as follows:

	PP&E		E&E assets		Total
Cost
At December 31, 2014	23,216		5,468		28,684
Acquisitions	—		31		31
Additions	901		198		1,099
Disposals and derecognition	(4,665	)	(2,247	)	(6,912	)
Transfers from E&E assets to PP&E	40		(40	)	—
Change in decommissioning liabilities	99		3		102
Expensed to dry hole1	—		(21	)	(21	)
At December 31, 2015	19,591		3,392		22,983
Acquisitions and extension	115		1		116
Additions	373		142		515
Disposals and derecognition	(905	)	(25	)	(930	)
Transfers from E&E assets to PP&E	179		(179	)	—
Change in decommissioning liabilities	360		(1	)	359
Expensed to dry hole	—		(116	)	(116	)
At December 31, 2016	19,713		3,214		22,927
Accumulated DD&A
At December 31, 2014	14,152		2,924		17,076
Charge for the year1	1,617		—		1,617
Disposals and derecognition	(4,119	)	(2,173	)	(6,292	)
Impairment, net of reversals1	652		977		1,629
At December 31, 2015	12,302		1,728		14,030
Charge for the period	1,211		—		1,211
Disposals and derecognition	(466	)	—		(466	)
Transfers from E&E assets to PP&E	46		(46	)	—
Impairment, net of reversals	(313	)	(5	)	(318	)
At December 31, 2016	12,780		1,677		14,457
Net book value
At December 31, 2016	6,933		1,537		8,470
At December 31, 2015	7,289		1,664		8,953
At December 31, 2014	9,064		2,544		11,608

(1)2015 Balances include $6 million in dry hole expense, $86 million in DD&A, and $153 million in impairment expense related to discontinued operations in Norway.

On April 6, 2016, a Production Sharing Contract (“PSC”) in Malaysia was extended to December 31, 2027. As a result, the Company agreed to $180 million in additional minimum work commitments (note 22) and an additional $160 million decommissioning liability (note 15). In addition, the Company committed to pay a lease extension payment of $60 million in various tranches until 2020 of which $29 million and $25 million, respectively, were

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included in accounts payable and other long-term obligations (note 18) on the  Restated Consolidated Balance Sheets as at December 31, 2016.

In 2016, dry hole expense of $116 million consists mainly of $46 million of well costs in Papua New Guinea, $35 million of well costs in Malaysia, $14 million of well costs in Canada, $11 million of well costs in Colombia and $10 million of well costs in Indonesia.

Non-Depleted Capital

PP&E and E&E assets include the following costs that were not subject to DD&A:

December 31,	2016	2015
E&E assets1
North America	969	1,030
Southeast Asia	479	540
Other	89	94
	1,537	1,664
Development projects2
North America	187	288
Southeast Asia	198	285
Other	14	13
	1,936	2,250

(1)E&E assets include undeveloped land, acquired unproved reserve costs not associated with producing fields, and exploration costs. Acquired costs of unproved reserves are not depleted while under active evaluation for commercial reserves. Exploration costs consist of drilling in progress and wells awaiting determination of proved reserves and are not depleted pending approval of development plans.

(2)Development projects are not depleted until the asset is substantially complete and ready for its intended use.

Costs relating to wells drilled prior to 2016 continue to be capitalized, since management’s ongoing assessment includes further planned activity. The number of wells drilled prior to 2016 and related costs are as follows:

		Number of
	Years	wells	Cost
Southeast Asia	2010-2015	15	141
Other	2008-2011	4	79
		19	220

Southeast Asia and other international wells relate to projects that are in the process of being evaluated, including the drilling of additional appraisal wells and the completion of additional seismic analysis. Some of these projects are in the final stages of project sanction.

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14. IMPAIRMENT

Years ended December 31,	2016		2015		2014
Impairment losses
E&E assets	36		848		388
PP&E	49		787		538
	85		1,635		926
Goodwill impairment	—		—		287
Impairment (reversal) in Equion (note 8)	(9	)	47		133
Impairment reversals
E&E assets	(41	)	—		—
PP&E	(362	)	(159	)	(32	)
	(403	)	(159	)	(32	)
Net impairment	(327	)	1,523		1,314

At December 31, 2016, the Company assessed the carrying amount of its oil and gas assets for indicators of impairment such as changes in future prices, future costs and reserves and resource volumes. The Company calculated the recoverable amount of CGUs as the value in use using a discounted cash flow model. The cash flow projections are based on the best available estimates of the CGU’s income and expenses using sector forecasts, prior results and the outlook of future performances and market developments. The Company’s annual budget and the business plan set macroeconomic forecasts for each of the countries, which include variables such as inflation, Gross Domestic Product growth, foreign exchange rates, royalty rates and income taxes, used to quantify the CGU’s income and expenses.

The calculation of the recoverable amounts use cash flow projections over the expected life of the respective fields, limited by the contractual expiration of the operating permits, licenses, agreements or contracts. The key estimates used to determine the variables that most affect the business’ cash flows are summarized below:

Commodity prices and foreign exchange rates

Commodity prices are based on market indicators at the end of the year. Management’s long-term assumptions are benchmarked against the forward price estimates of a range of analysts and industry agencies on an annual basis. In countries where international list prices do not reflect local market circumstances, the prices modeled factor in local market prices. The prices are consistent with the Company’s annual budget and the updated strategic plan. If the expected lives of the respective fields are longer than the five-year period, the future prices are extrapolated in line with operating expenses and capital expenditures.

Foreign exchange rates are based on management’s long-term assumptions set with reference to a range of underlying economic indicators.

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The following assumptions were used in developing the cash flow models and applied over the expected life of the respective fields within each CGU:

	2017	2018	2019	2020	20211
WTI/Dated Brent ($/bbl)	55.00	65.00	75.00	85.00	86.70
Henry Hub natural gas ($/mmbtu)	3.20	3.70	4.20	4.80	4.90
US$/C$	0.78	0.77	0.77	0.79	0.81

(1)Prices are escalated at 2.0% thereafter.

Reserves and production profiles

Production profiles estimates are based on management’s best estimates of output levels of existing wells and approved development plans. Reserve and contingent resource quantities form the basis of the production profiles within the discounted cash flow models. The data generated for each field takes into consideration the development plans approved and reasonable assumptions that would apply in appraising the assets, including expected license renewals.

Operating costs and future capital costs

Operating costs and future capital cost estimates are based on management’s best estimates of future costs based on the approved development plans until 2021. These costs were extrapolated at a growth rate of 2% for impairment testing purposes in 2022 and subsequent years.

Discount rate

Discount rates used reflect the estimated after-tax weighted average cost of capital rates adjusted for country specific risk to arrive at a discount rate for each CGU. The discount rates are intended to reflect current market assessment of the time value of money and the risks specific to the asset. The rates to be applied are reassessed each year.  The discount rates used in 2016 and 2015 by business segment and geographical area are shown below:

	2016		2015
North America	7.9-8.1	%	8.0-8.2	%
Southeast Asia	8.3-11.5	%	8.4-12.2	%
Other	9.4	%	9.3-9.5	%

Income taxes and royalties

Income taxes are calculated for each relevant jurisdiction using the tax rates and rules in place at the end of the year. Royalties are also calculated on a field-by-field basis using available deductions.

North America 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. The CGU consists of upstream properties and midstream assets.

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 recorded as result of the increase in the recoverable amount due to an improvement in the outlook of the assets. The CGU consists of upstream properties and midstream assets.

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The recoverable amounts as reflected by the value in use of the CGUs in North America, where impairments or reversals have been recorded, at December 31, 2016, were approximately $3.1 billion.

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

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

During 2015, as a result of sustained declines in commodity prices, the Company recorded a $481 million pre-tax ($293 million after-tax) impairment expense relating to Eagle Ford of which $389 million was to PP&E assets and $92 million to E&E assets. During 2014, the Company recorded a $614 million pre-tax ($614 million after-tax) impairment expense, of which $488 million was to PP&E assets and $126 million to E&E assets. The impairment was taken mainly as a result of the overall lower commodity price environment leading to the decrease of the properties and asset valuation.

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

The recoverable amounts as reflected by the value in use of the CGUs in Southeast Asia, where impairments or reversals have been recorded, at December 31, 2016, were approximately $1.0 billion.

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

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During 2015, the Company recorded a pre-tax PP&E impairment expense of $17 million ($11 million after-tax) related to Kinabalu in Malaysia, $100 million ($50 million after-tax) related to HST/HSD in Vietnam and $46 million ($46 million after-tax) to fully impair a property in Australia primarily as a result of lower commodity prices.

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

During 2014, the Company recorded impairment expense of $60 million pre-tax ($27 million after-tax) in Southeast Asia, of which $45 million pre-tax ($19 million after-tax) related to PP&E assets in Australia and $8 million pre-tax ($5 million after-tax) to PP&E assets in Malaysia.

Other Impairments

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

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

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

During 2014, the Company recorded pre-tax impairment expense of $234 million ($234 million after-tax) relating to E&E assets in the Kurdistan Region of Iraq after determining that future investment in a capital constrained environment was unlikely.

During 2014, the Company recorded an impairment expense of $133 million pre-tax ($133 million after-tax) related to its investment in Equion, due principally to the lower commodity price environment.

Impairment of Goodwill

Goodwill was assessed for impairment as at December 31, 2016 using the value in use. The value in use was estimated for a group of CGUs in an operating segment or a country, with allocated goodwill, based on the assumptions used in the asset impairment tests. Any determination with respect to the recoverable amount of the group of CGUs is sensitive to the changes in key assumptions.

No reasonably possible change in assumptions would cause goodwill to become impaired in the CGUs, or group of CGUs.

During 2014, the Company recorded a non-taxable goodwill impairment expense of $287 million in the North Sea operating segment, representing a full write-off of the North Sea goodwill balance. The goodwill write-off was a result of the Company’s view of the declining value of its North Sea assets driven by lower commodity prices and higher decommissioning and development cost estimates.

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15. DECOMMISSIONING LIABILITIES

Continuity of decommissioning liabilities	2016		2015
Balance, beginning of year	796		1,928
Liabilities incurred during the year	216		47
Liabilities settled during the year	(39	)	(84	)
Accretion expense1(note 16)	40		48
Revisions in estimated cash flows	121		(201	)
Change in discount rate	62		256
Disposals	(86	)	(1,198	)
Balance, end of year	1,110		796
Expected to be settled within one year	60		41
Expected to be settled in more than one year	1,050		755
	1,110		796

(1)Includes in 2015 $14 million related to discontinued operations in Norway.

Revisions in estimated discounted cash flows occurring in 2016 included revisions to cost estimates attributed to the net increase in future abandonment, reclamation and remediation costs, the depreciation of the US dollar relative to country level estimates denominated in local currency, and inflationary short-term cost environment assumptions, all generating increases in estimated cash flows. The liabilities incurred during the year related principally to new wells and facilities in North America and the PSC extension in Malaysia (note 13). Substantially all of the liabilities disposed of relate to the disposal of net assets in Australia/Timor-Leste (note 7).

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 calculated using the current estimated cost to retire the asset inflated to the estimated retirement date and then discounted using a weighted average credit-adjusted nominal rate of 4.5% at December 31, 2016 (December 31, 2015 - 4.8%). Total accretion expense from continuing operations for the year ended December 31, 2016 of $40 million (2015 - $34 million; 2014 - $26 million) has been included in Finance costs in the Restated Consolidated Statements of Loss.

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 the costs to be incurred.

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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	60	251	799	1,110

The Company has established decommissioning sinking funds of $98 million at December 31, 2016 (2015 - $85 million) (note 12) that represents secured funding for a portion of its decommissioning obligations in Southeast Asia and Other.

16. FINANCE COSTS

Years ended December 31,	2016	2015	2014
Interest on long-term debt	101	251	269
Interest on loans from related parties	29	10	—
Miscellaneous interest expense and other fees	20	32	32
Non-cash accretion expense (note 15)	40	34	26
	190	327	327

17. LONG-TERM DEBT

December 31,	2016		2015
Tangguh Project Financing	—		37
Debentures and Notes (Unsecured)1
8.50% notes (US$150 million), due 2016	—		150
6.625% notes (UK£250 million), due 20172	308		370
7.75% notes (US$700 million), due 2019	363		571
3.75% notes (US$600 million), due 2021	239		595
7.25% debentures (US$300 million), due 2027	54		57
5.75% notes (US$125 million), due 2035	88		96
5.85% notes (US$500 million), due 2037	130		139
6.25% notes (US$600 million), due 2038	117		129
5.50% notes (US$600 million), due 2042	94		123
Gross debt3	1,393		2,267
Less: current portion4	(308	)	(156	)
Long-term debt	1,085		2,111

(1)Interest on debentures and notes is payable semi-annually except for interest on the 6.625% notes, which is payable annually, and interest on the 8.50% notes, which was payable quarterly.

(2)Includes unrealized foreign exchange gain of $63 million (December 31, 2015 – $19 million gain).

(3)Financing costs of $10 million and $17 million have been netted against the individual debt facilities as at December 31, 2016 and 2015, respectively.

(4)The current liability of $308 million consists of 6.625% notes.

December 31,	2016	2015
Loans from Related Parties	1,756	1,007

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During the year ended December 31, 2016, the Company repaid debt of $754 million, including $150 million of 8.5% notes due in March 2016, $598 million of USD senior notes and debentures redeemed and repurchased, and $6 million of Tangguh project financing loan.

Bank Credit Facilities and Commercial Paper

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.

Debentures and Notes

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 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 resulted in a net gain of $149 million, which was recognized in other income on the Restated Consolidated Statements of Loss.

Related Party Financing

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

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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 (note 16). 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 Repsol Energy Resources Canada, Inc. (“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 (note 16).  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.

On June 8, 2016, ROGUSA, a subsidiary of the Company, 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 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.

In connection with the sale of 20% of the interest in ROGUSA (note 7), Repsol E&P USA Holdings Inc., an indirect subsidiary of the Company, entered into a $502 million loan agreement effective December 31, 2016 with RUSA. The loan receivable matures on June 30, 2017 and bears an interest rate of LIBOR (1 month). As at December 31, 2016, RUSA had a balance of $502 million payable to Repsol E&P USA Holdings Inc. In April 2017, the purchase price was confirmed and finalized, and the note receivable from RUSA was amended to $442 million.

Tangguh Project Financing

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 (note 7), the Company is no longer a participant of the above mentioned series of financing facilities.

Other

The Company has a financing structure whereby subsidiaries have $1.3 billion drawn on bank facilities that have been offset against equal amounts of cash deposited by another subsidiary with the same bank under a right of offset agreement. The Company offset these amounts at maturity on February 24, 2017.

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18. OTHER LONG-TERM OBLIGATIONS

December 31,	2016	2015
Accrued pension and other post-employment benefits liability (note 29)	83	86
Deferred credits	33	22
Long-term portion of discounted obligations under finance leases	21	31
Onerous contracts and other provisions	58	27
Long-term lease extension payment	25	—
Other	71	67
	291	233

Finance Leases

The Company has a leasing arrangement for the modification, refitting and use of Floating Storage Offloading (FSO) vessel for use in its operations. The imputed rate of interest on this lease, which expires in 2019, is 10%. The Company also has a leasing arrangement for the use of a condensate transportation vessel that has been categorized as a finance lease. The imputed rate of interest on this lease, which expires in 2026, is 4%.

The future minimum lease payments for finance leases and the present value of minimum finance lease payments by payment date are as follows:

	2016			2015
	Minimum		Present value of	Minimum		Present value of
December 31,	payments		payments	payments		payments
Within one year	13		12	16		14
After one year but not more than five years	19		16	32		25
More than five years	6		5	7		6
Total minimum lease payments	38		33	55		45
Less amounts representing accretion	(5	)	—	(10	)	—
Present value of minimum lease payments	33		33	45		45

Of the total discounted liability of $33 million (2015 - $45 million), $12 million (2015 - $14 million) is included in accounts payable and accrued liabilities.

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19. SHARE CAPITAL AND SHARE-BASED PAYMENTS

Authorized

The Company’s authorized share capital consists of an unlimited number of common shares without nominal or par value and an unlimited number of first and second preferred shares.

	2016		2015
Continuity of common shares	Shares	Amount	Shares		Amount
Balance, beginning of year	1,829,506,342	3,492	1,031,525,988		1,738
Shares issued to parent	4,869,110	9	—		—
Converted from preferred shares	—	—	8,000,000		195
Shares issued as payment of loan from related parties	—	—	785,340,314		1,500
Shares previously held in trust sold on open market	—	—	323,584		3
Shares purchased and held in trust for long-term PSU plan (see below)	—	—	(3,793,939	)	(30	)
Shares released from trust for long-term PSU plan	—	—	8,110,395		86
Balance, end of year	1,834,375,452	3,501	1,829,506,342		3,492

Common Shares Issued

On December 22, 2016, the Company issued 4,869,110 common shares at $1.91 per share to RERCI, a subsidiary of the Company’s ultimate parent Repsol, for proceeds of $9 million.

Subsequent to December 31, 2016, 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 (note 17).

On May 8, 2015, the Repsol Transaction was completed, whereby Repsol acquired all outstanding common and preferred shares of the Company.

On December 29, 2015, RERCI subscribed for $1.5 billion in the Company’s common shares (785,340,314 common shares at $1.91 per share), which settled $1.5 billion of the balance owing from the Company to RERCI under the revolving facility (note 17).

Preferred Shares Issued

Subsequent to the Repsol Transaction on May 8, 2015, all Series 1 preferred shares were converted on a 1:1 basis into common shares.

Stock Option Plans

Subsequent to the Repsol Transaction on May 8, 2015, all share-based payment units, including stock options, cash units, long-term performance share units, deferred share units, and restricted share units, were settled and paid in 2015.

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20. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of accumulated other comprehensive income are as follows:

	2016		2015		2014
Balance, beginning of year
Derivative financial instruments designated as cash flow hedges	2		2		2
Foreign currency translation adjustments	698		809		809
	700		811		811
Other comprehensive income (loss) for the year
Foreign currency translation	—		3		—
Transfer of accumulated translation adjustment to net income (note 6)	—		(114	)	—
Remeasurements relating to employee benefit plans	(3	)	7		(8	)
Share of remeasurements relating to employee benefit plans from joint ventures (note 8)	(38	)	—		—
	(41	)	(104	)	(8	)
Employee benefit plans remeasurements transferred to retained earnings	41		(7	)	8
Balance, end of year
Derivative financial instruments designated as cash flow hedges	2		2		2
Foreign currency translation adjustments	698		698		809
	700		700		811

Subsequent to the sale of substantially all of the assets and liabilities of the Company’s Norwegian operations on September 1, 2015 (note 6), management determined that the functional currency of the remaining Norwegian activities was more closely linked to the Norwegian krone (NOK) than to the US$. Accordingly, effective September 1, 2015, these activities have been accounted for using a NOK functional currency, resulting in a translation gain of $3 million included in other comprehensive income.

21. FINANCIAL INSTRUMENTS

The Company’s financial assets and liabilities at December 31, 2016 consisted of cash and cash equivalents, accounts receivable, amount due from related party, available-for-sale investments, bank indebtedness, accounts payable and accrued liabilities, loans from joint ventures, loans from related parties and long-term debt (including the current portion).

The Company is exposed to financial risks arising from its financial assets and liabilities. The financial risks include market risk related to foreign exchange rates, interest rates and commodity prices, credit risk and liquidity risk.

Fair Value of Financial Assets and Liabilities

The fair values of cash and cash equivalents, accounts receivable, amount due from related party, bank indebtedness, accounts payable and accrued liabilities, and loans from joint ventures approximate their carrying values due to the short-term maturity of those instruments.

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The fair value of public debentures and notes is based on market quotations, which reflect the discounted present value of the principal and interest payments using the effective yield for instruments having the same term and risk characteristics. The fair values of private notes are based on estimations provided by third parties. The fair value of the Company’s floating rate debt is determined by discounting future estimated coupon payments at the current market interest rate. The fair value of the Company’s long-term debt (including the current portion and loans from related parties) at December 31, 2016 was $3.2 billion (2015 - $3.2 billion), and the carrying value was $3.1 billion (2015 - $3.3 billion). The Company used Level 2 inputs as described below to estimate the fair value of the outstanding long-term debt as at December 31, 2016.

The fair values of all other financial assets and liabilities approximate their carrying values.

Risk management assets and liabilities are recorded at their estimated fair values. To estimate fair value, the Company uses quoted market prices when available, or models that utilize observable market data. The Company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

·Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis;

·Level 2 — inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Company obtains information from sources such as the New York Mercantile Exchange (NYMEX) and independent price publications; and

·Level 3 — inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument’s fair value, such as the Company’s internally developed assumptions about market participant assumptions used in pricing an asset or liability; for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair value measurement.

In forming estimates, the Company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement.

Currency Risk

The Company operates internationally and is therefore exposed to foreign exchange risk. Its primary exposure is from fluctuations in the US$ relative to the C$ and UK£.

The Company manages its foreign exchange exposure in a number of ways. By denominating most of its borrowings in US$, the Company is able to reduce some of its economic exposure to currency fluctuations. It also manages its translation exposure by generally matching internal borrowings with its subsidiaries’ functional currencies. The Company purchases foreign currencies, mostly at spot value, to meet foreign currency obligations as they come due.

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In respect of financial instruments existing at December 31, 2016, a 1% strengthening of the US$ against the other currencies noted above, with all other variables assumed constant, would have resulted in a decrease of $2 million in net loss and a $2 million impact on comprehensive loss during the year ended December 31, 2016. A similar weakening of the US$ would have had the opposite impact.

Interest Rate Risk

The Company is exposed to interest rate risk principally by virtue of its borrowings including loans from related parties and joint ventures. Borrowing at floating rates exposes the Company to short-term movements in interest rates. Borrowing at fixed rates exposes the Company to reset risk (i.e., at debt maturity).

In respect of financial instruments existing at December 31, 2016, a 1% increase in interest rates would have resulted in a $2 million increase in net loss and a $2 million impact on comprehensive loss during the year ended December 31, 2016. A similar 1% decrease in interest rates would have the opposite impact.

Credit Risk

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 were 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 note 30. Concentration of credit risk is managed by having a broad domestic and international customer base of primarily 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.

Liquidity Risk

The Company is exposed to liquidity risk, which it mitigates risk through its management of cash, debt, related party financing and its capital program.

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The table below summarizes the maturity profile of the Company’s financial liabilities based on contractual undiscounted payments:

	Total	2017	2018-2019	2020-2021	Thereafter
Long-term debt (note 17)	1,393	308	363	239	483
Loans from related parties (note 17)	1,756	—	1,756	—	—
Finance leases (note 18)	33	12	14	2	5
Bank indebtedness	5	5	—	—	—
Accounts payable and accrued liabilities	835	835	—	—	—
Loans from joint ventures (note 8)	10	10	—	—	—
	4,032	1,170	2,133	241	488

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. 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 (note 17). As at December 31, 2016, $1.8 billion drawings were outstanding under these facilities (note 17). As at December 31, 2016, $1.8 billion drawings were outstanding under these facilities (note 17). Subsequent to December 31, 2016, RERCI subscribed for 786,125,654 common shares of the Company’s, which settled $1.5 billion of the balance owing from the Company to RERCI under the revolving facility (note 19). In May 2017, the facility agreements between TEHS and RTYGF and between ROGCI and RERCI were modified to extend the maturity dates to June 30, 2020 and May 8, 2020, respectively.

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 DSAs. At the commencement of the joint venture, 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 at 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.

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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.

Commodity Price Risk

The Company is exposed to commodity price risk since its revenues are dependent on the price of crude oil, natural gas and NGLs. In prior years, the Company entered into derivative instruments to mitigate commodity price risk volatility under guidelines approved by the Board of Directors.

In 2015, the Company liquidated 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.

Capital Disclosures

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.

As a result of the cancellation of the Company’s bank credit facilities (Facility No.1 and No.2, note 17), the Company no longer has the principal financial covenant of a debt-to-cash flow ratio of less than 3.5:1.

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22. CONTINGENCIES AND COMMITMENTS

Provisions and Contingencies

The Company’s provision for decommissioning is presented in note 15. The other provisions recorded by the Company include onerous contract and legal provisions. As at December 31, 2016, other provisions of $111 million (2015 - $111 million) were recorded in accounts payable and accrued liabilities on the Restated Consolidated Balance Sheets.

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 $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.

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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 subsidiaries 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.

Estimated Future Purchase, Capital and Other Expenditure Commitments1,4

Estimated future commitments for 2017 and beyond are as follows:

						Subsequent
	2017	2018	2019	2020	2021	to 2021	Total
Investment commitments2	345	198	106	80	63	9	801
Service commitments	103	83	66	52	40	140	484
Transportation commmitments3	110	105	88	84	75	217	679
Operating leases	41	34	31	29	28	54	217
	599	420	291	245	206	420	2,181

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

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

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

(4)Commitments entered into by the Company’s joint arrangements have been summarized in note 8.

The Company leases certain of its ocean-going vessels and corporate offices, all of which, with the exception of the leasing arrangements described in note 18, are accounted for as operating leases. In addition to the minimum lease

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payments, the Company has ongoing operating commitments associated with the vessels. The majority of the vessel leases have an average life of five years, the office leases have an average life of 10 years and the transportation commitment contracts have average lives of between 10 and 15 years.

The Company has firm commitments for gathering, processing and transportation services that require the Company to pay tariffs to third parties for processing or shipment of certain contracted quantities of crude oil, natural gas and NGLs mainly in North America and Southeast Asia.

In the case of an operating lease entered into by the Company as the operator of a joint operation, the amounts reported represent the net operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed, by joint operation partners, whether the joint operation partners have co-signed the lease or not. Where the Company is not the operator of a joint operation, the Company’s share of the lease expense and future minimum lease payments is included in the amounts shown, whether the Company has co-signed the lease or not. Where lease rentals are dependent on a variable factor, the future minimum lease payments are based on the factor as at the inception of the lease.

During the year ended December 31, 2016, the Company incurred net rental expense of $29 million (2015 - $26 million; 2014 - $59 million) in respect of its operating leases associated with continuing operations.

Estimated Future Sales Commitments

The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings Limited (“Temasek”). Currently ROGCI’s share of the sale on a daily basis is approximately 75 billion British thermal units (“bbtu”). 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 is expected to remain the same and volume delivery requirements are expected to be adjusted to match the forward reserves profile and to 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 are 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.

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23. OTHER INCOME

Years ended December 31,	2016	2015	2014
Pipeline and customer treating tariffs	13	37	63
Investment income	12	12	17
Interest on loan to RSRUK (note 7)	—	10	28
Net gain on repayment of long-term debt (note 16)	26	149	—
Marketing and other miscellaneous income	99	109	50
	150	317	158

24. OTHER EXPENSES, NET

Years ended December 31,	2016		2015		2014
Foreign exchange gain	(67	)	(9	)	(39	)
PP&E derecognition	2		4		5
Taxes, interest and penalties	1		1		—
Inventory writedowns	10		17		10
Allowance for doubtful accounts	(2	)	21		1
Restructuring	17		38		18
Transaction costs incurred in relation to the Repsol Transaction	—		41		—
Onerous contracts and other provisions	68		121		3
Other miscellaneous	50		32		50
	79		266		48

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25. INCOME TAXES

Current Tax Expense (Recovery)

	North America		Southeast Asia		North Sea		Other		Total
Year ended December 31, 2016
Current tax	—		147		—		8		155
Adjustments related to prior years	1		2		—		(1	)	2
Petroleum Revenue Tax	—		6		—		—		6
Sale of TWOL (note 7)	—		52		—		—		52
Other	—		—		—		(8	)	(8	)
	1		207		—		(1	)	207
Year ended December 31, 2015
Current tax	(3	)	227		(419	)	10		(185	)
Adjustments related to prior years	(1	)	—		2		—		1
Petroleum Revenue Tax	—		7		—		—		7
	(4	)	234		(417	)	10		(177	)
Year ended December 31, 2014
Current tax	8		412		—		56		476
Adjustments related to prior years	(40	)	(22	)	—		—		(62	)
Petroleum Revenue Tax	—		15		—		—		15
	(32	)	405		—		56		429

Deferred Tax Expense (Recovery)

	North		Southeast
	America		Asia		North Sea		Other		Total
Year ended December 31, 2016
Origination and reversal of temporary differences	(221	)	(57	)	9		(32	)	(301	)
Adjustments related to prior years	(13	)	(6	)	—		9		(10	)
Petroleum Revenue Tax	—		(4	)	(9	)	—		(13	)
Changes in tax rates	—		—		—		(7	)	(7	)
Recognized deferred tax asset	(155	)	—		—		—		(155	)
Derecognized asset	—		142		—		12		154
	(389	)	75		—		(18	)	(332	)
Year ended December 31, 2015
Origination and reversal of temporary differences	(505	)	(134	)	462		53		(124	)
Adjustments related to prior years	—		(2	)	7		(5	)	—
Petroleum Revenue Tax	—		(1	)	—		—		(1	)
Changes in tax rates	—		—		—		—		—
Recognized asset	(544	)	—		—		—		(544	)
	(1,049	)	(137	)	469		48		(669	)
Year ended December 31, 2014
Origination and reversal of temporary differences	4		(12	)	(199	)	(23	)	(230	)
Adjustments related to prior years	7		—		—		(6	)	1
Petroleum Revenue Tax	—		(18	)	—		—		(18	)
Changes in tax rates	—		—		—		—		—
Derecognized asset	—		40		—		—		40
	11		10		(199	)	(29	)	(207	)

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Deferred Tax Assets and Liabilities

The significant components of the deferred tax (assets) and liabilities are as follows:

	PP&E and E&E assets		Decommissioning liabilities		Tax loss carryforward		Other		Total
At December 31, 2014	748		(1,162	)	(810	)	22		(1,202	)
Charged (credited) to tax expense, net	84		52		(733	)	(72	)	(669	)
Credited to equity	—		—		—		2		2
Other	338		900		—		25		1,263
At December 31, 2015	1,170		(210	)	(1,543	)	(23	)	(606	)
Charged (credited) to tax expense, net	242		(123	)	(456	)	5		(332	)
Credited to equity	108		—		—		—		108
Dispositions	(149	)	34		2		—		(113	)
At December 31, 2016	1,371		(299	)	(1,997	)	(18	)	(943	)

At December 31, 2016, the Company has the following non-capital loss carry-forwards:

	Loss carry-forward	Expiry
US	3,736	2028-2036
Canada	1,545	2036
Malaysia	242	No expiry
Colombia	190	No expiry
	5,713

The Company has recognized a deferred tax asset in the US in the amount of $1.1 billion, including net operating losses. The net operating losses have accumulated over the last several years. In arriving at the judgment to recognize the deferred tax asset the nature of the evidence supporting recognition includes:

·Future earnings projections over the next 20 years based on proved, probable and contingent resource estimates. As a result of the acquisition of the Company in 2015, there is increased confidence in projecting future earnings associated with contingent resources as compared to prior years based upon the ultimate parent company’s intention and ability to fund development activities.

·The net operating losses in the US have a 20 year carryforward period and do not begin to expire until 2028. Projections indicate sufficient positive cash flow to begin utilizing the net operating losses within a 3 year time frame and are expected to be fully utilized by 2027.

In Canada, Colombia and US, income projections show sufficient taxable income to utilize the losses recorded within the carry-forward period.

No deferred tax liability has been recognized for temporary differences associated with investments in subsidiaries, associates, branches and joint operations since the Company is in a position to control or jointly control the entity and it is considered probable that these temporary differences will not reverse in the foreseeable future.

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Effective Tax Rate

The following provides a reconciliation of the Canadian statutory tax rate of 27.19% (2015 – 26.67%; 2014 - 25.19%) to the effective tax rate on the Company’s loss from continuing operations before income taxes:

Years ended December 31,	2016		2015		2014
Loss from continuing operations before taxes	(637	)	(3,658	)	(119	)
Statutory income tax rate (%)	27.19	%	26.67	%	25.19	%
Income taxes calculated at the Canadian statutory rate	(173	)	(976	)	(30	)
Increase (decrease) in income taxes resulting from:
Change in statutory tax rates, net	(7	)	98		—
Non (taxable) deductible hedging	—		163		(308	)
Deductible PRT expense	8		(1	)	(3	)
Higher foreign tax rates	35		(29	)	(369	)
Non-deductible goodwill / impairment	7		—		257
Non-recognition of deferred tax asset, net	154		(331	)	534
Share-based payments	—		—		(7	)
Non-taxable equity loss	55		302		262
Recognition of deferred tax asset	(155	)	—		—
Sale of investment	11		—		(72	)
Repsol Transaction	—		(66	)	—
Other	(53	)	(13	)	(39	)
Income tax (recovery) expense (excluding PRT)	(118	)	(853	)	225

The 2016 effective tax rate was impacted by derecognition of deferred tax assets in Malaysia and Vietnam, earnings from joint ventures, and a rate decrease for reversal of Colombia timing differences. The rate was also impacted by the disposals of all of its investment in TWOL (note 7), including the non-taxable goodwill associated with TWOL.

The 2015 effective tax rate was impacted by the US recognition of a tax asset, equity earnings, the change in Alberta tax rates and a rate increase for reversal of Colombia timing differences. The rate was also impacted by contingencies for hedging gains/losses related to foreign production in Canada, capital loss carryback, loss of tax pools due to the Repsol Transaction and by non-taxable foreign exchange impact of foreign denominated tax basis.

The 2014 effective tax rate was impacted by non-taxable hedging gains, equity earnings, North Sea goodwill and the partial impairment of the investment in Equion. Hedging gains/losses related to foreign production are not taxable in Canada. The rate was also impacted by non-taxable foreign exchange impact of foreign denominated tax basis. In 2014, deferred tax assets continued to be derecognized in the US with significant amount from Eagle Ford impairment.

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Unrecognized Tax Benefit

Changes in the Company’s unrecognized tax benefit are as follows:

	2016		2015
Unrecognized tax benefit, beginning of year	252		102
Increase due to prior period tax positions	4		199
Decrease due to prior period tax positions	—		(23	)
Disposal	(20	)	(26	)
Unrecognized tax benefit, end of year	236		252

The Company’s entire unrecognized tax benefit as at December 31, 2016 and December 31, 2015, if recognized, would affect the Company’s effective tax rate. No significant change in the total unrecognized tax benefit is expected in 2017.

26. SUPPLEMENTAL CASH FLOW INFORMATION

Items Not Involving Cash from Continuing Operations

Years ended December 31,	2016		2015		2014
Depreciation, depletion and amortization	1,214		1,534		1,634
Impairment, net of reversals	(327	)	1,523		1,314
Dry hole	116		15		141
Share-based payments expense	—		2		27
(Gain) loss on disposals	(73	)	2		(550	)
Unrealized (gain) loss on held-for-trading financial instruments	—		1,268		(1,368	)
Deferred income tax recovery	(332	)	(669	)	(207	)
Foreign exchange	(69	)	1		(21	)
PP&E derecognition	2		4		5
Net gain on repayment of long-term debt (note 17)	(28	)	(149	)	—
Loss from joint ventures and associates, after tax	204		1,086		1,040
Other	46		21		31
	753		4,638		2,046

Changes in Non-Cash Operating Working Capital from Continuing Operations

Years ended December 31,	2016		2015		2014
Accounts receivable	(60	)	278		76
Inventories	16		8		2
Prepaid expenses	8		2		(20	)
Decommissioning expenditures	(36	)	(33	)	(43	)
Accounts payable and accrued liabilities	(28	)	(155	)	(164	)
Income and other taxes payable	51		(30	)	(116	)
Operating working capital in assets held for sale	—		—		13
	(49	)	70		(252	)

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Other Cash Flow Information

Years ended December 31,	2016	2015	2014
Cash interest paid	145	303	278
Cash interest received	—	1	25
Cash income taxes paid	182	263	497

In respect of its exploration and evaluation activities in 2016, the Company has included exploration expenditure of $105 million within cash provided by operating activities from continuing operations, and exploration capital expenditure of $149 million within cash used in investing activities from continuing operations.

27.CASH AND CASH EQUIVALENTS

The entire cash and cash equivalents balance of $52 million (2015 - $98 million), has been invested in bank deposits.

28.NET LOSS PER SHARE — BASIC AND DILUTED

(millions)	2016		2015		2014
Net loss from continuing operations	(512	)	(2,812	)	(341	)
Less: Share-based payments recoveries for all options	—		(38	)	(64	)
Less: Cumulative preferred share dividends after-tax	—		(1	)	(6	)
Less: Share-based payments expenses for unvested dilutive options	—		(3	)	(14	)
Diluted net loss from continuing operations	(512	)	(2,854	)	(425	)
Basic and diluted loss from discontinued operations	—		(294	)	(570	)
Weighted average number of common shares outstanding - basic	1,830		1,047		1,033
Dilution effect of stock options and PSUs	—		—		—
Weighted average number of common shares outstanding - diluted	1,830		1,047		1,033

Basic net loss per share is calculated by dividing net loss less after-tax cumulative preferred share dividends (if any), by the weighted average number of common shares outstanding during the year.

For the diluted net loss per share calculation, the net loss is adjusted for the change in the fair value of stock options. The weighted average number of shares outstanding during the year is adjusted for options expected to be exercised and management’s best estimate of shares expected to be issued in settlement of the Company’s obligations pursuant to the long-term PSU plan.

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29. EMPLOYEE BENEFITS

The Company operates defined benefit plans in Canada, defined contribution plans in Canada, the US and Indonesia, international notional defined contribution plan for third-country nationals and Canadian expatriates, and a notional defined benefit plan for former UK expatriates. The Company contributes to the Canadian registered defined benefit plans pursuant to independent actuarial advice. The Canadian non-registered defined benefit pension plans are unfunded, except for the assets held in refundable tax accounts by the Canada Revenue Agency. The Company also provides non-pension post-employment benefits to certain of its Canadian retirees.

The Company sponsors two registered and three non-registered defined benefit plans in Canada, which make pension payments throughout the life of the members. Although the Company has no commitment to provide for increases related to inflation in the Canadian defined benefit plans, the Company generally provided annual increases equal to one-half of the rate of inflation up to 2013 (2011 for service as an Executive). All of the Canadian defined benefit plans are closed to new entrants.

On December 19, 2016, the Company agreed to purchase annuities for members of the two registered defined benefit plans and liquidated the assets to cash as at December 31, 2016. On December 19, 2016, the Company agreed to purchase annuities for members of the two registered defined benefit plans and liquidated the assets to cash as at December 31, 2016.  During the three months ended March 31, 2017, the Company settled the pension obligation relating to these two plans, with the purchase of annuities by paying a premium to Canada Life Assurance Co. and Great West Life Assurance Co., who assumed all risks of pension obligation and associated payments. The annuities were purchased for C$68 million resulting in a loss of C$2 million due to the settlement.

Actuarial Assumptions

The following liability weighted actuarial assumptions were employed to determine the net benefit expense and the accrued benefit obligations for the defined benefit pension plans:

	2016	2015	2014
Accrued benefit obligation
Discount rate (%)	3.8	4.0	3.4
Rate of inflation (%)1	2.0	2.0	2.5
Mortality rate (refer to discussion below) 1
Benefit expense
Discount rate (%)	4.0	3.9	4.8

(1)Canadian defined benefit pension plans only.

The measurement of the Company’s net accrued benefit obligations is sensitive to changes in the Company’s significant actuarial assumptions:

·Discount rate assumptions reflect prevailing rates available on high quality corporate bonds. Discount rates have been selected following actuarial advice related to the countries where the Company operates defined benefit pension plans, taking into account the duration of the liabilities. The overall rate is the liability weighted average of the country-specific discount rates adopted for individual plans.

·Inflation is used to determine pension increases for the defined benefit pension plans. The assumption adopted is based on the Company’s best estimate of long-term inflation and is consistent with the discount rates adopted.

·Mortality assumptions are based on recommendations by the actuaries and reflect the most recent information. Assumptions used for the defined benefit pension plans indicate that the future life expectancy of a male (female) pensioner reaching age 65 in 2016 would be 22.9 (25.3) years and the future life expectancy from age 65 for a male (female) non-pensioner member currently aged 45 of 24.1 (26.4) years. An increase or decrease

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of 10% in the assumed mortality assumption rates decreases or increases, respectively, the future life expectancy by approximately two years.

A change in the Company’s significant actuarial assumptions would cause a change in the accrued benefit obligations by the following amounts:

	Increase (decrease) in pension benefit obligations
	Change in assumption	Increase in assumption		Decrease in assumption
Discount rate	1.0%	(15	)	18
Inflation rate1	1.0%	8		(7	)
Mortality rate1	10.0% Load	(4	)	4

(1)Canadian defined benefit pension plans only.

The methods used to carry out the sensitivity analyses alter the relevant assumption by the amount specified and assume that all other variables remain the same. Although this approach may not be realistic as some assumptions are related, it does determine the effect on the accrued benefit obligation of each individual assumption.

There is a risk that changes in the actuarial assumptions made for the discount rate, life expectancy, price inflation or other assumptions used to value the defined benefit obligations could result in increased obligations for the plans.

Investment Policies

At December 31, 2016, the total plan assets for the defined benefit registered pension plans were liquidated to cash of $61 million.

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Obligation, Assets and Funded Status

Information about the Company’s defined benefit pension plans is as follows:

	2016				2015
Pension plans grouped by funded status	Surplus		Deficit		Surplus		Deficit
Accrued benefit obligation
Accrued benefit obligation, beginning of year	45		88		58		180
Impact on Profit or Loss:
Current service cost	—		1		—		3
Past service cost	—		—		—		4
Plan curtailments	—		—		—		(2	)
Interest cost	2		3		2		4
Impact on Profit or Loss	2		4		2		9
Remeasurements through OCI:
Loss (gain) from change in financial assumptions	1		4		(2	)	(5	)
Gain from experience adjustments	(1	)	(2	)	—		—
Impact of Remeasurements on OCI	—		2		(2	)	(5	)
Benefits paid	(3	)	(5	)	(4	)	(8	)
Foreign currency translation	1		3		(9	)	(17	)
Plan settlements due to Norway disposition	—		—		—		(71	)
Accrued benefit obligation, end of year	45		92		45		88
Plan assets
Fair value of plan assets, beginning of year	49		12		62		58
Impact on Profit or Loss:
Interest income	2		—		2		1
Impact on Profit or Loss	2		—		2		1
Benefits paid	(3	)	(5	)	(4	)	(8	)
Employer contributions	—		5		—		7
Foreign currency translation	1		—		(11	)	(2	)
Plan settlements due to Norway disposition	—		—		—		(44	)
Fair value of plan assets, end of year	49		12		49		12
Funded status — surplus (deficit)1	4		(80	)	4		(76	)

(1)The net accrued benefit asset and net accrued benefit liability are included in other assets and other long-term obligations, respectively, on the Restated Consolidated Balance Sheets.

The net defined benefit asset recognized for the defined benefit plan in a surplus position represents the maximum economic benefit available to the Company in respect of its pension obligations. The Company has been able to recognize the entire surplus since it believes it is entitled to any surplus in the registered defined benefit plans through reductions in contributions and a refund in the event of a plan windup.

The weighted average duration of the accrued benefit obligations for the defined benefit pension plans is approximately 12 years.

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Funding

In Canada, the provincial pension regulator imposes a minimum funding requirement for registered defined benefit pension plans based on actuarial valuation reports prepared by independent actuaries at least every three years. The actuarial reports also set up maximum funding limits based on the status of the registered defined benefit pension plans as Designated Plans under the Income Tax Act (Canada). The most recent actuarial valuations of the registered defined benefit pension plans for funding purposes were at December 31, 2015. On January 9, 2017, the Canada Revenue Agency approved the removal of the Company’s Designated Plans status.

The Company’s objective, where legislation does not otherwise provide impediments, is to fund the registered defined benefit pension plans 100% on a basis that should ensure that benefits can be paid as they fall due. To provide reassurance to plan members that the Company will meet its obligations, letters of credit have been provided to ensure full funding in the event that certain default conditions occur.

The Company expects to make annual contributions to its defined benefit plans as follows:

	Pension Plans	Non-pension benefits plan	Total
2017	5	—	5
2018	5	—	5
2019	5	—	5
2020	5	—	5
2021	5	—	5
2022 – 2026	28	3	31

Of the aggregate accrued benefit obligation of $137 million at December 31, 2016, $86 million related to plans that are unfunded. Four unfunded plans, with a total deficit of $78 million, are secured by letters of credit in the amount of C$115 million.

Net Deficit

December 31,	2016		2015		2014
Accrued benefit obligation	137		133		238
Fair value of plan assets	61		61		120
Net deficit	(76	)	(72	)	(118	)

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Net Benefit Expense

The net benefit expense for the pension plans recognized in the Restated Consolidated Statements of Loss was as follows:

Years ended December 31,	2016	2015		2014
Current service cost	1	3		3
Past service cost	—	4		5
Plan curtailments	—	(2	)	—
Interest cost	3	3		4
Defined benefit plan expense	4	8		12
Defined contribution plan expense	10	14		16
Net benefit expense	14	22		28

Non-Pension Post-Employment Benefit Plan

At December 31, 2016, the accrued benefit obligation for the non-pension post-employment benefit plan was $9 million (2015 - $10 million). Non-pension post-employment benefits include medical, dental and life insurance benefits for certain current and future Canadian retired employees.

During the year ended December 31, 2016, a net benefit expense for non-pension post-employment benefits of $1 million (2015 - $1 million; 2014 - $3 million) was included in the general and administrative expense on the Restated Consolidated Statements of Loss.

A 1% increase or decrease in the assumed medical cost trend rate would have an immaterial impact on the accrued benefit obligation at December 31, 2016.

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30. RELATED PARTY DISCLOSURES

Major Subsidiaries

The Restated Consolidated Financial Statements include the financial statements of Repsol Oil & Gas Canada Inc. and its directly and indirectly owned subsidiaries. Transactions between subsidiaries are eliminated on consolidation. The following table lists the material operating subsidiaries owned directly or indirectly by the Company as at December 31:

	Jurisdiction of	Percentage of Voting
Name of Subsidiary	Incorporation	Securities Owned
Repsol Canada Energy Partnership¹	Alberta	100	%
Repsol Oil & Gas USA LLC.	Texas	80	%
Repsol Alberta Shale Partnership	Alberta	100	%
Talisman (Corridor) Ltd.	Barbados	100	%
Talisman (Vietnam15-2/01) Ltd.	Alberta	100	%
Repsol Oil & Gas Malaysia Limited	Barbados	100	%
Repsol Oil & Gas Malaysia (PM3) Limited	Barbados	100	%
Talisman (Algeria) B.V.	The Netherlands	100	%

(1)  Repsol Canada Energy Partnership is an Alberta general partnership which currently carries on substantially all of the Company’s conventional Canadian oil and gas operations.

Related party transactions with Repsol and Joint Ventures

During 2016, Repsol Canada Energy Partnership sold to Repsol Energy Canada Limited, a subsidiary of Repsol, approximately 65 trillion British thermal units (“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.

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.

The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings (Private) Limited (“Temasek”). Currently, ROGCI’s share of the sale on a daily basis is approximately 75 billion btu. The commitment matures in 2023. As a result of the acquisition of the Company by Repsol, GSPL and Temasek became the Company’s related parties. During 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.

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.

64

During 2016, a subsidiary of 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.

During 2016, the Company incurred $14 million reinsurance expense, respectively 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.

Other transactions between the Company and subsidiaries of the Company’s parent, Repsol, are disclosed in notes 6, 7, 17 and 21. Related party transactions with joint ventures are disclosed as part of notes 8 and 23.

Key Management Personnel Compensation

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

Years ended December 31,	2016	2015	2014
Short-term benefits	3	4	14
Pension and other post-employment benefits	—	3	5
Termination benefits	1	23	3
Share-based payments	—	11	3
Change of control payments	—	24	—
	4	65	25

Short-term benefits comprise salaries and fees, annual bonuses, cash, vehicle and other benefits.

The amount of pension benefits reported represents the attributable amount of the net benefit expense of the plans in which the key management personnel participate.

Termination benefits comprise amounts paid and accrued.

The share-based payments amount reported represented 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 that period.

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31. SEGMENTED INFORMATION

The Company’s activities are conducted in four geographic segments: 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. All activities relate to the exploration, development, production and transportation of oil, liquids and natural gas.

	North America (1)						Southeast Asia (2)
(millions of US$)	2016		2015		2014		2016		2015		2014
Revenue
Sales	815		938		1,804		917		1,163		2,050
Other income	137		262		70		6		11		3
Income (loss) from joint ventures and associates, after tax	—		—		—		—		—		—
Total revenue and other income	952		1,200		1,874		923		1,174		2,053
Segmented expenses
Operating	379		470		527		291		367		494
Transportation	98		101		89		49		55		56
DD&A	894		1,004		1,109		276		466		473
Impairment, net of reversals	(240	)	579		593		(86	)	606		60
Dry hole	14		—		11		91		1		92
Exploration	5		51		21		64		68		108
Other	110		194		54		25		40		19
Total segmented expenses	1,260		2,399		2,404		710		1,603		1,302
Segmented income (loss) before taxes	(308	)	(1,199	)	(530	)	213		(429	)	751
Non-segmented expenses
General and administrative
Finance costs
Share-based payments expense (recovery)
Currency translation
Gain on held-for-trading financial instruments
(Gain) loss on disposals
Total non-segmented expenses
Loss from continuing operations before taxes
Capital expenditures
Exploration	56		130		116		76		72		139
Development	259		633		1,206		101		138		300
Exploration and development	315		763		1,322		177		210		439
Acquisitions and extension
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment	5,524		5,589		6,321		1,206		1,448		2,223
Exploration and evaluation assets	969		1,030		1,345		479		540		667
Loans from related parties	569		334		—		—		—		—
Goodwill	105		105		110		152		169		169
Investments in joint ventures and associates	—		—		—		—		—		—
Other	1,380		1,240		555		541		591		740
Segmented assets	8,547		8,298		8,331		2,378		2,748		3,799
Non-segmented assets
Total assets
Decommissioning liabilities	699		485		381		398		282		334

1. North America	2016	2015	2014
Canada	415	590	773
US	537	610	1,101
Total revenue and other income	952	1,200	1,874
Canada	2,481	2,522	2,507
US	3,043	3,067	3,814
Property, plant and equipment	5,524	5,589	6,321
Canada	648	708	871
US	321	322	474
Exploration and evaluation assets	969	1,030	1,345

2. Southeast Asia	2016	2015	2014
Indonesia	561	654	1,015
Malaysia	263	328	576
Vietnam	84	138	358
Papua New Guinea	7	—	—
Australia	8	54	104
Total revenue and other income	923	1,174	2,053
Indonesia	465	883	941
Malaysia	615	361	698
Vietnam	124	107	308
Papua New Guinea	2	31	143
Australia	—	66	133
Property, plant and equipment	1,206	1,448	2,223
Indonesia	39	47	37
Malaysia	6	31	41
Vietnam	203	198	191
Papua New Guinea	231	264	398
Exploration and evaluation assets	479	540	667

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	North Sea (3)						Other (4)						Total
(millions of US$)	2016		2015		2014		2016		2015		2014		2016		2015		2014
Revenue
Sales	—		—		—		99		153		272		1,831		2,254		4,126
Other income	—		10		29		7		34		56		150		317		158
Income (loss) from joint ventures and associates, after tax	(266	)	(1,021	)	(1,055	)	62		(65	)	15		(204	)	(1,086	)	(1,040	)
Total revenue and other income	(266	)	(1,011	)	(1,026	)	168		122		343		1,777		1,485		3,244
Segmented expenses
Operating	—		—		—		38		69		62		708		906		1,083
Transportation	—		—		—		11		26		32		158		182		177
DD&A	—		—		—		44		64		52		1,214		1,534		1,634
Impairment, net of reversals	—		—		287		(1	)	338		374		(327	)	1,523		1,314
Dry hole	—		—		—		11		14		38		116		15		141
Exploration	—		16		—		36		40		66		105		175		195
Other	—		32		—		11		9		14		146		275		87
Total segmented expenses	—		48		287		150		560		638		2,120		4,610		4,631
Segmented income (loss) before taxes	(266	)	(1,059	)	(1,313	)	18		(438	)	(295	)	(343	)	(3,125	)	(1,387	)
Non-segmented expenses
General and administrative													244		298		396
Finance costs													190		327		327
Share-based payments expense (recovery)													—		(24	)	25
Currency translation													(67	)	(9	)	(39	)
Gain on held-for-trading financial instruments													—		(61	)	(1,427	)
(Gain) loss on disposals													(73	)	2		(550	)
Total non-segmented expenses													294		533		(1,268	)
Loss from continuing operations before taxes													(637	)	(3,658	)	(119	)
Capital expenditures
Exploration	—		—		—		17		13		149		149		215		404
Development	—		—		—		3		33		12		363		804		1,518
Exploration and development	—		—		—		20		46		161		512		1,019		1,922
Acquisitions and extension													113		31		35
Proceeds on dispositions													(325	)	(396	)	(1,517	)
Other non-segmented													3		24		47
Net capital expenditures													303		678		487
Property, plant and equipment	—		—		256		203		252		264		6,933		7,289		9,064
Exploration and evaluation assets	—		—		125		89		94		407		1,537		1,664		2,544
Loans from related parties	—		—		—		—		—		—		569		334		—
Goodwill	—		—		—		—		—		—		257		274		279
Investments in joint ventures and associates	—		—		—		233		318		523		233		318		523
Other	3		14		2,051		305		293		301		2,229		2,138		3,647
Segmented assets	3		14		2,432		830		957		1,495		11,758		12,017		16,057
Non-segmented assets													—		4		1,273
Total assets													11,778		12,021		17,330
Decommissioning liabilities	—		—		1,176		13		29		37		1,110		796		1,928

3. North Sea	2016		2015		2014
UK	—		10		28
Norway	—		—		1
Loss from RSRUK	(266	)	(1,021	)	(1,055	)
Total revenue and other income	(266	)	(1,011	)	(1,026	)
UK	—		—		—
Norway	—		—		256
Property, plant and equipment	—		—		256
UK	—		—		—
Norway	—		—		125
Exploration and evaluation assets	—		—		125

4. Other	2016	2015	2014
Algeria	94	117	182
Colombia5	74	5	161
Total revenue and other income	168	122	343
Algeria	136	184	224
Colombia	67	68	40
Property, plant and equipment	203	252	264
Colombia	89	94	208
Kurdistan Region of Iraq	—	—	199
Exploration and evaluation assets	89	94	407

(5)    Balances include after-tax equity income from Equion.

67

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/