10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

	(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2016
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to
	Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	71-0361522
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
300 Peach Street, P.O. Box 7000,
El Dorado, Arkansas	71731-7000
(Address of principal executive offices)	(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
[X] Yes    [  ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[X] Yes    [  ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.

Large accelerated filer [X]                Accelerated filer [  ]               Non-accelerated filer [  ]              Smaller reporting company [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
[  ] Yes    [X] No

Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2016 was 172,200,075.

MURPHY OIL CORPORATION

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1.  Financial Statements
Consolidated Balance Sheets	2
Consolidated Statements of Operations	3
Consolidated Statements of Comprehensive Income (Loss)	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Stockholders’ Equity	6
Notes to Consolidated Financial Statements	7
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.  Controls and Procedures	33
Part II – Other Information	33
Item 1.  Legal Proceedings	33
Item 1A.  Risk Factors	33
Item 6.  Exhibits	33
Signature	34

1

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)

	September 30,		December 31,
	2016		2015
ASSETS
Current assets
Cash and cash equivalents	$	753,093		283,183
Canadian government securities with maturities greater than 90 days at    the date of acquisition		117,938		173,288
Accounts receivable, less allowance for doubtful accounts of $1,605 in     2016 and 2015		400,532		522,672
Inventories, at lower of cost or market
Crude oil		11,196		25,583
Materials and supplies		151,107		141,205
Prepaid expenses		90,401		212,962
Deferred income taxes		50,879		51,183
Assets held for sale		29,978		38,340
Total current assets		1,605,124		1,448,416
Property, plant and equipment, at cost less accumulated depreciation,    depletion and amortization of $12,425,414 in 2016 and $11,924,193 in 2015		8,440,336		9,818,365
Deferred charges and other assets		348,555		227,031
Total assets	$	10,394,015		11,493,812
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	20,444		18,881
Accounts payable and accrued liabilities		876,664		1,643,632
Income taxes payable		13,817		4,819
Liabilities associated with assets held for sale		3,276		7,297
Total current liabilities		914,201		1,674,629
Long-term debt, including capital lease obligation		2,973,888		3,040,594
Deferred income taxes		50,244		239,811
Asset retirement obligations		748,576		793,474
Deferred credits and other liabilities		621,518		438,576
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		–		–
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2016 and 2015		195,056		195,056
Capital in excess of par value		921,675		910,074
Retained earnings		5,836,567		6,212,201
Accumulated other comprehensive loss		(571,031)		(704,542)
Treasury stock, 22,855,649 shares of Common Stock in 2016 and 23,021,013 shares of Common Stock in 2015, at cost		(1,296,679)		(1,306,061)
Total stockholders’ equity		5,085,588		5,306,728
Total liabilities and stockholders’ equity	$	10,394,015		11,493,812

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 35.

2

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)

		Three Months Ended		Nine Months Ended
	September 30,			September 30,
	2016		2015	2016	2015
REVENUES
Sales and other operating revenues	$	486,276	665,589	1,326,587	2,133,360
Gain (loss) on sale of assets		(730)	60	3,101	154,183
Interest and other income		14,987	49,300	38,602	87,443
Total revenues		500,533	714,949	1,368,290	2,374,986
COSTS AND EXPENSES
Lease operating expenses		119,663	183,826	435,296	643,736
Severance and ad valorem taxes		9,592	14,265	35,668	54,099
Exploration expenses, including undeveloped lease amortization		19,866	58,149	83,910	251,842
Selling and general expenses		55,523	71,791	196,143	237,934
Depreciation, depletion and amortization		255,900	433,706	797,288	1,318,123
Impairment of assets		–	2,300,974	95,088	2,300,974
Accretion of asset retirement obligations		11,043	11,918	35,514	35,437
Interest expense		40,088	32,009	107,207	91,945
Interest capitalized		(869)	(1,864)	(3,318)	(5,072)
Other expense (benefit)		6,486	18,192	(1,446)	81,804
Total costs and expenses		517,292	3,122,966	1,781,350	5,010,822
Loss from continuing operations before income taxes		(16,759)	(2,408,017)	(413,060)	(2,635,836)
Income tax benefit		(2,176)	(820,935)	(201,897)	(963,298)
Loss from continuing operations		(14,583)	(1,587,082)	(211,163)	(1,672,538)
Loss from discontinued operations, net of income taxes		(1,593)	(8,344)	(885)	(11,163)
NET LOSS	$	(16,176)	(1,595,426)	(212,048)	(1,683,701)
PER COMMON SHARE – BASIC
Loss from continuing operations	$	(0.08)	(9.22)	(1.23)	(9.55)
Loss from discontinued operations		(0.01)	(0.04)	(0.01)	(0.07)
Net loss	$	(0.09)	(9.26)	(1.24)	(9.62)
PER COMMON SHARE – DILUTED
Loss from continuing operations	$	(0.08)	(9.22)	(1.23)	(9.55)
Loss from discontinued operations		(0.01)	(0.04)	(0.01)	(0.07)
Net loss	$	(0.09)	(9.26)	(1.24)	(9.62)
Average Common shares outstanding
Basic		172,199,350	172,205,433	172,164,683	175,047,295
Diluted		172,199,350	172,205,433	172,164,683	175,047,295

See Notes to Consolidated Financial Statements, page 7. 

3

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(unaudited)

(Thousands of dollars)

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2016		2015	2016	2015
Net loss	$	(16,176)	(1,595,426)	(212,048)	(1,683,701)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		(37,369)	(195,440)	124,522	(462,054)
Retirement and postretirement benefit plans		2,515	3,116	7,544	9,105
Deferred loss on interest rate hedges reclassified to interest expense		482	482	1,445	1,445
Other comprehensive income (loss)		(34,372)	(191,842)	133,511	(451,504)
COMPREHENSIVE LOSS	$	(50,548)	(1,787,268)	(78,537)	(2,135,205)

See Notes to Consolidated Financial Statements, page 7.

4

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

	Nine Months Ended
	September 30,
	2016			2015
OPERATING ACTIVITIES
Net loss	$	(212,048)		(1,683,701)
Adjustments to reconcile net loss to net cash provided by   continuing operations activities:
Loss from discontinued operations		885		11,163
Depreciation, depletion and amortization		797,288		1,318,123
Impairment of assets		95,088		2,300,974
Amortization of deferred major repair costs		3,794		5,450
Dry hole costs		15,226		120,459
Amortization of undeveloped leases		35,828		62,331
Accretion of asset retirement obligations		35,514		35,437
Deferred and noncurrent income tax benefits		(345,157)		(975,120)
Pretax gains from disposition of assets		(3,101)		(154,183)
Net (increase) decrease in noncash operating working capital		(152,618)	1	97,026
Other operating activities, net		9,651		(41,431)
Net cash provided by continuing operations activities		280,350		1,096,528
INVESTING ACTIVITIES
Property additions and dry hole costs		(781,668)	2	(1,975,069)
Proceeds from sales of property, plant and equipment		1,154,623		423,842
Purchase of investment securities3		(651,218)		(865,251)
Proceeds from maturity of investment securities3		712,863		852,394
Other investing activities, net		(7,229)		(19,538)
Net cash provided (required) by investing activities		427,371		(1,583,622)
FINANCING ACTIVITIES
Borrowings of debt		541,444		885,000
Repayments of debt		(600,000)		(450,000)
Capital lease obligation payments		(7,808)		(7,156)
Purchase of treasury stock		–		(250,000)
Withholding tax on stock-based incentive awards		(1,138)		(8,976)
Issue cost of debt facility		(13,971)		–
Cash dividends paid		(163,586)		(184,789)
Other financing activities, net		(20)		(153)
Net cash required by financing activities		(245,079)		(16,074)
CASH FLOWS FROM DISCONTINUED OPERATIONS
Operating activities		2,830		(4,866)
Investing activities		–		5,343
Changes in cash included in current assets held for sale		(2,830)		179,774
Net increase in cash and cash equivalents of discontinued operations		–		180,251
Effect of exchange rate changes on cash and cash equivalents		7,268		8,276
Net increase (decrease) in cash and cash equivalents		469,910		(314,641)
Cash and cash equivalents at January 1		283,183		1,193,308
Cash and cash equivalents at September 30	$	753,093		878,667

12016 balance includes payments for deepwater rig contract exit of $266.6 million.

2Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.

3Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

5

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)

	Nine Months Ended
	September 30,
	2016		2015
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	–		–
Common Stock – par $1.00, authorized 450,000,000 shares,    issued 195,055,724 shares at September 30, 2016 and September 30, 2015
Balance at beginning of period		195,056		195,040
Exercise of stock options		–		16
Balance at end of period		195,056		195,056
Capital in Excess of Par Value
Balance at beginning of period		910,074		906,741
Exercise of stock options, including income tax benefits		–		(73)
Restricted stock transactions and other		(10,078)		(38,260)
Stock-based compensation		21,918		33,925
Other		(239)		(92)
Balance at end of period		921,675		902,241
Retained Earnings
Balance at beginning of period		6,212,201		8,728,032
Net loss for the period		(212,048)		(1,683,701)
Cash dividends		(163,586)		(184,789)
Balance at end of period		5,836,567		6,859,542
Accumulated Other Comprehensive Loss
Balance at beginning of period		(704,542)		(170,255)
Foreign currency translation gain (loss), net of income taxes		124,522		(462,054)
Retirement and postretirement benefit plans, net of income taxes		7,544		9,105
Deferred loss on interest rate hedges reclassified to interest expense,    net of income taxes		1,445		1,445
Balance at end of period		(571,031)		(621,759)
Treasury Stock
Balance at beginning of period		(1,306,061)		(1,086,124)
Purchase of treasury shares		–		(250,000)
Sale of stock under employee stock purchase plans		389		322
Awarded restricted stock, net of forfeitures		8,993		29,176
Balance at end of period – 22,855,649 shares of Common Stock in    2016 and 22,303,782 shares of Common Stock in 2015, at cost		(1,296,679)		(1,306,626)
Total Stockholders’ Equity	$	5,085,588		6,028,454

See Notes to Consolidated Financial Statements, page 7.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Nature of Business and Interim Financial Statements

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.  The Company sold its interest in a Canadian synthetic oil operation in the second quarter of 2016.  The Company acquired 70% interest in Duvernay Shale and a 30% interest in liquids rich Montney properties during the second quarter 2016.

INTERIM FINANCIAL STATEMENTS –In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position atSeptember30, 2016 and December 31, 2015, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended September30, 2016 and 2015, in conformity with accounting principles generally accepted in the United States of America (U.S.).  In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities.  Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2015 Form 10-Kreport, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the nine-monthperiod ended September30, 2016are not necessarily indicative of future results.

Note B – Property, Plant and Equipment

Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At September30, 2016, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $128.2 million.  The following table reflects the net changes in capitalized exploratory well costs during the

nine-month periods ended September30, 2016 and 2015.

(Thousands of dollars)	2016		2015
Beginning balance at January 1	$	130,514	120,455
Additions pending the determination of proved reserves		847	89,197
Other adjustments		(3,205)	–
Balance at September 30	$	128,156	209,652

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – Property, Plant and Equipment (Contd.)

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.  The projects are aged based on the last well drilled in the project.

		September 30,
	2016				2015
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	10,563	2	2	$	52,249	5	3
One to two years		53,101	3	3		32,192	2	1
Two to three years		31,627	2	–		27,842	2	–
Three years or more		32,865	4	–		97,369	4	2
	$	128,156	11	5	$	209,652	13	6

Of the $117.6 million of exploratory well costs capitalized more than one year at September30, 2016,  $64.5 million is in Brunei, $31.4 million is in Vietnam and $21.7 million is in Malaysia.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

In April 2016, a Canadian subsidiary of the Company signed a purchase and sale agreement for the sale of its five percent, non-operated working interest in Syncrude Canada Ltd.  (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”), subject to closing adjustments.  The sale was completed in June 2016 and the Company received net cash proceeds of $739.1 million.  The Company recorded an after-tax gain of $71.7 million in the second quarter of 2016 associated with the Syncrude divestiture.

In April 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  Total cash consideration received by Murphy upon closing of the transaction was $414.1million.  A gain on sale of approximately $187 million is being deferred and recognized over the next 20 years in the Canadian operating segment.  The Company has amortized $3.4 million of the deferred gain during 2016.  The remaining deferred gain is included as a component of deferred credits and other liabilities on the Company’s Consolidated Balance Sheet.

In a separate transaction, the same Canadian subsidiary signed a definitive agreement to acquire a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Montney lands in Alberta, the majority of which is unproved.  Under the terms of the joint venture the total consideration amounts to approximately $375 million, of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and the remaining $168.0 million in the form of a carried interest for a period of up to five years.  The transaction closed in the second quarter of 2016.

During the first quarter of 2016, declines in crude oil and natural gas prices from year end 2015 provided indications of possible impairments in certain of the company’s producing properties.  As a result of management’s assessments, the Company recognized pretax non-cash impairments charges of $95.1 million in the nine-month period ended September 30, 2016, to reduce the carrying value to their estimated fair value for its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the region.

During the third quarter 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties.  As a result of management’s assessments, during the third quarter of 2015, the Company recognized a pretax noncash impairment charge of approximately $2.3 billion to reduce the carrying value of certain producing properties in the Gulf of Mexico, Western Canada and Malaysia to their estimated fair value.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – Property, Plant and Equipment (Contd.)

During 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million.  The Company recorded an after-tax gain of $218.8 million on the sale of the final 10% portion of the total 30% sold.

Note C – Discontinued Operations

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented.  The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter of 2015.  The 2015 nine-month period includes an adjustment to the impairment recognized as a result of the final sale of the U.K. downstream assets.

The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2016 and 2015 were as follows:

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2016	2015	2016	2015
Revenues (costs)	$	(1,345)	(1,342)	(510)	381,154
Loss before income taxes	$	(1,593)	(8,366)	(885)	(8,029)
Income tax (benefit) expense		–	(22)	–	3,134
Loss from discontinued operations	$	(1,593)	(8,344)	(885)	(11,163)

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at September30, 2016 and December 31, 2015.

	September 30,		December 31,
(Thousands of dollars)	2016		2015
Current assets
Cash	$	5,097	7,927
Accounts receivable		9,001	12,037
Other		15,880	18,376
Total current assets held for sale	$	29,978	38,340
Current liabilities
Accounts payable	$	915	2,433
Accrued compensation and severance		–	2,179
Refinery decommissioning cost		2,361	2,685
Total current liabilities associated with assets held for sale	$	3,276	7,297

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Financing Arrangements and Debt

In August 2016 the Company reduced its existing $2.0 billion unsecured revolving credit facility (“2011 facility”) to $630 million and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (“2016 facility”) with a major banking consortium that expires in August 2019.  Facility fees of 0.5% are charged annually on the full $1.2 billion commitment.  The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which are included in financing activities in the Consolidated Statement of Cash Flows.  At September 30, 2016, the Company had nooutstanding borrowings under either credit facility, however, there was approximately $88 million of issued letters of credit under the 2016 facility.  The 2016 facility is unsecured, with guarantees from certain domestic and foreign subsidiaries.  Should the Company make substantial asset sales, the facility size would be automatically reduced to a minimum of $1.0 billion.  Borrowings under the 2016 facility are subject to varying interest rates ranging from LIBOR plus 250 basis points to LIBOR plus 450 basis points.  The terms of the 2016 facility include covenants that impose certain restrictions on the Company.  These financial covenants include a minimum adjusted EBITDAX of 2.5 times consolidated interest expense, consolidated debt not to exceed 3.75 times adjusted EBITDAX and minimum liquidity from U.S. and Canadian entities equal to or greater than $500 million.  Also beginning March 31, 2017, if the Company’s total leverage ratio exceeds 3.25 times the Company’s trailing twelve month consolidated adjusted EBITDAX, as defined in the 2016 facility, the facility will become secured, subject to limitations set forth in the Company’s existing notes.  The existing unsecured 2011 facility, which expires in June 2017, includes a financial covenant under which the Company may not have total debt in excess of 60% of its total capital employed (debt borrowed plus stockholders’ equity).  As of September 30, 2016, the Company was in compliance with all financial covenants contained in both credit facilities.  The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.

In August 2016, the Company sold $550 million of new notes that bear interest at the rate of 6.875% and mature on August 15, 2024.  The new notes pay interest semi-annually on February 15 and August 15 of each year.  The initial interest payment is to be made on February 15, 2017.  The proceeds of the $550 million notes were used for general corporate purposes.

The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through September 2028.  Current maturities and long-term debt on the Consolidated Balance Sheet included $20.4 million and $202.7 million, respectively, associated with this lease at September 30, 2016.

Note E – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.

	Nine Months Ended September 30,
(Thousands of dollars)	2016		2015
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	75,841	389,413
Increase in inventories		(15,768)	(16,607)
Decrease (increase) in prepaid expenses		122,399	(87,051)
Decrease in deferred income tax assets		720	4,863
Decrease in accounts payable and accrued liabilities		(376,310)	(134,458)
Increase (decrease) in current income tax liabilities		40,500	(59,134)
Net (increase) decrease in noncash operating working capital	$	(152,618)	97,026
Supplementary disclosures:
Cash income taxes paid (refunded), net	$	(3,911)	111,897
Interest paid, net of amounts capitalized		52,287	60,766
Non-cash investing activities:
Asset retirement costs capitalized	$	13,959	55,258
Decrease in capital expenditure accrual		179,203	374,720

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan.  All U.S. tax qualified plans meet the funding requirements of federal laws and regulations.  Contributions to foreign plans are based on local laws and tax regulations.  The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most active and retired U.S. employees.  Additionally, most U.S. retired employees are covered by a life insurance benefit plan.  The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September30,2016 and 2015.

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	2,610	5,898		674		826
Interest cost		5,913	8,972		1,109		1,192
Expected return on plan assets		(6,626)	(10,471)		–		–
Amortization of prior service cost		323	187		(21)		(21)
Amortization of transitional asset		–	402		2		2
Recognized actuarial loss		3,617	3,885		38		193
Net periodic benefit expense	$	5,837	8,873		1,802		2,192
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	8,533	15,751		2,022		2,482
Interest cost		20,386	24,893		3,324		3,576
Expected return on plan assets		(21,709)	(27,882)		–		–
Amortization of prior service cost		963	580		(62)		(62)
Amortization of transitional asset		–	947		4		5
Recognized actuarial loss		10,864	11,667		113		578
		19,037	25,956		5,401		6,579
Special termination benefits		–	8,606		(19)		–
Curtailments		822	306		–		–
Net periodic benefit expense	$	19,859	34,868		5,382		6,579

Curtailment expense for the ninemonths ended September30, 2016shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.  Termination and curtailment expenses for the nine months ended September 30, 2015 relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.  During the nine-month period ended September30, 2016, the Company made contributions of $10.0 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2016 for the Company’s defined benefit pension and postretirement benefit plans is anticipated to be $2.9 million.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Incentive Plans

The costs resulting from all share-based payment transactions are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The 2012 Annual Incentive Plan (2012 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees.  Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.  The 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock and other stock-based incentives to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2012 Long-Term Plan expires in 2022.  A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding.  The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30,2017.  The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors. 

In February 2016, the Committee granted stock options for 862,000 shares at an exercise price of $17.57 per share.  The Black-Scholes valuation for these awards was $5.03 per option.  The Committee also granted 394,000 performance-based RSU and 417,500 time-based RSU in February and April 2016.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $12.21 to $16.34 per unit.  The fair values of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which ranged from $17.57 to 24.075 per share.  Additionally, the Committee granted 708,200 SAR and 507,470 units of cash-settled RSU (RSU-C) to certain employees in 2016.  The SAR and RSU-C are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards.  The initial fair value of these SAR was equivalent to the stock options granted, while the initial value of RSU-C was equivalent to equity-settled restricted stock units granted.  Also in February 2016, the Committee granted 85,679 shares of time-based RSU to the Company’s Directors under the Non-employee Director Plan.  These shares vest on the third anniversary of the date of grant. The estimated fair value of these awards was$19.26 per unit on date of grant.

Amounts recognized in the financial statements with respect to share-based plans are as follows:

	Nine Months Ended
	September 30,
(Thousands of dollars)		2016	2015
Compensation charged against income before tax benefit	$	35,948	30,722
Related income tax benefit recognized		11,796	9,046

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Earnings per Share

Net loss was used as the numerator in computing both basic and diluted income per Common share for the

three-month and nine-month periods ended September30, 2016 and 2015.  The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(Weighted-average shares)	2016	2015	2016	2015
Basic method	172,199,350	172,205,433	172,164,683	175,047,295
Dilutive stock options*	–	–	–	–
Diluted method	172,199,350	172,205,433	172,164,683	175,047,295

*Due to a net loss recognized by the Company for the three-monthand nine-month periods ended September 30, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

	Three Months Ended			Nine Months Ended
		September 30,		September 30,
		2016	2015	2016		2015
Antidilutive stock options excluded from diluted shares		5,884,201	5,807,453		5,822,036	5,770,731
Weighted average price of these options	$	49.00	53.13		49.82	53.25

Note I – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) before income taxes.  For the three-month and nine-month periods in 2016 and 2015, the Company’s effective income tax rates were as follows:

	2016	2015
Three months ended September 30	13.0%	34.1%
Nine months ended September 30	48.9%	36.6%

The effective tax rates for most periods differ from the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.  Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 35% due to similar reasons.  The effective tax rate for the three-month period ended September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized.  The effective tax rate for the nine-month period ended September 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign areas.  The effective tax rate for the three-month period ended September 30, 2015 was less than the U.S. statutory tax rate primarily due to a deferred tax expense associated with an enacted increase in the statutory tax rate in Alberta.  The effective tax rate for the nine-month period ended September 30, 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets, partially offset by expenses in foreign jurisdictions for which no tax benefits were recognized and the enacted increase in statutory rate in Alberta.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As ofSeptember30, 2016, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:United States – 2011; Canada – 2008; Malaysia – 2009; and United Kingdom – 2014.

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Financial Instruments and Risk Management

Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges, such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the net payment upon settlement recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss.  This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil, natural gas liquids and natural gas it produces and sells.  The Company had open derivative contracts at September30, 2016 and 2015.  The impact from marking to market these commodity derivative contracts increased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016 and reduced the loss before income taxes by $7.4 million for the nine-month period ended September 30, 2015.

Open West Texas Intermediate (WTI) contracts were as follows:

	Volumes
At September 30, 2016	(barrels per day)	Swap Prices
October – December 2016	25,000	$50.67	per barrel
January – December 2017	16,000	$50.34	per barrel
At September 30, 2015
October – December 2015	15,000	$63.30	per barrel

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  At September30, 2016 and 2015 short-term derivative instruments were outstanding in Canada for approximately $25.2 million and $6.2 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The impact from marking to market these foreign currency derivative contracts was insignificant for the nine-month periods ended September30, 2016 and 2015, respectively.

After signing an agreement to sell its five percent non-operated working interest in Syncrude, the Company’s Canadian subsidiary entered into forward sales contracts for C$1.0 billion at a fixed rate to lock in the U.S. dollar value of the proceeds and protect the Company from exposure to weakening of the Canadian dollar.  Upon completion of the sale and settlement of the forward sale contracts, the Company recognized income of approximately $26.8 million in the second quarter of 2016 due to weakening of the Canadian dollar subsequent to entering into the contracts.

At September30, 2016 and December 31, 2015, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

	September 30, 2016			December 31, 2015
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity	Accounts receivable	$	192	Accounts receivable	$	89,358
Foreign exchange	Accounts receivable		142	Accounts payable		(29)

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Financial Instruments and Risk Management (Contd.)

For the three-month and nine-month periods ended September30, 2016 and 2015, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

			Gain (Loss)
		Three Months Ended			Nine Months Ended
(Thousands of dollars)		September 30,			September 30,
Type of Derivative Contract	Statement of Operations Location		2016	2015	2016	2015
Commodity	Sales and other operating revenues	$	11,871	39,392	(22,678)	46,811
Foreign exchange	Interest and other income		143	33	26,929	47
		$	12,014	39,425	4,251	46,858

Interest Rate Risks

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012.  These interest rate swaps matured in May 2012.  Under hedge accounting rules, the Company deferred the net cost associated with these contracts to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September30, 2016 and 2015,$1.5 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations.  The remaining loss deferred on these matured contracts at September30, 2016 was $10.8 million, which was recorded, net of income taxes of $5.8 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining three months of 2016.

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September30, 2016 and December 31,2015 are presented in the following table.

	September 30, 2016					December 31, 2015
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Foreign currency exchange         derivative contracts	$	–	142	–	142	–	–	–	–
Commodity derivative         contracts		–	192	–	192	–	89,358	–	89,358
	$	–	334	–	334	–	89,358	–	89,358
Liabilities:
Nonqualified employee         savings plans	$	13,637	–	–	13,637	12,971	–	–	12,971
Foreign currency exchange         derivative contracts		–	–	–	–	–	29	–	29
	$	13,637	–	–	13,637	12,971	29	–	13,000

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Financial Instruments and Risk Management (Contd.)

The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date.  The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates.  The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues in the Consolidated Statements of Operations while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses in the Consolidated Statements of Operations.  The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at September30, 2016 and December 31, 2015.

Fair Values – Nonrecurring

As a result of significantly lower commodity prices during the nine-month periods ended September 30, 2016 and 2015, the Company recognized $95.1 million and $2.3 billion, respectively, in pretax noncash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following tables.

	September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

	September 30, 2015
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Gulf of Mexico	$	–	–	216,602	361,402	144,800
Western Canada		–	–	23,526	707,100	683,574
Malaysia		–	–	1,208,900	2,681,500	1,472,600
	$	–	–	1,449,028	3,750,002	2,300,974

The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2015 and September30, 2016 and the changes during the nine-month period ended September30, 2016 are presented net of taxes in the following table.

					Deferred
					Loss on
		Foreign	Retirement and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)1	Adjustments1		Hedges1		Total1
Balance at December 31, 2015	$	(513,004)	(179,260)		(12,278)		(704,542)
Components of other comprehensive income:
Before reclassifications to income		124,522	(3)		–		124,519
Reclassifications to income		–	7,547	2	1,445	3	8,992
Net other comprehensive income		124,522	7,544		1,445		133,511
Balance at September 30, 2016	$	(388,482)	(171,716)		(10,833)		(571,031)

1All amounts are presented net of income taxes.

2Reclassifications before taxes of $11,602 for thenine-month period ended September30, 2016 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $4,055for the nine-month period ended September30, 2016 are included in Income tax expense.

3Reclassifications before taxes of $2,222for the nine-month period ended September30, 2016 are included in Interest expense.  Related income taxes of $777 for the nine-month period ended September30, 2016 are included in Income tax expense.

Note L – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were

not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by priorowners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Environmental and Other Contingencies(Contd.)

to environmental matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

During 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers have been notified.  The Company has not yet established a complete estimate of the costs to remediate the site.  Based on the assessments done to date, the Company recorded $43.9 million in other expense during 2015 associated with the estimated costs of remediating the site.  The Company has spent $32.8 million to date associated with this event.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and insurance recoveries.  It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through September 30, 2016.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of these matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note M – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2016 to 2020 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries during the last thee months of 2016 of approximately 99 million cubic feet per day (MMCFD) at C$3.00 per MCF,  79 MMCFD at C$2.83 per MCF from January 2017 to December 2017 and 59MMCFD at C$2.81 per MCF from January 2018 through December 2020.In October 2016, the Company entered into an additional 20 MMCFD of natural gas sales contracts for the January 2017 through December 2020 period at C$3.12 per MCF.  These natural gas contracts have been accounted for as normal sales for accounting purposes.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

NoteN – Business Segments

			Three Months Ended		Three Months Ended
	Total Assets		September 30, 2016		September 30, 2015
	at September 30,		External	Income	External	Income
(Millions of dollars)	2016		Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,448.9	201.8	(27.1)	335.1	(107.8)
Canada		1,557.3	80.9	(4.8)	123.2	(507.0)
Malaysia		2,186.1	202.7	65.0	207.3	(952.7)
Other		120.2	0.2	(8.1)	–	(28.6)
Total exploration and production		9,312.5	485.6	25.0	665.6	(1,596.1)
Corporate		1,051.5	14.9	(39.6)	49.3	9.0
Assets/revenue/income (loss) from continuing operations		10,364.0	500.5	(14.6)	714.9	(1,587.1)
Discontinued operations, net of tax		30.0	–	(1.6)	–	(8.3)
Total	$	10,394.0	500.5	(16.2)	714.9	(1,595.4)
			Nine Months Ended		Nine Months Ended
			September 30, 2016		September 30, 2015
			External	Income	External	Income
(Millions of dollars)			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$		520.2	(158.5)	955.0	(218.1)
Canada			264.4	(36.9)	428.4	(577.8)
Malaysia			541.4	135.1	897.6	(701.9)
Other			0.2	(39.2)	–	(130.7)
Total exploration and production			1,326.2	(99.5)	2,281.0	(1,628.5)
Corporate			42.1	(111.7)	94.0	(44.0)
Revenue/income (loss) from continuing operations			1,368.3	(211.2)	2,375.0	(1,672.5)
Discontinued operations, net of tax			–	(0.8)	–	(11.2)
Total	$		1,368.3	(212.0)	2,375.0	(1,683.7)

*Additional details about results of oil and gas operations are presented in the tables on pages  27 and 28.

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O –New Accounting Principles and Recent Accounting Pronouncements

Leases

In February2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous generally accepted accounting principles (GAAP) and this ASU is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in 2019 and is currently evaluating the standard and its impact on its consolidated financial statements and footnote disclosures.

Compensation-Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  Early adoption is permitted for any entity in any interim period or annual period.  The Company will adopt this guidance in 2017 and is currently evaluating the impact on its consolidated financial statements and footnote disclosures.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establisha  comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method.  The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Statement of CashFlows

In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15)”).  ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  ASU 2016-15 is effective for annual and interim periods beginning after December 5, 2017.  The Company is currently assessing the potential impact of ASU 2016-15 on its consolidated financial statements.

20

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS

Overall Review

During 2016, worldwide benchmark oil and natural gas prices have been approximately 20% below average comparable benchmark prices during the 2015 period.  These lower oil and natural gas prices coupled with lower net hydrocarbons sold and a property impairment in the 2016 period have led the Company to incur losses from operations in the first nine months of 2016.  Although the Company has been lowering its overall cost structure, a continuation of very low commodity prices would likely lead to further adverse effects on the Company’s income and cash flow in future periods.

Results of Operations

Murphy’s results by type of business is presented below.

	Income (Loss)
	Three Months Ended			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2016		2015	2016		2015
Exploration and production	$	25.0	(1,596.1)		(99.5)		(1,628.5)
Corporate and other		(39.6)	9.0		(111.7)		(44.0)
Loss from continuing operations		(14.6)	(1,587.1)		(211.2)		(1,672.5)
Discontinued operations		(1.6)	(8.3)		(0.8)		(11.2)
Net loss	$	(16.2)	(1,595.4)		(212.0)		(1,683.7)

Murphy’s net loss in the third quarter of 2016 was $16.2 million ($0.09 per diluted share) compared to net loss of $1,595.4 million ($9.26 per diluted share) in the third quarter of 2015.  Loss from continuing operations was $14.6 million ($0.08 per diluted share) in the third quarter 2016 compared to a loss of $1,587.1 million ($9.22 per diluted share) in the 2015 quarter.  In the 2016 third quarter, the Company’s exploration and production continuing operations earned $25.0 million compared to a loss of $1,596.1 million in the 2015 quarter.  The net loss in the 2016 quarter was favorably impacted by no asset impairments compared to the 2015 period, lower lease operating expenses and depreciation expense, lower exploration costs and lower selling and general expenses.  These were offset in part by lower revenues primarily due to significantly weaker realized oil and natural gas sales prices and lower volumes sold.  The corporate function had after-tax costs of $39.6 million in the 2016 third quarter compared to after-tax income of $9.0 million in the 2015 period with the unfavorable variance in the current period mostly due to lower benefits from foreign exchange effects and higher net interest costs offset in part by lower administrative costs.  The 2016 third quarter included $1.6 million loss ($0.01 per diluted share) from discontinued operations compared to a loss of $8.3 million ($0.04 per diluted share) in the 2015 period.  Discontinued operations in the prior period included an adjustment to the impairment previously recognized for refining and marketing operations in the U.K.

For the first nine months of 2016, net loss totaled $212.0 million ($1.24 per diluted share) compared to a net loss of $1,683.7 million ($9.62 per diluted share) for the same period in 2015.  Continuing operations had a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016, compared to a loss of $1,672.5 million ($9.55 per diluted share) in the same period of 2015.  In the first nine months of 2016, the Company’s exploration and production operations incurred a loss of $99.5 million compared to a loss of $1,628.5 million in the same period of 2015.  Exploration and production loss in 2016 was lower than the 2015 period primarily due to lower impairment expenses, lower lease operating expenses and depreciation expense, lower exploration expenses, and lower selling and general expenses.  These improvements were partially offset by lower revenues resulting from lower realized oil and natural gas sales prices and lower volumes sold, losses on open crude oil contract positions in the 2016 period versus gains in the 2015 period and lower gains on assets sold.  Corporate after-tax costs were $111.7 million in the 2016 period compared to after-tax costs of $44.0 million in the 2015 period as the current period had lower gains for the effects of foreign currency exchange and higher net interest costs, partially offset by lower administrative costs.  Net loss in the nine months of 2016 included a loss from discontinued operations of $0.8 million ($0.01 per diluted share) compared to a loss of $11.2 million ($0.07 per diluted share) in the 2015 period.  Discontinued operations in in the 2015 period primarily consisted of costs related to winding down of all operations in the U.K., of which the final components of the refining and marketing operations were sold in 2015.

21

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production

Results of exploration and production continuing operations are presented by geographic segment below.

		Income (Loss)
	Three Months Ended			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2016		2015	2016	2015
Exploration and production
United States	$	(27.1)	(107.8)	(158.5)	(218.1)
Canada		(4.8)	(507.0)	(36.9)	(577.8)
Malaysia		65.0	(952.7)	135.1	(701.9)
Other		(8.1)	(28.6)	(39.2)	(130.7)
Total	$	25.0	(1,596.1)	(99.5)	(1,628.5)

Third quarter 2016 vs. 2015

United States exploration and production operations reported a loss of $27.1 million in the third quarter of 2016 compared to a loss of $107.8 million in the 2015 quarter.  Results improved by $80.7 million in the 2016 quarter compared to the 2015 period primarily due to no impairment expenses in the 2016 period. Revenues declined $133.3 million in the current period primarily due to lower oil and natural gas realized sales prices and lower volumes sold together with unfavorable mark-to-market results relating to open crude oil contract positions. The decline in revenue was partially offset by lower supply costs and lower exploration expenses.  Lease operating expenses decreased by $7.3 million due to lower costs in Eagle Ford Shale and offshore Gulf of Mexico compared to same quarter in 2015 with most of the reduction due to the Company lowering its cost structure offset in part by higher costs of workovers.  Severance and ad valorem taxes in the 2016 quarter were $3.6 million lower than the 2015 period primarily due to weaker average commodity prices and lower volume sold.  Depreciation expense decreased $79.7 million in 2016 compared to 2015 due to lower volume sold and lower unit rates. Unit rates improved in Eagle Ford Shale in the 2016 period due to lower drilling costs and migration of reserves, while the offshore Gulf of Mexico unit rates improved primarily due to impairments reported in the prior year.  Exploration expenses were down $14.1 million in the third quarter of 2016 primarily related to lower dry hole costs of $9.4 million and lower undeveloped lease amortization compared to the 2015 quarter.

Operations in Canada had a loss of $4.8 million in the third quarter 2016 compared to losses of $507.0 million in the 2015 quarter, an improvement of $502.2 quarter over quarter.  Results for conventional operations improved $498.0 million in 2016 primarily due to impairments in the 2015 period that did not repeat in 2016.  Revenues improved primarily due to higher volume sold from its offshore assets offset by lower oil and natural gas sales prices realized in the other conventional producing areas. Depreciation expense was lower by $5.1 million primarily due to the impairment of its heavy oil properties during 2015 but lease operating expense increased $8.1 million due to higher natural gas volumes produced in the Tupper area of Western Canada and higher natural gas processing costs together with a slightly stronger Canadian dollar exchange rate.  The Company sold its non-operated interest in Syncrude at the end of the second quarter 2016.

Malaysia operations reported earnings of $65.0 million in the 2016 quarter compared to losses of $952.7 million during the same period in 2015.  Results improved $1,017.7 million in 2016 in Malaysia primarily due to no repeat of impairment expense in 2016, lower lease operating expense, lower depreciation expense and lower dry hole costs.  Lease operating expenses decreased in the 2016 period by $27.6 million due to lower maintenance and logistic costs and lower well work together with lower volume sold compared to 2015.  Depreciation expense was $82.2 million lower in 2016 compared to the 2015 quarter primarily due to lower unit rates following 2015 impairment charges at certain producing properties, and lower oil and natural gas volumes sold.

22

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Third quarter 2016 vs. 2015 (Contd.)

Other international operations reported a loss of $8.1 million in the third quarter of 2016 compared to a loss of $28.6 million in the 2015 quarter.  The $20.5 million improvement in the 2016 period was primarily related to lower exploration expenses, lower selling and general expenses and income tax benefits reported on investments in foreign areas.

Total hydrocarbon production averaged 169,844 barrels of oil equivalent per day in the 2016 third quarter, which represented a decrease of 18.2% from the 207,586 barrels of oil equivalents per day produced in the 2015 quarter.  Average crude oil and condensate production was 96,476 barrels per day in the third quarter of 2016 compared to 125,170 barrels per day in the third quarter of 2015.  Crude oil production decreased 14,997 barrels in the Eagle Ford Shale area of South Texas in 2016 due to well decline and significantly less drilling in the last half of 2015 and first half of 2016.   Light oil production increased by 1,197 barrels per day in 2016 due to the completion of the Company’s acquisition of acreage in the Kaybob Duvernay lands and Placid Montney lands in Alberta.  Heavy oil production from the Seal area in Western Canada was lower in 2016 primarily due to volumes shut-in associated with uneconomic wells and natural decline.  Oil production offshore Eastern Canada was slightly higher during 2016 due to better uptime at both the Hibernia and Terra Nova fields.  Synthetic oil production was nil in 2016 versus 10,907 barrels per day in 2015 due to the sale of its non-operated interest in Syncrude at the end of the second quarter 2016.  Higher oil production in 2016 in Malaysia was primarily attributable to more production at Kakap, offset by decline in other fields.  On a worldwide basis, the Company's crude oil and condensate prices averaged $44.64 per barrel in the third quarter 2016 compared to $46.20 per barrel in the 2015 period, a decline of 3.4% quarter to quarter.  Total production of natural gas liquids (NGL) was 9,703 barrels per day in the 2016 third quarter compared to 11,093 barrels per day in the same 2015 period.  The decrease in NGL production was primarily associated with lower natural gas volumes produced in the U.S.  The average sales price for U.S. NGL was $11.38 per barrel in the 2016 quarter compared to $10.25 per barrel in 2015.  Natural gas sales volumes averaged 382 million cubic feet per day in the third quarter 2016 compared to 428 million cubic feet per day in 2015.  Natural gas sales volumes decreased in North America in 2016 due primarily to lower volumes produced offshore Gulf of Mexico but partially offset by higher volumes in the Tupper area of Western Canada.  Natural gas sales volumes in Malaysia decreased in the 2016 period due to more unplanned downtime and a lower entitlement in Sarawak in the 2016 period.  North American natural gas sales prices averaged $1.96 per thousand cubic feet (MCF) in the 2016 quarter, 19.0% below the $2.42 per MCF average in the same quarter of 2015.  The average realized price for natural gas produced in the 2016 quarter at fields offshore Sarawak was $3.01 per MCF, compared to a price of $3.75 per MCF in the 2015 quarter.

Nine Months 2016 vs. 2015

United States exploration and production operations reported a loss of $158.5 million in the first nine months of 2016 compared to a loss of $218.1 million in the 2015 period.  The loss decreased $59.6 million in 2016 compared to the 2015 period due to no impairment expense in 2016, plus lower expense in the current year for lease operations, depreciation, exploration and administrative expenses, offset in part by lower revenues.  Revenue in the U.S. fell $434.8 million in the 2016 period due to both lower oil and natural gas realized sales prices and lower volumes sold, coupled with unrealized losses on marking open crude oil contracts to market value in the 2016 period versus unrealized gains in the 2015 period.  Lease operating expenses decreased by $77.7 million due to lower costs in Eagle Ford Shale and offshore Gulf of Mexico compared to the same period in 2015, with most of the reduction due to the Company reducing costs coupled with lower variable costs based on volumes produced.  Severance and ad valorem taxes in the first nine months of 2016 were $16.5 million lower than the 2015 period primarily due to weaker average commodity prices and lower volume sold.  Depreciation expense decreased $165.9 million in 2016 compared to 2015 due to lower unit rates and lower volume sold.  Unit rates improved in Eagle Ford Shale in the 2016 period due to lower drilling costs and migration of reserves, while the offshore Gulf of Mexico unit rates were improved primarily due to impairments reported in the prior year.  Exploration expenses were down $100.1 million in the 2016 period primarily related to lower dry hole costs of $74.1 million and lower undeveloped lease amortization expense compared to the first nine months of 2015.  Selling and general expenses were $18.3 million lower in the 2016 period primarily due to Company restructuring activities in both 2015 and 2016 periods.

Operations in Canada had a loss of $36.9 million in 2016 compared to a loss of $577.8 million in 2015.  Canadian results of operations improved by $540.9 million in the 2016 period.  Results for conventional operations improved by $470.3 million in 2016 due to lower impairment expense, no repeat of prior year charges for an environmental provision at the Seal heavy oil area, income tax benefits recognized on the sale of certain Montney midstream assets in 2016, and no repeat of a tax adjustment in 2015 for a 2% increase in the statutory tax rate in Alberta, plus lower depreciation expense and lower lease

23

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Nine Months 2016 vs. 2015 (Contd.)

operating expense.  These improvements were partially offset by lower average realized sales prices for crude oil and natural gas.  Lease operating expenses associated with conventional operations were $7.6 million lower in the first nine months of 2016 due to lower operating costs, lower plant workover costs and a weaker Canadian dollar exchange rate offset in part by higher processing costs for its Tupper area production.  Depreciation expense was $33.5 million lower in the 2016 period compared to 2015 due primarily to impairment of its Seal area heavy oil property in the 2015 period.  Impairment expense was $588.5 million lower in the first nine months of 2016, as low oil prices led to a write down of heavy oil properties at Seal in Western Canada in 2015 and the Terra Nova field offshore East Coast Canada in the first quarter of 2016.  Synthetic operations generated $47.7 million in income in 2016 compared to a loss of $22.9 million in the same period of 2015. A $71.7 million after-tax gain on sale of the Company’s non-operated interest in Syncrude completed at the end of the second quarter 2016 was the primary driver of the improvement.

Malaysia operations reported earnings of $135.1 million in 2016 compared to a loss of $701.9 million during the same period in 2015.  Results were up $837.0 million in 2016 in Malaysia primarily due to no impairment expense in the current year are lower depreciation and lease operating expenses in 2016, partially offset by lower 2016 revenues and no repeat of a $218.8 million after-tax gain on sale of a 10% interest in Malaysian assets in the 2015 period.  Revenue declined by 356.2 million in 2016 driven by lower commodity prices received and lower volumes sold compared to 2015 coupled with no repeat of the 2015 gain on sale.  Lease operating expenses decreased in the 2016 period by $68.3 million due to lower maintenance and logistic costs and cost cutting measures, and lower volume sold compared to 2015.  Depreciation expense was $305.1 million lower in 2016 compared to the same period in 2015 primarily due to lower unit rates following 2015 impairment charges at certain producing properties and lower oil and natural gas volumes sold.

Other international operations reported a loss of $39.2 million in the first nine months of 2016 compared to a loss of $130.7 million in the 2015 period.  The 2016 period included lower dry hole costs of $21.4 million, with the higher 2015 costs primarily associated with unsuccessful wildcat drilling offshore Australia.  Geological and geophysical costs were $16.9 million lower in the 2016 period, primarily due to less seismic data acquired in Australia.  Other exploration expenses were $12.2 million lower in the current year, mostly attributable to the Company closing certain field offices beginning in late 2015 and lowering its cost structure.  Other expenses were $20.9 million less in the 2016 period primarily related to an adjustment of previously recorded exit costs in the current period associated with ceasing production operations in Republic of Congo versus a charge in the 2015 period for uncollectible receivables from partners in the Republic of Congo.  Selling and general expenses were $17.7 million lower in 2016 due to Company restructuring initiatives implemented in both 2015 and 2016.

Total worldwide production averaged 178,319 barrels of oil equivalent per day during the nine months ended September 30, 2016, down from 210,313 barrels of oil equivalent produced in the same period in 2015.  Crude oil and condensate production in the first half of 2016 averaged 106,279 barrels per day compared to 128,888 barrels per day a year ago.  Crude oil production decreased 11,633 barrels per day in the Eagle Ford Shale in 2016 due to well decline and significantly less drilling beginning in the last half of 2015 and continuing into 2016.   Heavy oil production in Canada declined in 2016 in the Seal area of Western Canada primarily due to uneconomic well volumes shut-in caused by low sales prices, and natural decline.  Synthetic oil production in Canada also was lower in 2016 due to impacts from the sale of its interest in Syncrude at the end of the second quarter of 2016 and maintenance work and downtime associated with forest fires in the surrounding area during the period leading up to the disposition.  Lower oil production in 2016 in Malaysia was primarily attributable to natural well decline at most fields, partly offset by higher production at Kakap.  For the first nine months of 2016, the Company’s sales price for crude oil and condensate averaged $40.67 per barrel, down from $49.58 per barrel in 2015.  Total production of natural gas liquids was 9,275 barrels per day in the 2016 period compared to 10,431 barrels per day a year ago. The sales price for U.S. natural gas liquids averaged $10.31 per barrel in 2016 compared to $11.90 per barrel in 2015.  Natural gas sales volumes decreased from 426 million cubic feet per day in 2015 to 377 million cubic feet per day in 2016. Natural gas sales volumes decreased in North America due to lower gas volume in the Gulf of Mexico primarily in the Dalmatian field and slightly lower volume from the Eagle Ford Shale area of South Texas, offset in part by higher gas production volumes in the Tupper area in Western Canada. Lower natural gas production in Malaysia was primarily due to higher unplanned downtime, lower entitlement at Sarawak and more gas injection at Kikeh.  The average sales price for North American natural gas in the first nine months of 2016 was $1.61 per MCF, down from $2.44 per MCF realized in 2015.  Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.25 per MCF in 2016 compared to $4.31 per MCF in 2015.

Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.

24

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Ex

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2016		2015	2016	2015
Net crude oil and condensate produced – barrels per day	96,476		125,170	106,279	128,888
United States – Eagle Ford Shale	33,307		48,304	36,790	48,423
– Gulf of Mexico and other	11,722		16,992	12,791	14,027
Canada – light	1,288		91	791	104
– heavy	2,678		4,975	2,732	5,837
– offshore	9,400	.	6,846	8,483	7,413
– synthetic1	–		10,907	6,194	11,230
Malaysia1 – Sarawak	12,889		15,194	13,288	15,696
– Block K	25,192		21,861	25,210	26,158
Net crude oil and condensate sold – barrels per day	97,542		124,549	104,525	129,294
United States – Eagle Ford Shale	33,307		48,304	36,790	48,423
– Gulf of Mexico and other	11,722		16,992	12,791	14,027
Canada – light	1,288		91	791	104
– heavy	2,678		4,975	2,732	5,837
– offshore	9,027		5,611	8,576	7,238
– synthetic1	–		10,907	6,194	11,230
Malaysia1 – Sarawak	12,641		18,493	12,024	17,546
– Block K	26,879		19,176	24,627	24,889
Net natural gas liquids produced – barrels per day	9,703		11,093	9,275	10,431
United States – Eagle Ford Shale	6,940		8,192	6,972	7,744
– Gulf of Mexico and other	1,502		2,264	1,399	2,020
Canada	307		1	162	9
Malaysia1 – Sarawak	954		636	742	658
Net natural gas liquids sold – barrels per day	8,770		11,789	9,289	10,466
United States – Eagle Ford Shale	6,940		8,192	6,972	7,744
– Gulf of Mexico	1,502		2,264	1,399	2,020
Canada	307		1	162	9
Malaysia1 – Sarawak	21		1,332	756	693
Net natural gas sold – thousands of cubic feet per day	381,988		427,937	376,592	425,964
United States – Eagle Ford Shale	34,900		39,543	36,430	39,203
– Gulf of Mexico and other	16,873		47,987	19,012	53,010
Canada	204,816		196,111	206,458	194,136
Malaysia1 – Sarawak	115,535		128,963	103,327	117,339
– Block K	9,864		15,333	11,365	22,276
Total net hydrocarbons produced – equivalent barrels per day2	169,844		207,586	178,319	210,313
Total net hydrocarbons sold – equivalent barrels per day2	169,977		207,661	176,579	210,754

1The Company sold a 10% interest in Malaysia propertieson January 29, 2015.  The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016.  Production in this table includes production for these sold interests through the date of disposition.

2Natural gas converted on an energy equivalent basis of 6:1.

25

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2016		2015	2016	2015
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	44.59	48.70	40.65	49.27
– Gulf of Mexico		43.93	44.94	40.53	49.45
Canada          – light		36.36	37.70	41.04	43.41
– heavy		19.50	20.28	14.20	25.09
– offshore		45.87	48.09	40.15	53.77
– synthetic		–	46.53	35.59	49.72
Malaysia – Sarawak2		47.05	46.38	43.62	50.27
– Block K2		46.24	46.88	43.70	54.24
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale	$	10.89	10.26	10.06	11.52
– Gulf of Mexico		13.65	10.25	11.60	13.13
Canada1		39.23	–	41.04	22.31
Malaysia – Sarawak2		45.12	54.27	37.50	55.23
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	2.24	2.39	1.69	2.39
– Gulf of Mexico		2.35	2.46	1.81	2.47
Canada1		1.88	2.42	1.58	2.44
Malaysia – Sarawak2		3.01	3.75	3.25	4.31
– Block K		0.23	0.24	0.24	0.24

1  U.S. dollar equivalent.

2  Prices are net of payments under terms of the respective production sharing contracts.

26

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015

			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Three Months Ended September 30, 2016
Oil and gas sales and other operating revenues	$	201.8	80.9	–	202.7	0.2	485.6
Lease operating expenses		59.6	30.7	–	29.4	–	119.7
Severance and ad valorem taxes		8.5	1.1	–	–	–	9.6
Depreciation, depletion and amortization		141.1	46.5	–	62.0	1.5	251.1
Accretion of asset retirement obligations		4.2	2.8	–	4.0	–	11.0
Exploration expenses
Dry holes		0.8	–	–	0.4	(0.2)	1.0
Geological and geophysical		(0.1)	–	–	0.1	0.5	0.5
Other		2.5	–	–	–	5.5	8.0
		3.2	–	–	0.5	5.8	9.5
Undeveloped lease amortization		9.3	1.1	–	–	–	10.4
Total exploration expenses		12.5	1.1	–	0.5	5.8	19.9
Selling and general expenses		14.7	5.2	–	0.2	7.4	27.5
Other expenses		1.0	–	–	5.4	0.1	6.5
Results of operations before taxes		(39.8)	(6.5)	–	101.2	(14.6)	40.3
Income tax provisions (benefits)		(12.7)	(1.7)	–	36.2	(6.5)	15.3
Results of operations (excluding corporate    overhead and interest)	$	(27.1)	(4.8)	–	65.0	(8.1)	25.0
Three Months Ended September 30, 2015
Oil and gas sales and other operating revenues	$	335.1	76.4	46.8	207.3	–	665.6
Lease operating expenses		66.9	22.6	37.3	57.0	–	183.8
Severance and ad valorem taxes		12.1	0.9	1.3	–	–	14.3
Depreciation, depletion and amortization		220.8	51.6	12.1	144.2	1.6	430.3
Accretion of asset retirement obligations		5.2	1.6	1.3	3.8	–	11.9
Impairment of assets		144.8	683.6	–	1,472.6	–	2,301.0
Exploration expenses
Dry holes		10.2	–	–	14.1	(2.9)	21.4
Geological and geophysical		2.5	–	–	–	4.8	7.3
Other		1.8	0.1	–	–	11.0	12.9
		14.5	0.1	–	14.1	12.9	41.6
Undeveloped lease amortization		12.0	3.9	–	–	0.6	16.5
Total exploration expenses		26.5	4.0	–	14.1	13.5	58.1
Selling and general expenses		22.9	5.1	0.2	3.3	15.2	46.7
Other expenses		0.9	–	–	17.3	–	18.2
Results of operations before taxes		(165.0)	(693.0)	(5.4)	(1,505.0)	(30.3)	(2,398.7)
Income tax benefits		(57.2)	(190.2)	(1.2)	(552.3)	(1.7)	(802.6)
Results of operations (excluding corporate    overhead and interest)	$	(107.8)	(502.8)	(4.2)	(952.7)	(28.6)	(1,596.1)

27

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015

			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Nine Months Ended September 30, 2016
Oil and gas sales and other operating revenues	$	520.2	200.2	64.2	541.4	0.2	1,326.2
Lease operating expenses		169.6	73.3	69.9	122.5	–	435.3
Severance and ad valorem taxes		30.0	3.2	2.5	–	–	35.7
Depreciation, depletion and amortization		456.5	137.5	16.5	170.0	4.6	785.1
Accretion of asset retirement obligations		12.8	8.2	2.4	12.1	–	35.5
Impairment of assets		–	95.1	–	–	–	95.1
Exploration expenses
Dry holes		0.4	–	–	4.5	10.4	15.3
Geological and geophysical		0.6	2.9	–	0.6	4.8	8.9
Other		4.5	0.5	–	–	18.9	23.9
		5.5	3.4	–	5.1	34.1	48.1
Undeveloped lease amortization		31.9	3.4	–	–	0.5	35.8
Total exploration expenses		37.4	6.8	–	5.1	34.6	83.9
Selling and general expenses		49.9	20.9	0.5	8.6	26.6	106.5
Other expenses (benefits)		1.1	–	–	6.3	(8.8)	(1.4)
Results of operations before taxes		(237.1)	(144.8)	(27.6)	216.8	(56.8)	(249.5)
Income tax provisions (benefits)		(78.6)	(60.2)	(75.3)	81.7	(17.6)	(150.0)
Results of operations (excluding corporate    overhead and interest)	$	(158.5)	(84.6)	47.7	135.1	(39.2)	(99.5)
Nine Months Ended September 30, 2015
Oil and gas sales and other operating revenues	$	955.0	275.7	152.7	897.6	–	2,281.0
Lease operating expenses		247.3	80.9	124.7	190.8	–	643.7
Severance and ad valorem taxes		46.5	3.5	4.1	–	–	54.1
Depreciation, depletion and amortization		622.4	171.0	37.4	475.1	4.7	1,310.6
Accretion of asset retirement obligations		14.9	5.0	4.1	11.4	–	35.4
Impairment of assets		144.8	683.6	–	1,472.6	–	2,301.0
Exploration expenses
Dry holes		74.5	–	–	14.1	31.8	120.4
Geological and geophysical		7.8	–	–	1.2	21.7	30.7
Other		6.7	0.5	–	–	31.1	38.3
		89.0	0.5	–	15.3	84.6	189.4
Undeveloped lease amortization		48.5	12.4	–	–	1.5	62.4
Total exploration expenses		137.5	12.9	–	15.3	86.1	251.8
Selling and general expenses		68.2	18.4	0.7	4.5	44.3	136.1
Other expenses		8.4	44.0	–	17.3	12.1	81.8
Results of operations before taxes		(335.0)	(743.6)	(18.3)	(1,289.4)	(147.2)	(2,533.5)
Income tax provisions (benefits)		(116.9)	(188.7)	4.6	(587.5)	(16.5)	(905.0)
Results of operations (excluding corporate    overhead and interest)	$	(218.1)	(554.9)	(22.9)	(701.9)	(130.7)	(1,628.5)

28

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had after tax cost of $39.6 million in the 2016 third quarter compared to after-tax income of $9.0 million in the same 2015 quarter.  The $48.6 million higher cost in the 2016 period is primarily due to lower benefits from foreign currency exchange and higher net interest costs, partially offset by lower administrative costs and lower tax benefits.  An after-tax gain of $11.5 million occurred in 2016 on transactions denominated in foreign currencies, while the 2015 quarter had an after-tax gain of $47.8 million.  Net interest costs increased $9.1 million in the 2016 period primarily due to issuance of $550 million in notes, in August 2016, that mature in 2024 and an increase of 1.00% on the coupon rates on $1.5 billion of the Company’s outstanding notes effective June 1, 2016 following a downgrade by Moody’s Investor Services in February 2016.

For the first nine months of 2016, corporate activities reflected after-tax costs of $111.7 million compared to after-tax costs of $44.0 million a year ago.  The $67.7 million increase in net cost in the current year is primarily due to lower foreign currency exchange benefits and higher net interest cost.  An after-tax gain of $32.9 million occurred in 2016 on transactions denominated in foreign currencies compared to an after-tax gain of $82.3 million a year ago.  Net interest costs increased $17.0 million in the 2016 period primarily due to the aforementioned reasons above.

Discontinued Operations

The Company has presented all operations in the U.K. as discontinued operations in its consolidated financial statements.  In June 2015, the Company completed an agreement to sell the remaining U.K. downstream assets.

The after-tax results of the U.K. operations for the three-month and nine-month periods ended September 30, 2016 and 2015 are reflected in the following table.

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
(Millions of dollars)		2016	2015	2016	2015
U.K. refining and marketing	$	(1.0)	(8.3)	(1.1)	(11.0)
U.K. exploration and production		(0.6)	–	0.2	(0.2)
Loss from discontinued operations	$	(1.6)	(8.3)	(0.9)	(11.2)

Financial Condition

Net cash provided by continuing operating activities was $280.3 million for the first nine-months of 2016 compared to $1,096.5 million during the same period in 2015.  The decline in cash provided by continuing operations activities in 2016 was primarily attributable to significantly lower realized sales prices for the Company’s oil and gas production and lower volume sold during the current year, and payoff of deepwater rig exit costs, offset in part by lower lease operating expenses.  Changes in noncash operating working capital from continuing operations used cash of $152.6 million during the first nine-months of 2016, compared to generating cash of $97.0 million in 2015.  The use of cash in 2016 included $266.6 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015.  Proceeds from sales of property and equipment generated cash of $1,154.6 million in 2016 compared to $423.8 million in 2015.  The 2016 proceeds are mainly attributable to the sale of the Company’s non-operated 5% interest in Syncrude Canada Ltd. (“Syncrude”) for $739.1 million and the disposition of certain midstream assets in the Tupper area of Western Canada for $414.1 million.  The prior year amount primarily related to proceeds received upon sale of a 10% interest in Malaysian assets.  Other significant sources of cash included $712.9 million in the 2016 period and $852.4 million in 2015 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.  The Company borrowed $541.4 million in the 2016 period with the proceeds from the offering to be used for general corporate purposes.

29

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

The uses of cash for property additions and dry holes, which including amounts expensed, were $781.7 million and $1,975.1 million in the nine-month period ended September 30, 2016 and 2015, respectively.  Capital expenditures were significantly lower in 2016 compared to 2015 primarily due to the Company lowering its capital spending in response to lower commodity prices.  Total cash dividends to shareholders amounted to $163.6 million in 2016 and $184.8 million in 2015.  Beginning in the third quarter 2016, the Company decreased its quarterly dividend to $0.25 per share, which represents a 29% reduction from the previous quarterly level of $0.35 per share.  Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $651.2 million in the 2016 period and $865.3 million in the 2015 period.  The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 on its revolving credit facility maturing in June 2017.  The debt repayment was funded using proceeds from the sale of assets.  In the first nine months of 2015, the Company expended $250.0 million to acquire 5,967,313 shares of Common stock.  The Company used $450.0 million of cash in the 2015 period to repay current maturities of long-term debt.

Total accrual basis capital expenditures were as follows:

	Nine Months Ended
	September 30,
(Millions of dollars)	2016		2015
Capital Expenditures
Exploration and production	$	614.6		1,631.5
Corporate		20.7		37.5
Total capital expenditures	$	635.3		1,669.0

The reduction in capital expenditures in the exploration and production business in 2016 compared to 2015 was primarily attributable to lower development drilling in the Eagle Ford Shale area in the United States and offshore Malaysia and lower spending on exploration drilling in the Gulf of Mexico and other international operations.  The 2016 capital expenditures included $206 million to fund acquisition of Kaybob Duvernay and  Placid Montney properties in Canada.

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows

	Nine Months Ended
	September 30,
(Millions of dollars)	2016		2015
Property additions and dry hole costs per cash flow statements	$	781.7		1,975.1
Geophysical and other exploration expenses		32.8		69.0
Capital expenditure accrual changes and other		(179.2)		(375.1)
Total capital expenditures	$	635.3		1,669.0

Working capital (total current assets less total current liabilities) at September 30, 2016 was $690.9 million, $917.1 million more than December 31, 2015, with the increase primarily attributable to cash generated from the 2016 issuance of $550 million in long-term notes maturing in 2024, plus cash proceeds from asset dispositions that were used to fund deepwater rig contract exit and other accrued cost and other operating activities.

At September 30, 2016, long-term debt of $2,973.9 million had decreased by $66.7 million compared to December 31, 2015.  Long-term debt was paid down in 2016 using part of the sales proceeds from Canadian asset disposition offset in part by the 2016 issuance of $550 million in notes maturing in 2024.  A summary of capital employed at September 30, 2016 and December 31, 2015 follows.

.

	September 30, 2016				December 31, 2015
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	2,973.9	36.9	%	$	3,040.6	36.4	%
Stockholders' equity		5,085.6	63.1			5,306.7	63.6
Total capital employed	$	8,059.5	100.0	%	$	8,347.3	100.0	%

30

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

Cash and invested cash are maintained in several operating locations outside the United States.  At September 30, 2016, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $198.0 million in Canada and $92.4 million in Malaysia.  In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations.  A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to spur oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted.  Canada collects a 5% withholding tax on any cash repatriated to the United States through a dividend to the U.S. parent.  Additionally, the Company could incur U.S. tax charges if amounts drawn in the U.S. on its 2016 revolving credit facility, guaranteed by a foreign subsidiary, are outstanding at the end of a quarterly reporting period.

Accounting and Other Matters

Leases

In February 2016, The Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous generally accepted accounting principles (GAAP) and this ASU is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in 2019 and is currently evaluating the standard and its impact on its consolidated financial statements and footnote disclosures.

Compensation-Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  Early adoption is permitted for any entity in any interim period or annual period.  The Company will adopt this guidance in 2017 and is currently evaluating the impact on its consolidated financial statements and footnote disclosures.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method.  The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Statement of CashFlows

In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15)”).  ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  ASU 2016-15 is effective for annual and interim periods beginning after December 5, 2017.  The Company is currently assessing the potential impact of ASU 2016-15 on its consolidated financial statements.

Outlook

Worldwide crude oil prices improved during October 2016 when compared to the average prices during the third quarter of 2016 as global petroleum inventories began to show signs of decline.  The U.S. shed more than 40 million barrels of crude oil stocks from the historically high levels reached during the second quarter.  North American natural gas prices have improved in October 2016 relative to the third quarter of 2016 as the summer injection season came to a close.  The U.S commercial natural gas inventory excess to the prior year has been reduced by more than 90% since the end of the withdrawal season in March.  The Company expects its total oil and natural gas production to average 162,000 to 164,000 barrels of oil

31

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Outlook  (Contd)

equivalent per day in the fourth quarter 2016.  The Company currently anticipates total capital expenditures for the full year 2016 to be approximately $620 million, excluding the cost to acquire the Kaybob Duvernay and Placid Montney interests in Canada.

The Company will primarily fund its capital program and property acquisitions in 2016 using operating cash flow and proceeds from recent divestitures, but supplements funding where necessary using borrowed money.  As of September 30, 2016, there were no funds borrowed under either of its bank credit facilities.  The Company’s current 2016 outlook calls for no borrowings under its revolving credit agreement during the last quarter of 2016.  If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that unanticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

The significant reduction in the sales prices of crude oil has caused the Company to reduce capital expenditures, including development drilling and completion operations in North America.  The Company’s capital spending program in 2016 will be well below 2015 levels.  The reduced level of capital expenditures, if continued, could lead to lower production levels in future periods.  A further deterioration of low oil and/or gas prices, could lead to negative future effects on the Company, which could include reductions in proved reserves, additional impairment charges, the necessity for further cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its Common stock.

As of October 31,  2016 the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

	Contract or		Average
Commodities	Location	Dates	Volumes per Day		Average Prices
U.S. Oil	West Texas Intermediate	Oct. – Dec. 2016		25,000 bbls/d	$50.67 per bbl.
U.S. Oil	West Texas Intermediate	Jan.  – Dec. 2017		18,000 bbls/d	$50.60 per bbl.
Canadian Natural Gas	TCPL–NOVA System	Oct. – Dec. 2016		99 mmcf/d	C$3.00 per mcf
Canadian Natural Gas	TCPL–NOVA System	Jan. 2017 – Dec. 2017		99 mmcf/d	C$2.89 per mcf
Canadian Natural Gas	TCPL–NOVA System	Jan. 2018 – Dec. 2020		59 mmcf/d	C$2.81 per mcf

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards.  For further discussion of risk factors, see Murphy’s 2015 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 33 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note J to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were commodity transactions in place at September30, 2016 covering certain future U.S. crude oil sales volumes in 2016 and 2017.  A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net asset associated with these derivative contracts by approximately $41.4 million, while a 10% decrease in the benchmark price would have increased the recorded net asset by a similar amount.

There were derivative foreign exchange contracts in place at September30, 2016 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables.  A 10% strengthening of the U.S. dollar against the Canadian dollar would have decreased the recorded net asset associated with these contracts by approximately $2.5 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $2.5 million.  Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

32

ITEM 4.  CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During 2016, the Company implemented a new global Enterprise Resource Planning (ERP) system, which will handle the business and financial processes within the company’s operations and its corporate and administrative functions. The Company has modified its existing internal controls related to the ERP system implementation.  While the Company believes that this new system and the related changes to internal controls will ultimately strengthen its internal controls over financial reporting, there are inherent risks in implementing a new ERP system and the Company will continue to evaluate and test control changes in order to provide certification as of its fiscal year ending December 31, 2016 on the effectiveness, in all material respects, of its internal controls over financial reporting.

During the quarter ended September30, 2016, there were no other changes in the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties.  These risk factors are discussed in Item 1A Risk Factors in its 2015 Form 10-K filed on February 26, 2016.  The Company has not identified any additional risk factors not previously disclosed in its 2015 Form 10-K report.

ITEM 6. EXHIBITS

The Exhibit Index on page 35 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

33

SIGNATURE

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.

MURPHY OIL CORPORATION

(Registrant)

By		/s/ KEITH CALDWELL
	Keith Caldwell, Senior Vice President
	and Controller (Chief Accounting Officer
	and Duly Authorized Officer)

November 2, 2016

(Date)

34

EXHIBIT INDEX

Exhibit
No.
4.1	Third Supplemental Indenture dated as of August 17, 2016 between Murphy Oil Corporation and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Murphy’s Current Report on Form 8-K filed August 17, 2016)
10.1	Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company – International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Murphy’s Current Report on Form 8-K filed August 12, 2016)
10.2	Third Amendment to 5-Year Revolving Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Canam Offshore Limited, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Murphy’s Current Report on Form 8-K filed August 12, 2016)
12	Computation of Ratio of Earnings to Fixed Charges
31.1	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS	XBRL Instance Document
101. SCH	XBRL Taxonomy Extension Schema Document
101. CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	XBRL Taxonomy Extension Labels Linkbase Document
101. PRE	XBRL Taxonomy Extension Presentation Linkbase

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

35

EX-12.1

EXHIBIT 12

Murphy Oil Corporation and Consolidated Subsidiaries

Computation of Ratio of Earnings to Fixed Charges (unaudited)

(Thousands of dollars)

		Nine Months
		Ended		Years Ended December 31,
		September 30, 2016		2015		2014	2013	2012	2011
Income (loss) from continuing operations  before income taxes	$	(413,060)		(3,282,262)		1,252,270	1,472,687	1,368,010	1,167,875
Distributions greater than equity in earnings   of affiliates		4,481		4,104		4,962	5,204	6,648	2,622
Previously capitalized interest charged to   earnings during period		6,848		27,201		19,760	16,896	18,061	18,757
Interest and expense on indebtedness,   excluding capitalized interest		103,889		117,375		115,819	71,900	14,932	40,700
Interest portion of rentals(1)		14,644		26,932		46,528	44,478	42,103	42,235
Earnings (loss) before provision for taxes    and fixed charges	$	(283,198)		(3,106,650)		1,439,339	1,611,165	1,449,754	1,272,189
Interest and expense on indebtedness,   excluding capitalized interest		103,889		117,375		115,819	71,900	14,932	40,700
Capitalized interest		3,318		7,290		20,605	52,523	39,173	15,131
Interest portion of rentals(1)		14,644		26,932		46,528	44,478	42,103	42,235
Total fixed charges	$	121,851		151,597		182,952	168,901	96,208	98,066
Ratio of earnings to fixed charges		–	(2)	–	(2)	7.9	9.5	15.1	13.0

(1)Calculated as one-third of rentals.  Considered a reasonable approximation of interest factor.

(2)Earnings for the nine-month period ended September 30, 2016 and the year ended December 31, 2015 were inadequate to cover fixed charges by $405,049 and $3,258,247, respectively.

Ex. 12-1

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Roger W. Jenkins certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting 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 generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  November 2, 2016

/s/  Roger W. Jenkins

Roger W. Jenkins

Principal Executive Officer

Ex. 31-1

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. Eckart, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting 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 generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  November2, 2016

/s/   John W. Eckart

John W. Eckart

Principal Financial Officer

Ex. 31-2

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period endedSeptember 30, 2016as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Roger W. Jenkinsand John W. Eckart,  Principal Executive Officer and PrincipalFinancial Officer, respectively,of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 2, 2016

/s/  Roger W. Jenkins

Roger W. Jenkins

Principal Executive Officer

/s/   John W. Eckart

John W. Eckart

Principal Financial Officer

Ex. 32-1

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2016 shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	mur
Entity Registrant Name	MURPHY OIL CORP /DE
Entity Central Index Key	0000717423
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	172,200,075

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Current assets
Cash and equivalents		$ 753,093	$ 283,183
Canadian government securities with maturities greater than 90 days at the date of acquisition		117,938	173,288
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2016 and 2015		400,532	522,672
Inventories, at lower of cost or market
Crude oil		11,196	25,583
Materials and supplies		151,107	141,205
Prepaid expenses		90,401	212,962
Deferred income taxes		50,879	51,183
Assets held for sale		29,978	38,340
Total current assets		1,605,124	1,448,416
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,425,414 in 2016 and $11,924,193 in 2015		8,440,336	9,818,365
Deferred charges and other assets		348,555	227,031
Total assets		10,394,015	11,493,812
Current liabilities
Current maturities of long-term debt		20,444	18,881
Accounts payable and accrued liabilities		876,664	1,643,632
Income taxes payable		13,817	4,819
Liabilities associated with assets held for sale		3,276	7,297
Total current liabilities		914,201	1,674,629
Long-term debt, including capital lease obligation		2,973,888	3,040,594
Deferred income taxes		50,244	239,811
Asset retirement obligations		748,576	793,474
Deferred credits and other liabilities		621,518	438,576
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2016 and 2015		195,056	195,056
Capital in excess of par value		921,675	910,074
Retained earnings		5,836,567	6,212,201
Accumulated other comprehensive loss	[1]	(571,031)	(704,542)
Treasury stock, 22,855,649 shares of Common Stock in 2016 and 23,021,013 shares of Common Stock in 2015, at cost		(1,296,679)	(1,306,061)
Total stockholders' equity		5,085,588	5,306,728
Total liabilities and stockholders' equity		$ 10,394,015	$ 11,493,812

[1] All amounts are presented net of income taxes.

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
CONSOLIDATED BALANCE SHEETS [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 1,605	$ 1,605
Property, plant and equipment, accumulated depreciation, depletion and amortization	$ 12,425,414	$ 11,924,193
Cumulative Preferred Stock, par	$ 100	$ 100
Cumulative Preferred Stock, authorized	400,000	400,000
Cumulative Preferred Stock, issued	0	0
Common Stock, par	$ 1.00	$ 1.00
Common Stock, authorized	450,000,000	450,000,000
Common Stock, issued	195,055,724	195,055,724
Treasury stock, shares	22,855,649	23,021,013

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES
Sales and other operating revenues	$ 486,276	$ 665,589	$ 1,326,587	$ 2,133,360
Gain (loss) on sale of assets	(730)	60	3,101	154,183
Interest and other income	14,987	49,300	38,602	87,443
Total revenues	500,533	714,949	1,368,290	2,374,986
COSTS AND EXPENSES
Lease operating expenses	119,663	183,826	435,296	643,736
Severance and ad valorem taxes	9,592	14,265	35,668	54,099
Exploration expenses, including undeveloped lease amortization	19,866	58,149	83,910	251,842
Selling and general expenses	55,523	71,791	196,143	237,934
Depreciation, depletion and amortization	255,900	433,706	797,288	1,318,123
Impairment of assets		2,300,974	95,088	2,300,974
Accretion of asset retirement obligations	11,043	11,918	35,514	35,437
Interest expense	40,088	32,009	107,207	91,945
Interest capitalized	(869)	(1,864)	(3,318)	(5,072)
Other expense (benefit)	6,486	18,192	(1,446)	81,804
Total costs and expenses	517,292	3,122,966	1,781,350	5,010,822
Loss from continuing operations before income taxes	(16,759)	(2,408,017)	(413,060)	(2,635,836)
Income tax benefit	(2,176)	(820,935)	(201,897)	(963,298)
Loss from continuing operations	(14,583)	(1,587,082)	(211,163)	(1,672,538)
Loss from discontinued operations, net of income taxes	(1,593)	(8,344)	(885)	(11,163)
NET LOSS	$ (16,176)	$ (1,595,426)	$ (212,048)	$ (1,683,701)
PER COMMON SHARE - BASIC
Loss from continuing operations	$ (0.08)	$ (9.22)	$ (1.23)	$ (9.55)
Loss from discontinued operations	(0.01)	(0.04)	(0.01)	(0.07)
Net loss	(0.09)	(9.26)	(1.24)	(9.62)
PER COMMON SHARE - DILUTED
Loss from continuing operations	(0.08)	(9.22)	(1.23)	(9.55)
Loss from discontinued operations	(0.01)	(0.04)	(0.01)	(0.07)
Net loss	$ (0.09)	$ (9.26)	$ (1.24)	$ (9.62)
Average Common shares outstanding
Basic	172,199,350	172,205,433	172,164,683	175,047,295
Diluted	172,199,350	172,205,433	172,164,683	175,047,295

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016		Sep. 30, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net loss	$ (16,176)	$ (1,595,426)	$ (212,048)		$ (1,683,701)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	(37,369)	(195,440)	124,522		(462,054)
Retirement and postretirement benefit plans	2,515	3,116	7,544		9,105
Deferred loss on interest rate hedges reclassified to interest expense	482	482	1,445		1,445
Other comprehensive income (loss)	(34,372)	(191,842)	133,511	[1]	(451,504)
COMPREHENSIVE LOSS	$ (50,548)	$ (1,787,268)	$ (78,537)		$ (2,135,205)

[1] All amounts are presented net of income taxes.

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015
OPERATING ACTIVITIES
Net loss		$ (212,048)		$ (1,683,701)
Adjustments to reconcile net loss to net cash provided by continuing operations activities:
Loss from discontinued operations		885		11,163
Depreciation, depletion and amortization		797,288		1,318,123
Impairment of assets		95,088		2,300,974
Amortization of deferred major repair costs		3,794		5,450
Dry hole costs		15,226		120,459
Amortization of undeveloped leases		35,828		62,331
Accretion of asset retirement obligations		35,514		35,437
Deferred and noncurrent income tax benefits		(345,157)		(975,120)
Pretax gains from disposition of assets		(3,101)		(154,183)
Net (increase) decrease in noncash operating working capital		(152,618)	[1]	97,026
Other operating activities, net		9,651		(41,431)
Net cash provided by continuing operations activities		280,350		1,096,528
INVESTING ACTIVITIES
Property additions and dry hole costs		(781,668)	[2]	(1,975,069)
Proceeds from sales of property, plant and equipment		1,154,623		423,842
Purchase of investment securities	[3]	(651,218)		(865,251)
Proceeds from maturity of investment securities	[3]	712,863		852,394
Other investing activities, net		(7,229)		(19,538)
Net cash provided (required) by investing activities		427,371		(1,583,622)
FINANCING ACTIVITIES
Borrowings of debt		541,444		885,000
Repayments of debt		(600,000)		(450,000)
Capital lease obligation payments		(7,808)		(7,156)
Purchase of treasury stock				(250,000)
Withholding tax on stock-based incentive awards		(1,138)		(8,976)
Issue cost of debt facility		(13,971)
Cash dividends paid		(163,586)		(184,789)
Other financing activities, net		(20)		(153)
Net cash required by financing activities		(245,079)		(16,074)
CASH FLOWS FROM DISCONTINUED OPERATIONS
Operating activities		2,830		(4,866)
Investing activities				5,343
Changes in cash included in current assets held for sale		(2,830)		179,774
Net increase in cash and cash equivalents of discontinued operations				180,251
Effect of exchange rate changes on cash and cash equivalents		7,268		8,276
Net increase (decrease) in cash and cash equivalents		469,910		(314,641)
Cash and cash equivalents at January 1		283,183		1,193,308
Cash and cash equivalents at September 30		$ 753,093		$ 878,667

[1] 2016 balance includes payments for deepwater rig contract exit of $266.6 million.

[2] Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.

[3] Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Payments for deepwater rig exit costs	$ 266.6
Minimum [Member]
Maturity of Canadian government securities	90 days

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Cumulative Preferred Stock [Member]	Common Stock [Member]	Capital In Excess Of Par Value [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock [Member]	Total
Balance at beginning of period at Dec. 31, 2014		$ 195,040	$ 906,741	$ 8,728,032	$ (170,255)	$ (1,086,124)
Exercise of stock options, including income tax benefits		16	(73)
Foreign currency translation gain (loss), net of income taxes					(462,054)		$ (462,054)
Purchase of treasury shares						(250,000)
Net loss for the period				(1,683,701)			(1,683,701)
Restricted stock transactions and other			(38,260)
Cash dividends				(184,789)
Retirement and postretirement benefit plans					9,105		9,105
Sale of stock under employee stock purchase plans						322
Stock-based compensation			33,925
Other			(92)
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes					1,445		1,445
Awarded restricted stock, net of forfeitures						29,176
Balance at end of period at Sep. 30, 2015		195,056	902,241	6,859,542	(621,759)	(1,306,626)	6,028,454
Balance at beginning of period at Dec. 31, 2015		195,056	910,074	6,212,201	(704,542)	(1,306,061)	5,306,728
Foreign currency translation gain (loss), net of income taxes					124,522		124,522
Net loss for the period				(212,048)			(212,048)
Restricted stock transactions and other			(10,078)
Cash dividends				(163,586)
Retirement and postretirement benefit plans					7,544		7,544
Sale of stock under employee stock purchase plans						389
Stock-based compensation			21,918
Other			(239)
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes					1,445		1,445
Awarded restricted stock, net of forfeitures						8,993
Balance at end of period at Sep. 30, 2016		$ 195,056	$ 921,675	$ 5,836,567	$ (571,031)	$ (1,296,679)	$ 5,085,588

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY [Abstract]
Cumulative Preferred Stock, par	$ 100	$ 100	$ 100
Cumulative Preferred Stock, authorized	400,000	400,000	400,000
Cumulative Preferred Stock, issued	0	0	0
Common Stock, par	$ 1.00	$ 1.00	$ 1.00
Common Stock, authorized	450,000,000	450,000,000	450,000,000
Common Stock, issued	195,055,724	195,055,724	195,055,724
Treasury stock, shares	22,855,649	23,021,013	22,303,782

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Nature of Business and Interim Financial Statements

9 Months Ended

Sep. 30, 2016

Nature of Business and Interim Financial Statements [Abstract]

Nature of Business and Interim Financial Statements

Note A – Nature of Business and Interim Financial Statements

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.  The Company sold its interest in a Canadian synthetic oil operation in the second quarter of 2016.  The Company acquired 70% interest in Duvernay Shale and a 30% interest in liquids rich Montney properties during the second quarter 2016.

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at September30, 2016 and December 31, 2015, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September30, 2016 and 2015, in conformity with accounting principles generally accepted in the United States of America (U.S.).  In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities.  Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2015 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the nine-month period ended September30, 2016 are not necessarily indicative of future results.

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2016

Property, Plant And Equipment [Abstract]

Property, Plant and Equipment

Note B – Property, Plant and Equipment

Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At September30, 2016, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $128.2 million.  The following table reflects the net changes in capitalized exploratory well costs during the

nine-month periods ended September30, 2016 and 2015.

(Thousands of dollars)	2016		2015
Beginning balance at January 1	$	130,514	120,455
Additions pending the determination of proved reserves		847	89,197
Other adjustments		(3,205)	–
Balance at September 30	$	128,156	209,652

Note B – Property, Plant and Equipment (Contd.)

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.  The projects are aged based on the last well drilled in the project.

		September 30,
	2016				2015
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	10,563	2	2	$	52,249	5	3
One to two years		53,101	3	3		32,192	2	1
Two to three years		31,627	2	–		27,842	2	–
Three years or more		32,865	4	–		97,369	4	2
	$	128,156	11	5	$	209,652	13	6

Of the $117.6 million of exploratory well costs capitalized more than one year at September30, 2016,  $64.5 million is in Brunei, $31.4 million is in Vietnam and $21.7 million is in Malaysia.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

In April 2016, a Canadian subsidiary of the Company signed a purchase and sale agreement for the sale of its five percent, non-operated working interest in Syncrude Canada Ltd.  (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”), subject to closing adjustments.  The sale was completed in June 2016 and the Company received net cash proceeds of $739.1 million.  The Company recorded an after-tax gain of $71.7 million in the second quarter of 2016 associated with the Syncrude divestiture.

In April 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  Total cash consideration received by Murphy upon closing of the transaction was $414.1million.  A gain on sale of approximately $187 million is being deferred and recognized over the next 20 years in the Canadian operating segment.  The Company has amortized $3.4 million of the deferred gain during 2016.  The remaining deferred gain is included as a component of deferred credits and other liabilities on the Company’s Consolidated Balance Sheet.

In a separate transaction, the same Canadian subsidiary signed a definitive agreement to acquire a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Montney lands in Alberta, the majority of which is unproved.  Under the terms of the joint venture the total consideration amounts to approximately $375 million, of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and the remaining $168.0 million in the form of a carried interest for a period of up to five years.  The transaction closed in the second quarter of 2016.

During the first quarter of 2016, declines in crude oil and natural gas prices from year end 2015 provided indications of possible impairments in certain of the company’s producing properties.  As a result of management’s assessments, the Company recognized pretax non-cash impairments charges of $95.1 million in the nine-month period ended September 30, 2016, to reduce the carrying value to their estimated fair value for its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the region.

During the third quarter 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties.  As a result of management’s assessments, during the third quarter of 2015, the Company recognized a pretax noncash impairment charge of approximately $2.3 billion to reduce the carrying value of certain producing properties in the Gulf of Mexico, Western Canada and Malaysia to their estimated fair value.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

Note B – Property, Plant and Equipment (Contd.)

During 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million.  The Company recorded an after-tax gain of $218.8 million on the sale of the final 10% portion of the total 30% sold.

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Discontinued Operations

9 Months Ended

Sep. 30, 2016

Discontinued Operations [Abstract]

Discontinued Operations

Note C – Discontinued Operations

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented.  The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter of 2015.  The 2015 nine-month period includes an adjustment to the impairment recognized as a result of the final sale of the U.K. downstream assets.

The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2016 and 2015 were as follows:

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2016	2015	2016	2015
Revenues (costs)	$	(1,345)	(1,342)	(510)	381,154
Loss before income taxes	$	(1,593)	(8,366)	(885)	(8,029)
Income tax (benefit) expense		–	(22)	–	3,134
Loss from discontinued operations	$	(1,593)	(8,344)	(885)	(11,163)

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at September30, 2016 and December 31, 2015.

	September 30,		December 31,
(Thousands of dollars)	2016		2015
Current assets
Cash	$	5,097	7,927
Accounts receivable		9,001	12,037
Other		15,880	18,376
Total current assets held for sale	$	29,978	38,340
Current liabilities
Accounts payable	$	915	2,433
Accrued compensation and severance		–	2,179
Refinery decommissioning cost		2,361	2,685
Total current liabilities associated with assets held for sale	$	3,276	7,297

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Financing Arrangements and Debt

9 Months Ended

Sep. 30, 2016

Financing Arrangements and Debt [Abstract]

Financing Arrangements and Debt

Note D – Financing Arrangements and Debt

In August 2016 the Company reduced its existing $2.0 billion unsecured revolving credit facility (“2011 facility”) to $630 million and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (“2016 facility”) with a major banking consortium that expires in August 2019.  Facility fees of 0.5% are charged annually on the full $1.2 billion commitment.  The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which are included in financing activities in the Consolidated Statement of Cash Flows.  At September 30, 2016, the Company had nooutstanding borrowings under either credit facility, however, there was approximately $88 million of issued letters of credit under the 2016 facility.  The 2016 facility is unsecured, with guarantees from certain domestic and foreign subsidiaries.  Should the Company make substantial asset sales, the facility size would be automatically reduced to a minimum of $1.0 billion.  Borrowings under the 2016 facility are subject to varying interest rates ranging from LIBOR plus 250 basis points to LIBOR plus 450 basis points.  The terms of the 2016 facility include covenants that impose certain restrictions on the Company.  These financial covenants include a minimum adjusted EBITDAX of 2.5 times consolidated interest expense, consolidated debt not to exceed 3.75 times adjusted EBITDAX and minimum liquidity from U.S. and Canadian entities equal to or greater than $500 million.  Also beginning March 31, 2017, if the Company’s total leverage ratio exceeds 3.25 times the Company’s trailing twelve month consolidated adjusted EBITDAX, as defined in the 2016 facility, the facility will become secured, subject to limitations set forth in the Company’s existing notes.  The existing unsecured 2011 facility, which expires in June 2017, includes a financial covenant under which the Company may not have total debt in excess of 60% of its total capital employed (debt borrowed plus stockholders’ equity).  As of September 30, 2016, the Company was in compliance with all financial covenants contained in both credit facilities.  The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.

In August 2016, the Company sold $550 million of new notes that bear interest at the rate of 6.875% and mature on August 15, 2024.  The new notes pay interest semi-annually on February 15 and August 15 of each year.  The initial interest payment is to be made on February 15, 2017.  The proceeds of the $550 million notes were used for general corporate purposes.

The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through September 2028.  Current maturities and long-term debt on the Consolidated Balance Sheet included $20.4 million and $202.7 million, respectively, associated with this lease at September 30, 2016.

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Cash Flow Disclosures

9 Months Ended

Sep. 30, 2016

Cash Flow Disclosures [Abstract]

Cash Flow Disclosures

Note E – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.

	Nine Months Ended September 30,
(Thousands of dollars)	2016		2015
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	75,841	389,413
Increase in inventories		(15,768)	(16,607)
Decrease (increase) in prepaid expenses		122,399	(87,051)
Decrease in deferred income tax assets		720	4,863
Decrease in accounts payable and accrued liabilities		(376,310)	(134,458)
Increase (decrease) in current income tax liabilities		40,500	(59,134)
Net (increase) decrease in noncash operating working capital	$	(152,618)	97,026
Supplementary disclosures:
Cash income taxes paid (refunded), net	$	(3,911)	111,897
Interest paid, net of amounts capitalized		52,287	60,766
Non-cash investing activities:
Asset retirement costs capitalized	$	13,959	55,258
Decrease in capital expenditure accrual		179,203	374,720

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Employee and Retiree Benefit Plans

9 Months Ended

Sep. 30, 2016

Employee and Retiree Benefit Plans [Abstract]

Employee and Retiree Benefit Plans

Note F – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan.  All U.S. tax qualified plans meet the funding requirements of federal laws and regulations.  Contributions to foreign plans are based on local laws and tax regulations.  The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most active and retired U.S. employees.  Additionally, most U.S. retired employees are covered by a life insurance benefit plan.  The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30,2016 and 2015.

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	2,610	5,898		674		826
Interest cost		5,913	8,972		1,109		1,192
Expected return on plan assets		(6,626)	(10,471)		–		–
Amortization of prior service cost		323	187		(21)		(21)
Amortization of transitional asset		–	402		2		2
Recognized actuarial loss		3,617	3,885		38		193
Net periodic benefit expense	$	5,837	8,873		1,802		2,192
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	8,533	15,751		2,022		2,482
Interest cost		20,386	24,893		3,324		3,576
Expected return on plan assets		(21,709)	(27,882)		–		–
Amortization of prior service cost		963	580		(62)		(62)
Amortization of transitional asset		–	947		4		5
Recognized actuarial loss		10,864	11,667		113		578
		19,037	25,956		5,401		6,579
Special termination benefits		–	8,606		(19)		–
Curtailments		822	306		–		–
Net periodic benefit expense	$	19,859	34,868		5,382		6,579

Curtailment expense for the nine months ended September30, 2016 shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.  Termination and curtailment expenses for the nine months ended September 30, 2015 relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.  During the nine-month period ended September 30, 2016, the Company made contributions of $10.0 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2016 for the Company’s defined benefit pension and postretirement benefit plans is anticipated to be $2.9 million.

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Incentive Plans

9 Months Ended

Sep. 30, 2016

Incentive Plans [Abstract]

Incentive Plans

Note G – Incentive Plans

The costs resulting from all share-based payment transactions are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The 2012 Annual Incentive Plan (2012 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees.  Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.  The 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock and other stock-based incentives to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2012 Long-Term Plan expires in 2022.  A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding.  The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30,2017.  The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors. 

In February 2016, the Committee granted stock options for 862,000 shares at an exercise price of $17.57 per share.  The Black-Scholes valuation for these awards was $5.03 per option.  The Committee also granted 394,000 performance-based RSU and 417,500 time-based RSU in February and April 2016.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $12.21 to $16.34 per unit.  The fair values of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which ranged from $17.57 to 24.075 per share.  Additionally, the Committee granted 708,200 SAR and 507,470 units of cash-settled RSU (RSU-C) to certain employees in 2016.  The SAR and RSU-C are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards.  The initial fair value of these SAR was equivalent to the stock options granted, while the initial value of RSU-C was equivalent to equity-settled restricted stock units granted.  Also in February 2016, the Committee granted 85,679 shares of time-based RSU to the Company’s Directors under the Non-employee Director Plan.  These shares vest on the third anniversary of the date of grant. The estimated fair value of these awards was $19.26 per unit on date of grant.

Amounts recognized in the financial statements with respect to share-based plans are as follows:

	Nine Months Ended
	September 30,
(Thousands of dollars)		2016	2015
Compensation charged against income before tax benefit	$	35,948	30,722
Related income tax benefit recognized		11,796	9,046

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Earnings per Share

9 Months Ended

Sep. 30, 2016

Earnings per Share [Abstract]

Earnings per Share

Note H – Earnings per Share

Net loss was used as the numerator in computing both basic and diluted income per Common share for the

three-month and nine-month periods ended September30, 2016 and 2015.  The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(Weighted-average shares)	2016	2015	2016	2015
Basic method	172,199,350	172,205,433	172,164,683	175,047,295
Dilutive stock options*	–	–	–	–
Diluted method	172,199,350	172,205,433	172,164,683	175,047,295

     *Due to a net loss recognized by the Company for the three-month and nine-month periods ended September 30, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

	Three Months Ended			Nine Months Ended
		September 30,		September 30,
		2016	2015	2016		2015
Antidilutive stock options excluded from diluted shares		5,884,201	5,807,453		5,822,036	5,770,731
Weighted average price of these options	$	49.00	53.13		49.82	53.25

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Taxes [Abstract]

Income Taxes

Note I – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) before income taxes.  For the three-month and nine-month periods in 2016 and 2015, the Company’s effective income tax rates were as follows:

	2016	2015
Three months ended September 30	13.0%	34.1%
Nine months ended September 30	48.9%	36.6%

The effective tax rates for most periods differ from the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.  Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 35% due to similar reasons.  The effective tax rate for the three-month period ended September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized.  The effective tax rate for the nine-month period ended September 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign areas.  The effective tax rate for the three-month period ended September 30, 2015 was less than the U.S. statutory tax rate primarily due to a deferred tax expense associated with an enacted increase in the statutory tax rate in Alberta.  The effective tax rate for the nine-month period ended September 30, 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets, partially offset by expenses in foreign jurisdictions for which no tax benefits were recognized and the enacted increase in statutory rate in Alberta.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As ofSeptember30, 2016, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:United States – 2011; Canada – 2008; Malaysia – 2009; and United Kingdom – 2014.

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Financial Instruments and Risk Management

9 Months Ended

Sep. 30, 2016

Financial Instruments and Risk Management [Abstract]

Financial Instruments and Risk Management

Note J – Financial Instruments and Risk Management

Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges, such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the net payment upon settlement recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss.  This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil, natural gas liquids and natural gas it produces and sells.  The Company had open derivative contracts at September30, 2016 and 2015.  The impact from marking to market these commodity derivative contracts increased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016 and reduced the loss before income taxes by $7.4 million for the nine-month period ended September 30, 2015.

Open West Texas Intermediate (WTI) contracts were as follows:

	Volumes
At September 30, 2016	(barrels per day)	Swap Prices
October – December 2016	25,000	$50.67	per barrel
January – December 2017	16,000	$50.34	per barrel
At September 30, 2015
October – December 2015	15,000	$63.30	per barrel

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  At September30, 2016 and 2015 short-term derivative instruments were outstanding in Canada for approximately $25.2 million and $6.2 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The impact from marking to market these foreign currency derivative contracts was insignificant for the nine-month periods ended September30, 2016 and 2015, respectively.

After signing an agreement to sell its five percent non-operated working interest in Syncrude, the Company’s Canadian subsidiary entered into forward sales contracts for C$1.0 billion at a fixed rate to lock in the U.S. dollar value of the proceeds and protect the Company from exposure to weakening of the Canadian dollar.  Upon completion of the sale and settlement of the forward sale contracts, the Company recognized income of approximately $26.8 million in the second quarter of 2016 due to weakening of the Canadian dollar subsequent to entering into the contracts.

At September30, 2016 and December 31, 2015, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

	September 30, 2016			December 31, 2015
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity	Accounts receivable	$	192	Accounts receivable	$	89,358
Foreign exchange	Accounts receivable		142	Accounts payable		(29)

Note J – Financial Instruments and Risk Management (Contd.)

For the three-month and nine-month periods ended September30, 2016 and 2015, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

			Gain (Loss)
		Three Months Ended			Nine Months Ended
(Thousands of dollars)		September 30,			September 30,
Type of Derivative Contract	Statement of Operations Location		2016	2015	2016	2015
Commodity	Sales and other operating revenues	$	11,871	39,392	(22,678)	46,811
Foreign exchange	Interest and other income		143	33	26,929	47
		$	12,014	39,425	4,251	46,858

Interest Rate Risks

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012.  These interest rate swaps matured in May 2012.  Under hedge accounting rules, the Company deferred the net cost associated with these contracts to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September30, 2016 and 2015,$1.5 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations.  The remaining loss deferred on these matured contracts at September30, 2016 was $10.8 million, which was recorded, net of income taxes of $5.8 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining three months of 2016.

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities.  Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September30, 2016 and December 31,2015 are presented in the following table.

	September 30, 2016					December 31, 2015
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Foreign currency exchange         derivative contracts	$	–	142	–	142	–	–	–	–
Commodity derivative         contracts		–	192	–	192	–	89,358	–	89,358
	$	–	334	–	334	–	89,358	–	89,358
Liabilities:
Nonqualified employee         savings plans	$	13,637	–	–	13,637	12,971	–	–	12,971
Foreign currency exchange         derivative contracts		–	–	–	–	–	29	–	29
	$	13,637	–	–	13,637	12,971	29	–	13,000

Note J – Financial Instruments and Risk Management (Contd.)

The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date.  The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates.  The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues in the Consolidated Statements of Operations while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses in the Consolidated Statements of Operations.  The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at September30, 2016 and December 31, 2015.

Fair Values – Nonrecurring

As a result of significantly lower commodity prices during the nine-month periods ended September 30, 2016 and 2015, the Company recognized $95.1 million and $2.3 billion, respectively, in pretax noncash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following tables.

	September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

	September 30, 2015
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Gulf of Mexico	$	–	–	216,602	361,402	144,800
Western Canada		–	–	23,526	707,100	683,574
Malaysia		–	–	1,208,900	2,681,500	1,472,600
	$	–	–	1,449,028	3,750,002	2,300,974

The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2016

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

Note K – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2015 and September30, 2016 and the changes during the nine-month period ended September30, 2016 are presented net of taxes in the following table.

					Deferred
					Loss on
		Foreign	Retirement and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)1	Adjustments1		Hedges1		Total1
Balance at December 31, 2015	$	(513,004)	(179,260)		(12,278)		(704,542)
Components of other comprehensive income:
Before reclassifications to income		124,522	(3)		–		124,519
Reclassifications to income		–	7,547	2	1,445	3	8,992
Net other comprehensive income		124,522	7,544		1,445		133,511
Balance at September 30, 2016	$	(388,482)	(171,716)		(10,833)		(571,031)

1All amounts are presented net of income taxes.

2Reclassifications before taxes of $11,602 for thenine-month period ended September30, 2016 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $4,055for the nine-month period ended September30, 2016 are included in Income tax expense.

3Reclassifications before taxes of $2,222for the nine-month period ended September30, 2016 are included in Interest expense.  Related income taxes of $777 for the nine-month period ended September30, 2016 are included in Income tax expense.

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Environmental and Other Contingencies

9 Months Ended

Sep. 30, 2016

Environmental and Other Contingencies [Abstract]

Environmental and Other Contingencies

Note L – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were

not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by priorowners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related

Note L – Environmental and Other Contingencies(Contd.)

to environmental matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

During 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers have been notified.  The Company has not yet established a complete estimate of the costs to remediate the site.  Based on the assessments done to date, the Company recorded $43.9 million in other expense during 2015 associated with the estimated costs of remediating the site.  The Company has spent $32.8 million to date associated with this event.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and insurance recoveries.  It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through September 30, 2016.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of these matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

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Commitments

9 Months Ended

Sep. 30, 2016

Commitments [Abstract]

Commitments

Note M – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2016 to 2020 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries during the last thee months of 2016 of approximately 99 million cubic feet per day (MMCFD) at C$3.00 per MCF, 79 MMCFD at C$2.83 per MCF from January 2017 to December 2017 and 59 MMCFD at C$2.81 per MCF from January 2018 through December 2020.  In October 2016, the Company entered into an additional 20 MMCFD of natural gas sales contracts for the January 2017 through December 2020 period at C$3.12 per MCF.  These natural gas contracts have been accounted for as normal sales for accounting purposes.

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Business Segments

9 Months Ended

Sep. 30, 2016

Business Segments [Abstract]

Business Segments

Note N – Business Segments

			Three Months Ended		Three Months Ended
	Total Assets		September 30, 2016		September 30, 2015
	at September 30,		External	Income	External	Income
(Millions of dollars)	2016		Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,448.9	201.8	(27.1)	335.1	(107.8)
Canada		1,557.3	80.9	(4.8)	123.2	(507.0)
Malaysia		2,186.1	202.7	65.0	207.3	(952.7)
Other		120.2	0.2	(8.1)	–	(28.6)
Total exploration and production		9,312.5	485.6	25.0	665.6	(1,596.1)
Corporate		1,051.5	14.9	(39.6)	49.3	9.0
Assets/revenue/income (loss) from continuing operations		10,364.0	500.5	(14.6)	714.9	(1,587.1)
Discontinued operations, net of tax		30.0	–	(1.6)	–	(8.3)
Total	$	10,394.0	500.5	(16.2)	714.9	(1,595.4)
			Nine Months Ended		Nine Months Ended
			September 30, 2016		September 30, 2015
			External	Income	External	Income
(Millions of dollars)			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$		520.2	(158.5)	955.0	(218.1)
Canada			264.4	(36.9)	428.4	(577.8)
Malaysia			541.4	135.1	897.6	(701.9)
Other			0.2	(39.2)	–	(130.7)
Total exploration and production			1,326.2	(99.5)	2,281.0	(1,628.5)
Corporate			42.1	(111.7)	94.0	(44.0)
Revenue/income (loss) from continuing operations			1,368.3	(211.2)	2,375.0	(1,672.5)
Discontinued operations, net of tax			–	(0.8)	–	(11.2)
Total	$		1,368.3	(212.0)	2,375.0	(1,683.7)

*Additional details about results of oil and gas operations are presented in the tables on pages  27 and 28.

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New Accounting Principles and Recent Accounting Pronouncements

9 Months Ended

Sep. 30, 2016

New Accounting Principles and Recent Accounting Pronouncements [Abstract]

New Accounting Principles and Recent Accounting Pronouncements

Note O –New Accounting Principles and Recent Accounting Pronouncements

Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous generally accepted accounting principles (GAAP) and this ASU is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in 2019 and is currently evaluating the standard and its impact on its consolidated financial statements and footnote disclosures.

Compensation-Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  Early adoption is permitted for any entity in any interim period or annual period.  The Company will adopt this guidance in 2017 and is currently evaluating the impact on its consolidated financial statements and footnote disclosures.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method.  The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Statement of CashFlows

In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15)”).  ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  ASU 2016-15 is effective for annual and interim periods beginning after December 5, 2017.  The Company is currently assessing the potential impact of ASU 2016-15 on its consolidated financial statements.

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Nature of Business and Interim Financial Statements (Policies)

9 Months Ended

Sep. 30, 2016

Nature of Business and Interim Financial Statements [Abstract]

Nature of Business

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.  The Company sold its interest in a Canadian synthetic oil operation in the second quarter of 2016.  The Company acquired 70% interest in Duvernay Shale and a 30% interest in liquids rich Montney properties during the second quarter 2016.

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2016

Property, Plant And Equipment [Abstract]

Net Changes in Capitalized Exploratory Well Costs

(Thousands of dollars)	2016		2015
Beginning balance at January 1	$	130,514	120,455
Additions pending the determination of proved reserves		847	89,197
Other adjustments		(3,205)	–
Balance at September 30	$	128,156	209,652

Aging of Capitalized Exploratory Well Costs

		September 30,
	2016				2015
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	10,563	2	2	$	52,249	5	3
One to two years		53,101	3	3		32,192	2	1
Two to three years		31,627	2	–		27,842	2	–
Three years or more		32,865	4	–		97,369	4	2
	$	128,156	11	5	$	209,652	13	6

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2016

Discontinued Operations [Abstract]

Results of Operations Associated with Discontinued Operations

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2016	2015	2016	2015
Revenues (costs)	$	(1,345)	(1,342)	(510)	381,154
Loss before income taxes	$	(1,593)	(8,366)	(885)	(8,029)
Income tax (benefit) expense		–	(22)	–	3,134
Loss from discontinued operations	$	(1,593)	(8,344)	(885)	(11,163)

Major Categories of Assets and Liabilities Reflected as Held for Sale

	September 30,		December 31,
(Thousands of dollars)	2016		2015
Current assets
Cash	$	5,097	7,927
Accounts receivable		9,001	12,037
Other		15,880	18,376
Total current assets held for sale	$	29,978	38,340
Current liabilities
Accounts payable	$	915	2,433
Accrued compensation and severance		–	2,179
Refinery decommissioning cost		2,361	2,685
Total current liabilities associated with assets held for sale	$	3,276	7,297

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Cash Flow Disclosures (Tables)

9 Months Ended

Sep. 30, 2016

Cash Flow Disclosures [Abstract]

Cash Flow Activities

	Nine Months Ended September 30,
(Thousands of dollars)	2016		2015
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	75,841	389,413
Increase in inventories		(15,768)	(16,607)
Decrease (increase) in prepaid expenses		122,399	(87,051)
Decrease in deferred income tax assets		720	4,863
Decrease in accounts payable and accrued liabilities		(376,310)	(134,458)
Increase (decrease) in current income tax liabilities		40,500	(59,134)
Net (increase) decrease in noncash operating working capital	$	(152,618)	97,026
Supplementary disclosures:
Cash income taxes paid (refunded), net	$	(3,911)	111,897
Interest paid, net of amounts capitalized		52,287	60,766
Non-cash investing activities:
Asset retirement costs capitalized	$	13,959	55,258
Decrease in capital expenditure accrual		179,203	374,720

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Employee and Retiree Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Employee and Retiree Benefit Plans [Abstract]

Components of Net Periodic Benefit Expense

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	2,610	5,898		674		826
Interest cost		5,913	8,972		1,109		1,192
Expected return on plan assets		(6,626)	(10,471)		–		–
Amortization of prior service cost		323	187		(21)		(21)
Amortization of transitional asset		–	402		2		2
Recognized actuarial loss		3,617	3,885		38		193
Net periodic benefit expense	$	5,837	8,873		1,802		2,192
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2016	2015	2016		2015
Service cost	$	8,533	15,751		2,022		2,482
Interest cost		20,386	24,893		3,324		3,576
Expected return on plan assets		(21,709)	(27,882)		–		–
Amortization of prior service cost		963	580		(62)		(62)
Amortization of transitional asset		–	947		4		5
Recognized actuarial loss		10,864	11,667		113		578
		19,037	25,956		5,401		6,579
Special termination benefits		–	8,606		(19)		–
Curtailments		822	306		–		–
Net periodic benefit expense	$	19,859	34,868		5,382		6,579

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Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2016

Incentive Plans [Abstract]

Share-Based Plans, Amounts Recognized

	Nine Months Ended
	September 30,
(Thousands of dollars)		2016	2015
Compensation charged against income before tax benefit	$	35,948	30,722
Related income tax benefit recognized		11,796	9,046

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings per Share [Abstract]

Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(Weighted-average shares)	2016	2015	2016	2015
Basic method	172,199,350	172,205,433	172,164,683	175,047,295
Dilutive stock options*	–	–	–	–
Diluted method	172,199,350	172,205,433	172,164,683	175,047,295

     *Due to a net loss recognized by the Company for the three-month and nine-month periods ended September 30, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

Anti Dilutive Securities Not Included in Computation of Diluted EPS

	Three Months Ended			Nine Months Ended
		September 30,		September 30,
		2016	2015	2016		2015
Antidilutive stock options excluded from diluted shares		5,884,201	5,807,453		5,822,036	5,770,731
Weighted average price of these options	$	49.00	53.13		49.82	53.25

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Taxes [Abstract]

Effective Income Tax Rates

	2016	2015
Three months ended September 30	13.0%	34.1%
Nine months ended September 30	48.9%	36.6%

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Financial Instruments and Risk Management (Tables)

9 Months Ended

Sep. 30, 2016

Financial Instruments and Risk Management [Abstract]

WTI Open Contracts

	Volumes
At September 30, 2016	(barrels per day)	Swap Prices
October – December 2016	25,000	$50.67	per barrel
January – December 2017	16,000	$50.34	per barrel
At September 30, 2015
October – December 2015	15,000	$63.30	per barrel

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

	September 30, 2016			December 31, 2015
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity	Accounts receivable	$	192	Accounts receivable	$	89,358
Foreign exchange	Accounts receivable		142	Accounts payable		(29)

Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments

			Gain (Loss)
		Three Months Ended			Nine Months Ended
(Thousands of dollars)		September 30,			September 30,
Type of Derivative Contract	Statement of Operations Location		2016	2015	2016	2015
Commodity	Sales and other operating revenues	$	11,871	39,392	(22,678)	46,811
Foreign exchange	Interest and other income		143	33	26,929	47
		$	12,014	39,425	4,251	46,858

Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis

	September 30, 2016					December 31, 2015
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Foreign currency exchange         derivative contracts	$	–	142	–	142	–	–	–	–
Commodity derivative         contracts		–	192	–	192	–	89,358	–	89,358
	$	–	334	–	334	–	89,358	–	89,358
Liabilities:
Nonqualified employee         savings plans	$	13,637	–	–	13,637	12,971	–	–	12,971
Foreign currency exchange         derivative contracts		–	–	–	–	–	29	–	29
	$	13,637	–	–	13,637	12,971	29	–	13,000

Nonrecurring Fair Value Measurements

	September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

	September 30, 2015
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Gulf of Mexico	$	–	–	216,602	361,402	144,800
Western Canada		–	–	23,526	707,100	683,574
Malaysia		–	–	1,208,900	2,681,500	1,472,600
	$	–	–	1,449,028	3,750,002	2,300,974

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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2016

Accumulated Other Comprehensive Loss [Abstract]

Components of Accumulated Other Comprehensive Loss

					Deferred
					Loss on
		Foreign	Retirement and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)1	Adjustments1		Hedges1		Total1
Balance at December 31, 2015	$	(513,004)	(179,260)		(12,278)		(704,542)
Components of other comprehensive income:
Before reclassifications to income		124,522	(3)		–		124,519
Reclassifications to income		–	7,547	2	1,445	3	8,992
Net other comprehensive income		124,522	7,544		1,445		133,511
Balance at September 30, 2016	$	(388,482)	(171,716)		(10,833)		(571,031)

1All amounts are presented net of income taxes.

2Reclassifications before taxes of $11,602 for thenine-month period ended September30, 2016 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $4,055for the nine-month period ended September30, 2016 are included in Income tax expense.

3Reclassifications before taxes of $2,222for the nine-month period ended September30, 2016 are included in Interest expense.  Related income taxes of $777 for the nine-month period ended September30, 2016 are included in Income tax expense.

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2016

Business Segments [Abstract]

Segment Information

			Three Months Ended		Three Months Ended
	Total Assets		September 30, 2016		September 30, 2015
	at September 30,		External	Income	External	Income
(Millions of dollars)	2016		Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,448.9	201.8	(27.1)	335.1	(107.8)
Canada		1,557.3	80.9	(4.8)	123.2	(507.0)
Malaysia		2,186.1	202.7	65.0	207.3	(952.7)
Other		120.2	0.2	(8.1)	–	(28.6)
Total exploration and production		9,312.5	485.6	25.0	665.6	(1,596.1)
Corporate		1,051.5	14.9	(39.6)	49.3	9.0
Assets/revenue/income (loss) from continuing operations		10,364.0	500.5	(14.6)	714.9	(1,587.1)
Discontinued operations, net of tax		30.0	–	(1.6)	–	(8.3)
Total	$	10,394.0	500.5	(16.2)	714.9	(1,595.4)
			Nine Months Ended		Nine Months Ended
			September 30, 2016		September 30, 2015
			External	Income	External	Income
(Millions of dollars)			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$		520.2	(158.5)	955.0	(218.1)
Canada			264.4	(36.9)	428.4	(577.8)
Malaysia			541.4	135.1	897.6	(701.9)
Other			0.2	(39.2)	–	(130.7)
Total exploration and production			1,326.2	(99.5)	2,281.0	(1,628.5)
Corporate			42.1	(111.7)	94.0	(44.0)
Revenue/income (loss) from continuing operations			1,368.3	(211.2)	2,375.0	(1,672.5)
Discontinued operations, net of tax			–	(0.8)	–	(11.2)
Total	$		1,368.3	(212.0)	2,375.0	(1,683.7)

*Additional details about results of oil and gas operations are presented in the tables on pages  27 and 28.

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Nature of Business and Interim Financial Statements (Details)	3 Months Ended
	Jun. 30, 2016
Kaybob Duvernay Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired	70.00%
Montney Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired	30.00%

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Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended			9 Months Ended		12 Months Ended	24 Months Ended
	Sep. 30, 2016	Apr. 30, 2016	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year	$ 117,600		$ 117,600			$ 117,600
Proceeds from sales of property, plant and equipment						1,154,623	$ 423,842
Impairment of assets					$ 2,300,974	95,088	2,300,974
Syncrude Canada Ltd. [Member]
Property Plant And Equipment [Line Items]
Gain (loss) on sale of assets, net of taxes			71,700
Percentage of interest in oil and gas property sold during period				5.00%
Montney Natural Gas Fields [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment		$ 414,100
Deferred gain on sale of property		$ 187,000
Amortization of deferred gain						$ 3,400
Deferred gain, period of recognition						20 years
Brunei [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year	64,500		64,500			$ 64,500
Vietnam [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year	31,400		31,400			31,400
Malaysia [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year	21,700		$ 21,700			21,700
Proceeds from sales of property, plant and equipment								$ 417,200
Gain (loss) on sale of assets, net of taxes								$ 218,800
Impairment of assets							$ 1,472,600
Percentage of interest in oil and gas property sold during period								10.00%	30.00%
Kaybob Duvernay Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired				70.00%
Montney Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired				30.00%
Canada [Member]
Property Plant And Equipment [Line Items]
Impairment of assets						$ 95,088
Parent Company [Member] | Syncrude Canada Ltd. [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment	$ 739,100
Parent Company [Member] | Montney Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, cash paid				$ 206,700
Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, carried interest				$ 168,000
Cost of acquired assets, interest carry period						5 years
Athabasca Oil Corporation [Member] | Kaybob Duvernay Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired				70.00%
Athabasca Oil Corporation [Member] | Montney Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired				30.00%
Athabasca Oil Corporation [Member] | Subsidiary [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets				$ 375,000

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Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 130,514	$ 120,455
Additions pending the determination of proved reserves	847	89,197
Other adjustments	(3,205)
Balance at September 30	$ 128,156	$ 209,652

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Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($) item	Sep. 30, 2015 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 128,156	$ 209,652	$ 130,514	$ 120,455
No. of Wells	11	13
No. of Projects	5	6
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 10,563	$ 52,249
No. of Wells	2	5
No. of Projects	2	3
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 53,101	$ 32,192
No. of Wells	3	2
No. of Projects	3	1
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 31,627	$ 27,842
No. of Wells	2	2
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 32,865	$ 97,369
No. of Wells	4	4
No. of Projects		2

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Discontinued Operations (Results of Operations Associated with Discontinued Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Discontinued Operations [Abstract]
Revenues (costs)	$ (1,345)	$ (1,342)	$ (510)	$ 381,154
Loss before income taxes	(1,593)	(8,366)	(885)	(8,029)
Income tax (benefit) expense		(22)		3,134
Loss from discontinued operations	$ (1,593)	$ (8,344)	$ (885)	$ (11,163)

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Discontinued Operations (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 400,532	$ 522,672
Total current assets held for sale	29,978	38,340
Total current liabilities associated with assets held for sale	3,276	7,297
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	5,097	7,927
Accounts receivable	9,001	12,037
Other	15,880	18,376
Total current assets held for sale	29,978	38,340
Accounts payable	915	2,433
Accrued compensation and severance		2,179
Refinery decommissioning cost	2,361	2,685
Total current liabilities associated with assets held for sale	$ 3,276	$ 7,297

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Financing Arrangements and Debt (Details) - USD ($)	1 Months Ended		9 Months Ended	30 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2016	Aug. 31, 2019
Line of Credit Facility [Line Items]
Issue cost of debt facility			$ 13,971,000
Capital lease duration			25 years
Capital lease payment duration			15 years
Capital lease expiration date			Sep. 01, 2028
Capital lease obligations, current	$ 20,400,000		$ 20,400,000
Capital lease obligations, noncurrent	202,700,000		$ 202,700,000
6.875% Notes Due August 15, 2024 [Member]
Line of Credit Facility [Line Items]
Face amount of notes		$ 550,000,000
Notes payable, stated interest rate		6.875%
Maturity date			Aug. 15, 2024
2011 Unscured Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	630,000,000	$ 2,000,000,000	$ 630,000,000
Credit facility, maturity date			Jun. 01, 2017
Amount outstanding	0		$ 0
Maximum total debt to total capital employed			60.00%
2016 Senior Unsecured Guaranteed Credity Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 1,200,000,000		$ 1,200,000,000
Credit facility, maturity date			Aug. 01, 2019
Line of credit facility fee	0.50%
Issue cost of debt facility		$ 14,000,000
Amount outstanding	$ 0		$ 0
Minumum borrowing capacity through automatic reductions	$ 1,000,000,000		1,000,000,000
Maximum leverage ratio				325.00%
Minimum adjusted EBITDAX to consolidated interest expense	250.00%
Maximum consolidated debt to maximum adjusted EBITDAX	375.00%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | United States And Canada [Member]
Line of Credit Facility [Line Items]
Minimum liquidity	$ 500,000,000		500,000,000
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate above LIBOR	2.50%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate above LIBOR	4.50%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding	$ 88,000,000		$ 88,000,000

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Cash Flow Disclosures (Cash Flow Activities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016		Sep. 30, 2015
Cash Flow Disclosures [Abstract]
Decrease in accounts receivable	$ 75,841		$ 389,413
Increase in inventories	(15,768)		(16,607)
Decrease (increase) in prepaid expenses	122,399		(87,051)
Decrease in deferred income tax assets	720		4,863
Decrease accounts payable and accrued liabilities	(376,310)		(134,458)
Increase (decrease) in current income tax liabilities	40,500		(59,134)
Net (increase) decrease in noncash operating working capital	(152,618)	[1]	97,026
Cash income taxes paid (refunded), net	(3,911)		111,897
Interest paid, net of amounts capitalized	52,287		60,766
Asset retirement costs capitalized	13,959		55,258
Decrease in capital expenditure accrual	$ 179,203		$ 374,720

[1] 2016 balance includes payments for deepwater rig contract exit of $266.6 million.

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Employee and Retiree Benefit Plans (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Employee and Retiree Benefit Plans [Abstract]
Contributions to benefit plans	$ 10.0
Expected benefit plan contributions to be made during the year	$ 2.9

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Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2,610	$ 5,898	$ 8,533	$ 15,751
Interest cost	5,913	8,972	20,386	24,893
Expected return on plan assets	(6,626)	(10,471)	(21,709)	(27,882)
Amortization of prior service cost	323	187	963	580
Amortization of transitional asset		402		947
Recognized actuarial loss	3,617	3,885	10,864	11,667
Gross periodic benefit expense			19,037	25,956
Special termination benefits				8,606
Curtailments			822	306
Net periodic benefit expense	5,837	8,873	19,859	34,868
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	674	826	2,022	2,482
Interest cost	1,109	1,192	3,324	3,576
Amortization of prior service cost	(21)	(21)	(62)	(62)
Amortization of transitional asset	2	2	4	5
Recognized actuarial loss	38	193	113	578
Gross periodic benefit expense			5,401	6,579
Special termination benefits			(19)
Net periodic benefit expense	$ 1,802	$ 2,192	$ 5,382	$ 6,579

XML

Incentive Plans (Narrative) (Details) - $ / shares	1 Months Ended	9 Months Ended
	Feb. 29, 2016	Sep. 30, 2016
2012 Long-Term Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Long term plan expiration year		2022
Maximum number of shares available for issuance		8,700,000
Maximum number of shares available for issuance, annual rate		1.00%
Employee Stock Purchase Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Maximum number of shares available for issuance		980,000
Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options granted	862,000
Exercise price of options granted	$ 17.57
Granted stock options, valuation per option	$ 5.03
Stock-based compensation, fair value assumption model		Black-Scholes valuation model
Performance Based Restricted Share Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock units	394,000
Stock-based compensation, fair value assumption model		Monte Carlo valuation model
Performance Based Restricted Share Awards [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock, fair value	$ 12.21
Performance Based Restricted Share Awards [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock, fair value	$ 16.34
Time Based Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock units	417,500
Time Based Restricted Stock Units [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock, fair value	$ 17.57
Time Based Restricted Stock Units [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock, fair value	$ 24.075
Time Based Restricted Stock Units [Member] | Non-Employee Director Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock units	85,679
Vesting scheme		These shares vest on the third anniversary of the date of grant.
Time Based Restricted Stock Units [Member] | Non-Employee Director Plan [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock, fair value	$ 19.26
SAR [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock units	708,200
Cash-Settled RSU (RSU-C) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted restricted stock units	507,470

XML

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Incentive Plans [Abstract]
Compensation charged against income before tax benefit	$ 35,948	$ 30,722
Related income tax benefit recognized	$ 11,796	$ 9,046

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Earnings per Share (Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share) (Details) - shares		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings per Share [Abstract]
Basic method		172,199,350	172,205,433	172,164,683	175,047,295
Dilutive stock options	[1]
Diluted method		172,199,350	172,205,433	172,164,683	175,047,295

[1] Due to a net loss recognized by the Company for the three-month and nine-month periods ended September 30, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

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Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares	5,884,201	5,807,453	5,822,036	5,770,731
Weighted average price of these options	$ 49.00	$ 53.13	$ 49.82	$ 53.25

XML

Income Taxes (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016
Income Tax Examination [Line Items]
U.S. statutory rate	35.00%
United States [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2011
Canada [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2008
Malaysia [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2009
United Kingdom [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2014

XML

Income Taxes (Effective Income Tax Rates) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Taxes [Abstract]
Effective income tax rate	13.00%	34.10%	48.90%	36.60%

XML

Financial Instruments and Risk Management (Narrative) (Details) CAD in Billions	3 Months Ended			9 Months Ended
	Dec. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) item	Sep. 30, 2015 USD ($)	Jun. 30, 2016 CAD	Dec. 31, 2015 USD ($) item	May 31, 2012 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Deferred loss charged to income				$ 1,500,000	$ 1,500,000
Number of offsetting positions | item				0			0
Impairment Expense			$ 2,300,974,000	$ 95,088,000	2,300,974,000
10-Year Notes [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Note term				10 years
Face amount of notes								$ 350,000,000
Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Deferred loss charged to income	$ 700,000
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Increase (decrease) of income before taxes due to the impact of marking to market of derivative contracts				$ (3,900,000)	7,400,000
Interest Rate Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss deferred for fair value of interest rate derivative contracts, net of tax				10,800,000
Income tax on deferred loss on fair value of interest rate derivative contracts				5,800,000
Foreign Exchange Derivative Contracts [Member] | Currency, U.S. Dollar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Short-term derivative instruments			$ 6,200,000	25,200,000	$ 6,200,000
Forward Sale Contracts [Member] | Currency, Canadian Dollar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain charged to income		$ 26,800,000
Short-term derivative instruments | CAD						CAD 1.0
Accounts Receivable [Member] | Nondesignated [Member] | Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of commodity derivative contracts				192,000			$ 89,358,000
Accounts Receivable [Member] | Nondesignated [Member] | Foreign Exchange Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of commodity derivative contracts				$ 142,000
Syncrude Canada Ltd. [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of interest in oil and gas property sold during period		5.00%

XML

Financial Instruments and Risk Management (WTI Open Contracts) (Details)	Sep. 30, 2016 bbl / d $ / bbl	Sep. 30, 2015 bbl / d $ / bbl
October - December 2016 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Volumes (barrels per day) | bbl / d	25,000
Swap Prices | $ / bbl	50.67
January - December 2017 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Volumes (barrels per day) | bbl / d	16,000
Swap Prices | $ / bbl	50.34
October - December 2015 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Volumes (barrels per day) | bbl / d		15,000
Swap Prices | $ / bbl		63.30

XML

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Commodity Derivative Contracts [Member] | Accounts Receivable [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 192	$ 89,358
Foreign Exchange Derivative Contracts [Member] | Accounts Receivable [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 142
Foreign Exchange Derivative Contracts [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		$ (29)

XML

Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 12,014	$ 39,425	$ 4,251	$ 46,858
Commodity Derivative Contracts [Member] | Sales And Other Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	11,871	39,392	(22,678)	46,811
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 143	$ 33	$ 26,929	$ 47

XML

Financial Instruments and Risk Management (Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	$ 334	$ 89,358
Liability Derivatives	13,637	13,000
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	13,637	12,971
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	334	89,358
Liability Derivatives		29
Non-Qualified Employee Savings Plans [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	13,637	12,971
Non-Qualified Employee Savings Plans [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	13,637	12,971
Foreign Exchange Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	142
Liability Derivatives		29
Foreign Exchange Derivative Contracts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	142
Liability Derivatives		29
Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	192	89,358
Commodity Derivative Contracts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives	$ 192	$ 89,358

XML

Financial Instruments and Risk Management (Nonrecurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	$ 3,750,002		$ 3,750,002
Total Pretax (Noncash) Impairment Expense	2,300,974	$ 95,088	2,300,974
Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties	1,449,028		1,449,028
Gulf Of Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	361,402		361,402
Total Pretax (Noncash) Impairment Expense			144,800
Gulf Of Mexico [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties	216,602		216,602
Canada [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment		167,055
Total Pretax (Noncash) Impairment Expense		95,088
Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties		$ 71,967
Western Canada [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	707,100		707,100
Total Pretax (Noncash) Impairment Expense			683,574
Western Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties	23,526		23,526
Malaysia [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	2,681,500		2,681,500
Total Pretax (Noncash) Impairment Expense			1,472,600
Malaysia [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties	$ 1,208,900		$ 1,208,900

XML

Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016		Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]			$ (704,542)
Before reclassifications to income	[1]			124,519
Reclassifications to income	[1]			8,992
Net other comprehensive income		$ (34,372)	$ (191,842)	133,511	[1]	$ (451,504)
Ending Balance	[1]	(571,031)		(571,031)
Reclassifications before taxes, included in net periodic benefit expense				11,602
Reclassifications income tax, included in net periodic benefit expense				4,055
Reclassifications before taxes, included in interest expense				2,222
Reclassifications income tax, included in interest expense				777
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]			(513,004)
Before reclassifications to income	[1]			124,522
Net other comprehensive income	[1]			124,522
Ending Balance	[1]	(388,482)		(388,482)
Retirement and Postretirement Benefit Plan Adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]			(179,260)
Before reclassifications to income	[1]			(3)
Reclassifications to income	[1],[2]			7,547
Net other comprehensive income	[1]			7,544
Ending Balance	[1]	(171,716)		(171,716)
Deferred Loss On Interest Rate Derivative Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	[1]			(12,278)
Reclassifications to income	[1],[3]			1,445
Net other comprehensive income	[1]			1,445
Ending Balance	[1]	$ (10,833)		$ (10,833)

[1] All amounts are presented net of income taxes.

[2] Reclassifications before taxes of $11,602 for the nine-month period ended September 30, 2016 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $4,055 for the nine-month period ended September 30, 2016 are included in Income tax expense.

[3] Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2016 are included in Interest expense. Related income taxes of $777 for the nine-month period ended September 30, 2016 are included in Income tax expense.

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Environmental and Other Contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended	21 Months Ended
	Dec. 31, 2015	Sep. 30, 2016
Environmental and Other Contingencies [Abstract]
Remediation costs	$ 43.9
Payments for environmental liabilities		$ 32.8

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Commitments (Narrative) (Details) - Natural Gas [Member]	Oct. 31, 2016 MMcf / d CAD / Mcf	Sep. 30, 2016 MMcf / D MMcf / d CAD / Mcf
2016 Deliveries [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / D		99
Swap price (per share)		3.00
January 2017 Through December 2017 Deliveries [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / d		79
Swap price (per share)		2.83
January 2018 Through December 2020 Deliveries [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / D		59
Swap price (per share)		2.81
Subsequent Event [Member] | January 2017 Through December 2020 Deliveries, Contract 2 [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / d	20
Swap price (per share)	3.12

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Business Segments (Segment Information) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total Assets		$ 10,394,015		$ 10,394,015		$ 11,493,812
External Revenues		500,533	$ 714,949	1,368,290	$ 2,374,986
Net income (loss)		(16,176)	(1,595,426)	(212,048)	(1,683,701)
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		10,364,000		10,364,000
External Revenues		500,500	714,900	1,368,300	2,375,000
Net income (loss)		(14,600)	(1,587,100)	(211,200)	(1,672,500)
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		30,000		30,000
Net income (loss)		(1,600)	(8,300)	(800)	(11,200)
Corporate [Member]
Segment Reporting Information [Line Items]
Total Assets		1,051,500		1,051,500
External Revenues		14,900	49,300	42,100	94,000
Net income (loss)		(39,600)	9,000	(111,700)	(44,000)
Exploration and production [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	9,312,500		9,312,500
External Revenues	[1]	485,600	665,600	1,326,200	2,281,000
Net income (loss)	[1]	25,000	(1,596,100)	(99,500)	(1,628,500)
Exploration and production [Member] | Operating Segments [Member] | United States [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	5,448,900		5,448,900
External Revenues	[1]	201,800	335,100	520,200	955,000
Net income (loss)	[1]	(27,100)	(107,800)	(158,500)	(218,100)
Exploration and production [Member] | Operating Segments [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	1,557,300		1,557,300
External Revenues	[1]	80,900	123,200	264,400	428,400
Net income (loss)	[1]	(4,800)	(507,000)	(36,900)	(577,800)
Exploration and production [Member] | Operating Segments [Member] | Malaysia [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	2,186,100		2,186,100
External Revenues	[1]	202,700	207,300	541,400	897,600
Net income (loss)	[1]	65,000	(952,700)	135,100	(701,900)
Exploration and production [Member] | Operating Segments [Member] | Other Regions [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	120,200		120,200
External Revenues	[1]	200		200
Net income (loss)	[1]	$ (8,100)	$ (28,600)	$ (39,200)	$ (130,700)

[1] Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.