6-K

FORM 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

November 8, 2016

REPSOL OIL & GAS CANADA INC.

Commission File No. 1-6665

[Translation of registrant’s name into English]

2000, 888 - 3rd Street S.W.,

Calgary, Alberta, Canada, T2P 5C5

[Address of principal executive offices]

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F o   Form 40-F x

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ¨

Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant’s “home country”), or under the rules of the home country exchange on which the registrant’s securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant’s security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.

Exhibit Title

99.1	Interim Condensed Consolidated Financial Statements
99.2	Interim Management’s Discussion and Analysis
99.3	CEO Certification of Interim Filings
99.4	CFO Certification of Interim Filings

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	REPSOL OIL & GAS CANADA INC.
	[Registrant]
Date: November 8, 2016	By:	/s/ Leslie A. Lawson
		Leslie A. Lawson
		Assistant Corporate Secretary

2

EX-99.1

Exhibit 99.1

REPSOL OIL & GAS CANADA INC.

Condensed Consolidated Balance Sheets

(Unaudited)

	September 30,	December 31,
(millions of US$)	2016	2015
Assets
Current
Cash and cash equivalents	81	98
Accounts receivable	357	372
Income and other taxes receivable	39	67
Amount due from related party (note 10)	76	334
Inventories	100	103
Prepaid expenses	18	25
	671	999
Other assets (note 6)	186	184
Investments (note 5)	370	392
Goodwill	274	274
Property, plant and equipment (note 7)	6,860	7,289
Exploration and evaluation assets (note 7)	1,604	1,664
Long-term income tax receivable	21	—
Deferred tax assets	1,441	1,219
	10,756	11,022
Total assets	11,427	12,021
Liabilities
Current
Bank indebtedness	7	7
Accounts payable and accrued liabilities	774	884
Obligation to fund equity investee (note 5)	472	571
Income and other taxes payable	39	65
Loans from joint ventures (note 5)	25	14
Current portion of long-term debt (note 10)	7	156
	1,324	1,697
Decommissioning liabilities (note 8)	851	755
Other long-term obligations (note 11)	330	233
Loans from related parties (note 10)	1,945	1,007
Obligation to fund equity investee (note 5)	308	56
Long-term debt (note 10)	1,436	2,111
Deferred tax liabilities	519	613
	5,389	4,775
Contingencies and commitments (note 14)
Shareholder’s equity
Common shares (note 12)	3,492	3,492
Contributed surplus	86	86
Retained earnings	436	1,271
Accumulated other comprehensive income	700	700
	4,714	5,549
Total liabilities and shareholder’s equity	11,427	12,021

See accompanying notes.

1

Condensed Consolidated Statements of Loss

(Unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
(millions of US$)	2016		2015		2016		2015
			(restated)				(restated)
Revenue
Sales	473		541		1,307		1,762
Other income (note 15)	30		35		103		123
Loss from joint ventures, after tax (note 5)	(190	)	(231	)	(312	)	(545	)
Total revenue and other income	313		345		1,098		1,340
Expenses
Operating	175		226		529		677
Transportation	38		47		121		137
General and administrative	56		61		177		228
Depreciation, depletion and amortization	301		394		924		1,184
Impairment, net of reversals (note 7)	14		325		14		373
Dry hole	41		1		54		14
Exploration	19		20		81		142
Finance costs (note 9)	44		83		145		246
Share-based payments recovery	—		—		—		(24	)
Gain on held-for-trading financial instruments	—		—		—		(62	)
(Gain) loss on disposals	(1	)	—		6		9
Other, net (note 16)	5		34		32		180
Total expenses	692		1,191		2,083		3,104
Loss from continuing operations before taxes	(379	)	(846	)	(985	)	(1,764	)
Income taxes (note 17)
Current income tax expense (recovery)	40		(359	)	115		(224	)
Deferred income tax expense (recovery)	(96	)	412		(326	)	644
	(56	)	53		(211	)	420
Net loss from continuing operations	(323	)	(899	)	(774	)	(2,184	)
Discontinued operations
Net income (loss) from discontinued operations (note 4)	—		112		—		(294	)
Net loss	(323	)	(787	)	(774	)	(2,478	)
Per common share (US$):
Net loss from continuing operations	(0.18	)	(0.86	)	(0.42	)	(2.11	)
Net income (loss) from discontinued operations	—		0.11		—		(0.28	)
Net loss	(0.18	)	(0.75	)	(0.42	)	(2.39	)
Diluted net loss from continuing operations	(0.18	)	(0.86	)	(0.42	)	(2.14	)
Diluted net income (loss) from discontinued operations	—		0.11		—		(0.28	)
Diluted net loss	(0.18	)	(0.75	)	(0.42	)	(2.42	)
Weighted average number of common shares outstanding (millions)
Basic	1,830		1,044		1,830		1,039
Diluted	1,830		1,044		1,830		1,039

See accompanying notes.

2

Condensed Consolidated Statements of Comprehensive Loss

(Unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
(millions of US$)	2016		2015		2016		2015
Net loss	(323	)	(787	)	(774	)	(2,478	)
Items to be reclassified to net income or loss in subsequent periods:
Foreign currency translation	—		3		—		3
Transfer of accumulated comprehensive income on disposition of foreign operations	—		(114	)	—		(114	)
Items not to be reclassified to net income or loss in subsequent periods:
Remeasurements relating to pension and other post-employment benefits1	(1	)	(4	)	(6	)	7
Share of remeasurements relating to pension and other post-employment benefit plans from joint ventures2 (note 5)	(26	)	—		(55	)	—
Other comprehensive loss	(27	)	(115	)	(61	)	(104	)
Comprehensive loss	(350	)	(902	)	(835	)	(2,582	)

(1)  For the three and nine months ended September 30, 2016, amount is net of tax of $nil and $2 million respectively (2015 - $2 million and $2 million respectively).

(2)  For the three and nine months ended September 30, 2016, amount is net of tax of $nil and $nil respectively.

See accompanying notes.

3

Condensed Consolidated Statements of Changes in Shareholder’s Equity

(Unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
(millions of US$)	2016		2015		2016		2015
Common shares (note 12)
Balance at beginning of period	3,492		1,992		3,492		1,738
Converted from preferred shares	—		—		—		195
Shares purchased and held in trust for long-term PSU plan	—		—		—		(30	)
Shares in trust sold on open market	—		—		—		3
Shares released from trust for long-term PSU plan	—		—		—		86
Balance at end of period	3,492		1,992		3,492		1,992
Contributed surplus
Balance at beginning of period	86		86		86		176
Preferred shares conversion difference	—		—		—		(4	)
Settlement of long-term PSU plan grant	—		—		—		(104	)
Share-based payments	—		—		—		18
Balance at end of period	86		86		86		86
Retained earnings
Balance at beginning of period	786		2,690		1,271		4,489
Net loss	(323	)	(787	)	(774	)	(2,478	)
Remeasurements of employee benefit plans transferred to retained earnings	(1	)	(4	)	(6	)	7
Share of remeasurements of employee benefit plans from joint ventures transferred to retained earnings	(26	)	—		(55	)	—
Common share dividends	—		—		—		(117	)
Preferred share dividends	—		—		—		(2	)
Balance at end of period	436		1,899		436		1,899
Accumulated other comprehensive income
Balance at beginning of period	700		811		700		811
Other comprehensive loss	(27	)	(115	)	(61	)	(104	)
Remeasurements of employee benefit plans transferred to retained earnings	1		4		6		(7	)
Share of remeasurements of employee benefit plans from joint ventures transferred to retained earnings	26		—		55		—
Balance at end of period	700		700		700		700

See accompanying notes.

4

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
(millions of US$)	2016		2015		2016		2015
			(restated)				(restated)
Operating activities
Net loss from continuing operations	(323	)	(899	)	(774	)	(2,184	)
Add: Finance costs (cash and non-cash) (note 9)	44		83		145		246
Items not involving cash (note 18)	440		1,378		928		4,077
	161		562		299		2,139
Changes in non-cash working capital	(7	)	(393	)	(45	)	(370	)
Cash provided by operating activities from continuing operations	154		169		254		1,769
Investing activities
Capital expenditures
Exploration, development and other	(128	)	(295	)	(354	)	(791	)
Property acquisitions and extension	—		(2	)	(62	)	(10	)
Proceeds on dispostions net of payments	—		—		(10	)	—
Investment in joint ventures (note 5)	(54	)	(97	)	(237	)	(459	)
Changes in non-cash working capital	31		(2	)	(4	)	(230	)
Cash used in investing activities from continuing operations	(151	)	(396	)	(667	)	(1,490	)
Financing activities
Long-term debt repaid (note 10)	—		—		(751	)	(1,558	)
Long-term debt issued (note 10)	—		—		—		452
Loans from joint ventures (note 5)	26		22		60		81
Loans from related parties (note 10)	19		128		937		959
Amount due from related party (note 10)	(23	)	—		258		—
Common shares purchased (note 12)	—		—		—		(30	)
Common shares held in trust sold (note 12)	—		—		—		3
Finance costs (cash)	(34	)	(73	)	(115	)	(223	)
Common share dividends	—		—		—		(117	)
Preferred share dividends	—		—		—		(2	)
Deferred credits and other	(1	)	(9	)	(8	)	(39	)
Changes in non-cash working capital	12		16		15		26
Cash provided by (used in) financing activities from continuing operations	(1	)	84		396		(448	)
Effect of translation on foreign currency cash and cash equivalents	—		—		—		1
Cash used in operating activities from discontinued operations (note 4)	—		(5	)	—		(29	)
Cash provided by investing activities from discontinued operations (note 4)	—		46		—		9
Net increase (decrease) in cash and cash equivalents	2		(102	)	(17	)	(188	)
Cash and cash equivalents net of bank indebtedness, beginning of period	72		167		91		253
Cash and cash equivalents net of bank indebtedness, end of period	74		65		74		65
Cash and cash equivalents	81		78		81		78
Bank indebtedness	(7	)	(13	)	(7	)	(13	)
Cash and cash equivalents net of bank indebtedness, end of period	74		65		74		65

See accompanying notes.

5

Notes to the Interim Condensed Consolidated Financial Statements

(Unaudited)

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

1. CORPORATE 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 — 3rd Street SW, Calgary, Alberta, Canada, T2P 5C5.

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

The interim condensed Consolidated Financial Statements as at and for the three and nine month periods ended September 30, 2016 were approved by the Audit Committee on November 7, 2016.

2. BASIS OF PREPARATION

These interim condensed Consolidated Financial Statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting as issued by the International Accounting Standards Board (IASB). Certain information and disclosures required to be included in notes to annual Consolidated Financial Statements prepared in accordance with International Financial Reporting Standards (IFRS) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC), as issued by the IASB, have been condensed or omitted.

The interim condensed Consolidated Financial Statements should be read in conjunction with the audited annual Consolidated Financial Statements as at and for the year ended December 31, 2015 and the notes thereto.

These interim condensed Consolidated Financial Statements were prepared on a going concern basis, under the historical cost convention, except for certain financial assets and liabilities measured at fair value through the interim condensed Consolidated Statement of Loss.

Comparative period balances of the interim condensed 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.

6

3. SIGNIFICANT ACCOUNTING POLICIES

The interim condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the audited annual Consolidated Financial Statements as at and for the year ended December 31, 2015.

4. 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 interim condensed Consolidated Statements of Loss for the period of ownership. Comparative period balances of the interim condensed Consolidated Statements of Loss and Cash Flows have been restated.

Net income (loss) from discontinued operations reported on the interim condensed Consolidated Statements of Loss is composed of the following:

	Three months ended September 30, 2015		Nine months ended September 30, 2015
Revenue	38		182
Expenses	(28	)	(429	)
	10		(247	)
Loss on remeasurement of discontinued operations	(10	)	(482	)
Realized accumulated translation adjustments on disposition of foreign operations	114		114
Income (loss) from discontinued operations before taxes	114		(615	)
Income taxes
Current income tax recovery	(1	)	(8	)
Deferred income tax expense (recovery)	3		(313	)
Net income (loss) from discontinued operations	112		(294	)

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

	Three months ended September 30, 2015		Nine months ended September 30, 2015
Operating	(5	)	(29	)
Investing	46		9
Cash flows from discontinued operations	41		(20	)

7

5. INVESTMENTS

	September 30, 2016	December 31, 2015
Investments in Joint Ventures
Equity investment in Equion Energía Limited (“Equion”)	292	318
Available-for-sale investments
Transasia Pipeline Company Pvt. Ltd.	34	34
Other	44	40
	78	74
	370	392

	September 30, 2016		December 31, 2015
Obligation to Fund Equity Investee1
Equity investment in Repsol Sinopec Resources UK (“RSRUK”)2	(780	)	(627	)

(1)The Company’s planned equity funding for the next 12 months is $472 million net (December 31, 2015 - $571 million). The remaining $308 million (December 31, 2015 - $56 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 and is one of two shareholders in this strategic corporate joint venture. The movement in the investment in Equion joint venture during the period is as follows:

	Nine months ended September 30, 2016		Year ended December 31, 2015
Balance, beginning of period	318		523
Share of net income (loss) and comprehensive income (loss)	23		(65	)
Dividend declared by Equion1	(49	)	(93	)
Impairment	—		(47	)
Balance, end of period	292		318

(1) Settled through a reduction in the loan payable to Equion, which is unsecured, due upon demand and bears interest at LIBOR plus 0.3%.

RSRUK Joint Venture

The Company has a 51% interest in the ownership and voting rights of RSRUK and is one of two shareholders in the corporate joint venture. The movement in the investment in the RSRUK joint venture during the period is as follows:

	Nine months ended September 30, 2016		Year ended December 31, 2015
Balance, beginning of period	(627	)	(186	)
Investment in RSRUK	237		1,094
Loan to RSRUK, net of repayments and settlements	—		(514	)
Share of net loss and comprehensive loss	(390	)	(1,021	)
Balance, end of period	(780	)	(627	)

8

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.

	September 30, 2016						December 31, 2015
Summarized Balance Sheets	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Cash and cash equivalents	37		67		104		20		108		128
Other current assets	243		188		431		275		140		415
Loans receivable from shareholders	—		51		51		—		29		29
Non-current assets	3,808		659		4,467		3,957		836		4,793
Total assets	4,088		965		5,053		4,252		1,113		5,365
Current liabilities	594		135		729		655		184		839
Decommissioning liabilities	5,064		17		5,081		4,952		19		4,971
Non-current liabilities	111		180		291		26		224		250
Total liabilities	5,769		332		6,101		5,633		427		6,060
Net assets (liabilities)	(1,681	)	633		(1,048	)	(1,381	)	686		(695	)
ROGCI’s interest	51	%	49	%			51	%	49	%
ROGCI’s share of net assets (liabilities)	(857	)	310		(547	)	(704	)	336		(368	)
Goodwill	77		162		239		77		162		239
	(780	)	472		(308	)	(627	)	498		(129	)
Accumulated impairment on investment	—		(180	)	(180	)	—		(180	)	(180	)
ROGCI’s investment (obligation to fund)	(780	)	292		(488	)	(627	)	318		(309	)

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

9

	Three months ended						Three months ended
Summarized Statements of Income	September 30, 2016						September 30, 2015
(Loss)	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Revenue	158		106		264		208		152		360
Operating	207		14		221		253		17		270
Transportation	5		9		14		2		11		13
General and administrative	3		—		3		1		—		1
Depreciation, depletion and amortization	32		58		90		164		89		253
Exploration expense	1		—		1		2		—		2
Finance costs	53		—		53		56		1		57
Impairment	135		—		135		—		—		—
Other	13		—		13		24		30		54
Income (loss) before tax	(291	)	25		(266	)	(294	)	4		(290	)
Current income tax expense (recovery)	(31	)	(3	)	(34	)	(18	)	35		17
Deferred income tax expense	132		7		139		132		16		148
Net income (loss)	(392	)	21		(371	)	(408	)	(47	)	(455	)
Other comprehensive loss	(51	)	—		(51	)	—		—		—
Comprehensive income (loss)	(443	)	21		(422	)	(408	)	(47	)	(455	)
ROGCI’s interest	51	%	49	%			51	%	49	%
ROGCI’s share of income (loss)	(200	)	10		(190	)	(208	)	(23	)	(231	)
ROGCI’s share of other comprehensive loss	(26	)	—		(26	)	—		—		—
ROGCI’s share of comprehensive income (loss)	(226	)	10		(216	)	(208	)	(23	)	(231	)

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

10

	Nine months ended						Nine months ended
Summarized Statements of Income	September 30, 2016						September 30, 2015
(Loss)	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Revenue	477		299		776		598		382		980
Operating	563		38		601		730		56		786
Transportation	14		30		44		13		27		40
General and administrative	(15	)	—		(15	)	42		—		42
Restructuring costs	—		—		—		5		—		5
Depreciation, depletion and amortization	187		193		380		448		240		688
Exploration expense	5		—		5		4		—		4
Finance costs	160		1		161		134		2		136
Impairment	146		—		146		260		—		260
Other	27		8		35		71		33		104
Income (loss) before tax	(610	)	29		(581	)	(1,109	)	24		(1,085	)
Current income tax expense (recovery)	(72	)	29		(43	)	(70	)	51		(19	)
Deferred income tax expense (recovery)	119		(47	)	72		(2	)	6		4
Net income (loss)	(657	)	47		(610	)	(1,037	)	(33	)	(1,070	)
Other comprehensive loss	(107	)	—		(107	)	—		—		—
Comprehensive income (loss)	(764	)	47		(717	)	(1,037	)	(33	)	(1,070	)
ROGCI’s interest	51	%	49	%			51	%	49	%
ROGCI’s share of income (loss)	(335	)	23		(312	)	(529	)	(16	)	(545	)
ROGCI’s share of other comprehensive loss	(55	)	—		(55	)	—		—		—
ROGCI’s share of comprehensive income (loss)	(390	)	23		(367	)	(529	)	(16	)	(545	)

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

11

	Three months ended September 30, 2016						Three months ended September 30, 2015
Summarized Statements of Cash Flows	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Cash provided by (used in) operating activities	(9	)	26		17		22		105		127
Cash used in investing activities	(95	)	(60	)	(155	)	(188	)	(77	)	(265	)
Cash provided by financing activities	103		—		103		188		—		188

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

	Nine months ended September 30, 2016						Nine months ended September 30, 2015
Summarized Statements of Cash Flows	RSRUK1		Equion1		Total		RSRUK1		Equion1		Total
Cash provided by (used in) operating activities	(195	)	110		(85	)	(226	)	255		29
Cash used in investing activities	(246	)	(151	)	(397	)	(663	)	(289	)	(952	)
Cash provided by financing activities	458		—		458		897		—		897

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

RSRUK Joint Venture

As at September 30, 2016, the investment balance in the RSRUK joint venture was negative $780 million. Based on anticipated funding requirements in the next 12 months, the Company has recorded $472 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 June 2015, the shareholders of RSRUK provided an equity funding facility of $1.7 billion, of which the Company is committed to $867 million, for the purpose of funding capital, decommissioning and operating expenditures of RSRUK. This facility is effective from July 1, 2015 and had a maturity date of December 31, 2016. In September 2016, this agreement was modified to extend the maturity date to December 31, 2017. During the three and nine month periods ended September 30, 2016, the shareholders of RSRUK agreed to subscribe for common shares of RSRUK in the amount of $105 million and $465 million under this facility, respectively, of which the Company’s share was $54 million and $237 million, respectively.

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

12

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 13.

Equion Joint Venture

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

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

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

6. OTHER ASSETS

	September 30, 2016	December 31, 2015
Accrued pension asset	4	4
Decommissioning sinking fund	94	85
Transportation rights1	77	84
Other	11	11
Total	186	184

(1)Net of $31 million accumulated depreciation (December 31, 2015 - $24 million).

13

7. 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	68		1		69
Additions	255		100		355
Disposals and derecognition	(436	)	—		(436	)
Transfers from E&E assets to PP&E	108		(108	)	—
Change in decommissioning liabilities	165		(4	)	161
Expensed to dry hole	—		(54	)	(54	)
At September 30, 2016	19,751		3,327		23,078
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	926		—		926
Disposals and derecognition	(356	)	—		(356	)
Transfers from E&E assets to PP&E	19		(19	)	—
Impairment, net of reversals	—		14		14
At September 30, 2016	12,891		1,723		14,614
Net book value
At September 30, 2016	6,860		1,604		8,464
At December 31, 2015	7,289		1,664		8,953
At December 31, 2014	9,064		2,544		11,608

(1)    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, respectively.

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 14) and recognized an additional $160 million decommissioning liability (note 8). In addition, the Company committed to pay a lease extension payment

14

of $60 million in various tranches until 2020 of which $29 million and $24 million, respectively, were included in accounts payable and other long-term obligations (note 11) on the interim condensed Consolidated Balance Sheets as at September 30, 2016.

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.

8. DECOMMISSIONING LIABILITIES

Continuity of decommissioning liabilities	Nine months ended  September 30, 2016		Year ended  December 31, 2015
Balance, beginning of period	796		1,928
Liabilities incurred during the period	170		47
Liabilities settled during the period	(20	)	(84	)
Accretion expense	30		48
Revisions in estimated cash flows	(3	)	(201	)
Change in discount rate	—		256
Disposals	(86	)	(1,198	)
Balance, end of period	887		796
Expected to be settled within one year	36		41
Expected to be settled in more than one year	851		755
	887		796

During the nine months ended September 30, 2016, the Company recognized an additional $160 million decommissioning liability as a result of a PSC extension in Malaysia. In addition, $86 million of decommissioning liability was disposed of as a result of the asset sale in Australia/Timor-Leste (note 7). The provision has been discounted using a weighted average credit-adjusted nominal rate of 4.8% at September 30, 2016 (December 31, 2015 — 4.8%).

9. FINANCE COSTS

	Three months ended  September 30		Nine months ended  September 30
	2016	2015	2016	2015
Interest on long-term debt	23	62	79	192
Interest on loans from related parties	8	4	20	5
Miscellaneous interest expense and other fees	3	7	16	26
Accretion expense	10	10	30	23
	44	83	145	246

15

10. LONG-TERM DEBT

	September 30, 2016		December 31, 2015
Tangguh Project Financing	34		37
Debentures and Notes (Unsecured)
US$ denominated	1,085		1,860
UK£ denominated (UK£ million)	324		370
Gross debt	1,443		2,267
Less: current portion	(7	)	(156	)
Long-term debt	1,436		2,111

	September 30, 2016	December 31, 2015
Loans from Related Parties	1,945	1,007

During the nine month period ended September 30, 2016, the Company repaid debt of $751 million, including $150 million of 8.5% notes due in March 2016, $598 million of USD senior notes and debentures redeemed and repurchased, and $3 million of Tangguh project financing loan. The current liability consists of $7 million in Tangguh project financing.

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. As a result of the cancellation, the Company no longer has the principal financial covenant of a debt-to-cash flow ratio of less than 3.5:1.

16

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 (collectively, the “Securities”). The principal amount tendered and accepted was as follows:

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

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

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

The above discussed tender offer and redemption of outstanding senior notes resulted in a gain of $26 million (net of $7 million financing and bank fees), which was recognized in other income on the interim condensed Consolidated Statements of Loss.

Tangguh Project Financing

In connection with its interest in the Tangguh LNG project, the Company is a participant in a series of project financing facilities, the Company’s share of which is up to $105 million. At September 30, 2016, approximately $34 million was outstanding under these facilities.

During the nine month period ended September 30, 2016, an LNG expansion project in Indonesia was approved. As a result, the Company became a participant in a second series of project financing facilities, the Company’s share of which is up to $114 million. Draws under these facilities bear interest at LIBOR plus 1.37% to LIBOR plus 3.45% per annum. These facilities are to mature on July 20, 2029.

17

Related Party Facilities

On May 8, 2015, TE Holding SARL. (“TEHS”), a subsidiary of the Company, entered into a $500 million revolving facility with Repsol Tesoreria y Gestion Financiera, S.A. (“RTYGF”), a subsidiary of Repsol. Originally, the facility was to mature on May 8, 2016 and to bear an interest rate of LIBOR (1 month) plus 0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. On November 17, 2015, the interest rate in the facility agreement was amended to LIBOR (1 month) plus 1.20%. Effective June 13, 2016, the credit limit of this facility was increased to $550 million. As at September 30, 2016, there were $446 million drawings outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine months ended September 30, 2016 was $2 million and $4 million, respectively.

On May 8, 2015, the Company also entered into a $1.0 billion revolving facility with Repsol Energy Resources Canada, Inc. (“RERCI”), a subsidiary of Repsol. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) plus 1.20%. The facility limit was increased to $2.8 billion on December 9, 2015. At September 30, 2016, the Company had $1.5 billion outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine month periods ended September 30, 2016 was $6 million and $16 million, respectively.

On December 22, 2015, the Company and RERCI entered into a subscription agreement which provides for the capitalization of the Company’s balances owing under this revolving facility. The Board of Directors of the Company authorized the issuance of up to an aggregate of $2.6 billion in common shares of the Company (1,361,256,544 common shares at $1.91 per share), to be settled by RERCI contributing receivables owing from the Company under this revolving facility. As at September 30, 2016, $1.1 billion drawings remained available under the subscription agreement.

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

18

11. OTHER LONG-TERM OBLIGATIONS

	September 30, 2016	December 31, 2015
Accrued pension and other post-employment benefits liabilities	98	86
Deferred credits	34	22
Long-term portion of discounted obligations under finance leases	25	31
Onerous lease contracts and other provisions	74	27
Long-term lease extension payment (note 7)	24	—
Other	75	67
	330	233

The fair value of financial liabilities included above approximates the carrying amount.

12. SHARE CAPITAL

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.

Common Shares Issued

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

On December 29, 2015, RERCI, a subsidiary of the Company’s parent Repsol, 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 10).

Subsequent to December 31, 2015, there were no activities relating to the Company’s common shares.

	Year ended December 31, 2015
Continuity of common shares	Shares		Amount
Balance, beginning of period	1,031,525,988		1,738
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	(3,793,939	)	(30	)
Shares released from trust for long-term PSU plan	8,110,395		86
Balance, end of period	1,829,506,342		3,492

19

13. FINANCIAL INSTRUMENTS

The Company’s financial assets and liabilities at September 30, 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).

Fair Value of Financial Assets and Liabilities

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

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 September 30, 2016 was $3.4 billion (December 31, 2015 - $3.2 billion), and the carrying value was $3.4 billion (December 31, 2015 - $3.3 billion). The Company uses Level 2 inputs to estimate the fair value of the outstanding long-term debt as at September 30, 2016.

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

Currency Risk

The Company operates internationally and is therefore exposed to foreign exchange risk.  The Company’s 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.  The Company 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 its current foreign currency obligations as they come due.

In respect of financial instruments existing at September 30, 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 $2 million impact on comprehensive loss during the three month period ended September 30, 2016. A similar weakening of the US$ would have had the opposite impact.

20

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). Risk management activities aim to manage the mix of fixed-to-floating debt to best manage the trade-off between longer term interest rate reset risk and shorter term volatility in interest rates.

In respect of financial instruments existing at September 30, 2016, a 1% increase in interest rates would have resulted in a $3 million increase in net loss and a $3 million impact on comprehensive loss during the three month period ended September 30, 2016.

Credit Risk

A significant proportion of the Company’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At September 30, 2016, approximately 84% of the Company’s accounts receivable was current and the largest single counterparty exposure, accounting for 5% of the total, was with a highly rated counterparty. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base primarily of highly rated counterparties.

Liquidity Risk

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

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 2015 and 2016, the Company also entered into three revolving facilities with subsidiaries of its parent, Repsol, with total borrowing limit of $3.5 billion (note 10). As at September 30, 2016, a total of $1.9 billion drawings were outstanding under these facilities (note 10). The subscription agreement underlying the revolving facility provides for the capitalization of the Company’s balances owing (note 12).

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted.  At September 30, 2016, the Company had $0.2 billion letters of credit outstanding, primarily related to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations.  The Company also guaranteed $0.8 billion demand letters of credit issued under RSRUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK. In addition, there were $87 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

RSRUK is required to provide 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 Petroleum UK Limited (Addax) assumed 49% of the decommissioning obligations of RSRUK. Addax’s parent company, China

21

Petrochemical Corporation, has provided an unconditional and irrevocable guarantee for this 49% of the UK decommissioning obligations.

The UK government passed legislation in 2013 which provides for a contractual instrument, known as a Decommissioning Relief Deed, for the government to guarantee tax relief on decommissioning costs at 50%, allowing security under DSAs to be posted on an after-tax basis and reducing the value of letters of credit required to be posted by 50%. RSRUK has entered into a Decommissioning Relief Deed with the UK Government and continues to negotiate with counterparties to amend all DSAs accordingly. As of September 30, 2016, only two DSAs were still required to be negotiated on a post-tax basis. Tax relief guaranteed by the UK government is limited to corporate tax paid since 2002. Under the limitation, RSRUK’s tax relief is capped at $1.7 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At September 30, 2016, RSRUK has $2.9 billion of demand shared facilities in place under which letters of credit of $1.6 billion have been issued. The Company guarantees 51% of all letters of credit issued under these shared facilities.

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

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

At September 30, 2016, the Company’s share of RSRUK’s total recorded decommissioning liabilities was $2.7 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.

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.

22

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 substantially all its contracts related to commodity price risk management. The Company has not entered into any new commodity price risk management derivative contracts subsequently.

14. CONTINGENCIES AND COMMITMENTS

Provisions and Contingencies

From time to time, the Company is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below, may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While the Company assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. None of these claims are currently expected to have a material impact on the Company’s financial position. A summary of specific legal proceedings and contingencies is as follows:

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

On July 13, 2015, Addax and Sinopec International Petroleum Exploration and Production Corporation (“Sinopec”), filed a “Notice of Arbitration” against ROGCI and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% of the shares of RSRUK. ROGCI and TCHL filed their response to the Notice of Arbitration on October 1, 2015. On May 25, 2016, Addax and Sinopec filed their Statement of Claim, in which they seek, in the event that their claims were confirmed in their entirety, repayment of their initial investment in RSRUK, together with any additional investment, past or future, in such company, and further for any loss of opportunity, which they estimate in a total approximate amount of $5.5 billion. The Court of Arbitration has decided, among other procedural matters, to schedule the hearing for January 29 to February 16, 2018. The Company believes the claims included in the Statement of Claim are without merit.

During the first quarter of 2016, the Alberta Energy Regulator (“AER”) informed the Company that certain permits to construct well sites and access roads were obtained without the Company following proper procedures. The Company

23

continues to investigate its permit applications and work with the AER in this matter. At this time, the implications to the Company are not known.

Government and Legal Proceedings with Tax Implications

Specific tax claims which the Company and its subsidiaries are parties to at September 30, 2016 are as follows:

Canada

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

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

Indonesia

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

Malaysia

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

Timor-Leste

The authorities of Timor-Leste, questioned the deduction by Talisman Resources (JPDA 06-105) Pty Limited, the Company’s subsidiary in East Timor, of certain expenses for income tax purposes. This line of questioning is at a very preliminary stage of debate with the authorities.

Commitments

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

As a result of the PSC extension in Malaysia in April 2016 (note 7), the Company agreed to $180 million in additional minimum work commitments.

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

24

15. OTHER INCOME

	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015
Pipeline and customer treating tariffs	4	6	11	32
Investment income	4	4	4	10
Interest on loan to RSRUK (note 5)	—	—	—	10
Net gain on repayment of long-term debt (note 10)	—	—	26	—
Marketing and other miscellaneous income	22	25	62	71
	30	35	103	123

16. OTHER EXPENSES, NET

	Three months ended September 30			Nine months ended September 30
	2016		2015	2016		2015
Foreign exchange (gain) loss	(19	)	3	(45	)	8
Restructuring	1		—	15		35
Transaction costs1	—		—	—		41
Onerous lease contracts	12		3	15		8
Other miscellaneous	11		28	47		88
	5		34	32		180

(1) Costs incurred in relation to the acquisition of ROGCI by Repsol.

17. INCOME TAXES

Current Income Tax Expense (Recovery)

	Three months ended September 30			Nine months ended September 30
	2016	2015		2016	2015
North America	—	—		1	(5	)
Southeast Asia	39	60		111	189
North Sea	—	(419	)	—	(418	)
Other	1	—		3	10
Total	40	(359	)	115	(224	)

25

Deferred Income Tax Expense (Recovery)

	Three months ended September 30				Nine months ended September 30
	2016		2015		2016		2015
North America	(66	)	(36	)	(244	)	141
Southeast Asia	(29	)	(13	)	(65	)	2
North Sea	—		445		—		469
Other	(1	)	16		(17	)	32
Total	(96	)	412		(326	)	644

18. SUPPLEMENTAL CASH FLOW

Items Not Involving Cash

	Three months ended September 30			Nine months ended September 30
	2016		2015	2016		2015
Depreciation, depletion and amortization	301		394	924		1,184
Impairment, net of reversals	14		325	14		373
Dry hole	41		1	54		14
(Gain) loss on disposals	(1	)	—	6		9
Unrealized loss on held-for-trading financial instruments	—		—	—		1,268
Deferred income tax	(96	)	412	(326	)	644
Foreign exchange	(21	)	3	(50	)	16
Loss from joint ventures and associates, after tax	190		231	312		545
Other	12		12	(6	)	24
	440		1,378	928		4,077

Other Cash Flow Information

	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015
Cash interest paid	26	55	94	185
Cash interest received	—	—	1	1
Cash income taxes paid	42	80	130	227

26

19. RELATED PARTY DISCLOSURES

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

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

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

The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings (Private) Limited (“Temasek”). Currently, ROGCI’s share of the sale on a daily basis is approximately 75 billion btu. The commitment matures in 2023.  As a result of the acquisition of the Company by Repsol, GSPL and Temasek became the Company’s related parties. During the three and nine month periods ended September 30, 2016, the Company’s gas sales to GSPL totaled $37 million and $87 million, respectively (net the Company’s share). As at September 30, 2016, the amount included in accounts receivable as a result of this commitment was $22 million.

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

Other transactions between the Company and subsidiaries of the Company’s parent, Repsol, are disclosed in notes 4, 10 and 12. Related party transactions with joint ventures are disclosed as part of note 5.

27

20. 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 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)
	Three months ended September 30				Nine months ended September 30				Three months ended September 30			Nine months ended September 30
(millions of US$)	2016		2015		2016		2015		2016		2015	2016	2015
Revenue
Sales	220		225		581		727		224		288	662	910
Other income	28		27		93		79		1		1	3	2
Income (loss) from joint ventures, after tax	—		—		—		—		—		—	—	—
Total revenue and other income	248		252		674		806		225		289	665	912
Segmented expenses
Operating	86		114		280		362		80		97	222	266
Transportation	24		25		75		76		13		13	38	41
DD&A	226		258		685		767		64		122	208	372
Impairment, net of reversals	—		325		—		325		13		—	13	48
Dry hole	2		—		15		—		39		1	39	—
Exploration	1		(3	)	2		44		14		16	56	52
Other	16		7		56		116		8		2	13	25
Total segmented expenses	355		726		1,113		1,690		231		251	589	804
Segmented income (loss) from continuing operations before taxes	(107	)	(474	)	(439	)	(884	)	(6	)	38	76	108
Non-segmented expenses
General and administrative
Finance costs
Share-based payments recovery
Currency translation
Gain on held-for-trading
Financial instruments
(Gain) loss on asset disposals
Total non-segmented expenses
Loss from continuing operations before taxes
Capital expenditure
Exploration	10		45		39		84		48		9	50	54
Development	39		179		178		471		23		46	62	109
Exploration and development	49		224		217		555		71		55	112	163
Acquisitions and extension
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment					5,183		5,589					1,459	1,448
Exploration and evaluation assets					960		1,030					536	540
Amount due from related party					76		334					—	—
Goodwill					105		105					169	169
Investments in joint ventures and associates					—		—					—	—
Other					1,370		1,240					668	591
Segmented assets					7,694		8,298					2,832	2,748
Non-segmented assets
Total assets (5)
Decommissioning liabilities (5)					497		485					366	282

	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015
1. North America
Canada	104	95	296	332
US	144	157	378	474
Total revenue and other income	248	252	674	806
Canada			2,292	2,522
US			2,891	3,067
Property, plant and equipment (5)			5,183	5,589
Canada			650	708
US			310	322
Exploration and evaluation assets (5)			960	1,030

	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015
2. Southeast Asia
Indonesia	146	161	416	506
Malaysia	59	95	176	263
Vietnam	18	33	59	111
Papua New Guinea	2	—	5	—
Australia	—	—	9	32
Total revenue and other income	225	289	665	912
Indonesia			847	883
Malaysia			516	361
Vietnam			73	107
Papua New Guinea			23	31
Australia			—	66
Property, plant and equipment (5)			1,459	1,448
Indonesia			58	47
Malaysia			13	31
Vietnam			202	198
Papua New Guinea			263	264
Exploration and evaluation assets (5)			536	540

(5)  Current year represents balances at September 30. Prior year represents balances at December 31.

28

	North Sea (3)								Other (4)							Total
	Three months ended September 30				Nine months ended September 30				Three months ended September 30			Nine months ended September 30				Three months ended September 30				Nine months ended September 30
(millions of US$)	2016		2015		2016		2015		2016	2015		2016		2015		2016		2015		2016		2015
Revenue
Sales	—		—		—		—		29	28		64		125		473		541		1,307		1,762
Other income	—		1		—		11		1	6		7		31		30		35		103		123
Income (loss) from joint ventures, after tax	(200	)	(208	)	(335	)	(529	)	10	(23	)	23		(16	)	(190	)	(231	)	(312	)	(545	)
Total revenue and other income	(200	)	(207	)	(335	)	(518	)	40	11		94		140		313		345		1,098		1,340
Segmented expenses
Operating	—		—		—		—		9	15		27		49		175		226		529		677
Transportation	—		—		—		—		1	9		8		20		38		47		121		137
DD&A	—		—		—		—		11	14		31		45		301		394		924		1,184
Impairment, net of reversals	—		—		—		—		1	—		1		—		14		325		14		373
Dry hole	—		—		—		—		—	—		—		14		41		1		54		14
Exploration	—		(4	)	—		16		4	11		23		30		19		20		81		142
Other	—		19		—		23		—	3		8		8		24		31		77		172
Total segmented expenses	—		15		—		39		26	52		98		166		612		1,044		1,800		2,699
Segmented income (loss) from continuing operations before taxes	(200	)	(222	)	(335	)	(557	)	14	(41	)	(4	)	(26	)	(299	)	(699	)	(702	)	(1,359	)
Non-segmented expenses
General and administrative																56		61		177		228
Finance costs																44		83		145		246
Share-based payments recovery																—		—		—		(24	)
Currency translation																(19	)	3		(45	)	8
Gain on held-for-trading financial instruments																—		—		—		(62	)
(Gain) loss on asset disposals																(1	)	—		6		9
Total non-segmented expenses																80		147		283		405
Loss from continuing operations before taxes																(379	)	(846	)	(985	)	(1,764	)
Capital expenditure
Exploration	—		—		—		—		6	1		14		10		64		55		103		148
Development	—		—		—		—		—	7		2		27		62		232		242		607
Exploration and development	—		—		—		—		6	8		16		37		126		287		345		755
Acquisitions and extension																2		3		69		11
Proceeds on dispositions																—		—		—		—
Other non-segmented																—		3		3		22
Net capital expenditures																128		293		417		788
Property, plant and equipment					—		—					218		252						6,860		7,289
Exploration and evaluation assets					—		—					108		94						1,604		1,664
Amount due from related party					—		—					—		—						76		334
Goodwill					—		—					—		—						274		274
Investments in joint ventures and associates					—		—					292		318						292		318
Other					6		14					272		293						2,316		2,138
Segmented assets					6		14					890		957						11,422		12,017
Non-segmented assets																				5		4
Total assets (5)																				11,427		12,021
Decommissioning liabilities (5)					—		—					24		29						887		796

	Three months ended September 30				Nine months ended September 30
	2016		2015		2016		2015
3. North Sea
UK	—		—		—		10
Norway	—		1		—		1
Loss from RSRUK	(200	)	(208	)	(335	)	(529	)
Total revenue and other income	(200	)	(207	)	(335	)	(518	)

	Three months ended September 30			Nine months ended September 30
	2016	2015		2016	2015
4. Other
Algeria	29	15		61	93
Colombia6	11	(4	)	33	47
Total revenue and other income	40	11		94	140
Algeria				152	184
Colombia				66	68
Property, plant and equipment (5)				218	252
Colombia				108	94
Kurdistan Region of Iraq				—	—
Exploration and evaluation assets (5)				108	94

(5)  Current year represents balances at September 30. Prior year represents balances at December 31.

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

29

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/

EX-99.2

Exhibit 99.2

Management’s Discussion and Analysis (MD&A)

(November 8, 2016)

General

This interim MD&A should be read in conjunction with the unaudited interim condensed Consolidated Financial Statements of Repsol Oil & Gas Canada Inc. (“ROGCI” or “the Company”), formerly Talisman Energy Inc. as at and for the three and nine month periods ended September 30, 2016 and 2015, and the 2015 MD&A and audited annual Consolidated Financial Statements of the Company. The Company’s interim condensed Consolidated Financial Statements have been prepared in accordance with International Accounting Standard (“IAS”) 34, Interim Financial Reporting within International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The Company’s financial statements are prepared on a consolidated basis and include the accounts of the Company and its subsidiaries. Substantially all of the Company’s activities are conducted jointly with others, and the interim condensed Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities, with the exception of the Company’s investments in Repsol Sinopec Resources UK Limited (“RSRUK”, formerly Talisman Sinopec Energy UK Limited) and Equion Energía Limited (“Equion”) which are accounted for using the equity method.

All comparisons are between the three month periods ended September 30, 2016 and 2015, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this MD&A are listed in the section “Abbreviations and Definitions”. Unless otherwise indicated, amounts only reflect results from consolidated subsidiaries. Additional information relating to the Company, including the Company’s Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.

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

1

FINANCIAL AND OPERATING HIGHLIGHTS

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

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

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

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

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

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

2

DAILY AVERAGE PRODUCTION

	Three months ended September 30				Nine months ended September 30
	Gross before  royalties		Net of royalties		Gross before  royalties		Net of royalties
	2016	2015	2016	2015	2016	2015	2016	2015
Oil and liquids from Consolidated Subsidiaries (mbbls/d)
North America	39	40	33	34	39	42	34	36
Southeast Asia	26	33	17	22	29	37	20	25
North Sea	—	10	—	10	—	12	—	12
Other1	16	14	8	8	12	14	6	9
	81	97	58	74	80	105	60	82
Oil and liquids from Joint Ventures (mbbls/d)
RSRUK	22	20	22	20	22	18	22	18
Equion	13	13	10	11	13	12	11	10
	35	33	32	31	35	30	33	28
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d)	116	130	90	105	115	135	93	110
Natural gas from Consolidated Subsidiaries (mmcf/d)
North America	775	788	667	677	789	788	687	683
Southeast Asia	423	464	316	331	445	481	340	345
North Sea	—	18	—	18	—	19	—	19
	1,198	1,270	983	1,026	1,234	1,288	1,027	1,047
Natural gas from Joint Ventures (mmcf/d)
RSRUK	2	6	2	5	3	4	3	4
Equion	23	41	20	39	33	41	26	34
	25	47	22	44	36	45	29	38
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d)	1,223	1,317	1,005	1,070	1,270	1,333	1,056	1,085
Total daily production from Consolidated Subsidiaries (mboe/d)
North America	177	180	152	154	180	182	156	158
Southeast Asia	101	116	73	81	108	123	80	86
North Sea	—	13	—	13	—	15	—	15
Other	16	14	8	8	12	14	6	9
	294	323	233	256	300	334	242	268
Total daily production from Joint Ventures (mboe/d)
RSRUK	23	21	23	21	23	19	23	19
Equion	17	20	14	18	19	20	15	16
	40	41	37	39	42	39	38	35
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d)	334	364	270	295	342	373	280	303
Less production from discontinued operations (mboe/d)
North Sea	—	13	—	13	—	15	—	15
Total production from continuing operations (mboe/d)	334	351	270	282	342	358	280	288

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

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

3

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

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

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

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

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

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

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

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

(1)Gross before royalties.

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

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

The Company’s produced oil is frequently stored in tanks until there is sufficient volume to be lifted. The Company recognizes revenue and the related expenses on crude oil production, when liftings have occurred. Volumes

4

presented in the “Daily Average Production” table represent production volumes in the period, which include oil and liquids volumes produced into inventory and exclude volumes sold out of inventory.

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

COMPANY NETBACKS1,2,3

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

(1)Netbacks do not include pipeline operations.

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

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

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

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

5

COMMODITY PRICES AND EXCHANGE RATES1,2

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

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

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

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

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

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

6

EXPENSES

Unit Operating Expenses1,2

	Three months ended September 30				Nine months ended September 30
	Gross before  royalties		Net of royalties		Gross before  royalties		Net of royalties
($/boe)	2016	2015	2016	2015	2016	2015	2016	2015
North America	5.13	6.79	5.96	7.93	5.54	7.11	6.38	8.23
Southeast Asia	8.49	8.71	11.77	12.40	7.43	8.35	9.99	11.84
Other	6.29	14.48	13.08	25.60	7.17	13.99	14.38	20.95
	6.34	7.85	8.02	9.98	6.29	7.89	7.78	9.93

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

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

Total Operating Expenses1,2

	Three months ended September 30		Nine months ended September 30
(millions of $)	2016	2015	2016	2015
North America	86	114	280	362
Southeast Asia	80	97	222	266
Other	9	15	27	49
	175	226	529	677

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

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

Total operating expenses decreased by 23% to $175 million in 2016.

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

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

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

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

7

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

	Three months ended September 30				Nine months ended September 30
	Gross before  royalties		Net of royalties		Gross before  royalties		Net of royalties
($/boe)	2016	2015	2016	2015	2016	2015	2016	2015
North America	13.80	15.59	16.04	18.21	13.88	15.33	15.99	17.73
Southeast Asia	7.09	10.37	9.82	14.76	7.03	11.18	9.46	15.87
Other	9.19	11.98	19.11	21.19	10.34	11.73	20.74	17.57
	11.24	13.48	14.20	17.16	11.27	13.58	13.95	17.09

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

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

Total DD&A Expense1,2

	Three months ended September 30		Nine months ended September 30
(millions of $)	2016	2015	2016	2015
North America	226	258	685	767
Southeast Asia	64	122	208	372
Other	11	14	31	45
	301	394	924	1,184

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

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

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

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

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

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

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

8

Income (Loss) from Joint Ventures and Associates1

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

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

RSRUK Joint Venture

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

Equion Joint Venture

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

Corporate and Other1,2

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

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

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

In 2016, G&A expense decreased by $5 million relative to 2015 principally due to lower workforce expenses in Southeast Asia and sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016.

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

9

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

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

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

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

INCOME TAXES1,2

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

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

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

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

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

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

10

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

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

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

·Impact of tax depreciation differences;

·Foreign exchange on foreign denominated tax pools;

·Recovery from the Malaysia dry hole expensed in 2016.

CAPITAL EXPENDITURES1

	Three months ended September 30		Nine months ended September 30
($ millions)	2016	2015	2016	2015
North America	49	224	217	555
Southeast Asia	71	55	112	163
Other	6	8	16	37
Exploration and development expenditure from Consolidated Subsidiaries2	126	287	345	755
Corporate, IS and Administrative	—	3	3	22
Acquisitions and extensions	2	3	69	11
Net capital expenditure for Consolidated Subsidiaries	128	293	417	788
RSRUK	48	80	168	290
Equion	3	11	12	32
Exploration and development expenditure from Joint Ventures3	51	91	180	322
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures	179	384	597	1,110

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

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

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

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

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

11

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

On May 8, 2015, TE Holding SARL. (“TEHS”), a subsidiary of the Company, entered into a $500 million revolving facility with Repsol Tesoreria y Gestion Financiera, S.A. (“RTYGF”), a subsidiary of Repsol. Originally, the facility was to mature on May 8, 2016 and to bear an interest rate of LIBOR (1 month) plus 0.80%. On September 30, 2015, the facility agreement was amended to extend the maturity date to May 8, 2018. On November 17, 2015, the interest rate in the facility agreement was amended to LIBOR (1 month) plus 1.20%. Effective June 13, 2016, the credit limit of this facility was increased to $550 million. As at September 30, 2016, there were $446 million drawings outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine months ended September 30, 2016 was $2 million and $4 million, respectively.

12

On May 8, 2015, the Company also entered into a $1.0 billion revolving facility with Repsol Energy Resources Canada, Inc. (“RERCI”), a subsidiary of Repsol. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) plus 1.20%. The facility limit was increased to $2.8 billion on December 9, 2015. At September 30, 2016, the Company had $1.5 billion outstanding under this facility. Interest expense related to the facility recognized by the Company during the three and nine month periods ended September 30, 2016 was $6 million and $16 million, respectively.

On December 22, 2015, the Company and RERCI entered into a subscription agreement which provides for the capitalization of the Company’s balances owing under this revolving facility. The Board of Directors of the Company authorized the issuance of up to an aggregate of $2.6 billion in common shares of the Company (1,361,256,544 common shares at $1.91 per share), to be settled by RERCI contributing receivables owing from the Company under this revolving facility. As at September 30, 2016, $1.1 billion drawings remained available under the subscription agreement.

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

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

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

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

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

13

The Company manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by integrating funding from subsidiaries of its ultimate parent, Repsol.

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

In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted.  At September 30, 2016, the Company had $0.2 billion letters of credit outstanding, primarily related to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations.  The Company also guaranteed $0.8 billion demand letters of credit issued under RSRUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK. In addition, there were $87 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.

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

The UK government passed legislation in 2013 which provides for a contractual instrument, known as a Decommissioning Relief Deed, for the government to guarantee tax relief on decommissioning costs at 50%, allowing security under DSAs to be posted on an after-tax basis and reducing the value of letters of credit required to be posted by 50%. RSRUK has entered into a Decommissioning Relief Deed with the UK Government and continues to negotiate with counterparties to amend all DSAs accordingly. As of September 30, 2016, only two DSAs were still required to be negotiated on a post-tax basis. Tax relief guaranteed by the UK government is limited to corporate tax paid since 2002. Under the limitation, RSRUK’s tax relief is capped at $1.7 billion, representing corporate income taxes paid and recoverable since 2002 translated into US dollars.

At September 30, 2016, RSRUK has $2.9 billion of demand shared facilities in place under which letters of credit of $1.6 billion have been issued. The Company guarantees 51% of all letters of credit issued under these shared facilities.

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

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

14

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

Any changes to decommissioning estimates influence the value of letters of credit required to be provided pursuant to DSAs. In addition, the extent to which shared facility capacity is available and the cost of that capacity are influenced by the Company’s investment-grade credit rating.

The Company monitors its balance sheet with reference to its liquidity. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from equity accounted entities (defined as cash provided by operating activities before adjusting for changes in non-cash working capital, and exploration expenditure), cash provided by and used in investing activities and related party credit facilities.

A significant proportion of the Company’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At September 30, 2016, approximately 84% of the Company’s accounts receivable was current and the largest single counterparty exposure, accounting for 5% of the total, was with a highly rated counterparty. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base primarily of highly rated counterparties.

Subsequent to December 31, 2015, there were no activities relating to the Company’s common shares. There were 1,829,506,342 common shares outstanding at Nov 7, 2016.

For additional information regarding the Company’s liquidity and capital resources, refer to notes 7, 16, 18, 19 and 21 to the Company’s 2015 audited Consolidated Financial Statements and notes 5, 11, 12, 13 and 14 to the Company’s interim condensed Consolidated Financial Statements.

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the audited Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, decommissioning obligations, lease commitments relating to corporate offices and ocean-going vessels, firm commitments for gathering, processing and transmission services, minimum work commitments under various international agreements, other service contracts and fixed price commodity sales contracts.

15

Additional disclosure of the Company’s decommissioning liabilities, debt and related party loan repayment obligations and significant commitments can be found in notes 7, 14, 16, 17 and 22 to the 2015 audited Consolidated Financial Statements.

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

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

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

TRANSACTIONS WITH RELATED PARTIES

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

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

North America

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

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

Rest of World

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

16

Southeast Asia

The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings (Private) Limited (“Temasek”). Currently, ROGCI’s share of the sale on a daily basis is approximately 75 billion btu. The commitment matures in 2023.  As a result of the acquisition of the Company by Repsol, GSPL and Temasek became the Company’s related parties. During the three and nine month periods ended September 30, 2016, the Company’s gas sales to GSPL totaled $37 million and $87 million, respectively (net the Company’s share). As at September 30, 2016, the amount included in accounts receivable as a result of this commitment was $22 million.

RSRUK

In June 2015, the shareholders of RSRUK provided an equity funding facility of $1.7 billion, of which the Company is committed to $867 million, for the purpose of funding capital, decommissioning and operating expenditures of RSRUK. This facility is effective from July 1, 2015 and had a maturity date of December 31, 2016. In September 2016, this agreement was modified to extend the maturity date to December 31, 2017. During the three and nine month periods ended September 30, 2016, the shareholders of RSRUK agreed to subscribe for common shares of RSRUK in the amount of $105 million and $465 million under this facility, respectively, of which the Company’s share was $54 million and $237 million, respectively.

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

Equion

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

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

RISK MANAGEMENT

In addition to the risks discussed in the liquidity and capital resources section of this MD&A, the Company monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, the Company periodically enters into physical delivery transactions for commodities of fixed or collared prices and into derivative financial instruments to reduce exposure to unfavourable movements in commodity prices, interest rates and foreign exchange rates. The terms of these contracts or instruments may limit the benefit of favourable changes in commodity prices, interest rates and currency values and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with contracts. The Company has established a system

17

of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties.

The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 3(r) to the Company’s 2015 audited Consolidated Financial Statements.

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

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

USE OF ESTIMATES AND JUDGMENTS

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates and judgment. Actual results could differ materially from those estimates. Judgments and estimates are reviewed by management on a regular basis.

For additional information regarding the use of estimates and judgments, refer to the notes to the Company’s audited Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2015.

SIGNIFICANT ACCOUNTING POLICIES

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

INTERNAL CONTROL OVER FINANCIAL REPORTING

During the three and nine month periods ended September 30, 2016, the integration activities with the Company’s ultimate parent, Repsol, continued and changes to the Company’s organizational design, policies and individuals with significant roles in internal control over financial reporting have changed. In order to mitigate the potential effect associated with these changes, the Company has implemented additional controls intended to ensure responsibilities are clearly understood and information and communication controls are effective. Testing of the design and operating effectiveness of the Company’s controls will continue throughout 2016.

LEGAL PROCEEDINGS

From time to time, the Company is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below, may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While the Company assesses the merits of each lawsuit and defends itself accordingly, the Company may be

18

required to incur significant expenses or devote significant resources to defend itself against such litigation. None of these claims are currently expected to have a material impact on the Company’s financial position. A summary of specific legal proceedings and contingencies is as follows:

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

On July 13, 2015, Addax and Sinopec International Petroleum Exploration and Production Corporation (“Sinopec”), filed a “Notice of Arbitration” against ROGCI and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% of the shares of RSRUK. ROGCI and TCHL filed their response to the Notice of Arbitration on October 1, 2015. On May 25, 2016, Addax and Sinopec filed their Statement of Claim, in which they seek, in the event that their claims were confirmed in their entirety, repayment of their initial investment in RSRUK, together with any additional investment, past or future, in such company, and further for any loss of opportunity, which they estimate in a total approximate amount of $5.5 billion. The Court of Arbitration has decided, among other procedural matters, to schedule the hearing for January 29 to February 16, 2018. The Company believes the claims included in their Statement of Claim are without merit.

During the first quarter of 2016, the Alberta Energy Regulator (“AER”) informed the Company that certain permits to construct well sites and access roads were obtained without the Company following proper procedures.  The Company continues to investigate its permit applications and work with the AER in this matter. At this time, the implications to the Company are not known.

Government and Legal Proceedings with Tax Implications

Specific tax claims which the Company and its subsidiaries are parties to at September 30, 2016 are as follows:

Canada

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

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

Indonesia

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

19

Malaysia

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

Timor-Leste

The authorities of Timor-Leste questioned the deduction by Talisman Resources (JPDA 06-105) Pty Limited, the Company’s subsidiary in East Timor, of certain expenses for income tax purposes. This line of questioning is at a very preliminary stage of debate with the authorities.

ADVISORIES

Forward-Looking Statements

This interim MD&A contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation.

This forward-looking information includes, but is not limited to, statements regarding:

·Business strategy, plans and priorities;

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

·The estimated impact on the Company’s financial performance from changes in production volumes, commodity prices and exchange rates;

·Expected sources of capital to fund the Company’s capital program and potential acquisitions, investments or dispositions;

·Anticipated funding of the decommissioning liabilities;

·Anticipated timing and results of legal proceedings;

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

·Potential future related party transactions and asset transactions.

The factors or assumptions on which the forward-looking information is based include: projected capital investment levels; the flexibility of capital spending plans; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; ability to obtain regulatory and partner approval; commodity price and cost assumptions; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 2016 assumes escalating commodity prices.

20

Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by the Company and described in the forward-looking information contained in this MD&A.

The material risk factors include, but are not limited to:

·Fluctuations in oil and gas prices, foreign currency exchange rates, interest rates and tax or royalty rates;

·The risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas;

·Risks and uncertainties involving geology of oil and gas deposits;

·Risks associated with project management, project delays and/or cost overruns;

·Uncertainty related to securing sufficient egress and access to markets;

·The uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;

·The uncertainty of estimates and projections relating to production, costs and expenses, including decommissioning liabilities;

·Risks related to strategic and capital allocation decisions, including potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

·The outcome and effects of any future acquisitions and dispositions;

·Health, safety, security and environmental risks, including risks related to the possibility of major accidents;

·Environmental, regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing;

·Uncertainties as to access to capital, including the availability and cost of credit and other financing, and changes in capital markets;

·Risks in conducting foreign operations (for example, civil, political and fiscal instability and corruption);

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

·Risks related to the attraction, retention and development of personnel;

·Changes in general economic and business conditions;

·The possibility that government policies, regulations or laws may change or governmental approvals may be delayed or withheld; and

·Results of the Company’s risk mitigation strategies, including insurance activities.

21

The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results or strategy are included in the Company’s most recent AIF. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the SEC.

Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law.

ADVISORY — OIL AND GAS INFORMATION

Throughout this MD&A, the Company makes reference to production volumes. Such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments. Net production volumes are reported after the deduction of these amounts.

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

USE OF ‘BOE’

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

ABBREVIATIONS AND DEFINITIONS

The following abbreviations and definitions are used in this MD&A:

AIF	Annual Information Form
bbl	barrel
bbls	barrels
bbls/d	barrels per day
btu	British thermal units
bcf	billion cubic feet
boe	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
C$	Canadian dollar
DD&A	Depreciation, depletion and amortization
DSA	Decommissioning Security Agreements
E&E	Exploration and evaluation
EU	European Union
G&A	General and administrative
GAAP	Generally Accepted Accounting Principles
gj	gigajoule
HH LD	Henry Hub Last Day
IFRIC	International Financial Reporting Interpretations Committee
IFRS	International Financial Reporting Standards
LIBOR	London Interbank Offered Rate
LLS	Light Louisiana Sweet
LNG	Liquefied Natural Gas
mbbls/d	thousand barrels per day
mboe/d	thousand barrels of oil equivalent per day
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmbbls	million barrels

22

mmboe	million barrels of oil equivalent
mmbtu	million British thermal units
mmcf/d	million cubic feet per day
mmcfe/d	million cubic feet equivalent per day
NGL	Natural Gas Liquids
NYMEX	New York Mercantile Exchange
PP&E	Property, plant and equipment
PRT	Petroleum Revenue Tax
PSU	Performance share unit
tcf	trillion cubic feet
UK	United Kingdom
UK£	Pound sterling
US	United States of America
US$ or $	United States dollar
WCS	Western Canadian Select
WTI	West Texas Intermediate

Gross production means the Company’s interest in production volumes (through working interests and royalty interests) before the deduction of royalties. Net production means the Company’s interest in production volumes after deduction of royalties payable by the Company.

23

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/

EX-99.3

Exhibit 99.3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

I, Luis Cabra Dueñas, Vice-Chairman and Chief Executive Officer of Repsol Oil & Gas Canada Inc., certify the following:

1.I have reviewed the interim financial report and interim MD&A (together the “interim filings”) of Repsol Oil & Gas Canada Inc. (the “issuer”) for the interim period ended September 30, 2016.

2.Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings:

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that:

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial

reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) (2013 framework).

5.2N.A.

5.3N.A.

6.The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2016 and ended on September 30, 2016 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 8, 2016

/s/ Luis Cabra Duenas

Luis Cabra Dueñas

Vice-Chairman and Chief Executive Officer

EX-99.4

Exhibit 99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

I, David Charlton, Vice-President Finance, Treasurer and Chief Financial Officer of Repsol Oil & Gas Canada Inc., certify the following:

1.I have reviewed the interim financial report and interim MD&A (together the “interim filings”) of Repsol Oil & Gas Canada Inc. (the “issuer”) for the interim period ended September 30, 2016.

2.Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings:

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that:

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial

reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission   (“COSO”) (2013 framework).

5.2        N.A.

5.3        N.A.

6.The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2016 and ended on September 30, 2016 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 8, 2016

/s/ David Charlton

David Charlton

Vice-President Finance, Treasurer and

Chief Financial Officer