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.~~

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

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.

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 ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ 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 ~~2016~~2017 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month ~~and nine-month periods~~period ended ~~September 30, 2017~~March 31, 2018 are not necessarily indicative of future results.

Beginning in the period ended September 30, 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations. The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below ~~Operating~~“Operating income (loss) from continuing operations.” Previously reported periods have been ~~changed~~reclassified to conform to the current period presentation. These reclassifications did not impact previously reported Income ~~(loss)~~ from continuing operations before income taxes, ~~Loss~~Income from continuing operations, or Net ~~Loss.~~income.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance. Under the new standard, an entity is required to recognize revenue when it transfers 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. Additional disclosures are required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method. The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU. Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 and recorded revenue when deliveries occurred and legal ownership of the commodity transferred to the customer.

There was no adjustment to the opening balance of stockholders’ equity as at January 1, 2018, resulting from application of the new ASU promulgated in ASC Topic 606 using the modified retrospective method. The comparative information has not been adjusted and continues to be reported under ASC Topic 605 – Revenue Recognition. See also Note C for further discussion of Revenue Recognition.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)

Accounting Principles Adopted (Cont.)

Compensation – Retirement Benefits. In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual and interim periods beginning after December 15, 2017. The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

Compensation – Stock Compensation. In May 2017, the FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. The Company adopted this accounting standard in the first quarter of 2018 and it did not have material impact on its consolidated financial statements.

Statement of Operations – Reporting Comprehensive Income. In February 2018, the FASB issued an ASU,which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to deferred loss on interest rate derivative hedges. The adoption of this ASU will have no future impact.

Recent Accounting Pronouncements

Leases. In February 2016, the FASB issued an 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 right-of-use 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 the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU will have on its consolidated financial statements.

Note C – Revenue from Contracts with Customers

Significant Accounting Policy

Revenue is recognized when the Company satisfies a performance obligation by transferring control over a commodity to a customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties.

Revenue is presented as Company share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) worldwide. The Company’s revenue from sales of oil and gas production activities are subdivided into three key geographic segments: the U.S., Canada, and Malaysia. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production.

U.S.- In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- Primarily all long-term contracts in Canada, except for certain natural gas physical forward sales fixed-price contracts, are floating commodity index priced. For the Onshore business in Canada, the recorded revenue is adjusted for transportation and any gain or loss on spot purchases made to meet committed volumes on sales contracts for the month. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

Malaysia- In Malaysia, the Company has interests in nine separate PSCs. The Company serves as the operator of all these areas other than the unitized Kakap-Gumusut field. Crude oil contracts in Malaysia share similar features of largely fixed cargo quantities, variable index-based pricing, and potential discounts at the point of meeting the performance obligation when the vessel is loaded. Malaysia also has three long term Gas Sales Agreements (GSA) with terms until the end of the field life, economic life, or PSC term.

Disaggregation of Revenue

The Company reviews performance based on three key geographical segments and between onshore and offshore sources of Revenue within these geographies.

For the three months ended March 31, 2018 and 2017, the Company recognized $607.0 million and $509.0 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)


		Three Months Ended
		March 31,
(Thousands of dollars)		2018	2017
Net crude oil and condensate revenue
United States – Onshore	$	182,649	149,986
– Offshore		71,528	53,813
Canada – Onshore		21,293	9,121
– Offshore		54,315	37,014
Malaysia – Sarawak		77,306	65,783
– Block K		94,572	87,831
Total crude oil and condensate revenue		501,663	403,548

Net natural gas liquids revenue
United States – Onshore		12,134	9,647
– Offshore		1,639	1,916
Canada – Onshore		3,469	432
– Offshore		–	–
Malaysia – Sarawak		6,192	5,182
– Block K		–	–
Total natural gas liquids revenue		23,434	17,177

Net natural gas revenue
United States – Onshore		6,770	7,036
– Offshore		2,937	2,663
Canada – Onshore		39,594	39,847
– Offshore		–	–
Malaysia – Sarawak		32,383	38,589
– Block K		173	175
Total natural gas revenue		81,857	88,310
Total revenue from contracts with customers		606,954	509,035

Gain (loss) on crude contracts		(29,502)	37,077
Other operating income (loss)		8,492	(1,454)
Gain (loss) on sale of assets		(339)	131,982
Total revenue	$	585,605	676,640

Contract Balances and Asset Recognition

As of March 31, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $178.7 million and $203.4 million, respectively. Payment terms for Murphy’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any upstream oil and gas sale contracts that have financing components as at March 31, 2018.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)

Performance Obligations

The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of Murphy’s sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy. The contractually stated price for each unit of commodity transferred under these contracts represents the stand-alone selling price of the commodity.

As at March 31, 2018, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:


Current Long-Term Contracts Outstanding at March 31, 2018
Location	Commodity	End Date	Description	Approximate Net Volumes
U.S. Onshore	Oil	Q2 2019	Fixed quantity delivery in Eagle Ford	4,000 BOE/Day
U.S. Onshore	Oil	Q3 2019	Fixed quantity delivery in Eagle Ford	2,000 BOE/Day
U.S. Onshore	Oil	Q4 2021	Fixed quantity delivery in Eagle Ford	2018: 19,000 BOE/Day 2019-2021: 13,000 BOE/Day
U.S. Onshore	Gas and NGL	Q2 2026	Deliveries from dedicated acreage in Eagle Ford	As produced
Canada Onshore	Gas	Q4 2020	Contracts to sell natural gas at Alberta AECO Cdn dollar 2.81/MCF	59 MMCF/Day
Canada Onshore	Gas	Q4 2020	Contracts to sell natural gas at USD Index pricing	59 MMCF/Day

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Property, Plant and Equipment

Exploratory Wells

Under ~~Financial Accounting Standards Board (FASB)~~FASB guidance 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 ~~September 30, 2017,~~March 31, 2018, the Company had total capitalized exploratory well costs pending the determination of proved reserves of ~~$178.4~~$176.3 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~nine-month~~three-month periods ended ~~September 30, 2017~~March 31, 2018 and ~~2016.~~

2017.



(Thousands of dollars)	2017		2016	2018		2017
Beginning balance at January 1	$	148,500	130,514	$	175,640	148,500
Additions pending the determination of proved reserves		51,614	847		623	39,653
Reclassifications to proved properties based on the determination of proved reserves		(13,370)	–		–	(13,370)
Capitalized exploratory well costs charged to expense		(8,360)	–		–	(8,360)
Other adjustments		–	(3,205)
Balance at September 30	$	178,384	128,156
Balance at March 31				$	176,263	166,423

There were no capitalized well costs charged to expense during the first three months of 2018. The capitalized well costs charged to expense during the first ~~nine~~three months of 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia, in which development of the well could not be justified due to noncommercial hydrocarbon quantities ~~found and change in development plan due to commodity prices.~~

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.

Of the ~~$136.8~~$162.6 million of exploratory well costs capitalized more than one year at ~~September 30, 2017,~~March 31, 2018, $70.4 million is in Brunei, ~~$43.2~~$43.8 million is in Vietnam, $27.8 million is in the U.S. and ~~$23.2~~$20.6 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 January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was approximately ~~$49.0~~$48.8 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $132.4 million pretax gain was reported in the ~~first quarter of~~ 2017 period related to the sale. Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately ~~$19.4~~$19.6 million. There were no gains or losses recorded related to these non-core Eagle Ford Shale sales.

During the second quarter 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”). The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.

~~During the second quarter~~In 2016, a Canadian subsidiary of the Company completed a divestiture of 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 upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred and is being recognized over approximately the next 1918 years in the Canadian operating segment. The Company amortized approximately ~~$5.3~~$1.9 million and ~~$3.4~~$1.7 million of the deferred gain during the ~~nine-month periods ended September 30,~~first three months of 2018 and 2017, ~~and 2016,~~ respectively. The remaining deferred gain of ~~$185.0~~$175.2 million was included as a component of ~~deferred~~Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of ~~September 30, 2017.~~March 31, 2018.

~~During the second quarter~~In 2016, a Canadian subsidiary of Murphy Oil acquired a ~~70 percent~~70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a ~~30 percent~~30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of ~~September 30, 2017, $32.0~~March 31, 2018, $64.3 million of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.

Declines in future oil and gas prices in early 2016 led to impairments in certain of the Company’s producing properties and the nine-month period in 2016 included pretax non-cash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. See also Note J.

~~The Company has an interest in~~In 2006, the Kakap field in Block K ~~Malaysia.~~was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the operators. The ~~Kakap field~~Gumusut-Kakap Unit is operated by another ~~company and was jointly developed with the Gumusut field owned by others. As required by the agreements governing the field, a redetermination (unitization) review was required in 2016.~~company. In the fourth quarter 2016, the operators completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of$39.1 million ~~in redetermination expense~~($24.1 million after tax) related to an expected ~~reduction~~revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, ~~PETRONAS officially approved~~the Company received Petronas’ official approval to the redetermination change that reduced the Company’s working interest ~~from 8.6%~~in oil operations to ~~approximately 6.7%~~6.67% effective at April 1, 2017. ~~The Company partially settled $21.8 million~~Working interest redeterminations are required at different points within the life of the unitized field. Following a partial payment, the remaining redetermination ~~expense in cash~~liability of $17.3 million was included as a component of Other current liabilities in the ~~second quarter~~Company’s Consolidated Balance Sheet as of ~~2017. The~~March 31, 2018.

Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company ~~currently expects to settle the remainder of the redetermination costs in future periods. It is possible that the final adjustment amount could be different than the current estimate. Due to the change in working~~now has a 6.37% interest ~~the future payments under a capital lease of a floating, production and storage facility~~ in the Kakap field ~~are lower~~in Block K Malaysia as of March 31, 2018. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company ~~reduced~~recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest. The remaining redetermination liability of $15.0 million was included as a component of Other current liabilities in the ~~total debt recorded on the~~Company’s Consolidated Balance Sheet ~~in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.~~as of March 31, 2018.

The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:

~~Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).~~

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations ~~and Seal operations in Canada~~ reflected as held for sale on the ~~company’s~~Company’s Consolidated Balance Sheets at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016.~~2017.

The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the sale in January 2017.

At ~~September 30, 2017,~~March 31, 2018, the Company ~~has~~had a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August ~~2019.~~2021. At ~~September 30, 2017,~~March 31, 2018, the Company had no outstanding borrowings under the 2016 facility, however, there were ~~$84.8~~$91.4 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility. Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin. Had there been any amounts borrowed under the 2016 facility at ~~September 30, 2017,~~March 31, 2018, the applicable base interest rate would have been ~~4.50%~~5.1875%. At ~~September 30, 2017,~~March 31, 2018, the Company was in compliance with all covenants related to the 2016 facility.

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 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025. The Company incurred transaction costs of $8.2 million on the issue of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment will be paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 2.50% notes in September 2017. The 2.50% notes had an original maturity of December 2017.

In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion), with a major banking consortium that expires in August 2019. The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows. Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024. 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 March 2029. Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included ~~$9.8~~$9.6 million and ~~$136.5~~$125.3 million, respectively, associated with this lease at ~~September 30, 2017.~~March 31, 2018.

*2016 balance included payments for deepwater rig contract exit of $266.6 million.

The Company has defined benefit pension plans that are principally noncontributory and cover most North American full-time employees. All pension plans are funded except for the U.S. nonqualified supplemental 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. 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, 2017~~March 31, 2018 and ~~2016.~~2017.

~~Curtailment~~The components of net periodic benefit expense ~~for~~other than the ~~nine months ended September 30, 2016, shown~~service cost component are included in the ~~table above, relates to restructuring activities~~line item “Interest and other income (loss)” in ~~the U.S. undertaken by the Company in the first quarter~~Consolidated Statements of ~~2016.~~

During the ~~nine-month~~three-month period ended ~~September 30, 2017,~~March 31, 2018, the Company made contributions of ~~$24.0~~$6.4 million to its defined benefit pension and postretirement benefit plans. Remaining ~~required~~ funding in ~~2017~~2018 for the Company’s defined benefit pension and postretirement plans is anticipated to be ~~$6.8~~$23.3 million.

The costs resulting from all share-based and cash-based incentive plans 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~~2017 Annual Incentive Plan ~~(2012~~(2017 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 certain other employees. Cash awards under the ~~2012~~2017 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 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; allowed shares not granted in an earlier year may be granted in future years. The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during ~~2016 and~~ the first six months of 2017. The ESPP terminated on June 30, 2017 and was not renewed by the Company.

In ~~February 2017,~~the first quarter of 2018, the Committee granted ~~stock options for 599,000 shares at an exercise price of $28.505 per share. The Black-Scholes valuation for these awards was $7.96 per option. The Committee also granted 556,000~~905,500 performance-based

~~RSU~~ RSUs and ~~282,000~~736,000 time-based ~~RSU in February 2017.~~RSUs to certain employees. The fair value of the performance-based ~~RSU,~~RSUs, using a Monte Carlo valuation model, ranged from ~~$24.10~~$28.27 to ~~$28.28~~$30.56 per unit. The fair value of the time-based ~~RSU~~RSUs was estimated based on the fair market value of the Company’s stock on the date of ~~grant, which~~grant. The fair value of the time-based RSUs granted February 6, 2018 was ~~$28.505~~$28.42 per ~~share.~~unit, the fair value of the time-based RSUs granted February 20, 2018 was $26.56 per unit, and the fair value of the time-based RSUs granted March 1, 2018 was $25.69 per unit. Additionally, on February 6, 2018 the Committee granted ~~329,400 SAR and 154,150 units of~~715,100 cash-settled ~~RSU~~RSUs (RSUC) to certain employees, and on March 9, 2018 granted 29,000 RSUCs to certain employees. The ~~SAR and~~ RSUC 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~~the RSUCs was equivalent to the ~~stock options granted, while the initial value of RSUC was equivalent to~~ equity-settled restricted stock units granted. Also in February, the Committee granted ~~83,220~~77,803 shares of time-based ~~RSU~~RSUs to the Company’s Directors under the Non-Employee Director Plan. These ~~shares~~units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was ~~$28.84~~$28.28 per unit on date of grant.

~~For all periods presented,~~All stock option exercises are non-cash transactions for the ~~Company had no~~Company. The employee receives net shares, after applicable withholding taxes, upon each stock ~~options exercised.~~

option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the three-month period ended March 31, 2018.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1 million per executive per year, is not eligible for a US income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

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

three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2018 and ~~2016.~~2017. The following table reconciles the weighted-average shares outstanding used for these computations.

*~~Due~~The following table reflects certain options to ~~net losses recognized by~~purchase shares of common stock that were outstanding during the ~~Company for all~~ periods presented ~~no unvested stock awards~~but were not included in the computation of diluted ~~earnings per share~~shares above because the ~~effect would have been anti-dilutive.~~

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income ~~(loss)~~from continuing operations before income ~~tax expense.~~taxes. For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ the Company’s effective income tax rates were as follows:

The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate of(21% in 2018, 35% in 2017) 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%~~21% due to similar reasons.

Due to uncertainty related to language in Section 965(n) of the 2017 Tax Act, and specifically whether current operating losses from 2017 were required to be applied to offset a company’s deemed taxable repatriation of foreign earnings under the 2017 Tax Act, the Company’s provisional tax expense recorded in the Company’s December 31, 2017 financial statements reflected use of all the estimated 2017 tax operating loss against the deemed repatriation. This resulted in no loss carryover from 2017 into 2018 and foreign tax credits considered to be of no value given the Company’s offsetting $228.2 million valuation allowance. On April 2, 2018, the Internal Revenue Service issued new guidance related to the Section 965(n) election. This guidance resolved the ambiguity and allowed the Company to preserve the 2017 tax net operating loss as a carryforward by allowing the crediting of the previously unused foreign tax credits against all but $36 million of current income tax on the deemed inclusion of foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense for the quarter by $156 million and resulted in a $36 million charge to taxes payable relating to the deemed inclusion. The Company anticipates paying this $36 million tax payable over eight years as permitted by the 2017 Tax Act.

The effective tax rate for the three-month period ended ~~September 30, 2017~~March 31, 2018 was below the U.S. statutory tax rate of ~~35%~~21% primarily due to the discrete tax effect of the new guidance relating to Section 965(n) and non-taxable foreign exchange gains from Malaysia. These impacts were partially offset by higher tax rates in certain foreign tax jurisdictions and expenses in foreign jurisdictions not fully deductible from ~~losses~~income at the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.

The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate of 35% primarily due to an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items. During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise.

rate. 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, 2016March 31, 2017 was above the U.S. statutory tax rate primarily due to ~~deferred~~a tax ~~benefits recognized~~expense recorded in the period related to ~~the Canadian asset dispositions and~~undistributed foreign earnings partially offset by income tax ~~benefits~~benefit on ~~investments~~investment in foreign areas.

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 of ~~September 30, 2017,~~March 31, 2018, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2014; Canada – 2012; Malaysia – ~~2010;~~2011; and United Kingdom – ~~2015.~~2016.

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 reports gains and losses on derivative instruments in the Corporate segment. 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 gain or loss associated with recording the fair value of these contracts was deferred in Accumulated ~~Other Comprehensive Loss~~other comprehensive loss until the anticipated transactions occur. This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

The Company is subject to commodity price risk related to crude oil it produces and sells. During the first ~~nine months~~quarter of 2018 and 2017, ~~and 2016,~~ the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production. Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At ~~September 30,~~March 31, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2018 at an average price of $54.88.

At March 31, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2017 at an average price of $50.41 and 6,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $51.83. At September 30, 2017, the fair value of WTI contracts of $3.2 million was included in Accounts Payable. The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $3.2 million for the nine-month period ended September 30, 2017.

At September 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. At September 30, 2016, the fair value of WTI contracts of $0.2 million was included in Accounts Receivable. The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016.

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at ~~September 30, 2017.~~

At ~~September 30, 2016,~~March 31, 2017, short-term derivative instruments were outstanding in Canada for approximately ~~$25.2~~$18.5 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil. The fair values of open foreign currency derivative contracts were assets of ~~$0.1~~$0.2 million at ~~September 30, 2016.~~

At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

For the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ 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.

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016, $2.2~~$0.7 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at ~~September 30, 2017~~March 31, 2018 was ~~$8.9~~$9.7 million, which is recorded, net of income taxes of ~~$4.8~~$2.6 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately ~~$0.7~~$2.2 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining ~~three~~nine months of ~~2017.~~

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 ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 are presented in the following table.

The fair value of WTI crude oil derivative contracts in ~~2017~~2018 and ~~2016~~2017 was based on active market quotes for WTI crude oil. 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~~Gain (loss) on crude contracts 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 ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016.~~2017.

As a result of the fall in forward commodity prices during the first nine-month period ended September 30, 2016, the Company recognized approximately $95.1 million in pretax non-cash impairment charges related to producing properties. The fair value information associated with these impaired properties is presented in the following table.

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

The components of Accumulated ~~Other Comprehensive Loss~~other comprehensive loss on the Consolidated Balance Sheets at December 31, ~~2016~~2017 and ~~September 30, 2017~~March 31, 2018 and the changes during the ~~nine-month~~three-month period ended ~~September 30, 2017~~March 31, 2018 are presented net of taxes in the following table.

1Reclassifications before taxes of ~~$11,039 for the nine-month period ended September 30, 2017~~$4,041 are included in the computation of net periodic benefit ~~expense.~~expense for the three-month period ended March 31, 2018. See Note GH for additional information. Related income taxes of ~~$3,873 for the nine-month period ended September 30, 2017~~$871 are included in Income tax ~~expense.~~expense (benefit) for the three-month period ended March 31, 2018.

2Reclassifications before taxes of ~~$2,222 for the nine-month period ended September 30, 2017~~$741 are included in Interest expense, ~~net.~~net, for the three-month period ended March 31, 2018. Related income taxes of ~~$777 for the nine-month period ended September 30, 2017~~$156 are included in Income tax expense. (benefit) for the three-month period ended March 31, 2018. See Note L for additional information.

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,~~legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences ~~and~~or 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 prior owners 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 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 has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. 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~~In early 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 were notified. Based on the assessments done, the Company recorded $43.9 million in Other expense during 2015 and a further $3.8 million in the first quarter of 2018 associated with the estimated costs of remediating the site. ~~As of September 30, 2017, the~~The Company has ~~a remaining accrued liability of $5.8~~spent $39.7 million associated with this event. During the first nine months of 2017, the Company’s Canadian subsidiary paid approximately $130 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter.from inception to March 31, 2018. Further refinements in the estimated total cost to remediate the site are anticipated in future ~~periods including possible insurance recoveries.~~periods. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of liability recorded. The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.

As of March 31, 2018, the Company has a remaining accrued liability of $7.1 million associated with this event. In the first quarter of 2018, the Company received $15.0 million in respect to an insurance claim regarding this matter and the outcome of further insurance claims by the Company is pending.

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 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.

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its ~~2017~~2018 to 2020 natural gas sales volumes in Western Canada. During the period from ~~October to December 2017 the natural gas sales contracts call for deliveries of 124 million cubic feet per day at Cdn $2.97 per MCF. During the period from January~~April 2018 through December 2020 the natural gas sales contracts call for deliveries of 59 million cubic feet per day at Cdn $2.81 per MCF. ~~During the period from November 2017 through March 2018 the natural gas sales contracts call for deliveries of 20 million cubic feet per day at US $3.51 per MCF.~~

These natural gas contracts have been accounted for as normal sales for accounting purposes.

Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, ~~miscellaneous~~other gains and losses (including foreign exchange gains and ~~losses)~~losses and realized and unrealized gains and losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made to ~~2016~~2017 Exploration and production and Corporate External ~~Revenue~~Revenues and Income (Loss) to align with current period ~~presentation (see Note A).~~presentation.

1Additional details about results of oil and gas operations are presented in the tables on page 28.

22017 revenue includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada.

3 In 2018, the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously reported in the Exploration and production business) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to reflect comparable disclosure.

Overall Review

For the three months ended March 31, 2018, the Company produced 168 thousand barrels of oil equivalent per day. The Company invested $300 million in capital expenditures in the first quarter of 2018 primarily in the United States and Canada. The Company reported net income of $168.3 million for the three months ended March 31, 2018, which included an income tax gain of $120.0 million as a result of a 2018 Internal Revenue Service (IRS) interpretation of the Tax Cuts and Jobs Act (2017 Tax Act) enacted in the fourth quarter of 2017.

During the first quarter of 2018, worldwide benchmark oil and natural gas prices were above average comparable benchmark prices during 2017, natural gas sales volumes were higher principally as a result of growth in Canada and the financials results benefited from foreign exchange gains, insurance proceeds and a one-time U.S. tax gain. The gains from price, volume and foreign exchange were partially offset by unrealized losses from crude contracts and higher lease operating expense in the Gulf of Mexico. The results are explained in more detail below.

Results of Operations

Murphy’s income (loss) by type of business is presented below.



	Income (Loss)
	Three Months Ended
	March 31,
(Millions of dollars)	2018		2017
Exploration and production	$	115.6	151.0
Corporate and other		53.1	(93.5)
Income from continuing operations		168.7	57.5
Discontinued operations		(0.4)	1.0
Net income	$	168.3	58.5

For the first quarter of 2018, Murphy’s net income was $168.3 million ($0.96 per diluted share) compared to net income of $58.5 million ($0.34 per diluted share) in the first quarter of 2017. Income from continuing operations increased from $57.5 million ($0.33 per diluted share) in the 2017 quarter to $168.7 million ($0.97 per diluted share) in the 2018 period.

The Company’s exploration and production (E&P) continuing operations earned $115.6 million in the 2018 quarter compared to earnings of $151.0 million in the 2017 quarter. The E&P results for the 2018 quarter were favorably impacted by higher revenues due to higher realized oil sales prices and higher volumes sold, lower depreciation expense, partially offset by higher lease operating expense. The 2017 results included a pre-tax gain of $132.4 million ($96.0 million after-tax) related to the sale of Seal heavy oil assets. In 2018 the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously reported in the E&P segment) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to the Corporate segment to reflect comparable disclosure.

The Corporate segment had after-tax income of $53.1 million in the first quarter of 2018 compared to an after-tax loss of $93.5 million in the 2017 period with the favorable variance in the current period primarily due to a benefit to income tax expense of $120.0 million related to an IRS interpretation of the 2017 Tax Act versus a deferred tax charge of $54.6 million in 2017 associated with the estimated tax consequence of future repatriation of Malaysian and Canadian earnings. See further details of the Corporate segment results on page 29.

The first quarter of 2018 included losses from discontinued operations of $0.4 million ($0.01 per diluted share) compared to income from discontinued operations of $1.0 million ($0.01 per diluted share) in the first quarter of 2017.

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

Results of Operations (Contd.)

Exploration and Production

Results of E&P continuing operations are presented by geographic segment below.



		Income (Loss)
	Three Months Ended
	March 31,
(Millions of dollars)	2018		2017
Exploration and production
United States	$	36.2	(1.1)
Canada		24.4	100.6
Malaysia		70.4	58.6
Other International		(15.4)	(7.1)
Total	$	115.6	151.0

First quarter 2018 vs. 2017

United States E&P operations reported earnings of $36.2 million in the first quarter of 2018 compared to a loss of $1.1 million in the first quarter of 2017. Results were $37.3 million favorable in the 2018 quarter compared to the 2017 period due to higher revenues ($53.9 million) and lower depreciation ($16.7 million), partially offset by higher lease operating expenses ($10.5 million) and higher exploration expenses ($8.9 million). Higher revenues were primarily due to higher realized prices, while lower depreciation expense was due primarily to lower volumes sold and lower rates at Eagle Ford Shale and in the U.S. Gulf of Mexico. Higher lease operating expenses were principally a result of workover costs on the Kodiak well in the U.S. Gulf of Mexico business. Higher exploration expenditures are principally a result of data acquisition costs in the U.S Gulf of Mexico business.

Canadian E&P operations reported earnings of $24.4 million in the first quarter 2018 compared to earnings of $100.6 million in the 2017 quarter. Results were unfavorable $76.2 million due to 2017 including a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada in January 2017. Adjusting for the impact of gain on sale of assets, Canadian results of operations improved $19.8 million in the 2018 quarter compared to the 2017 period due to higher revenue ($32.7 million), insurance proceeds ($11.3 million), partially offset by higher lease operating expense ($7.8 million), higher depreciation ($11.0 million) and higher taxes ($6.4 million). Higher revenues were a result of both higher volumes at the Tupper, Kaybob and Placid assets and higher realized crude prices. Insurance proceeds related to cash received in relation to the spill at the now divested Seal asset. Higher taxes (excluding the Seal gain in 2017) are the result of higher net earnings. Higher lease operating expenses and depreciation are a result of higher volumes sold.

Malaysia E&P operations reported earnings of $70.4 million in the first quarter of 2018 and compared to earnings of $58.6 million in the comparable 2017 period. Results were favorable by $11.8 million due to higher revenues ($13.5 million), lower lease operating expenses ($3.9 million), lower exploration expenses ($3.0 million) and lower other operating expenses ($6.2 million), partially offset by higher taxes ($15.4 million). Higher revenues are principally due to higher realized prices. Lower lease operating expenses are due to lower volumes sold. Lower exploration expenses are due to the Marakas-01 well in Block SK314A dry hole expense in 2017. Lower other expenses are due to the cost of a rig exit recorded in 2017.

Other international E&P operations reported a loss from continuing operations of $15.4 million in the first quarter of 2018 compared to a loss of $7.1 million in the 2017 quarter. The loss was $8.3 million higher in the 2018 period versus 2017 primarily related to higher exploration expenses ($4.7 million) in Brazil, Mexico and Vietnam and higher taxes ($12.3 million). Higher taxes are due to no repeat of income tax benefits on investments in foreign areas recognized in 2017.

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

Results of Operations (Contd.)

*Exploration and Production (Contd.)

First quarter 2018 vs. 2017 (Contd.)

Total hydrocarbon production averaged 167,506 barrels of oil equivalent per day in the 2018 first quarter, which represented a 1% decrease from the 169,225 barrels per day produced in the 2017 quarter.

Average crude oil and condensate production was 88,533 barrels per day in the first quarter of 2018 compared to 95,605 barrels per day in the first quarter of 2017. The decrease of 7,072 barrels per day was principally due to lower volumes at Malaysia (5,997 barrels per day) due to field decline, and lower volumes at Eagle Ford Shale (2,282 barrels per day) due to less new wells brought online. On a worldwide basis, the Company's crude oil and condensate prices averaged $63.58 per barrel in the first quarter 2018 compared to $49.88 per barrel in the 2017 period, an increase of 27% quarter to quarter.

Total production of natural gas liquids (NGL) was 8,892 barrels per day in the 2018 first quarter compared to 8,916 barrels per day in the same 2017 period. The average sales price for U.S. NGL was $20.26 per barrel in the 2018 quarter compared to $16.14 per barrel in 2017. The average sales price for NGL in Canada was $43.58 per barrel in the 2018 quarter compared to $18.45 per barrel in 2017. Average NGL prices in Malaysia in the first quarter 2018 and 2017 were $71.21 per barrel and $49.63 per barrel, respectively.

Natural gas sales volumes averaged 420 million cubic feet per day (MMCFD) in the first quarter 2018 compared to 388 MMCFD in 2017. The increase of 32 MMCFD was a result of increased volumes at Canada (44 MMCFD), partially offset by lower volumes at Malaysia (9 MMCFD) and lower volumes in U.S. (3 MMCFD). Higher volumes at Canada are a result of more wells online at the Tupper business. Lower volumes at Malaysia were principally due to field decline, while lower volumes in U.S are due to fewer wells brought online at Eagle Ford Shale. Natural gas prices for the total Company averaged $2.16 per thousand cubic feet (MCF) in the 2018 quarter, versus $2.53 per MCF average in the same quarter of 2017. Natural gas sales prices in the U.S. averaged $2.46 per MCF in the 2018 quarter versus $2.32 per MCF average in the same quarter of 2017. In Canada, natural gas sales prices averaged $1.68 per MCF in the 2018 quarter, 18% below the $2.04 per MCF average in the same quarter of 2017. The average realized price for natural gas produced in the 2018 quarter at fields offshore Sarawak was $3.37 per MCF, compared to a price of $3.68 per MCF in the 2017 quarter.

Additional details about results of oil and gas operations are presented in the tables on pages 2928.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2018 and 2017 follow.






	Three Months Ended
	March 31,
	2018	2017
Net crude oil and condensate produced – barrels per day	88,533	95,605
United States – Eagle Ford Shale	31,321	33,603
– Gulf of Mexico	12,847	12,364
Canada – Onshore	4,358	1,882
– Offshore	8,189	9,916
– Heavy1	–	610
Malaysia – Sarawak	12,861	13,518
– Block K	18,372	23,712
Brunei	585	–

Net crude oil and condensate sold – barrels per day	87,668	89,887
United States – Eagle Ford Shale	31,321	33,603
– Gulf of Mexico	12,847	12,364
Canada – Onshore	4,358	1,882
– Offshore	9,188	7,982
– Heavy1	–	610
Malaysia – Sarawak	13,322	13,476
– Block K	16,632	19,970

Net natural gas liquids produced – barrels per day	8,892	8,916
United States – Eagle Ford Shale	6,719	6,848
– Gulf of Mexico	834	1,113
Canada	884	260
Malaysia – Sarawak	455	695
	–	–
Net natural gas liquids sold – barrels per day	9,403	9,381
United States – Eagle Ford Shale	6,719	6,848
– Gulf of Mexico	834	1,113
Canada	884	260
Malaysia – Sarawak	966	1,160

Net natural gas sold – thousands of cubic feet per day	420,484	388,223
United States – Eagle Ford Shale	31,101	34,328
– Gulf of Mexico	12,802	12,115
Canada	261,305	217,095
Malaysia – Sarawak	106,672	116,560
– Block K	8,604	8,125

Total net hydrocarbons produced – equivalent barrels per day2	167,506	169,225
Total net hydrocarbons sold – equivalent barrels per day2	167,152	163,972

130The Company sold the Seal area heavy oil field in January 2017.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)



	Three Months Ended
	March 31,
	2018		2017
Weighted average Exploration and Production sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	64.28	49.45
– Gulf of Mexico		63.00	48.74
Canada 1 – Onshore		54.29	40.67
– Offshore		65.69	51.53
– Heavy2		–	26.81
Malaysia – Sarawak3		64.48	54.24
– Block K3		63.18	48.87

Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale	$	19.93	15.63
– Gulf of Mexico		22.57	19.35
Canada1		43.58	18.45
Malaysia – Sarawak3		71.21	49.63

Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	2.40	2.26
– Gulf of Mexico		2.58	2.52
Canada1		1.68	2.04
Malaysia – Sarawak3		3.37	3.68
– Block K3		0.22	0.24

1U.S. dollar equivalent.

2The Company sold the Seal area heavy oil field in January 2017.

3Prices are net of payments under the terms of the respective production sharing contracts.

~~Note O~~

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – ~~New~~ THREE MONTHS ENDED MARCH 31, 2018 AND 2017




	United
(Millions of dollars)	States 1		Canada 2	Malaysia	Other	Total
Three Months Ended March 31, 2018
Oil and gas sales and other operating revenues	$	278.1	118.3	210.8	–	607.2
Lease operating expenses		58.5	30.4	47.6	–	136.5
Severance and ad valorem taxes		11.8	0.4	–	–	12.2
Depreciation, depletion and amortization		121.6	55.7	47.7	0.8	225.8
Accretion of asset retirement obligations		4.4	2.0	3.5	–	9.9
Exploration expenses
Geological and geophysical		5.9	–	0.2	2.9	9.0
Other		1.2	0.1	–	5.4	6.7
		7.1	0.1	0.2	8.3	15.7
Undeveloped lease amortization		12.7	0.2	–	0.3	13.2
Total exploration expenses		19.8	0.3	0.2	8.6	28.9
Selling and general expenses		14.4	7.7	2.8	5.9	30.8
Other expense (benefit)		0.8	(11.7)	(1.1)	(0.1)	(12.1)
Results of operations before taxes		46.8	33.5	110.1	(15.2)	175.2
Income tax provisions		10.6	9.1	39.7	0.2	59.6
Results of operations (excluding corporate overhead and interest)	$	36.2	24.4	70.4	(15.4)	115.6

Three Months Ended March 31, 2017
Oil and gas sales and other operating revenues	$	224.2	218.0	197.3	–	639.5
Lease operating expenses		48.0	22.6	51.5	–	122.1
Severance and ad valorem taxes		10.7	0.5	–	–	11.2
Depreciation, depletion and amortization		138.3	44.7	47.9	1.0	231.9
Accretion of asset retirement obligations		4.2	2.0	4.4	–	10.6
Exploration expenses
Dry holes		(0.3)	–	3.2	–	2.9
Geological and geophysical		0.3	0.1	–	4.4	4.8
Other		2.0	0.1	–	8.9	11.0
		2.0	0.2	3.2	13.3	18.7
Undeveloped lease amortization		8.9	1.1	–	–	10.0
Total exploration expenses		10.9	1.3	3.2	13.3	28.7
Selling and general expenses		15.5	7.2	2.3	4.9	29.9
Other expense (benefit)		(3.0)	–	5.1	–	2.1
Results of operations before taxes		(0.4)	139.7	82.9	(19.2)	203.0
Income tax provisions (benefit)		0.7	39.1	24.3	(12.1)	52.0
Results of operations (excluding corporate overhead and interest)	$	(1.1)	100.6	58.6	(7.1)	151.0

1 In 2018, the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously in the E&P segment) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to reflect comparable disclosure.

22017 revenue includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada.

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

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to operating functions, had net income of $53.1 million in the 2018 first quarter compared to net loss of $93.5 million in the same 2017 quarter. The $146.6 million variance in the 2018 period was primarily due to a credit to income tax expense of $120.0 million related to an IRS interpretation of the Tax Cuts and Jobs Act. The 2018 period also includes an after-tax foreign currency exchange gain of $11.9 million versus a loss of $11.6 million in the 2017 period. After-tax realized and unrealized gains/losses on crude oil contracts were a loss of $23.3 million in 2018 versus a gain of $24.1 million in 2017. Further, the 2017 period included a deferred tax charge of $54.6 million associated with the estimated tax consequence of future repatriation of Malaysian and Canadian earnings that were deemed no longer indefinitely invested. Net interest costs and selling and general expenses were relatively unchanged year over year.

Discontinued Operations

The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. The after-tax results of these operations for the three-month periods ended March 31, 2018 and 2017 are reflected in the following table.


		Three Months Ended
		March 31,
(Millions of dollars)		2018	2017
U.S. refining and marketing	$	(0.6)	1.0
U.K. refining and marketing		0.2	–
Income (loss) from discontinued operations	$	(0.4)	1.0

Financial Condition

Net cash provided by continuing operating activities was $278.5 million for the first three months of 2018 compared to $305.5 million during the same period in 2017. The reduction in cash provided by continuing operations activities in 2018 was primarily attributable to higher cash taxes paid as result of repatriating cash from Canada. Changes in operating working capital from continuing operations increased cash by $41.6 million during the first three months of 2018, compared to $43.4 million in 2017.

Cash used for property additions and dry holes, which includes amounts expensed, were $273.9 million and $211.6 million in the three-month periods ended March 31, 2018 and 2017, respectively. Proceeds from sales of property and equipment generated cash of $0.3 million in 2018 compared to $64.1 million in 2017 primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain non-core assets of Eagle Ford Shale in South Texas in 2017. Total cash dividends to shareholders amounted to $43.3 million for the three months ended March 31, 2018 compared to $43.1 million in the same period of 2017.

Total accrual basis capital expenditures were as follows:


	Three Months Ended
	March 31,
(Millions of dollars)	2018		2017
Capital Expenditures
Exploration and production	$	295.3		213.6
Corporate		5.1		0.9
Total capital expenditures	$	300.4		214.5

The increase in capital expenditures in the exploration and production business in 2018 compared to 2017 was primarily attributable to higher developmental drilling activities in Eagle Ford Shale and Kaybob Duvernay.

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

Financial Condition (Contd.)

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



	Three Months Ended
	March 31,
(Millions of dollars)	2018		2017
Property additions and dry hole costs per cash flow statements	$	273.9		211.6
Geophysical and other exploration expenses		15.7		15.8
Capital expenditure accrual changes and other		10.8		(12.9)
Total capital expenditures	$	300.4		214.5

Working capital (total current assets less total current liabilities) at March 31, 2018 was $442.0 million, $95.4 million less than December 31, 2017, with the decrease primarily attributable to lower cash, accounts receivable, and inventory balances offset by higher accounts payable and income tax payable.

At March 31, 2018, long-term debt of $2,898.9 million had decreased by $7.6 million compared to December 31, 2017. A summary of capital employed at March 31, 2018 and December 31, 2017 follows.



	March 31, 2018				December 31, 2017
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	2,898.9	38.2	%	$	2,906.5	38.6	%
Stockholders' equity		4,692.3	61.8	%		4,620.2	61.4	%
Total capital employed	$	7,591.2	100.0	%	$	7,526.7	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. At March 31, 2018, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $773.9 million in Canada and $101.3 million in Malaysia. In addition, $16.4 million of cash was held in the United Kingdom, but was reflected in current Assets held for sale on the Company’s Consolidated Balance Sheet at March 31, 2018. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any cash repatriated to the U.S.

Accounting and Other Matters

Accounting Principles Adopted

~~Business Combinations~~

Revenue from Contracts with Customers.In ~~January 2017,~~May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance. Under the new standard, an entity is required to ~~clarify~~recognize revenue when it transfers goods or services to customers in an amount that reflects the ~~definition~~consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures are required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method. The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU. Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 and recorded revenue when deliveries occurred and legal ownership of the commodity transferred to the customer.

Statement of Cash Flows. In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business ~~to assist entities~~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. The amendments in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update isthis ASU were effective for annual and interim periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements.2017. The Company adopted this guidance in ~~2017~~2018 and it did not have a material impact on its consolidated financial ~~statements and footnote disclosures.~~statements.

1730

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)

~~Note O – New~~ Accounting ~~Principles Adopted~~and Other Matters (Contd.)

Accounting Principles Adopted (Cont.)

Compensation – ~~Stock Compensation~~

Retirement Benefits.In March ~~2016,~~2017, the FASB issued an ASU ~~intended to simplify~~requiring that the ~~accounting~~service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible 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.~~capitalization. The ~~amendments in this ASU were~~update is effective for annual and interim periods beginning after December 15, ~~2016, and interim periods within those annual periods.~~2017. The Company adopted ~~this guidance~~the standard in ~~2017~~the first quarter of 2018 and it did not have a material impact on its consolidated financial ~~statements and footnote disclosures as there were no exercises of Company options during the period.~~statements.

~~Note P – Recent Accounting Pronouncements~~

Compensation – Stock ~~Compensation~~

Compensation.In May 2017, the FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. ~~Early adoption is permitted.~~ The Company ~~does not believe the application of~~adopted this accounting standard ~~will~~in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

~~Compensation~~Statement of Operations – ~~Retirement Benefits~~

Reporting Comprehensive Income. In ~~March 2017,~~February 2018, the FASB issued an ASU, ~~requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as~~which allows a reclassification from accumulated other ~~current employee compensation costs and other components of those benefit costs be presented separately~~comprehensive income to retained earnings for stranded tax effects resulting from the ~~service cost component~~Tax Cuts and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted.Jobs Act. The Company ~~does not believe the application of~~elected to early adopt this accounting standard ~~will have a material impact on its consolidated financial statements.~~

~~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 ASU’s 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. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard induring the first quarter of 2018 ~~using either the modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams~~ and is developing accounting policies and applicable disclosures to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this andrecorded discrete adjustments from accumulated other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustmentcomprehensive income to retained earnings ~~as necessary.~~of $28.4 million related to retirement and postretirement obligations and $1.8 million related to deferred loss on interest rate derivative hedges. The adoption of this ASU will have no future impact.

Recent Accounting Pronouncements

~~Leases~~

Leases.In February 2016, the FASB issued an 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 right-of-use 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 the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU ~~may~~will have on its consolidated financial statements.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note P – Recent Accounting Pronouncements (Contd~~.)

~~Statement of Cash Flows~~

In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument 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. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.

~~Overall~~ ~~Review~~

During the three-month and nine-month periods ended September 30, 2017, worldwide benchmark oil and natural gas prices were above average comparable benchmark prices during 2016. Although prices were above 2016 levels, unrealized losses from foreign exchange movements along with higher tax expense on earnings of foreign subsidiaries more than offset this increase in revenue in the third quarter.

For the three months ended September 30, 2017, the Company produced 154 thousand barrels of oil equivalent per day. There was no production in the 2017 quarter from Canadian synthetic and heavy oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively. The Company invested $287 million in capital expenditure in the third quarter of 2017 primarily in the United States and Canada. The Company reported a net loss of $65.9 million, for the three months ended September 30, 2017, which included a foreign exchange after-tax loss of $43.9 million, principally on intercompany loans in the quarter and an after-tax loss of $11.8 million in the third quarter relating to crude oil derivative contracts.

For the nine-month period ended September 30, 2017, the Company reported a net loss of $25.0 million, which included an after-tax gain of $96.0 million on the sale of the Seal heavy oil property in Canada. The Company produced 162 thousand barrels of oil equivalent per day for the nine-month 2017 period and invested $702 million in capital expenditures, principally in the United States and Canada. The Company incurred a non-cash deferred tax expense in the first nine months of 2017 of $65.2 million on earnings of foreign subsidiaries, the majority of which was recorded in first quarter of 2017 and recorded a foreign exchange after-tax loss of $86.6 million, principally on intercompany loans in the first nine months of 2017. Further detail and discussion is provided in the narrative below.

~~Results of Operations~~

~~Murphy’s income (loss) by type of business is presented below.~~

Income (Loss)

Three Months Ended

Nine Months Ended

September 30,

September 30,
(Millions of dollars)

2017

2016

2017

2016
Exploration and production

$
33.6

25.0

276.6

(99.5)
Corporate and other

(99.9)

(39.6)

(302.8)

(111.7)
Loss from continuing operations

(66.3)

(14.6)

(26.2)

(211.2)
Discontinued operations

0.4

(1.6)

1.2

(0.8)
Net loss

$
(65.9)

(16.2)

(25.0)

(212.0)

~~Third quarter 2017 vs. 2016~~

For the third quarter of 2017, Murphy’s net loss was $65.9 million ($0.38 per diluted share) compared to net loss of $16.2 million ($0.09 per diluted share) in the third quarter of 2016. Loss from continuing operations fell lower from a loss of $14.6 million ($0.08 per diluted share) in the 2016 quarter to a loss of $66.3 million ($0.38 per diluted share) in the 2017 period. The Company’s exploration and production (E&P) continuing operations earned $33.6 million in the 2017 quarter compared to earnings of $25.0 million in the 2016 quarter. The E&P results in the 2017 quarter were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices, lower lease operating expenses, lower depreciation expense and lower dry hole costs, partially offset by lower volume sold, higher selling and general expenses and higher deferred tax expense on earnings of foreign subsidiaries. The corporate function had after-tax costs of $99.9 million in the 2017 third quarter compared to after-tax costs of $39.6 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs in the current quarter. The third quarter of 2017 included gains from discontinued operations of $0.4 million ($0.00 per diluted share) compared to losses from discontinued operations of $1.6 million ($0.01 per diluted share) in the third quarter of 2016.

~~Nine months 2017 vs. 2016~~

For the first nine months of 2017, Murphy’s net loss was $25.0 million ($0.14 per diluted share) compared to a net loss of $212.0 million ($1.24 per diluted share) for the same period in 2016. Loss from continuing operations improved from a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016 to a loss of $26.2 million ($0.15 per diluted share) in 2017. In the first nine months of 2017, the Company’s E&P continuing operations earned $276.6 million compared to a loss of $99.5 million in the same period of 2016. The results for the first nine months of 2017 were favorably impacted

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Nine months 2017 vs. 2016 (contd.)~~

by higher revenues due to higher realized oil and natural gas sales prices, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, lower selling and general expenses, lower dry hole costs and higher tax benefits on investments in foreign areas, partially offset by higher non-cash deferred tax expense on earnings of foreign subsidiaries, higher other expense related primarily to rig demobilization in Malaysia and lower oil and natural gas volume sold. The corporate function had after-tax costs of $302.8 million in the first nine months of 2017 compared to after-tax costs of $111.7 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and non-cash deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs. Income from discontinued operations was $1.2 million ($0.01 per diluted share) in the first nine months of 2017 compared to a loss of $0.8 million ($0.01 per diluted share) in the 2016 period.

~~Exploration and Production~~

~~Results of E&P continuing operations are presented by geographic segment below.~~

Income (Loss)

Three Months Ended

Nine Months Ended

September 30,

September 30,
(Millions of dollars)
2017

2016

2017

2016
Exploration and production

United States
$
(19.9)

(27.1)

11.0

(158.5)
Canada

(3.2)

(4.8)

102.6

(36.9)
Malaysia

67.7

65.0

173.9

135.1
Other International

(11.0)

(8.1)

(10.9)

(39.2)
Total
$
33.6

25.0

276.6

(99.5)

~~Third quarter 2017 vs. 2016~~

United States E&P operations reported a net loss of $19.9 million in the third quarter of 2017 compared to a net loss of $27.1 million in the 2016 quarter. Results improved $7.2 million in the 2017 quarter compared to the 2016 period. Higher oil and natural gas realized sales prices more than offset impacts of lower volumes sold. Lease operating expenses decreased due to lower costs in Eagle Ford Shale compared to the same quarter in 2016 with most of the reduction due to the Company’s continuous focus on improving its cost structure. Depreciation expense decreased in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale and Gulf of Mexico and lower average unit rates in the Gulf of Mexico in the 2017 period. Amortization of undeveloped leases were higher in the 2017 quarter due to costs related to certain offshore leases expiring in 2017 and 2018. Revenue in the U.S. decreased by $5.9 million in the period as the U.S. segment recorded $18.1 million unrealized losses on open crude oil contracts in 2017 versus losses of $1.3 million in the 2016 period. This was offset in part by higher oil and gas sales revenue. Selling and general expenses increased in the third quarter of 2017 primarily due to higher allocated benefit costs in the current period versus 2016.

Canadian E&P operations reported a net loss of $3.2 million in the third quarter 2017 compared to a loss of $4.8 million in the 2016 quarter. Canadian results of operations improved $1.6 million in the 2017 quarter compared to the 2016 period due to higher average sales prices received in 2017 for both oil and natural gas and lower lease operating expenses, partially offset by non-recurring 2016 income tax benefits associated with divestiture of Montney midstream assets in 2016 and a gain on sale of its synthetic operations completed in the third quarter 2016. Natural gas sales volumes increased in 2017 due to new production in the Kaybob Duvernay and Placid Montney areas of Western Canada.

Malaysia E&P operations reported earnings of $67.7 million in the third quarter of 2017 and compared to earnings of $65.0 million in the comparable 2016 period. Results were favorable to 2016 in Malaysia as higher average oil and natural gas prices realized, were mostly offset by lower natural gas volume sold, higher lease operating expense, higher depreciation expense, higher administrative expense and higher income tax expense. Crude oil and natural gas sales volumes in Malaysia were lower in the 2017 quarter versus 2016, primarily due to a maintenance shutdown in Sarawak in 2017. Depreciation expense was higher in 2017 compared to the 2016 quarter primarily due to higher unit rates in Block K and Sarawak partly offset by lower volumes sold in Block K and Sarawak.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Exploration and Production~~ ~~(Contd.)~~

~~Third quarter 2017 vs. 2016 (Contd.)~~

Other international E&P operations reported a loss from continuing operations of $11.0 million in the third quarter of 2017 compared to a loss of $8.1 million in the 2016 quarter. The results were $2.9 million lower in the 2017 period versus 2016 primarily related to higher exploration expenses and lower income tax benefits on investments in foreign areas, partially offset by lower selling and general expenses resulting from restructuring activity in 2016.

Total hydrocarbon production averaged 153,842 barrels of oil equivalent per day in the 2017 third quarter, which represented a 9% decrease from the 169,844 barrels of oil equivalents per day produced in the 2016 quarter. When the Seal asset sold in 2017 is excluded, the Company’s worldwide production decreased 8% in 2017 compared to 2016.

Average crude oil and condensate production was 84,230 barrels per day in the third quarter of 2017 compared to 96,476 barrels per day in the third quarter of 2016. Crude oil production in the Eagle Ford Shale area of South Texas in the 2017 quarter was essentially flat to the same quarter in 2016. Crude oil production in the Gulf of Mexico was lower in the 2017 quarter due to well decline and unplanned downtime. Heavy oil production from the Seal area in Western Canada was divested in mid-January 2017. Onshore oil production in Canada improved in the 2017 quarter in the Company’s Kaybob Duvernay and Placid Montney areas acquired in the third quarter of 2016. Oil production offshore Eastern Canada was lower during 2017 primarily due to unplanned downtime at both Hibernia and Terra Nova fields. Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to lower working interest in the Kakap field subsequent to the redetermination of working interest. On a worldwide basis, the Company's crude oil and condensate prices averaged $49.82 per barrel in the third quarter 2017 compared to $44.64 per barrel in the 2016 period, an increase of 12% quarter to quarter.

Total production of natural gas liquids (NGL) was 9,128 barrels per day in the 2017 third quarter compared to 9,703 barrels per day in the same 2016 period. The decrease in NGL production was primarily associated with lower natural gas liquids volumes in the U.S, offset by higher volumes in Canada. The average sales price for U.S. NGL was $18.02 per barrel in the 2017 quarter compared to $11.38 per barrel in 2016. Average NGL prices in Malaysia in the third quarter of 2017 and 2016 were $49.66 per barrel and $45.12 per barrel, respectively.

Natural gas sales volumes averaged 363 million cubic feet per day in the third quarter 2017 compared to 382 million cubic feet per day in 2016. Natural gas sales volumes increased in North America for the 2017 period due primarily to new volumes in the Kaybob Duvernay and Placid Montney areas of Western Canada acquired in the third quarter of 2016, and growth in the Tupper Montney business, offset in part by lower volumes produced in both offshore Gulf of Mexico and in Eagle Ford Shale. Natural gas production volumes in Malaysia decreased in the 2017 period due to lower demand and planned downtime at Sarawak in the current period. North American natural gas sales prices averaged $1.93 per thousand cubic feet (MCF) in the 2017 quarter, 2% below the $1.96 per MCF average in the same quarter of 2016. The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.60 per MCF, compared to a price of $3.01 per MCF in the 2016 quarter.

~~Nine months 2017 vs. 2016~~

United States E&P operations reported earnings of $11.0 million in the first nine months of 2017 compared to a loss of $158.5 million in the 2016 period, an improvement of $169.5 million in 2017 compared to the 2016 period. Revenue in the U.S. was $176.5 million in the period as oil and natural gas realized sales prices and unrealized gains on crude oil derivative contracts more than offset lower sales volume. Lease operating expenses decreased by $33.9 million primarily due to lower costs in Eagle Ford Shale and Gulf of Mexico mainly related to cost structure improvements coupled with lower variable costs based on volumes produced. Depreciation expense decreased $54.2 million in 2017 compared to 2016 due to lower unit rates in the Gulf of Mexico in the 2017 period and lower U.S. volume sold. Exploration expenses were $6.6 million higher in the 2017 period primarily related to higher undeveloped lease amortization expense compared to the same period of 2016. Income taxes increased by $87.7 million in the 2017 period due to improvements in net income.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Exploration and Production~~ ~~(Contd.)~~

~~Nine months 2017 vs. 2016 (Contd.)~~

Canadian E&P operations reported earnings of $102.6 million in the first nine months of 2017 compared to a loss of $36.9 million in the 2016 period. Results for conventional operations improved by $187.2 million in 2017 due to a gain of $132.4 million on the sale of Seal heavy oil assets in 2017, lower impairment expense of $95.1 million in 2017 and higher average realized sales prices for crude oil and natural gas, partially offset by lower oil volume sold (from the sale of Seal and Syncrude assets in quarter 1 2017 and quarter 2 2016, respectively), higher lease operating expense for conventional operations and non-recurring income tax benefits recognized on the sale of certain Montney midstream assets in 2016.

Malaysia E&P operations reported earnings of $173.9 million in the first nine months of 2017 compared to earnings of $135.1 million during the same period in 2016. Results improved $38.8 million in 2017 in Malaysia primarily due to higher revenue of $53.0 million driven by higher commodity prices received and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold (from Block K due to normal field decline). Depreciation expense was $10.1 million lower in 2017 compared to the same period in 2016 primarily due to lower unit rates in Sarawak and lower oil volume sold, partly offset by higher natural gas volume sold in Sarawak and higher unit rates at Block K.

Other international E&P operations reported a loss of $10.9 million in the first nine months of 2017 compared to a loss of $39.2 million in the 2016 period. The 2017 period included lower dry hole costs of $10.4 million, with the higher 2016 costs primarily associated with unsuccessful drilling in Block 11-2/11 in Vietnam. The 2017 period also included income tax benefits on investments in foreign areas of $32.9 million. Other exploration expenses were $5.9 million higher in the current year, mostly attributable to costs in Mexico, Australia and Brazil. Other expenses were $8.8 million higher in the 2017 period primarily related to no repeat of a credit from an adjustment of previously recorded exit costs in 2016 in the Republic of Congo.

Total worldwide production averaged 161,917 barrels of oil equivalent per day during the nine months ended September 30, 2017, a 9% decrease from 178,319 barrels of oil equivalent produced in the same period in 2016. When Seal and Syncrude are excluded, the Company’s worldwide production decreased by 4%. Crude oil and condensate production in the first nine months of 2017 averaged 89,580 barrels per day compared to 106,279 barrels per day in 2016. Crude oil production decreased at Eagle Ford Shale in 2017 due to production decline associated with significantly less drilling in response to lower prices and phasing of capital expenditures into late 2017. Heavy oil production declined in 2017 in the Seal area of Western Canada primarily due to divestment of the asset in January 2017. Synthetic oil production in Canada also was nil in 2017 due to the Company’s divestiture of Syncrude Canada Ltd. in the second quarter of 2016. Lower oil production in 2017 in Block K Malaysia was primarily attributable to lower working interest in Kakap field subsequent to the redetermination of working interest. For the first nine months of 2017, the Company’s sales price for crude oil and condensate averaged $49.41 per barrel, up from $40.67 per barrel in 2016.

Total production of NGLs was 9,140 barrels per day in the 2017 period compared to 9,275 barrels per day in 2016. The sales price for U.S. NGLs averaged $16.33 per barrel in 2017 compared to $10.31 per barrel in 2016.

Natural gas sales volumes increased from 377 million cubic feet per day in 2016 to 379 million cubic feet per day in 2017. Natural gas sales volume increased, primarily due to less unplanned downtime in 2017 in Sarawak. North American natural gas volumes were flat as improvement in Canada due to the 2017 volumes from Kaybob Duvernay and Placid Montney fields were offset in part by lower U.S. volume due to natural field decline. The average sales price for North American natural gas in the first nine months of 2017 was $2.08 per MCF, up from $1.58 per MCF realized in 2016. Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.50 per MCF in 2017 compared to $3.25 per MCF in 2016.

~~Additional details about results of oil and gas operations are presented in the tables on pages~~ 29 ~~and~~ 30.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Exploration and Production~~ ~~(Contd.)~~

~~Selected operating statistics for the three-month and nine-month periods ended September 30, 2017 and 2016 follow.~~

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Net crude oil and condensate produced – barrels per day

84,230

96,476

89,580

106,279
United States – Eagle Ford Shale

33,070

33,307

33,281

36,790
                             – Gulf of Mexico and other

10,240

11,722

11,309

12,791
Canada – onshore

3,240

1,288

2,729

791
                    – offshore

6,225

9,400

8,100

8,483
                    – heavy1

–

2,678

201

2,732
                    – synthetic1

–

–

–

6,194
Malaysia – Sarawak

11,508

12,889

12,727

13,288
                        – Block K

19,947

25,192

21,233

25,210

Net crude oil and condensate sold – barrels per day

92,033

97,542

89,597

104,525
United States – Eagle Ford Shale

33,070

33,307

33,281

36,790
                             – Gulf of Mexico and other

10,240

11,722

11,309

12,791
Canada – onshore

3,240

1,288

2,729

791
                    – offshore

6,533

9,027

7,812

8,576
                    – heavy1

–

2,678

201

2,732
                    – synthetic1

–

–

–

6,194
Malaysia – Sarawak

13,083

12,641

13,350

12,024
                        – Block K

25,867

26,879

20,915

24,627

Net natural gas liquids produced – barrels per day

9,128

9,703

9,140

9,275
United States – Eagle Ford Shale

6,669

6,940

6,812

6,972
                             – Gulf of Mexico and other

910

1,502

967

1,399
Canada

510

307

410

162
Malaysia – Sarawak

1,039

954

951

742

Net natural gas liquids sold – barrels per day

9,213

8,770

9,165

9,289
United States – Eagle Ford Shale

6,669

6,940

6,812

6,972
                             – Gulf of Mexico

910

1,502

967

1,399
Canada

510

307

410

162
Malaysia – Sarawak

1,124

21

976

756

Net natural gas sold – thousands of cubic feet per day

362,901

381,988

379,182

376,592
United States – Eagle Ford Shale

29,476

34,900

32,862

36,430
                             – Gulf of Mexico and other

11,232

16,873

11,654

19,012
Canada

223,032

204,816

220,121

206,458
Malaysia – Sarawak

90,181

115,535

106,481

103,327
                        – Block K

8,980

9,864

8,064

11,365

Total net hydrocarbons produced – equivalent barrels per day2

153,842

169,844

161,917

178,319
Total net hydrocarbons sold – equivalent barrels per day2

161,730

169,977

161,959

176,579

1~~The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.~~

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

~~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,

2017

2016

2017

2016
Weighted average sales prices

Crude oil and condensate – dollars per barrel

United States – Eagle Ford Shale
$
48.49

44.59

48.42

40.65
                      – Gulf of Mexico

47.82

43.93

47.48

40.53
          Canada1    – onshore

43.15

36.36

43.64

41.04
                           – offshore

51.26

45.87

50.35

40.15
                           – heavy2

–

19.50

25.12

14.20
                           – synthetic2

–

–

–

35.59
Malaysia – Sarawak3

52.62

47.05

52.07

43.62
  – Block K3

51.36

46.24

50.95

43.70

    Natural gas liquids – dollars per barrel

United States – Eagle Ford Shale
$
17.89

10.89

16.12

10.06
                       – Gulf of Mexico

19.00

13.65

17.84

11.60
Canada1

22.77

39.23

22.48

41.04
Malaysia – Sarawak3

49.66

45.12

49.94

37.50

    Natural gas – dollars per thousand cubic feet

United States – Eagle Ford Shale
$
2.44

2.24

2.53

1.69
                       – Gulf of Mexico

2.49

2.35

2.56

1.81
Canada1

1.84

1.88

1.99

1.58
Malaysia – Sarawak3

3.60

3.01

3.50

3.25
  – Block K

0.25

0.23

0.24

0.24

1~~U.S. dollar equivalent.~~

2~~The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.~~

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

~~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, 2017 AND 2016~~

United

(Millions of dollars)

States

Canada

Malaysia

Other

Total
Three Months Ended September 30, 2017

Oil and gas sales and other operating revenues

$
195.9

81.9

220.5

–

498.3
Lease operating expenses

43.5

28.7

40.6

–

112.8
Severance and ad valorem taxes

10.5

0.3

–

–

10.8
Depreciation, depletion and amortization

128.4

45.9

63.7

1.0

239.0
Accretion of asset retirement obligations

4.3

2.0

4.4

–

10.7
Exploration expenses

Dry holes

(0.6)

–

(2.5)

–

(3.1)
Geological and geophysical

0.1

–

–

1.5

1.6
Other

1.5

0.2

–

7.7

9.4

1.0

0.2

(2.5)

9.2

7.9
Undeveloped lease amortization

20.4

0.2

–

–

20.6
Total exploration expenses

21.4

0.4

(2.5)

9.2

28.5
Selling and general expenses

16.6

6.9

4.8

5.1

33.4
Other expenses

0.8

0.5

1.2

–

2.5
Results of operations before taxes

(29.6)

(2.8)

108.3

(15.3)

60.6
Income tax provisions (benefits)

(9.7)

0.4

40.6

(4.3)

27.0
Results of operations (excluding corporate
overhead and interest)

$
(19.9)

(3.2)

67.7

(11.0)

33.6

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

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations (Contd~~.)

~~Exploration and Production~~ ~~(Contd.)~~

OI~~L AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016~~

Canada

United

Conven-

(Millions of dollars)

States

tional

Synthetic*

Malaysia

Other

Total
Nine Months Ended September 30, 2017

Oil and gas sales and other operating revenues

$
696.7

388.1

–

594.4

–

1,679.2
Lease operating expenses

135.7

76.8

–

133.6

–

346.1
Severance and ad valorem taxes

31.6

1.2

–

–

–

32.8
Depreciation, depletion and amortization

402.3

136.6

–

160.0

2.9

701.8
Accretion of asset retirement obligations

12.8

5.9

–

12.9

–

31.6
Exploration expenses

Dry holes

(1.9)

–

–

0.8

–

(1.1)
Geological and geophysical

1.0

0.1

–

–

6.0

7.1
Other

5.5

0.3

–

–

24.8

30.6

4.6

0.4

–

0.8

30.8

36.6
Undeveloped lease amortization

39.4

1.4

–

–

–

40.8
Total exploration expenses

44.0

1.8

–

0.8

30.8

77.4
Selling and general expenses

48.7

21.2

–

10.5

15.0

95.4
Other expenses

1.5

0.4

–

9.1

–

11.0
Results of operations before taxes

20.1

144.2

–

267.5

(48.7)

383.1
Income tax provisions (benefits)

9.1

41.6

–

93.6

(37.8)

106.5
Results of operations (excluding corporate
overhead and interest)

$
11.0

102.6

–

173.9

(10.9)

276.6

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)

*~~The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016.~~

~~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 net cost of $99.9 million in the 2017 third quarter compared to $39.6 million in the same 2016 quarter. The $60.3 million increased cost in the 2017 period is primarily due to after-tax foreign currency exchange losses of $43.9 million in the 2017 period versus gains in the 2016 period, higher net interest expense of $9.5 million in 2017 and deferred tax charges on undistributed earnings of certain foreign subsidiaries of $4.7 million in 2017, partially offset by lower administrative costs in the current quarter. Net interest costs increased in the 2017 period primarily due to accelerated interest payment upon the early repayment of the December 2017 notes, additional interest on $550 million notes issued in August 2017 (2025 maturity) and an increase of 1.00% on the coupon rates on $950 million of the Company’s outstanding notes effective September 1, 2016 following a downgrade by Moody’s Investor Services in February 2016. Selling and general expenses decreased $4.7 million in the third quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of the cost structure.

During the first nine months of 2017, Corporate activities had a net cost of $302.8 million compared to $111.7 million for the same period of 2016. The $191.1 million increased cost in the 2017 period compared to the 2016 period was primarily due to after-tax losses from foreign currency exchange of $86.6 million in the 2017 period versus gains in the 2016 period, deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries of $65.2 million and higher net interest expense of $34.5 million in 2017 due to additional interest on the $550 million notes issued in August 2017 and an increase of 1.00% on the coupon rates on $950 million of the Company’s notes. These were partially offset by lower administrative costs in 2017. During the first nine months of 2017, the Company’s determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the first nine month of 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ nine-month 2017 earnings. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise.

~~Discontinued Operations~~

~~The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.~~ ~~The after-tax results of these operations for the three-month and nine-month periods ended September 30, 2017 and 2016 are reflected in the following table.~~

Three Months Ended

Nine Months Ended

September 30,

September 30,
(Millions of dollars)

2017

2016

2017

2016
U.S. refining and marketing

$
(0.7)

–

(0.7)

–
U.K. refining and marketing

1.1

(1.0)

1.9

(1.1)
U.K. exploration and production

–

(0.6)

–

0.3
Income (loss) from discontinued operations

$
0.4

(1.6)

1.2

(0.8)

~~Financial Condition~~

Net cash provided by continuing operating activities was $819.6 million for the first nine months of 2017 compared to $280.3 million during the same period in 2016. The improvement in cash provided by continuing operations activities in 2017 was primarily attributable to higher realized sales prices for the Company’s oil and gas production, lower lease operating and administrative expenses, and rig cancellation payments in 2016 which are discussed below, partially offset by lower volume sold in the current year and higher interest costs. Changes in operating working capital from continuing operations increased cash by $1.1 million during the first nine months of 2017, compared to a use of cash of $152.6 million in 2016. 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 $69.1 million in 2017 primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain areas of Eagle Ford Shale in South Texas, while the 2016 period generated cash of $1,154.6 million mainly related to the sale of Syncrude Canada Limited and certain midstream assets in the Tupper area of Western Canada. Other significant sources of cash included $320.8 million in the 2017 period and $712.9 million in 2016 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Financial Condition~~ ~~(Contd.)~~

Cash used for property additions and dry holes, which includes amounts expensed, were $706.4 million and $781.7 million in the nine-month period ended September 30, 2017 and 2016, respectively. Total cash dividends to shareholders amounted to $129.4 million for the nine-months ended September 30, 2017 compared to $163.6 million in the same period of 2016 as the ~~Company lowered the dividend from $1.40 per share to $1.00 per share effective in the third quarter 2016. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $651.2 million in the 2016 period.~~ The proceeds of the $550 million notes issued in August 2017, were used to redeem the Company’s $550 million 2.50% notes in September 2017. The 2.50% notes had a maturity date of December 2017 and were retired early. ~~The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 using proceeds from the sale of assets.~~

~~Total accrual basis capital expenditures were as follows:~~

Nine Months Ended

September 30,
(Millions of dollars)
2017

2016
Capital Expenditures

Exploration and production
$
694.7

614.6
Corporate

6.9

20.7
Total capital expenditures
$
701.6

635.3

The increase in capital expenditures in the exploration and production business in 2017 compared to 2016 was primarily attributable to higher developmental drilling activities in Eagle Ford Shale and Kaybob Duvernay and Placid Montney assets, partially offset by 2016 acquisition costs in the Kaybob Duvernay and liquids rich Placid Montney properties in Canada and lower spending in Malaysia.

~~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)

2017

2016
Property additions and dry hole costs per cash flow statements

$
706.4

781.7
Geophysical and other exploration expenses

37.7

32.8
Capital expenditure accrual changes and other

(42.5)

(179.2)
Total capital expenditures

$
701.6

635.3

Working capital (total current assets less total current liabilities) at September 30, 2017 was $615.6 million, $558.8 million more than December 31, 2016, with the increase primarily attributable to the Company redeeming the $550 million in 2.50% notes in September 2017, higher cash balances and lower accounts payable.

At September 30, 2017, long-term debt of $2,908.3 million had increased by $485.5 million compared to December 31, 2016. A summary of capital employed at September 30, 2017 and December 31, 2016 follows.

September 30, 2017

December 31, 2016
(Millions of dollars)
Amount

%

Amount

%
Capital employed

Long-term debt
$
2,908.3

36.9
%

$
2,422.8

33.0
%
Stockholders' equity

4,980.1

63.1
%

4,916.7

67.0
%
Total capital employed
$
7,888.4

100.0
%

$
7,339.5

100.0
%

Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2017, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5 million in Canada and $261.6 million in Malaysia. In addition, $17.0 million of cash was held in the United Kingdom, but was reflected in current Assets Held for Sale on the Company’s Consolidated Balance Sheet at September 30, 2017. 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 incentivize 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

~~Financial Condition~~ ~~(Contd.)~~

~~any cash repatriated to the United States through a dividend to the U.S. parent. See the “Corporate” section on page~~ 31 ~~of this Form 10-Q report regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.~~

~~Accounting and Other Matters~~

~~Business Combinations~~

In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material 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 were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.

In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~Compensation – Retirement Benefits~~

In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~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 ASU’s 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. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

~~Accounting and Other Matters~~ ~~(Contd.)~~

~~Leases~~

In February 2016, FASB issued an 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 right-of-use 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 the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

~~Statement of Cash Flows~~

Outlook

Average worldwide crude oil prices in ~~October 2017~~April 2018 have ~~slightly~~ improved from the average prices during the ~~third~~first quarter of ~~2017.~~2018. North American natural gas prices ~~decreased~~increased slightly in ~~October~~April from the ~~2017 third~~2018 first quarter. The Company expects its total oil and natural gas production to average ~~170,000~~167,000 – ~~172,000~~170,000 barrels of oil equivalent per day in the ~~fourth~~second quarter ~~2017.~~2018. The Company currently anticipates total capital expenditures for the full year ~~2017~~2018 to be approximately ~~$940 million.~~$1.11 billion.

The Company will primarily fund its remaining capital program in ~~2017~~2018 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects.

As of ~~November 1, 2017,~~May 2, 2018, 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	Contract or Location	Dates	Volumes per Day		Average Prices
U.S. Oil	West Texas Intermediate	~~Oct. – Dec. 2017~~		~~22,000 bbls/d~~	~~$50.41 per bbl.~~
~~U.S. Oil~~	~~West Texas Intermediate~~	~~Jan.~~Apr. – Dec. 2018		~~7,000~~21,000 bbls/d	$~~51.92~~54.88 per bbl.

Canada Natural Gas	~~TCPL–~~NOVA ~~System~~Gas Transmission Ltd.	~~Jul.~~Apr. 2018 – Dec. ~~2017~~		~~124 mmcf/d~~	~~C$2.97 per mcf~~
~~Natural Gas~~	~~TCPL–NOVA System~~	~~Jan. – Dec. 2018~~2020		59 mmcf/d	C$2.81 per mcf
~~Natural Gas~~	~~Alberta Alliance~~	~~Nov. 2017 – Mar. 2018~~		~~20 mmcf/d~~	~~US$3.51 per mcf~~	*

*~~Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate~~.

2831

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

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 ~~2016~~2017 Annual Report on Form 10-K on file with the U.S. Securities and

Exchange Commission and page 3633 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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


	(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, 2017~~March 31, 2018
	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


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)


		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		23
Item 3. Quantitative and Qualitative Disclosures About Market Risk		3633
Item 4. Controls and Procedures		3633
Part II – Other Information		3633
Item 1. Legal Proceedings		3633
Item 1A. Risk Factors		3633
Item 6. Exhibits		3633
Signature		3734



	September 30,		December 31,		March 31,		December 31,
	2017		2016		2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	997,207		872,797	$	938,615		964,988
Canadian government securities with maturities greater than 90 days at the date of acquisition		–		111,542
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2017 and 2016		267,209		357,099
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2018 and 2017						212,639		243,472
Inventories, at lower of cost or market		120,066		127,071		94,157		105,127
Prepaid expenses		39,427		63,604		39,936		35,087
Assets held for sale		23,248		27,070		22,696		22,929
Total current assets		1,447,157		1,559,183		1,308,043		1,371,603
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,027,902 in 2017 and $12,607,815 in 2016		8,283,738		8,316,188
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,422,869 in 2018 and $12,280,741 in 2017						8,207,736		8,220,031
Deferred income taxes		406,703		365,935		368,878		211,543
Deferred charges and other assets		55,161		54,554		53,553		57,765

Total assets	$	10,192,759		10,295,860	$	9,938,210		9,860,942
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	9,781		569,817	$	9,557		9,902
Accounts payable		584,025		784,975		615,963		595,916
Income taxes payable		57,687		13,920		77,488		44,604
Other taxes payable		30,160		28,167		19,745		23,574
Other accrued liabilities		146,607		102,777		140,158		156,681
Liabilities associated with assets held for sale		3,270		2,776		3,160		3,530
Total current liabilities		831,530		1,502,432		866,071		834,207
Long-term debt, including capital lease obligation		2,908,285		2,422,750		2,898,850		2,906,520
Deferred income taxes		108,756		69,081		128,719		159,098
Asset retirement obligations		747,602		681,528		691,170		709,299
Deferred credits and other liabilities		616,452		617,490		661,093		631,627
Liabilities associated with assets held for sale		–		85,900
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 2017 and 2016		195,056		195,056
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,065,341 shares in 2018 and 195,055,724 in 2017						195,065		195,056
Capital in excess of par value		910,936		916,799		891,191		917,665
Retained earnings		5,575,175		5,729,596		5,400,474		5,245,242
Accumulated other comprehensive loss		(425,504)		(628,212)		(544,737)		(462,243)
Treasury stock		(1,275,529)		(1,296,560)		(1,249,686)		(1,275,529)
Total stockholders’ equity		4,980,134		4,916,679		4,692,307		4,620,191
Total liabilities and stockholders’ equity	$	10,192,759		10,295,860	$	9,938,210		9,860,942


		Three Months Ended		Nine Months Ended			Three Months Ended
	September 30,			September 30,		March 31,
	2017		2016*	2017	2016*	2018		2017 1

Revenues
Sales and other operating revenues	$	498,202	486,276	1,552,473	1,326,587
Gain (loss) on sale of assets		117	(730)	130,765	3,101
Revenue from sales to customers						$	606,954	509,035
Gain (loss) on crude contracts							(29,502)	37,077
Gain on sale of assets and other income							8,153	130,528
Total revenues		498,319	485,546	1,683,238	1,329,688		585,605	676,640

Costs and expenses
Lease operating expenses		112,751	119,663	346,072	435,296		136,496	122,142
Severance and ad valorem taxes		10,816	9,592	32,771	35,668		12,157	11,213
Exploration expenses		28,492	19,866	77,356	83,910
Exploration expenses, including undeveloped lease amortization							28,928	28,663
Selling and general expenses		56,672	55,523	168,259	196,143		51,417	51,255
Depreciation, depletion and amortization		243,636	255,900	714,782	797,288
��Depreciation, depletion and amortization							230,733	236,154
Accretion of asset retirement obligations		10,654	11,043	31,638	35,514		9,914	10,556
Impairment of assets		–	–	–	95,088
Other expense (benefit)		2,454	6,486	10,988	(1,446)		(11,048)	2,157
Total costs and expenses		465,475	478,073	1,381,866	1,677,461		458,597	462,140

Operating income (loss) from continuing operations		32,844	7,473	301,372	(347,773)
Operating income from continuing operations							127,008	214,500

Other income (loss)
Interest and other income (loss)		(47,721)	14,987	(93,524)	38,602		15,084	(15,021)
Interest expense, net		(48,681)	(39,219)	(138,423)	(103,889)		(45,049)	(44,597)
Total other loss		(96,402)	(24,232)	(231,947)	(65,287)		(29,965)	(59,618)

Income (loss) from continuing operations before income taxes		(63,558)	(16,759)	69,425	(413,060)
Income from continuing operations before income taxes							97,043	154,882
Income tax expense (benefit)		2,760	(2,176)	95,602	(201,897)		(71,647)	97,387
Loss from continuing operations		(66,318)	(14,583)	(26,177)	(211,163)
Income from continuing operations							168,690	57,495
Income (loss) from discontinued operations, net of income taxes		425	(1,593)	1,177	(885)		(437)	969

NET LOSS	$	(65,893)	(16,176)	(25,000)	(212,048)
NET INCOME						$	168,253	58,464

INCOME (LOSS) PER COMMON SHARE – BASIC
INCOME PER COMMON SHARE – BASIC
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)	$	0.98	0.33
Discontinued operations		-	(0.01)	0.01	(0.01)		(0.01)	0.01
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
Net Income						$	0.97	0.34

INCOME (LOSS) PER COMMON SHARE – DILUTED
INCOME PER COMMON SHARE – DILUTED
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)	$	0.97	0.33
Discontinued operations		-	(0.01)	0.01	(0.01)		(0.01)	0.01
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
Net Income						$	0.96	0.34

Cash dividends per Common share		0.25	0.25	0.75	0.95		0.25	0.25

Average Common shares outstanding (thousands)
Basic		172,573	172,199	172,509	172,165		172,805	172,422
Diluted		172,573	172,199	172,509	172,165		174,620	173,089


	Three Months			Nine Months		Three Months
	Ended September 30,			Ended September 30,		Ended March 31,
(Thousands of dollars)		2017	2016	2017	2016		2018	2017
Revenues (costs)	$	598	5	853	1,454
Revenues						$	–	129
Income (loss) before income taxes		425	(1,593)	1,177	(885)		(437)	969
Income tax benefit		–	–	–	–		–	–
Income (loss) from discontinued operations	$	425	(1,593)	1,177	(885)	$	(437)	969


	Three Months Ended March 31,
(Thousands of dollars)	2018		2017
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Decrease in accounts receivable	$	30,467	36,246
Decrease in inventories		12,189	4,497
Decrease (increase) in prepaid expenses		(5,031)	17,788
Decrease in accounts payable and accrued liabilities		(25,270)	(44,240)
Increase in income taxes payable		29,199	29,127
Net decrease in noncash operating working capital	$	41,554	43,418
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	7,940	3,422
Interest paid, net of amounts capitalized of $1,139 in 2018 and $1,093 in 2017		35,666	17,720

Non-cash investing activities:
Asset retirement costs capitalized	$	727	565
Decrease (increase) in capital expenditure accrual		(10,757)	12,906


	Nine Months Ended September 30,
(Thousands of dollars)	2017		2016
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Decrease in accounts receivable	$	90,614	75,841
Decrease (increase) in inventories		5,869	(15,768)
Decrease in prepaid expenses		25,285	122,399
Decrease in other		–	720
Decrease in accounts payable and accrued liabilities		(115,977)	(376,310)	*
(Decrease) increase in current income tax liabilities		(4,721)	40,500
Net (increase) decrease in noncash operating working capital	$	1,070	(152,618)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	25,118	(3,911)
Interest paid, net of amounts capitalized of $3,338 in 2017 and $3,318 in 2016		95,899	52,287

Non-cash investing activities:
Asset retirement costs capitalized	$	38,992	13,959
Decrease in capital expenditure accrual		42,403	179,203



	Three Months Ended September 30,							Three Months Ended March 31,
	Pension Benefits			Other Postretirement Benefits				Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016			2018	2017	2018		2017
Service cost	$	2,037	2,610		427		674	$	2,255	2,032		494		425
Interest cost		7,261	5,913		966		1,109		6,737	6,719		874		966
Expected return on plan assets		(8,070)	(6,626)		–		–		(7,506)	(7,185)		–		–
Amortization of prior service cost (credit)		259	323		(18)		(21)		257	254		(10)		(18)
Amortization of transitional asset		–	–		–		2
Recognized actuarial loss		3,610	3,617		–		38		5,215	3,554		–		–
Net periodic benefit expense	$	5,097	5,837		1,375		1,802	$	6,958	5,374		1,358		1,373

	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	6,099	8,533		1,276		2,022
Interest cost		20,267	20,386		2,899		3,324
Expected return on plan assets		(21,730)	(21,709)		–		–
Amortization of prior service cost (credit)		767	963		(55)		(62)
Amortization of transitional asset		–	–		–		4
Recognized actuarial loss		10,673	10,864		–		113
Curtailments		–	822		–		(19)
Net periodic benefit expense	$	16,076	19,859		4,120		5,382



	Three Months Ended				Nine Months Ended
��									Three Months Ended
		September 30,			September 30,					March 31,
		2017	2016		2017		2016			2018	2017
Antidilutive stock options excluded from diluted shares		5,257,718		5,884,201		5,578,495		5,822,036		3,798,792		5,029,752
Weighted average price of these options	$	46.46	$	49.00	$	46.86	$	49.82	$	50.77	$	52.26



	2017	2016
Three months ended September 30	(4.3%)	13.0%
Nine months ended September 30	137.7%	48.9%



			Gain (Loss)						Gain (Loss)
		Three Months Ended			Nine Months Ended			Three Months Ended
(Thousands of dollars)		September 30,			September 30,			March 31,
Type of Derivative Contract	Statement of Operations Location		2017	2016	2017	2016	Statement of Operations Location		2018	2017
Commodity	Sales and other operating revenues	$	(13,573)	11,871	50,365	(22,678)	Gain (loss) on crude contracts	$	(29,502)	37,077
Foreign exchange	Interest and other income (loss)		–	143	73	26,929	Interest and other income (loss)		–	225
		$	(13,573)	12,014	50,438	4,251		$	(29,502)	37,302



	September 30, 2017					December 31, 2016				March 31, 2018					December 31, 2017
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Liabilities:
Nonqualified employee savings plans	$	15,161	–	–	15,161	13,904	–	–	13,904	$	15,756	–	–	15,756	16,158	–	–	16,158
Commodity derivative contracts		–	3,226	–	3,226	–	48,864	–	48,864		–	53,444	–	53,444	–	39,093	–	39,093
Foreign currency exchange derivative contracts		–	–	–	–	–	73	–	73
	$	15,161	3,226	–	18,387	13,904	48,937	–	62,841	$	15,756	53,444	–	69,200	16,158	39,093	–	55,251


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



					Deferred
					Loss on
		Foreign	Retirement and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)	Adjustments		Hedges		Total
Balance at December 31, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):			��
Before reclassifications to income		194,094	3		–		194,097
Reclassifications to income		–	7,166	1	1,445	2	8,611
Net other comprehensive income		194,094	7,169		1,445		202,708
Balance at September 30, 2017	$	(252,461)	(164,136)		(8,907)		(425,504)


	FORM 10-Q



					Deferred
			Retirement		Loss on
		Foreign	and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)	Adjustments		Hedges		Total
Balance at December 31, 2017	$	(274,830)	(178,987)		(8,426)		(462,243)
2018 components of other comprehensive income (loss):
Before reclassifications to income and retained earnings		(52,275)	(32,159)		(1,815)		(86,249)
Reclassifications to income		–	3,170	1	585	2	3,755
Net other comprehensive income		(52,275)	(28,989)		(1,230)		(82,494)
Balance at March 31, 2018	$	(327,105)	(207,976)		(9,656)		(544,737)




	United
(Millions of dollars)	States		Canada	Malaysia	Other	Total
Three Months Ended September 30, 2017
Oil and gas sales and other operating revenues	$	195.9	81.9	220.5	–	498.3
Lease operating expenses		43.5	28.7	40.6	–	112.8
Severance and ad valorem taxes		10.5	0.3	–	–	10.8
Depreciation, depletion and amortization		128.4	45.9	63.7	1.0	239.0
Accretion of asset retirement obligations		4.3	2.0	4.4	–	10.7
Exploration expenses
Dry holes		(0.6)	–	(2.5)	–	(3.1)
Geological and geophysical		0.1	–	–	1.5	1.6
Other		1.5	0.2	–	7.7	9.4
		1.0	0.2	(2.5)	9.2	7.9
Undeveloped lease amortization		20.4	0.2	–	–	20.6
Total exploration expenses		21.4	0.4	(2.5)	9.2	28.5
Selling and general expenses		16.6	6.9	4.8	5.1	33.4
Other expenses		0.8	0.5	1.2	–	2.5
Results of operations before taxes		(29.6)	(2.8)	108.3	(15.3)	60.6
Income tax provisions (benefits)		(9.7)	0.4	40.6	(4.3)	27.0
Results of operations (excluding corporate overhead and interest)	$	(19.9)	(3.2)	67.7	(11.0)	33.6


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




			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic*	Malaysia	Other	Total
Nine Months Ended September 30, 2017
Oil and gas sales and other operating revenues	$	696.7	388.1	–	594.4	–	1,679.2
Lease operating expenses		135.7	76.8	–	133.6	–	346.1
Severance and ad valorem taxes		31.6	1.2	–	–	–	32.8
Depreciation, depletion and amortization		402.3	136.6	–	160.0	2.9	701.8
Accretion of asset retirement obligations		12.8	5.9	–	12.9	–	31.6
Exploration expenses
Dry holes		(1.9)	–	–	0.8	–	(1.1)
Geological and geophysical		1.0	0.1	–	–	6.0	7.1
Other		5.5	0.3	–	–	24.8	30.6
		4.6	0.4	–	0.8	30.8	36.6
Undeveloped lease amortization		39.4	1.4	–	–	–	40.8
Total exploration expenses		44.0	1.8	–	0.8	30.8	77.4
Selling and general expenses		48.7	21.2	–	10.5	15.0	95.4
Other expenses		1.5	0.4	–	9.1	–	11.0
Results of operations before taxes		20.1	144.2	–	267.5	(48.7)	383.1
Income tax provisions (benefits)		9.1	41.6	–	93.6	(37.8)	106.5
Results of operations (excluding corporate overhead and interest)	$	11.0	102.6	–	173.9	(10.9)	276.6


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)


	MURPHYOILCORPORATION
	(Registrant)

	By	/s/ CHRISTOPHER D. HULSE
		Christopher D. Hulse,
		Vice President and Controller
		(Chief Accounting Officer and Duly Authorized Officer)



Exhibit
No.

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