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Filed Pursuant to Rule 424(b)(5)
Registration No. 333-207463

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Amount to be Registered		Aggregate Offering Price		Registration Fee(1)
6.875% Notes Due 2024		$550,000,000		100.000%		$55,385

 

(1)	Calculated in accordance with Rule 457(r) of the Securities Act of 1933.

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Final Prospectus Supplement

(To Prospectus dated October 16, 2015)

 

$550,000,000 6.875% Notes Due 2024    

We are offering $550,000,000 aggregate principal amount of 6.875% notes due 2024 (the “notes”). The notes will bear interest at the rate of 6.875% per year, payable semiannually in arrears on February 15 and August 15 of each year, commencing February 15, 2017. The notes will mature on August 15, 2024.

At any time prior to August 15, 2019, we may redeem the notes, in whole or in part, at a price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed or (ii) a make-whole redemption price determined by using a discount rate of the applicable treasury rate plus 50 basis points, plus in each case, accrued and unpaid interest on the principal amount of the notes being redeemed to, but not including, the redemption date. At any time on or after August 15, 2019, we may redeem the notes, in whole or in part, at the applicable redemption prices set forth under “Description of the notes—Optional Redemption”, plus accrued and unpaid interest on the principal amount of the notes being redeemed to, but not including, the redemption date.

The notes will be senior unsecured obligations of Murphy Oil Corporation and will rank equally with all of Murphy Oil Corporation’s other senior unsecured indebtedness from time to time outstanding.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

See “Risk factors” beginning on page S-17 for a discussion of certain risks that you should consider in connection with making an investment in the notes.

The notes will be a new issue of securities and currently there is no established trading market for the notes. We do not intend to list the notes on any securities exchange or any automated dealer quotation system.

 

		Price to public(1)				Underwriting discount				Proceeds to us, before expenses
Per note			100.000	%			1.500	%			98.500	%
Total		$	550,000,000			$	8,250,000			$	541,750,000

(1)

Plus accrued interest from August 17, 2016 if settlement occurs after that date.

The notes will be issued only in registered book-entry form, in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The underwriters expect to deliver the notes to purchasers through the facilities of The Depository Trust Company for the benefit of its participants, including Euroclear Bank S.A./N.V. and Clearstream Banking, société anonyme, on or about August 17, 2016.

Joint Physical Book-Running Managers

 

J.P. Morgan		BofA Merrill Lynch

 

 

Joint Book-Running Managers

 

BNP PARIBAS		DNB Markets

 

Scotiabank		MUFG

 

Wells Fargo Securities		Goldman, Sachs & Co.

 

 

Co-Managers

 

Regions Securities LLC		Capital One Securities

August 12, 2016

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We have not, and the underwriters have not, authorized anyone to provide any information other than that contained or incorporated by reference in this prospectus supplement, the accompanying prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We do not, and the underwriters do not, take any responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you.

We are not, and the underwriters are not, making an offer of these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information provided by this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this prospectus supplement or, with respect to information incorporated by reference, as of the date of that information. Our business, financial condition, results of operations and prospects may have changed since those respective dates.

 

 

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		Page
Prospectus supplement
About this prospectus			S-ii
Where you can find more information			S-ii
Forward-looking statements			S-iii
Summary			S-1
Risk factors			S-17
Use of proceeds			S-26
Capitalization			S-27
Management’s discussion and analysis of financial condition and results of operations			S-28
Business and properties			S-66
Description of other indebtedness			S-79
Description of the notes			S-81
Material U.S. federal income tax considerations for Non-U.S. Holders			S-97
Underwriting			S-100
Legal matters			S-104
Experts			S-104

 

		Page
Prospectus
About this Prospectus			2
Murphy Oil Corporation			2
Where You Can Find More Information			3
Special Note on Forward-Looking Statements			3
Ratio of Earnings to Fixed Charges			4
Use of Proceeds			4
Description of Common Stock			5
Description of Preferred Stock			7
Description of Depositary Shares			8
Description of Debt Securities			10
Description of Warrants			19
Description of Purchase Contracts			20
Description of Units			21
Forms of Securities			22
Plan of Distribution			23
Validity of Securities			23
Experts			23

 

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About this prospectus

This document has two parts. The first part consists of this prospectus supplement, which describes the specific terms of this offering and the notes offered. The second part is the accompanying prospectus, dated October 16, 2015, which provides more general information, some of which may not apply to this offering. If the description of the offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

In this prospectus supplement, we refer to Murphy Oil Corporation and its wholly owned subsidiaries as “we,” “our,” “us,” “the Company,” “Murphy Oil” or “Murphy” unless the context clearly indicates otherwise.

Before purchasing any notes, you should carefully read both this prospectus supplement and the accompanying prospectus, together with the additional information in the documents we have listed under the heading “Where you can find more information.”

Where you can find more information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC”). You may read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room. Our SEC filings are also available to the public at the SEC’s web site at http://www.sec.gov.

The SEC allows us to “incorporate by reference” into this prospectus supplement the information we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference or deemed incorporated by reference is considered to be a part of this prospectus supplement. Information that we file with the SEC after the date of this prospectus supplement will update and supersede this information. We incorporate by reference the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14, or 15(d) of the Securities Exchange Act of 1934, as amended, until our offering is completed:

 

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Our Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 26, 2016;

 

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Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, filed on May 6, 2016 and June 30, 2016, filed on August 4, 2016;

 

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Our Definitive Proxy Statement on Schedule 14A filed on March 28, 2016 (solely to the extent incorporated by reference into Part III of our Annual Report on Form 10-K); and

 

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Our Current Reports on Form 8-K filed on January 28, 2016 (excluding Item 2.02), February 5, 2016, May 2, 2016, May 12, 2016, May 16, 2016, June 27, 2016, August 4, 2016, August 10, 2016 and August 12, 2016.

You may request a free copy of these filings by writing to, or telephoning, us at the following address and phone number:

Corporate Secretary

Murphy Oil Corporation

P.O. Box 7000

El Dorado, Arkansas 71731-7000

(870) 862-6411

 

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Forward-looking statements

This prospectus supplement and the accompanying prospectus, including the documents we incorporate by reference, 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, as well as those contained under the caption “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015. We undertake no duty to publicly update or revise any forward-looking statements.

 

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Risk factors

Investing in the notes involves risks. You should carefully consider all the information set forth in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference herein and therein before deciding to invest in the notes. In particular, we urge you to carefully consider the risk factors set forth below as well as those under the heading “Risk Factors” in our Annual Report on Form 10-K for fiscal year ended December 31, 2015.

Risks relating to our business

Current low oil prices may adversely affect the Company’s operations in several ways in the future.

As noted elsewhere in this prospectus supplement, crude oil prices were significantly weaker in 2015 than in prior years. Oil prices have continued to slide into early 2016. These low oil prices have adversely affected the company in several ways, and could continue to do so in 2016 as noted below:

 

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The lower sales value for the Company’s oil production has hurt cash flows and net income. The current low commodity prices are expected to continue this trend into 2016.

 

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Lower cash flows have caused the Company to reduce its capital expenditure program, thereby potentially hampering its ability to grow production and add proved reserves. The Company may be forced to continue to reduce its capital expenditures to balance its cash positions going forward.

 

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Lower expected future oil prices led to significant impairment expenses in 2015. Further reductions for future oil prices in 2016 could lead to more impairment charges, some of which could be significant.

 

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Low oil prices could lead to reductions in the Company’s proved reserves in 2016. Low prices could make certain of the Company’s proved reserves uneconomic, which in turn could lead to removal of certain of the Company’s 2015 year-end reported proved oil reserves in future periods. These reserve reductions could be significant.

 

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Major credit rating agencies have initiated or completed credit reviews of many oil and gas companies, including Murphy Oil. The low oil prices have hurt oil companies financial metrics, and the credit rating agencies tend to lower credit ratings during such periods of low commodity prices. In addition, banks and other suppliers of financing capital may reduce their lending limits to oil companies due to weak oil prices. At December 31, 2015, Murphy’s long-term debt was rated “BBB” with a negative outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a negative outlook by Moody’s Investor Services (Moody’s). In February 2016, S&P, Fitch, and Moody’s each downgraded the Company’s credit rating on its outstanding notes. The Company’s long-term debt ratings are currently “BBB-” with stable outlook by S&P, “BB+” with stable outlook by Fitch, and “B1” with negative outlook by Moody’s. Fitch’s and Moody’s actions reduced the Company’s credit rating to below investment grade status. These downgrades could adversely affect our cost of capital and our ability to raise debt in public markets in future periods.

Certain of these effects are further discussed in risk factors that follow.

Murphy Oil’s businesses operate in highly competitive environments, which could adversely affect it in many ways, including its profitability, its ability to grow, and its ability to manage its businesses.

Murphy operates in the oil and gas industry and experiences intense competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, and independent producers of oil and natural gas. Virtually all of the state-owned and major integrated oil companies and many of the independent producers that compete with the Company have substantially greater resources than

 

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Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.

If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.

Murphy continually depletes its oil and natural gas reserves as production occurs. In order to sustain and grow its business, the Company must successfully replace the crude oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production by obtaining rights to explore for, develop and produce hydrocarbons in promising areas. In addition, it must find, develop and produce and/or purchase reserves at a competitive cost structure to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production segments of its business, therefore, is dependent on its ability to find, develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products and at costs competitive with competing companies in the industry.

Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.

Proved reserves of crude oil, natural gas liquids (NGL) and natural gas included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus have been prepared by qualified Company personnel or qualified independent engineers based on an unweighted average of crude oil, NGL and natural gas prices in effect at the beginning of each month of the respective year as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs. Estimates of economically recoverable crude oil, NGL and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. Under existing SEC rules, reported proved reserves must be reasonably certain of recovery in future periods.

Murphy’s actual future oil and natural gas production may vary substantially from its reported quantity of proved reserves due to a number of factors, including:

 

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Oil and natural gas prices which are materially different than prices used to compute proved reserves

 

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Operating and/or capital costs which are materially different than those assumed to compute proved reserves

 

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Future reservoir performance which is materially different from models used to compute proved reserves, and

 

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Governmental regulations or actions which materially change operations of a field.

The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2015, approximately 28% of the Company’s crude oil proved reserves, 41% of natural gas liquids proved reserves and 54% of natural gas proved reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.

The discounted future net revenues from our proved reserves as reported and incorporated by reference in this prospectus supplement and the accompanying prospectus should not be considered as the market value of the

 

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reserves attributable to our properties. As required by GAAP, the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations.

In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas business in general.

Volatility in the global prices of crude oil, natural gas liquids and natural gas significantly affects the Company’s operating results.

Among the most significant variables affecting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces. West Texas Intermediate (WTI) crude oil prices averaged about $49 per barrel in 2015, compared to $93 per barrel in 2014 and $98 per barrel in 2013. The closing price for WTI at the end of 2015 was approximately $37 per barrel. As demonstrated by the significant decline in WTI crude oil prices in late 2014 and 2015, prices can be quite volatile. The average NYMEX natural gas sales price was $2.61 per thousand cubic feet (MCF) in 2015, down from $4.34 per MCF in 2014 and $3.73 per MCF in 2013. The closing price for NYMEX natural gas trades as of December 31, 2015, was $2.34 per MCF. As demonstrated in 2013 through 2015, the sales prices for crude oil and natural gas can be significantly different in U.S. markets compared to markets in foreign locations. A small percentage of the Company’s crude oil production is heavy and more sour than WTI quality crude; therefore, this crude oil usually sells at a discount to WTI and other light and sweet crude oils. In addition, the sales prices for heavy and sour crude oils do not always move in relation to price changes for WTI and lighter/sweeter crude oils. Certain crude oils produced by the Company, including certain U.S. and Canadian crude oils and all crude oil produced in Malaysia, generally price off of oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the U.S. WTI prices. The most common crude oil indices used to price the Company’s crude include Louisiana Light Sweet (LLS), Brent and Malaysian crude oil indices. Certain natural gas production offshore Sarawak have been sold in recent years at a premium to average North American natural gas prices due to pricing structures built into the sales contracts. Associated natural gas produced at fields in Block K offshore Sabah are sold at heavily discounted prices compared to North American gas prices as stipulated in the sales contract. The Company cannot predict how changes in the sales prices of oil and natural gas will affect its results of operations in future periods. The Company often seeks to hedge a portion of its exposure to the effects of changing prices of crude oil and natural gas by purchasing forwards, swaps and other forms of derivative contracts.

Exploration drilling results can significantly affect the Company’s operating results.

The Company drills exploratory wells each year which subjects its exploration and production operating results to significant exposure to dry holes expense, which may have adverse effects on, and create volatility for, the Company’s results of operations. In 2015, wildcat wells were primarily drilled offshore Australia, Malaysia and in the Gulf of Mexico. The Company’s 2016 planned exploratory drilling program includes only commitment wells in Block SK 314A in Malaysia and Blocks 11-21/11 and 15-1/05 in Vietnam.

Potential federal or state regulations could increase the Company’s costs and/or restrict operating methods, which could adversely affect its production levels.

The Company uses a technique known as hydraulic fracturing whereby water, sand and certain chemicals are injected into deep oil and gas bearing reservoirs in North America. This process creates fractures in the rock formation within the reservoir which enables oil and natural gas to migrate to the wellbore. The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada. This practice is generally regulated by the states, but at times the U.S. has proposed additional regulation under the Safe

 

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Drinking Water Act. In June 2011, the State of Texas adopted a law requiring public disclosure of certain information regarding the components used in the hydraulic fracturing process. The Provinces of British Columbia and Alberta have also issued regulations related to hydraulic fracturing activities under their jurisdictions. It is possible that the states, the U.S., Canadian provinces and certain municipalities adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected or its costs of drilling and completion could be increased.

In April 2016, the U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE) announced final rules providing for broad regulatory changes related to well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items known broadly as the Well Control Rule. The rules will require compliance over the next several years and could significantly increase the Company’s future costs in the U.S. Gulf of Mexico.

Hydraulic fracturing exposes the Company to operational and regulatory risks and third party claims.

Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas. These risks include underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or ground water contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water. Any diminished access to water for use in the process could curtail the Company’s operations or otherwise result in operational delays or increased costs.

Capital financing may not always be available to fund Murphy’s activities.

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding needs may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices such as those experienced in 2015 and early 2016. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company must periodically renew these financing arrangements based on foreseeable financing needs or as they expire. The Company’s existing bank financing facility has a capacity of $630 million and matures in June 2017. On August 10, 2016, the Company entered into a new revolving credit facility, with aggregate commitments of $1.2 billion and a maturity in 2019. Consummation of this offering is a condition precedent to the availability of the new revolving credit facility. In addition, the Company amended its existing revolving credit facility to reduce the commitments of the exiting lenders that have committed to the new revolving credit facility and allowed for the incurrence of the new revolving credit facility. There is the possibility that financing arrangements may not always be available at sufficient levels required to fund the Company’s activities in future periods. On February 18, 2016, Moody’s Investor Services downgraded the Company’s senior unsecured notes to a “B1” rating, effectively reducing the Company’s credit to below investment grade status. The ability of the Company to obtain future debt financing may be adversely affected by this credit rating downgrade. Also, in February, Fitch Rating downgraded the Company’s notes to below investment grade. These downgrades could adversely affect our cost of capital and our ability to raise debt as needed in public markets in future periods. Additionally, in order to obtain debt financing in future years, the Company may have to provide more security to its lenders.

 

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Additionally, should low oil and gas prices continue in 2016 and 2017, the ability of the Company to repay or refinance its $550 million note that matures in December 2017 may be adversely impacted. The Company 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. Although not considered likely, the Company may not be able in the future to sell notes in the marketplace.

Murphy has limited or virtually no control over several factors that could adversely affect the Company.

The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, natural gas liquids and natural gas, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products. Changes in commodity prices also impact the volume of production attributed to the Company under production sharing contracts in Malaysia. Economic slowdowns, such as those experienced in 2008 and 2009, had a detrimental effect on the worldwide demand for these energy commodities, which effectively led to reduced prices for oil and natural gas for a period of time. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. Lower prices for crude oil and natural gas inevitably lead to lower earnings for the Company. The Company also often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry. The current low crude oil price environment in 2015 and early 2016 has caused the Company to reduce discretionary drilling programs, which in turn, hurts the Company’s future production levels and future cash flow generated from operations.

Many of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its significant revenue generating properties. During 2015, approximately 15% of the Company’s total production was at fields operated by others, while at December 31, 2015, approximately 22% of the Company’s total proved reserves were at fields operated by others.

Murphy’s operations and earnings have been and will continue to be affected by worldwide political developments.

Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production. As of December 31, 2015, approximately 21% of the Company’s proved reserves, as defined by the U.S. Securities and Exchange Commission, were located in countries other than the U.S. and Canada. Certain of the reserves held outside these two countries could be considered to have more political risk. In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Governments could also initiate regulations concerning matters such as currency fluctuations, protection and remediation of the environment, and concerns over the possibility of global warming or other climate change being affected by human activity including the production and use of hydrocarbon energy. Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act, the Canada Corruption of Foreign Officials Act, the Malaysia Anti-Corruption Commission Act, the U.K. Bribery Act, and similar anti-corruption compliance statutes. Because these and other factors too numerous to list are subject to changes caused by governmental and political considerations and are often made in response to

 

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changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

Murphy’s business is subject to operational hazards, security risks and risks normally associated with the exploration for and production of oil and natural gas.

The Company operates in urban and remote, and often inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes and other forms of severe weather, and mechanical equipment failures, industrial accidents, fires, explosions, acts of war, civil unrest, piracy and acts of terrorism could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, personal injury, including death, and property damages for which the Company could be deemed to be liable, and which could subject the Company to substantial fines and/or claims for punitive damages.

The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms. A number of significant oil and natural gas fields lie in offshore waters around the world. Probably the most vulnerable of the Company’s offshore fields are in the U.S. Gulf of Mexico, where severe hurricanes and tropical storms have often led to shutdowns and damages. The U.S. hurricane season runs from June through November. Although the Company maintains insurance for such risks as described elsewhere in this prospectus supplement, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.

In addition, the Company has risks associated with cybersecurity attacks. Although the Company maintains processes and systems to monitor and avoid damages from security threats, there can be no assurance that such processes and systems will successfully avert such security breaches. A successful breach could lead to system disruptions, loss of data or unauthorized release of highly sensitive data. This could lead to property or environmental damages and could have an adverse effect on the Company’s revenues and costs.

Murphy’s insurance may not be adequate to offset costs associated with certain events and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.

Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $500 million per occurrence and in the annual aggregate. Generally, this insurance covers various types of third party claims related to personal injury, death and property damage, including claims arising from “sudden and accidental” pollution events. The Company also maintains insurance coverage with an additional limit of $400 million per occurrence ($850 million for Gulf of Mexico operations not related to a named windstorm), all or part of which could be applicable to certain sudden and accidental pollution events. These policies have deductibles ranging from $10 to $25 million. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.

Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.

The Company is involved in numerous lawsuits seeking cash settlements for alleged personal injuries, property damages and other business-related matters. Certain of these lawsuits will take many years to resolve through court proceedings or negotiated settlements. None of these lawsuits are considered individually material or aggregate to a material amount in the opinion of management.

 

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The Company is exposed to credit risks associated with sales of certain of its products to third parties.

Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers. For certain oil and gas properties operated by the Company, other companies which own partial interests may not be able to meet their financial obligation to pay for their share of capital and operating costs as they come due. The inability of a purchaser of the Company’s oil or natural gas or a partner of the Company to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.

Murphy’s operations could be adversely affected by changes in foreign currency conversion rates.

The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, therefore, the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations and the British pound is the functional currency for most remaining U.K. discontinued operations. In certain countries, such as Canada, Malaysia and the United Kingdom, significant levels of transactions occur in currencies other than the functional currency. In Malaysia, such transactions include tax payments, while in Canada, certain crude oil sales are priced in U.S. dollars. This exposure to currencies other than the functional currency can lead to significant impacts on consolidated financial results. Exposures associated with current and deferred income tax liability balances in Malaysia are generally not hedged. A strengthening of the Malaysian ringgit against the U.S. dollar would be expected to lead to currency losses in consolidated operations; gains would be expected if the ringgit weakens versus the dollar. Foreign exchange exposures between the U.S. dollar and the British pound are not hedged. The Company would generally expect to incur currency losses when the U.S. dollar strengthens against the British pound and would conversely expect currency gains when the U.S. dollar weakens against the pound. In Canada, currency risk is often managed by selling forward U.S. dollars to match the collection dates for crude oil sold in that currency. See Note L in the audited consolidated financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus for additional information on derivative contracts.

The costs and funding requirements related to the Company’s retirement plans are affected by several factors.

The costs and funding requirements related to the Company’s retirement plans are affected by several factors. A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its consolidated balance sheet.

Risks relating to the notes

The notes are structurally subordinated to all liabilities of our subsidiaries and all liabilities guaranteed by our subsidiaries.

The notes are structurally subordinated to all liabilities of our subsidiaries and all liabilities guaranteed by our subsidiaries, including without limitation, their debt and trade payables and our revolving credit facilities. As of June 30, 2016, after giving effect to our new revolving credit facility, the amendment of our existing revolving credit facility and the guarantee of our obligations under our existing revolving credit facility by certain of our material subsidiaries, which will not guarantee the notes, we would have had approximately $178.6 million of issued and undrawn letters of credit outstanding, all of which would have been structurally senior to the notes. Additionally, as of June 30, 2016 our subsidiaries had approximately $798.1 million in indebtedness,

 

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trade payables and other accrued current liabilities outstanding, all of which would rank structurally senior to the notes. None of our subsidiaries has guaranteed or otherwise become obligated with respect to the notes. Our right to receive assets from any of our subsidiaries upon its liquidation or reorganization, and the right of the holders of the notes to participate in those assets, is structurally subordinated to claims of that subsidiary’s creditors. We and our subsidiaries will be permitted under the terms of the indenture governing the notes to incur certain additional indebtedness or otherwise enter into agreements that may restrict or prohibit subsidiaries of ours from the making of distributions, the payment of dividends or the making of loans to us. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that subsidiary and any debt of that subsidiary senior to that held by us, and our rights could otherwise be subordinated to the rights of other creditors of that subsidiary. Furthermore, we are a holding company and currently conduct substantially all of our operations through our subsidiaries, and our subsidiaries generate substantially all of our operating income and cash flow. As a result, distributions or advances from our subsidiaries are the principal source of the funds we use to meet our debt service obligations. None of our subsidiaries is under any obligation to make payments to us, and any payments to us would depend on the earnings or financial condition of our subsidiaries and various business considerations. Contractual or other legal restrictions may also limit our subsidiaries’ ability to pay dividends or make distributions, loans or advances to us. For these reasons, we may not have access to any assets or cash flows of our subsidiaries to make interest and principal payments on the notes.

Changes in our credit ratings may adversely affect your investment in the notes.

The credit ratings of our indebtedness are an assessment by rating agencies of our ability to pay our debts when due. These ratings are not recommendations to purchase, hold or sell the notes, inasmuch as the ratings do not comment as to market price or suitability for a particular investor, are limited in scope, and do not address all material risks relating to an investment in the notes, but rather reflect only the view of each rating agency at the time the rating is issued. The ratings are based on current information furnished to the ratings agencies by us and information obtained by the ratings agencies from other sources. An explanation of the significance of such rating may be obtained from such rating agency. There can be no assurance that such credit ratings will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant. Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could affect the market value and liquidity of the notes and increase our borrowing costs.

Despite our current level of indebtedness, we and our subsidiaries may still be able to incur substantially more debt.

We and our subsidiaries may be able to incur substantial additional indebtedness, including additional notes and secured indebtedness, in the future. The indenture governing the notes will not prohibit us from incurring additional indebtedness that is not secured or guaranteed by our subsidiaries. Further, the indenture governing the notes will not fully prohibit our subsidiaries from incurring additional indebtedness or prohibit us or our subsidiaries from incurring secured indebtedness, and any limitations will be subject to a number of significant qualifications and exceptions. Additionally, the indenture governing the notes will not prevent us or our subsidiaries from incurring obligations that do not constitute indebtedness under the indenture.

The notes will be effectively junior to all of our secured indebtedness unless they are entitled to be equally and ratably secured.

The notes will be our senior unsecured obligations and will rank equally with all our other senior unsecured indebtedness. The notes will be effectively subordinated to any secured debt we may incur in the future to the

 

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extent of the value of the assets securing such debt. Although the indenture governing the notes will limit our ability to incur secured debt, any limitations will be subject to a number of significant qualifications and exceptions. If we default on the notes, become bankrupt, liquidate or reorganize, any secured creditors could use our assets securing their debt to satisfy their secured debt before you would receive any payment on the notes. If the value of the collateral is not sufficient to pay any secured debt in full, our secured creditors would share the value of our other assets, if any, with you and the holders of other claims against us that rank equally with the notes. As of June 30, 2016, we had approximately $2.44 billion of consolidated indebtedness outstanding, none of which was secured. Under the terns of our new revolving credit facility, if the total leverage ratio falls below a ratio to be agreed, we will be obligated to provide, subject to certain exceptions, a pledge of substantially all of our tangible and intangible assets, as well as the tangible and intangible assets of the guarantors thereunder.

We may be unable to purchase the notes upon a change of control triggering event.

The terms of the notes will require us to make an offer to repurchase the notes upon the occurrence of a change of control triggering event at a purchase price equal to 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the repurchase. The occurrence of a change of control triggering event would cause an event of default under our revolving credit facility and therefore could cause us to have to repay amounts outstanding thereunder, and any financing arrangements we may enter into in the future may also require repayment of amounts outstanding in the event of a change of control triggering event and therefore limit our ability to fund the repurchase of your notes pursuant to the change of control offer. It is possible that we will not have sufficient funds, or be able to arrange for additional financing, at the time of the change of control triggering event to make the required repurchase of notes. If we have insufficient funds to repurchase all notes that holders tender for purchase pursuant to the change of control offer, and we are unable to raise additional capital, an event of default would occur under the indenture. An event of default could cause any other debt that we may have at that time to become automatically due, further exacerbating our financial condition and diminishing the value and liquidity of the notes. We cannot assure you that additional capital would be available to us on acceptable terms, or at all. See “Description of the notes—Repurchase upon a change of control triggering event.”

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The notes are a new issue of securities for which there is no established trading market. The underwriters have advised us that they intend to make a market in the notes, as permitted by applicable laws and regulations; however, the underwriters are not obligated to make a market in the notes and they may discontinue their market-making activities at any time without notice. Therefore, an active market for the notes may not develop or, if developed, may not continue. The liquidity of any market for the notes will depend upon, among other things, the number of holders of the notes, our performance, the market for similar securities, the interest of securities dealers in making a market in the notes and other factors. If a market develops, the notes could trade at prices that may be lower than the initial offering prices of the notes.

 

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Use of proceeds

We expect the net proceeds from this offering of notes to be approximately $541.0 million, after deducting underwriting discounts and other estimated expenses of the offering. We intend to use the net proceeds of this offering for general corporate purposes, which may include repayment, repurchase or redemption of our 2.5% notes due 2017. See “Underwriting” beginning on page S-100.

 

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Capitalization

We have provided in the table below our unaudited consolidated capitalization as of June 30, 2016, and as adjusted to give effect to the issuance of the notes offered hereby and the use of proceeds therefrom for general corporate purposes.

 

		As of June 30, 2016
(unaudited) (in thousands)		Actual				As Adjusted
Cash and cash equivalents		$	267,483			$	808,433
Long-term debt:
2.50% Notes, due 2017			550,000				550,000
4.00% Notes, due 2022			500,000				500,000
3.70% Notes, due 2022			600,000				600,000
6.875% Notes, due 2024 offered hereby			—				550,000
7.05% Notes, due 2029			250,000				250,000
5.125% Notes, due 2042			350,000				350,000
Notes payable to banks, 1.89% at June 30, 2016			—				—
Unamortized discount on Notes payable			(17,174	)			(26,224	)
Revolving Credit Facilities(1)			—				—
Capital Lease Obligation			202,660				202,660
Total long-term debt (excluding current maturities)		$	2,435,486			$	2,976,436
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			195,056				195,056
Capital in excess of par value			914,236				914,236
Retained earnings			5,895,794				5,895,794
Accumulated other comprehensive income			(536,659	)			(536,659	)
Treasury stock, 22,856,616 shares of Common Stock , at cost			(1,296,734	)			(1,296,734	)
Total stockholders’ equity		$	5,171,693			$	5,171,693
Total capitalization (long-term debt and stockholders’ equity)		$	7,607,179			$	8,148,129

 

 

(1)

Currently, our existing revolving credit facility has commitments in an aggregate amount of $630 million, none of which were drawn as of June 30, 2016. On August 10, 2016, we entered into the New Revolving Facility which has aggregate commitments of $1.2 billion. On August 10, 2016 we also entered into an amendment of our existing revolving credit facility to reduce the commitments of the exiting lenders that have committed to the New Revolving Credit Facility and allow for the incurrence of the New Revolving Credit Facility.

 

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Management’s discussion and analysis of financial condition and results of operations

Management’s discussion and analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the combined financial statements and notes included in this prospectus supplement. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under “Forward-looking statements” and “Risk factors” included elsewhere in this prospectus supplement.

Overview

Murphy Oil Corporation is a worldwide oil and gas exploration and production company. Significant Company operating and financial highlights during 2015 were as follows:

 

•

Completed the sale of 10% of its interest in Malaysia assets for a price of $417.2 million. The Company recorded an after-tax gain of $218.8 million on the sale. Total proceeds received from the 30% sale over 2015 and 2014 totaled $1.87 billion after post closing adjustments.

 

•

Produced 208,000 barrels of oil equivalent per day.

 

•

Ended 2015 with proved reserves, totaling 774.0 million barrels of oil equivalent, and replaced proved reserves equal to 123% of production on a barrel of oil equivalent basis during the year, including the 10% Malaysia sell-down in 2015.

 

•

Reduced lease operating expense per barrel oil equivalent by 18 percent year-over-year.

 

•

Lowered G&A expense by approximately 16 percent year-over-year.

 

•

Completed the sale of U.K. downstream operations.

The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in the second quarter of 2015 for cash proceeds of $5.5 million. The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented.

On August 30, 2013, the Company completed the separation of its former U.S. retail marketing business by distributing all common shares of this business to Murphy Oil’s shareholders.

Both the U.S. and U.K. downstream businesses are reported as discontinued operations within the Company’s consolidated financial statements. Additionally, the Company includes U.K. oil and gas operations, which were sold in a series of transactions in the first half of 2013, as discontinued operations.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States, Canada and Malaysia and then selling these products to customers. The Company’s revenue is highly affected by the prices of crude oil, natural gas and NGL. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced

 

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must exceed the combined costs of producing these products, depreciation of capital expenditures, and expenses related to exploration, administration, and for capital borrowed from lending institutions and note holders.

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company, especially the price of crude oil as oil represented 61% of total hydrocarbons produced on an energy equivalent basis (one barrel of crude oil equals six thousand cubic feet of natural gas) in 2015. In 2016, the Company’s ratio of hydrocarbon production represented by oil is expected to be essentially the same as 2015. When oil-price linked natural gas in Malaysia is combined with oil production, the Company’s 2016 total expected production is approximately 70% linked to the price of oil. If the prices for crude oil and natural gas remains weak in 2016 or beyond, this will have an unfavorable impact on the Company’s operating profits. As described on page S-29, the Company has entered into fixed price derivative swap contracts in the United States that will reduce its exposure to changes in crude oil prices for approximately 42% of its 2016 U.S. oil production and holds forward delivery contracts that will reduce its exposure to changes in natural gas prices for approximately 28% of the natural gas it expects to produce in Western Canada in 2016.

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

Oil prices and North American natural gas prices weakened in 2015 compared to the 2014 period. The sales price for a barrel of West Texas Intermediate (WTI) crude oil averaged $48.80 in 2015, $93.00 in 2014 and $98.00 in 2013. The sales price for a barrel of Platts Dated Brent crude oil declined to $52.46 per barrel in 2015, following averages of $99.00 per barrel and $108.66 per barrel in 2014 and 2013, respectively. Both the WTI index and Dated Brent experienced a 47% decrease in 2015. During 2015 the discount for WTI crude compared to Dated Brent narrowed compared to the two prior years. The WTI to Dated Brent discount was $3.66 per barrel during 2015, compared to $6.00 per barrel in 2014 and $10.61 per barrel in 2013. In early 2016, Dated Brent has been trading near par or at a slight discount to WTI. Worldwide oil prices began to weaken in the fall of 2014 and continued to soften throughout 2015.

The softening of prices beginning in late 2014 and continuing into 2015 caused average oil prices for both 2015 and 2014 periods to be below the average levels achieved in 2013. The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $2.61 in 2015, $4.33 in 2014 and $3.73 in 2013. NYMEX natural gas prices in 2015 were 40% below the average price in 2014, with the price decrease generally caused by domestic production elevating inventories to record levels and a much warmer than normal fourth quarter reducing residential demand. NYMEX natural gas prices in 2014 were 16% above the average price experienced in 2013, with the price increase generally caused by colder average winter season temperatures in North America in the later year. On an energy equivalent basis, the market continued to discount North American natural gas and NGL compared to crude oil in 2015. Crude oil prices in early 2016 have been significantly below the 2015 average prices, and natural gas prices in North America in 2016 have thus far been below the 2015 levels due to excess supply partially due to warmer than normal temperatures across much of the Northern U.S. during the early winter season of 2015-2016.

On June 23, 2016, the Company’s Canadian subsidiary, Murphy Oil Company Ltd., closed the sale of its 5% non-operated working interest in Syncrude Canada Ltd. to Suncor Energy Inc. The transaction was previously announced on April 27, 2016, with an effective date of April 1, 2016. This non-core asset divestiture positively impacted corporate liquidity by increasing net cash on the balance sheet by $739.1 million before-tax.

 

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Results of Operations

Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the six months ended June 30, 2016 and 2015 and the last three years ended December 31 are presented in the following table.

 

		Six Months Ended June 30,								Years Ended December 31,
(Millions of dollars, except EPS)		2016				2015				2015				2014				2013
Net income (loss)		$	(195.9	)		$	(88.3	)		$	(2,270.8	)			905.6				1,123.5
Diluted EPS			(1.14	)			(0.50	)			(13.03	)			5.03				5.94
Income (loss) from continuing operations		$	(196.6	)		$	(85.5	)		$	(2,255.8	)			1,025.0				888.1
Diluted EPS			(1.14	)			(0.48	)			(12.94	)			5.69				4.69
Income (loss) from discontinued operations		$	0.7			$	(2.8	)		$	(15.0	)			(119.4	)			235.4
Diluted EPS			—				(0.02	)			(0.09	)			(0.66	)			1.25

Murphy Oil’s net loss in 2015 was primarily caused by impairment expense to reduce the carrying value of certain properties in the Gulf of Mexico, Western Canada and Malaysia, lower realized sales prices for oil and natural gas, lower oil and natural gas sales volumes, and the costs of exiting deepwater rig contracts in the Gulf of Mexico. Results of continuing operations in 2015 were $3,280.8 million worse than 2014 and included a $218.8 million after- tax gain on sale of 10% of the Company’s oil and gas assets in Malaysia. Results in 2014 included a $321.4 million after-tax gain on sale of 20% of the Company’s oil and gas assets in Malaysia. Excluding this gain in Malaysia from both years, results from continuing operations in 2015 were $3,178.2 million below the prior year, primarily due to the reasons mentioned above. In 2015 and 2014, the Company’s U.K. refining and marketing operations generated losses of $14.8 million and $120.6 million, respectively, which led to overall losses from discontinued operations in each year.

The Company’s net income in 2014 was 19% lower than 2013, primarily due to an unfavorable variance in the results of discontinued operations between years. In August 2013, the Company distributed to its shareholders through a spin-off transaction all of the U.S. retail marketing operations. This business generated after-tax income of $134.8 million in 2013. Additionally, in early 2013, the Company sold all of its U.K. oil and gas assets, which including a gain on the disposal, generated income of $219.8 million in 2013. In 2014 and 2013, the Company’s U.K. refining and marketing operations generated losses of $120.6 million and $119.2 million, respectively. Income from continuing operations in 2014 exceeded 2013 results by 15% and included a $321.4 million after-tax gain on sale of 20% of the Company’s oil and gas assets in Malaysia. Excluding this gain in Malaysia, profits from continuing operations in 2014 were $184.5 million below the prior year, primarily due to lower average realized oil sales prices during 2014 compared to 2013.

Six months ended June 30, 2016 versus six months ended June 30, 2015

For the first six months of 2016, net loss totaled $195.9 million ($1.14 per diluted share) compared to a net loss of $88.3 million ($0.50 per diluted share) for the same period in 2015. Continuing operations had a loss of $196.6 million ($1.14 per diluted share) in the first six months of 2016, compared to a loss of $85.5 million ($0.48 per diluted share) in the same period of 2015. In the first half of 2016, the Company’s exploration and production operations incurred a loss of $124.4 million compared to a loss of $32.5 million in the same period of 2015. Exploration and production loss in 2016 was higher than the 2015 period primarily due to lower revenues resulting from significantly lower realized oil and natural gas sales prices and lower volume sold, impairment expenses in Canada in 2016 and lower after-tax gains on assets sold. These were partially offset by lower lease operating expenses and production taxes, lower depreciation expense, lower exploration costs and lower expenses for environmental costs. Corporate after-tax costs were $72.2 million in the 2016 period compared to after-tax costs of $53.0 million in the 2015 period as the current period had lower gains for the effects of foreign currency exchange and higher net interest costs, partially offset by lower administrative costs. Net loss

 

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in the first half of 2016 included income from discontinued operations of $0.7 million ($0.00 per diluted share) compared to a loss of $2.8 million ($0.02 per diluted share) in the 2015 period. Discontinued operations in both periods primarily consists of costs related to winding down of all operations in the U.K. The final components of the refining and marketing operations were sold at the end of the second quarter 2015.

2015 versus 2014

Net loss in 2015 totaled $2,270.8 million ($13.03 per diluted share) compared to 2014 net income of $905.6 million ($5.03 per diluted share). Continuing operations results in 2015 were significantly weaker, recording a loss of $2,255.8 million ($12.94 per diluted share), while 2014 had income of $1,025.0 million ($5.69 per diluted share). The 2015 unfavorable variance for results of continuing operations was primarily associated with impairment expense, lower realized sales prices for oil and natural gas, lower oil and natural gas sales volumes, costs of existing deepwater rig contracts in the Gulf of Mexico, a deferred tax charge associated with a distribution from a foreign subsidiary, and lower after-tax gains generated from sale of oil and gas assets in Malaysia, partially offset by higher unrealized gains on crude oil contracts.

Lower oil and gas production volumes and lower costs for services led to lower overall extraction costs in 2015. The 2015 results were also favorably affected by higher foreign exchange gains and lower overall administrative costs. The results of discontinued operations were a loss of $15.0 million ($0.09 per diluted share) in 2015 compared to a loss of $119.4 million ($0.66 per diluted share) in 2014. The prior year’s results for discontinued operations included an impairment charge associated with its Milford Haven, Wales refinery, partially offset by a gain on disposition of the U.K. retail marketing fuel stations in the prior year.

Sales and other operating revenues in 2015 were $2.5 billion below 2014 due to both weaker oil and natural sales prices and lower oil and natural gas sales volumes in 2015 compared to 2014. Average crude oil sales prices and North American natural gas sales prices realized in 2015 fell by 45% and 37%, respectively, compared to the prior year and sales volumes fell by approximately 7% in 2015 on a barrel of oil equivalent basis. Realized oil prices were significantly lower in 2015 due to an oversupply of crude oil available on a worldwide scale. The decrease in sales volumes was mostly attributable to the late 2014 and early 2015 sale of a combined 30% interest in its Malaysia assets nearly offset by growth in the Eagle Ford Shale in South Texas and higher production from the Tupper area in Western Canada.

Gain on sale of assets was $15.3 million higher in 2015, primarily associated with a pretax gain of $155.1 million generated on sale of 10% of the Company’s oil and gas assets in Malaysia compared to $144.8 million gain on sale of 20% in 2014. Interest and other income in 2015 was $43.6 million above 2014 levels primarily due to higher profits realized on changes in foreign exchange rates during 2015. Lease operating expenses declined $257.6 million in 2015 compared to 2014 essentially due to sale of interests in Malaysia, lower service costs, cost saving initiatives and a lower average foreign exchange rate in Canada. Severance and ad valorem taxes decreased by $41.4 million in 2015 primarily due to lower average realized sales prices for oil and natural gas volumes in the United States.

Exploration expenses were $42.7 million less than 2014 primarily due to lower geological and geophysical costs and lower exploration costs in other foreign areas. Selling and general expenses in 2015 decreased by nearly 16% from 2014 as the Company implemented key organizational changes including lowering staffing levels by over 20% from end of the prior year. Depreciation, depletion and amortization expenses fell by $286.4 million due to both lower volume sold and lower per-unit capital amortization rates. Impairment expense associated with asset writedowns increased by $2.4 billion primarily due to the significant decline in current and future oil prices during 2015 resulting in writedowns of assets in the Seal heavy oil field in Western Canada and oil and natural gas fields offshore Malaysia and deepwater Gulf of Mexico. The deepwater rig contract exit costs of $282.0 million are for two deepwater rigs that were under contract in the Gulf of Mexico. These rigs were

 

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stacked before their contract expiration dates and the remaining obligations owed in 2016 under the contracts were expensed in 2015.

Interest expense in 2015 was $11.8 million lower than 2014 due principally to lower average borrowing levels in the 2015 period. Interest costs capitalized decreased by $13.3 million in 2015 due to fewer ongoing development projects in the 2015 period. Other operating expense was $53.7 million higher in 2015 compared to 2014 primarily due to recording estimated costs of remediating a site at the Seal field in a remote area of Alberta. Income tax benefits in 2015 were $1.0 billion compared to expense of $227.3 million in the prior year. The benefits reported in 2015 were the result of large pre-tax losses, a significant portion of which is related to impairments in the 2015 period, no local income taxes owed on the Malaysia sale, and deferred tax benefit on the sale due to the purchaser assuming certain future tax payment obligations, offset in part by a deferred tax charge in the U.S. associated with a $2.0 billion distribution from a foreign subsidiary to its parent in December 2015.

The effective tax rate in 2015 was 31.3% up from 18.2% in 2014. The 2014 period benefited from Malaysia tax benefits upon sale of 20% interest and higher U.S. tax benefits on foreign exploration areas.

2014 versus 2013

Net income in 2014 totaled $905.6 million ($5.03 per diluted share) compared to 2013 net income of $1,123.5 million ($5.94 per diluted share). Income from continuing operations increased in 2014, amounting to $1,025.0 million ($5.69 per diluted share), while 2013 amounted to $888.1 million ($4.69 per diluted share). The 2014 increase for continuing operations was primarily associated with a $321.4 million after-tax gain generated from sale of 20% of our oil and gas assets in Malaysia. Additionally, the Company’s earnings in 2014 benefited from sale of 10% more oil and 5% more natural gas compared to 2013, but the average realized sales price for crude oil was 8% lower in 2014 compared to 2013. Higher oil and gas production volumes led to higher overall extraction costs in 2014, plus the significant weakening of oil and gas prices in late 2014 led to higher impairment expense compared to 2013. Net interest expense was higher in 2014 compared to 2013 due to a combination of more borrowings and lower amounts capitalized to oil and gas development projects.

The 2014 results were favorably affected by slightly higher tax benefits associated with foreign exploration activities and lower overall administrative costs. The results of discontinued operations were a loss of $119.4 million ($0.66 per diluted share) in 2014 compared to earnings of $235.4 million ($1.25 per diluted share) in 2013. The results for discontinued operations in 2013 included a $216.1 million after-tax gain on sale of U.K. oil and gas properties as well as profitable operating results of $134.8 million from U.S. retail marketing operations that were spun-off to shareholders in August 2013. The losses generated by U.K. refining and marketing operations were similar in both years.

Sales and other operating revenues in 2014 were $23.8 million below 2013 as higher oil and natural gas sales volumes in the later year were more than offset by weaker oil sales prices compared to 2013. Sales volumes grew by 8.5% in 2014 on a barrel of oil equivalent basis, but average crude oil sales prices realized in 2014 fell by 8% compared to 2013. The overall increase in sales volumes was mostly attributable to growth in the Eagle Ford Shale in South Texas. Oil prices declined sharply in late 2014 due to an oversupply of crude oil available on a worldwide scale. Gain on sale of assets was $139.0 million higher in 2014, primarily associated with a pretax gain of $144.8 million generated on sale of 20% of the Company’s oil and gas assets in Malaysia in December 2014. Interest and other income in 2014 was $29.2 million below 2013 levels primarily due to lower profits realized on changes in foreign exchange rates during the later year.

Lease operating expenses declined $162.9 million in 2014 compared to 2013 essentially due to nonrecurring costs in the earlier year upon shut down of oil production operations in Republic of the Congo. Severance and ad valorem taxes increased by $19.9 million in 2014 caused by higher volume of oil produced and a higher well count in the Eagle Ford Shale. Exploration expenses increased $11.4 million in 2014 compared to 2013 primarily

 

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due to higher amortization costs associated with Eagle Ford Shale leaseholds. Higher costs in 2014 for exploratory drilling were mostly offset by lower seismic costs compared to 2013. Selling and general expense was reduced by $15.2 million in 2014 compared to the prior year mostly related to nonrecurring costs in 2013 associated with the spin-off of the U.S. retail marketing business to shareholders.

Depreciation, depletion and amortization expense rose $352.9 million in 2014 due to both higher overall oil and natural gas production levels and higher per-unit capital amortization rates in areas where production growth was achieved. Impairment expense associated with asset writedowns increased $29.7 million in 2014 primarily due to non-recoverability of goodwill for conventional operations in Canada that was originally recorded in association with an oil and gas company acquisition in 2000. Accretion expense increased $1.8 million in 2014 primarily due to added levels of discounted asset retirement liabilities associated with development drilling in the Gulf of Mexico. Interest expense in 2014 was $12.0 million more than the prior year due to higher average borrowing levels compared to 2013. Interest costs capitalized in 2014 were $31.9 million below 2013 levels due to fewer ongoing oil development projects during the later year.

Other operating expense was $24.9 million in 2014 and primarily included costs associated with write-down of materials inventory in Malaysia. Income tax expense was $357.3 million lower in 2014 compared to 2013 due to a combination of deferred tax benefits associated with the sale of Malaysia assets and sanction of a development in Block H Malaysia, larger U.S. tax benefits related to exploration losses in foreign areas where the Company has completed operations and exited the area, and lower overall pretax earnings. As to the Malaysia sale, no local income taxes were owed and a deferred tax benefit arose due to the purchaser assuming certain future tax payment obligations. The effective tax rate in 2014 was 18.2%, down from 39.7% in 2013. The Malaysian tax benefits upon sale of 20% interest, combined with higher U.S. tax benefits on foreign exploration areas led to an effective tax rate for the Company in 2014 below the 35.0% U.S. statutory tax rate.

Segment Results—In the following table, the Company’s results of operations for the six months ended June 30, 2016 and 2015 and the last three years ended December 31 are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.

 

		Six Months Ended June 30,
(Millions of dollars)		2016				2015				2015				2014				2013
Exploration and production - continuing operations
United States		$	(131.4)			$	(110.4)			$	(615.7)			$	387.1			$	435.4
Canada			(31.9)				(70.7)				(583.4)				156.5				180.8
Malaysia			70.1				250.7				(653.2)				896.2				786.4
Other			(31.2)				(102.1)				(158.6)				(250.0	)			(373.8	)
Total exploration and production - continuing operations			(124.4)				(32.5)				(2,010.9)				1,189.8				1,028.8
Corporate and other			(72.2)				(53.0)				(244.9)				(164.8	)			(140.7	)
Income (loss) from continuing operations			(196.6)				(85.5)				(2,255.8)				1,025.0				888.1
Income (loss) from discontinued operations			0.7				(2.8)				(15.0)				(119.4	)			235.4
Net income (loss)		$	(195.9)			$	(88.3)			$	(2,270.8)			$	905.6			$	1,123.5

 

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Exploration and Production

Six months ended June 30, 2016 versus six months ended June 30, 2015

United States exploration and production operations reported a loss of $131.4 million in the first half of 2016 compared to a loss of $110.4 million in the 2015 period. The loss increased $21.0 million in 2016 compared to the 2015 period due to lower revenues partially offset by lower production costs and lower exploration expenses. Revenue in the U.S. fell $301.6 million in the period due to both lower oil and natural gas realized sales prices and lower volumes sold. Lease operating expenses decreased by $70.4 million due to lower costs in Eagle Ford Shale and offshore Gulf of Mexico compared to the same period in 2015 with most of the reduction due to the Company aggressively attacking its cost structure coupled with lower variable costs based on volumes produced. Severance and ad valorem taxes in the first half of 2016 were $13.0 million lower than the 2015 period primarily due to weaker average commodity prices and lower volume sold. Depreciation expense decreased $86.2 million in 2016 compared to 2015 due to lower unit rates in Eagle Ford Shale in the 2016 period and lower U.S. volume sold. Exploration expenses were down $86.1 million in the 2016 period primarily related to lower dry hole costs of $64.9 million and lower undeveloped lease amortization compared to the first half of 2015.

Operations in Canada had a loss of $31.9 million in the first half of 2016 compared to a loss of $70.7 million in the 2015 six months. Canadian results of operations improved by $38.8 million in the 2016 period. Results for conventional operations worsened by $27.7 million in 2016 due to impairment expense, lower average realized sales prices for crude oil and natural gas and lower oil volume sold. These were partially offset by higher natural gas volumes produced, lower production costs, no repeat of prior year charges for an environmental provision at the Seal heavy oil area, income tax benefits recognized on the sale of certain Montney midstream assets in 2016, and no repeat of a tax adjustment in 2015 for a 2% increase in the statutory tax rate in Alberta. Lease operating expenses associated with conventional operations were $15.6 million lower in the first six months of 2016 due to both lower costs and a weaker Canadian dollar exchange rate. Depreciation expense was $28.7 million lower in the 2016 period compared to 2015 due primarily to lower unit rates and mix of volume sold. Impairment expense was $95.1 million in 2016, as low oil prices led to a write down of heavy oil properties at Seal in Western Canada and the Terra Nova field offshore East Coast Canada in the first quarter of the year. Synthetic operations generated $47.9 million in income in 2016 compared to a loss of $18.6 million in the same period of 2015. A $71.7 million after-tax gain on sale of the Company’s non-operated interest in Syncrude completed at the end of the second quarter was the primary driver of the improvement. Normal operating results were $5.2 million lower in the 2016 period versus the 2015 quarter. Lower oil sales prices and lower volume sold in the 2016 period were partially offset by lower supply costs and no reoccurrence of the 2015 adjustment related to the aforementioned increase in the Alberta statutory tax rate. Lease operating expenses associated with synthetic operations were $17.6 million lower in the 2016 quarter due to lower variable costs and a weaker Canadian dollar exchange rate. Depreciation expense declined $8.9 million in the 2016 period due to lower unit rate and lower volume produced. Production volumes, lease operating expense and depreciation expense were significantly impacted by the facility being shut-in for 44 days of the quarter due to forest fires in the area.

Malaysia operations reported earnings of $70.1 million in the first half of 2016 compared to earnings of $250.7 million during the same period in 2015. Results were down $180.6 million in 2016 in Malaysia primarily due to a $218.8 million after-tax gain on sale of a 10% interest in Malaysian assets in the 2015 period. Revenue declined by $351.4 million driven by lower commodity prices received and lower volumes sold in the 2016 period, but this was partially offset by lower lease operating expenses and lower depreciation expense. Lease operating expenses decreased in the 2016 period by $40.7 million due to lower maintenance costs and cost cutting measures, and lower volume sold compared to 2015. Depreciation expense was $222.6 million lower in 2016 compared to the same period in 2015 primarily due to lower unit rates following 2015 impairment charges at certain producing properties and lower oil and natural gas volumes sold.

 

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Other international operations reported a loss of $31.2 million in the first six months of 2016 compared to a loss of $102.1 million in the 2015 period. The 2016 period included lower dry hole costs of $23.9 million, with the higher 2015 costs primarily associated with unsuccessful wildcat drilling offshore Australia. Geological and geophysical costs were $12.6 million lower in the 2016 period, primarily due to less seismic data acquired in Australia. Other exploration expenses were $6.7 million lower in the current year, mostly attributable to the Company closing certain field offices beginning in late 2015 and aggressively attacking its cost structure. Other expenses were $21.0 million less in the 2016 period primarily related to an adjustment of previously recorded exit costs in the current period associated with ceasing production operations in Republic of Congo versus a charge in the 2015 period for uncollectible receivables from partners in Murphy West Africa.

2015 versus 2014

Exploration and production (E&P) continuing operations recorded a loss of $2,010.9 million in 2015 compared to earnings of $1,189.8 million in 2014 and $1,028.8 million in 2013. Results from exploration and production operations decreased $3,200.7 million in 2015 compared to 2014 primarily due to impairment expense, lower realized sales prices for oil and natural gas, lower oil and natural gas sales volumes, deepwater rig contract exit costs and lower after-tax gains on sale of interests in Malaysia, offset in part by lower extraction costs and lower selling and general expenses. Crude oil sales prices fell during 2015 in all areas of the Company’s operations, and crude oil price realizations averaged $47.99 per barrel in 2015 compared to $87.23 per barrel in 2014, a price drop of 45% year on year. North America natural gas sales prices and Malaysia natural gas sold at Sarawak fell 37% and 26%, respectively, compared to 2014. Oil and gas extraction costs, including associated production taxes, on a per-unit basis, improved by 13% in 2015 and, together with lower oil and natural gas volumes sold, resulted in $588.6 million in lower costs.

Compared to 2014, total sales volumes in 2015 for crude oil and natural gas fell 9% and 4%, respectively, while natural gas liquids sales volumes rose 8%. Oil sale volumes were lower primarily due to the sale of 30% of its interests in Malaysia over December 2014 and January 2015, partially offset by production growth in the Eagle Ford Shale and new fields brought on-stream in Malaysia in 2014. Natural gas liquid sales volumes increased due to growth in Eagle Ford Shale. Natural gas sales volumes fell primarily due to the decline in Malaysia resulting from the sale of 30% of the Company’s interest and were nearly offset by 26% increase in Canada due to new wells in 2015 and in the second half of 2014 and improved recovery techniques. Heavy oil sales volumes in the Seal area of Canada were lower in 2015 due to well decline and uneconomic wells being shut-in. Also, more downtime for synthetic oil operations led to slightly lower sales volumes in 2015.

Lease operating expenses declined $257.6 million in 2015 compared to 2014 essentially due to sale of interests in Malaysia, lower service costs, cost saving initiatives and a lower average foreign exchange rate in Canada. Severance and ad valorem taxes decreased by $41.4 million in 2015 primarily due to lower average realized sales prices for oil and natural gas volumes in the United States. Exploration expenses were $42.7 million less than 2014 primarily due to lower geological and geophysical costs and lower exploration costs in other foreign areas. Selling and general expenses decreased by 16% over 2014 as the Company implemented key organizational changes including lowering staffing levels by 20% from the end of 2014.

Depreciation, depletion and amortization expense fell by $289.6 million due to both lower volume sold and lower per-unit capital amortization rates. Impairment expense associated with asset writedowns was approximately $2.5 billion in 2015 compared to $51 million in 2014. The increase is primarily due to the significant decline in current and future oil prices during 2015 resulting in writedowns of assets in the Seal heavy oil field in Western Canada, and oil and natural gas fields offshore Malaysia and deepwater Gulf of Mexico. The deepwater rig contract exit costs of $282.0 million are for two deepwater rigs that were under contract in the Gulf of Mexico and were stacked before their contract expiration dates. The remaining obligations owed in 2016 under the rig contracts were expensed in 2015.

 

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Other operating expense was $53.7 million higher in 2015 compared to 2014 primarily due to recording estimated costs of remediating a site at the Seal field in a remote area of Alberta. Income tax benefits in 2015 were $1.1 billion compared to expense of $285.7 million in 2014. The benefits reported in 2015 were result of large pre-tax losses, a significant portion of which is related to impairments in the 2015 period, plus no local income taxes owed on the Malaysia sale and a deferred tax benefit due to the purchaser assuming certain future tax payment obligations. The effective tax rate in 2015 was 35.6% up from 19.4% in 2014. The 2014 period benefited from Malaysia tax benefits upon sale of 20% interest and higher U.S. tax benefits on foreign exploration areas.

2014 versus 2013

E&P income from continuing operations increased $161.0 million in 2014 compared to 2013 primarily due to an after-tax gain of $321.4 million on sale of 20% of the Company’s interest in Malaysia in late 2014. Excluding this gain in Malaysia, E&P earnings declined $160.4 million in 2014, essentially due to lower margins realized on oil sales. The margin decline was attributable to lower average crude oil sales prices in 2014. Crude oil sales prices fell during 2014 in all areas of the Company’s operations, and crude oil price realizations averaged $87.23 per barrel compared to $94.96 per barrel in 2013, a price drop of 8% year on year.

Oil and gas extraction costs, including associated production taxes, were slightly lower on a per-unit basis, but increased overall by $210.8 million due to higher combined total oil and gas sales volumes of 8.5% during 2014. Compared to 2013, total sales volumes in 2014 for crude oil rose 6%, while natural gas liquids sales volumes rose 213% and natural gas sales volumes rose 5%. These 2014 increases in crude oil and gas liquids sales volumes were primarily associated with growth in operations in the Eagle Ford Shale, while natural gas volumes increased due to both Eagle Ford Shale drilling and start-up of the Dalmatian field in the Gulf of Mexico. Crude oil sales volumes offshore Sarawak Malaysia increased in 2014 due to a full year of production from new oil fields brought online in 2013. Crude oil sales volumes in 2014 offshore Block K Malaysia were less than 2013 due to lower production at the Kikeh field coupled with an underlift of sales volumes based on timing of the Company’s cargo sales. Heavy oil sales volumes in Canada were lower in 2014 due to well decline in the Seal area. Also, more downtime for synthetic oil operations led to lower sales volumes in 2014. The final cargo sale in Republic of the Congo occurred in early 2013 and the field has been abandoned.

The Company brought on new natural gas wells in the Tupper area of Western Canada in the second half of 2014, but these new gas volumes did not fully offset production decline at other gas wells in the area during the full year 2014. Lease operating expenses were $163.0 million lower in 2014 primarily due to no repeat of 2013 costs associated with the now abandoned Azurite field in Republic of the Congo. Excluding the costs in Republic of the Congo, lease operating expenses increased by $28.0 million in 2014, primarily due to higher oil and gas production levels in the Eagle Ford Shale area. Severance and ad valorem taxes increased $19.9 million in 2014 compared to the prior year due to continued growth in production volumes and well count in the Eagle Ford Shale. Depreciation expense for E&P operations increased $353.9 million in 2014 due to higher overall production levels and capital amortization rates above the Company’s average for new production added in the Gulf of Mexico and offshore Malaysia.

Accretion expense related to discounted asset retirement obligations increased $1.8 million as expense associated with new wells in the Gulf of Mexico and offshore Malaysia was only partially offset by the favorable effect of settling abandonment obligations in Republic of the Congo. Asset impairment expense of $51.3 million in 2014 was higher by $29.7 million; significantly weaker oil and gas prices at year-end 2014 led to writedown of a natural gas field in the Gulf of Mexico and writeoff of goodwill associated with an oil and gas company acquired in 2000 in Western Canada. Exploration expense was $11.4 million higher in 2014 due to larger amortization costs associated with dropping remote undeveloped leases in the Eagle Ford Shale. Additionally, the Company had increased costs in 2014 for exploratory wells drilled in an earlier year in the Gulf of Mexico

 

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and Malaysia that were expensed due to significantly lower natural gas prices and denial of a requested gas holding period extension, respectively. This was partially offset by lower seismic costs incurred in 2014 in Southeast Asia.

Selling and general expenses for E&P operations increased $41.1 million in 2014 compared to the prior year due to higher overall staffing levels and less costs recovered from partners in Malaysia due to fewer development activities ongoing during 2014. Other expenses were $24.9 million in 2014 and primarily related to writedown in value of materials inventory associated with Malaysia operations. Income tax expense for E&P operations in 2014 was $370.6 million below 2013 levels due to lower pretax earnings, a benefit related to future tax liabilities assumed by the purchaser of 20% of assets in Malaysia, a benefit associated with sanction of a development plan in Block H Malaysia, and higher U.S. tax benefits in 2014 associated with foreign operations that were exited.

The results of operations for oil and gas producing activities for each of the six months ended June 30, 2016 and 2015 and each of the last three years are shown by major operating areas on pages F-59 and F-60 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus.

A summary of oil and gas revenues is presented in the following table.

 

		Six Months Ended June 30,
(Millions of dollars)		2016				2015				2015				2014				2013
United States – Oil and gas liquids		$	381.5			$	570.9			$	1,176.9			$	2,062.1			$	1,724.7
– Natural gas			14.7				41.4				70.4				127.2				72.7
Canada – Conventional oil and gas liquids			65.2				114.2				181.0				453.3				507.2
– Synthetic oil			60.7				105.7				203.0				391.5				441.0
– Natural gas			54.3				85.3				167.7				201.3				198.1
Malaysia – Oil and gas liquids			275.4				445.1				790.6				1,680.2				1,875.0
– Natural gas			64.9				89.6				185.4				357.5				404.0
Republic of the Congo – oil			—				—				—				—				83.6
Total oil and gas revenues		$	916.7			$	1,452.2			$	2,775.0			$	5,273.1			$	5,306.3

The following table contains selected operating statistics for the six months ended June 30, 2016 and 2015 and the last three years ended December 31.

 

		Six Months Ended June 30,
		2016				2015				2015				2014				2013
Net crude oil and condensate produced – barrels per day
United States – Eagle Ford Shale			38,550				48,483				47,325				45,534				33,580
Gulf of Mexico			13,331				12,519				13,794				14,366				11,943
Canada – light			540				110				115				47				59
heavy			2,759				6,276				5,341				7,411				9,123
offshore			8,020				7,702				7,421				8,758				9,099
synthetic			9,326				11,394				11,699				11,997				12,886
Malaysia – Sarawak(1)			13,490				15,951				15,249				20,274				10,323
Block K			25,219				28,343				25,456				34,021				42,808
Republic of the Congo			—				—				—				—				1,046
Continuing operations			111,235				130,778				126,400				142,408				130,867
Discontinued operations – United Kingdom			—				—				—				—				648
Total crude oil and condensate produced			111,235				130,778				126,400				142,408				131,515

 

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		Six Months Ended June 30,
		2016				2015				2015				2014				2013
Net crude oil and condensate sold – barrels per day
United States – Eagle Ford Shale			38,550				48,483				47,326				45,534				33,580
Gulf of Mexico			13,331				12,519				13,794				14,366				11,943
Canada – light			540				110				115				47				59
heavy			2,759				6,276				5,341				7,411				9,123
offshore			8,348				8,065				7,151				8,789				8,586
synthetic			9,326				11,394				11,699				11,997				12,886
Malaysia(1) – Sarawak			11,712				17,066				16,360				19,991				10,728
Block K			23,488				27,793				26,583				32,578				43,482
Republic of the Congo			—				—				—				—				2,093
Continuing operations			108,054				131,706				128,369				140,713				132,480
Discontinued operations – United Kingdom			—				—				—				—				621
Total crude oil and condensate sold			108,054				131,706				128,369				140,713				133,101
Net natural gas liquids produced – barrels per day
United States – Eagle Ford Shale			6,988				7,517				7,558				5,778				2,064
Gulf of Mexico			1,347				1,895				1,998				2,596				800
Canada			88				14				10				25				64
Malaysia(1) – Sarawak			635				668				668				840				635
Total net gas liquids produced			9,058				10,094				10,234				9,239				3,563
Net natural gas liquids sold – barrels per day
United States – Eagle Ford Shale			6,988				7,517				7,558				5,778				2,064
Gulf of Mexico			1,347				1,895				1,998				2,596				800
Canada			88				14				10				25				64
Malaysia(1) – Sarawak			1,127				368				606				986				66
Total net natural gas liquids sold			9,550				9,794				10,172				9,385				2,994
Net natural gas sold – thousands of cubic feet per day
United States – Eagle Ford Shale			37,203				39,030				38,304				33,370				20,571
Gulf of Mexico			20,094				55,563				49,068				55,101				32,641
Canada			207,288				193,133				196,774				156,478				175,449
Malaysia(1) – Sarawak			97,155				111,431				121,650				168,712				164,671
Block K			12,124				25,804				21,818				32,295				29,699
Continuing operations			373,864				424,961				427,614				445,956				423,031
Discontinued operations – United Kingdom			—				—				—				—				815
Total natural gas sold			373,864				424,961				427,614				445,956				423,846
Total net hydrocarbons produced – equivalent barrels per day(2)			182,604				211,699				207,903				225,973				205,719
Total net hydrocarbons sold – equivalent barrels per day(2)			179,915				212,327				209,809				224,454				206,736
Estimated net hydrocarbon reserves – million equivalent barrels(2),(3)			—				—				774.0				756.5				687.9

 

(1)

The Company sold 20% interest in Malaysia properties on December 18, 2014 and sold an additional 10% interest on January 29, 2015. This table includes volumes for these sold interests through the date of disposition.

 

(2)

Natural gas converted at a 6:1 ratio.

 

(3)

At December 31.

Six months ended June 30, 2016 versus six months ended June 30, 2015

Total worldwide production averaged 182,604 barrels of oil equivalent per day during the six months ended June 30, 2016, a decrease from 211,699 barrels of oil equivalent produced in the same period in 2015. Crude oil

 

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and condensate production in the first half of 2016 averaged 111,235 barrels per day compared to 130,778 barrels per day in the first half of 2015. Crude oil production decreased 9,933 barrels per day in the Eagle Ford Shale in 2016 due to well decline associated with significantly less drilling beginning in the last half of 2015 and continuing into 2016 in response to lower prices. Heavy oil production in Canada declined in 2016 in the Seal area of Western Canada primarily due to uneconomic well volumes shut-in caused by low sales prices, and natural decline. Synthetic oil production in Canada also was lower in 2016 due to impacts of maintenance work and downtime associated with forest fires in the surrounding area. Lower oil production in 2016 in Malaysia was primarily attributable to natural well decline. Total production of natural gas liquids was 9,058 barrels per day in the 2016 period compared to 10,094 barrels per day a year ago. Natural gas sales volumes decreased from 425 million cubic feet per day in 2015 to 374 million cubic feet per day in 2016. Natural gas sales volumes increased in North America due to higher gas production volumes in the Tupper area in Western Canada and Eagle Ford Shale area of South Texas, offset in part by lower gas volumes in the Gulf of Mexico primarily in the Dalmatian field. The increase in North America was more than offset by lower production in Malaysia due to unplanned downtime in both Sarawak and Block K.

2015 versus 2014

The Company’s total crude oil and condensate production averaged 126,400 barrels per day in 2015, compared to 142,408 barrels per day in 2014. The 2015 crude oil production level was 11% below 2014. On a pro-forma basis, assuming the sale of 30% of the Company’s interest in Malaysia properties occurred at the beginning of 2014, total hydrocarbon production for 2015 increased 4% compared to the 2014 period as adjusted for the sale. Crude oil production in the United States totaled 61,119 barrels per day in 2015, up from 59,900 barrels per day in 2014. The 2% increase in U.S. crude oil production year over year was primarily related to additional wells brought on production as part of an ongoing development drilling and completion program at Eagle Ford Shale in South Texas. Heavy crude oil production in Western Canada fell from 7,411 barrels per day in 2014 to 5,341 barrels per day in 2015, with the reduction attributable to wells shut-in due to economic conditions and natural well performance decline in the Seal area. Crude oil volumes produced offshore Eastern Canada totaled 7,421 barrels per day in 2015, off from 8,758 barrels per day in the previous year due to less production at Hibernia field primarily due to planned maintenance in 2015. Synthetic crude oil production volume in Canada was 11,699 barrels per day in 2015 compared to 11,997 barrels per day in 2014 due to impacts of unplanned outages offset in part by lower Canadian royalty rates. Crude oil production offshore Sarawak decreased from 20,274 barrels per day in 2014 to 15,249 barrels per day in 2015. Block K in Malaysia had crude oil production of 25,456 barrels per day in 2015, down from 34,021 barrels per day in 2014. Lower oil production in 2015 in Malaysia was primarily attributable to impacts from the sale of 30% of the Company’s total interest offset in part by production from new fields brought on-stream in 2014.

The Company produced natural gas liquids (NGL) of 10,234 barrels per day in 2015, up from 9,239 barrels per day in 2014. The higher NGL volumes of 995 barrels per day in 2015 were mostly attributable to the increase of 1,780 barrels per day in the Eagle Ford Shale partially offset by well decline in Gulf of Mexico and the sale of 30% of its interests in Malaysia.

Worldwide sales of natural gas were 427.6 million cubic feet (MMCF) per day in 2015, compared to 446.0 MMCF per day in 2014. Natural gas sales volumes decreased in 2015, primarily due to the decline in Malaysia after the sale of 30% of the Company’s interests, offset in part by higher gas production volumes in the Dalmatian field in the Gulf of Mexico, Eagle Ford Shale area in South Texas and Tupper area in Western Canada. Natural gas sales volumes in Canada improved from 156.5 MMCF per day in 2014 to 196.8 MMCF per day in 2015 due to wells added during 2015 and in the second half of 2014 and improved recovery techniques. At the Company’s fields offshore Sarawak Malaysia, gas production decreased from 168.7 MMCF per day in 2014 to 121.7 MMCF per day in 2015 due to sale of 30% interest in Malaysian properties. Natural gas sales volumes from Block K offshore Malaysia were 21.8 MMCF per day in 2015, down from 32.3 MMCF per day in 2014 due to the sale of 30% of the Company’s interests and higher downtime at the third party receiving facility.

 

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2014 versus 2013

Crude oil production in 2014 totaled 142,408 barrels per day compared to 131,515 barrels per day in 2013. The 2014 crude oil production level was a Company record and 8% above 2013. Crude oil production in the United States totaled 59,900 barrels per day in 2014, up from 45,523 barrels per day in 2013. The 32% increase in U.S. crude oil production year over year was a U.S. record for the Company and was primarily related to increased volumes produced in the Eagle Ford Shale in South Texas. The Company’s Eagle Ford Shale drilling program utilized an average of almost eight drilling rigs during 2014. U.S. production also benefited in 2014 from start-up of the Dalmatian field in the Gulf of Mexico. Heavy crude oil production in Western Canada fell from 9,123 barrels per day in 2013 to 7,411 barrels per day in 2014, with the reduction attributable to well performance decline in the Seal area.

Crude oil volumes produced offshore Eastern Canada totaled 8,758 barrels per day in 2014, off from 9,099 barrels per day in the previous year as well decline at Hibernia was not fully offset by the benefit of less 2014 downtime at Terra Nova. Synthetic crude oil production volume was 11,997 barrels per day in 2014 compared to 12,886 barrels per day in 2013 due to the latter year experiencing greater levels of downtime for repairs. Crude oil production offshore Sarawak increased from 10,323 barrels per day in 2013 to 20,274 barrels per day in 2014; the Company brought several new fields online during 2013 which provided a full year of production in 2014. Block K in Malaysia had crude oil production of 34,021 barrels per day in 2014, down from 42,808 barrels per day in 2013. Both the Kakap main field and the Siakap field came on stream during 2014, but this partial year production did not fully offset lower production at the Kikeh field. The Kikeh field had lower production in 2014 due to a combination of an outage for hook-up of the Siakap field, a facility fire early in the year, and normal well decline. Prior to going off production in early 2013, the Azurite field produced 1,046 barrels of crude oil per day. Additionally, discontinued fields in the U.K. that were all sold in early 2013 provided crude oil production of 648 barrels per day.

The Company produced NGL of 9,239 barrels per day in 2014, up from 3,563 barrels per day in 2013. The higher NGL volumes of 5,676 barrels per day in 2014 were mostly attributable to increases of 3,714 barrels per day in the Eagle Ford Shale and 1,227 barrels per day associated with start-up of the Dalmatian field in the Gulf of Mexico.

Worldwide sales of natural gas were 446.0 million cubic feet (MMCF) per day in 2014, compared to 423.8 MMCF per day in 2013. Significant development drilling in the Eagle Ford Shale and start-up of the Dalmatian field in the Gulf of Mexico drove up U.S. natural gas sales volumes from 53.2 MMCF per day in 2013 to 88.5 MMCF per day in 2014. Natural gas sales volumes in Canada fell from 175.4 MMCF per day in 2013 to 156.5 MMCF per day in 2014 as decline at existing wells in the Tupper area of British Columbia were not fully offset by gas volumes produced at new wells brought on line during 2014. At the Company’s fields offshore Sarawak Malaysia, gas production increased from 164.7 MMCF per day in 2013 to 168.7 MMCF per day in 2014 due to higher customer demand in the later year. Natural gas sales volumes from Block K offshore Malaysia were 32.3 MMCF per day in 2014, up from 29.7 MMCF per day in 2013 due to higher demand from the third party receiving facility.

 

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The following table contains the weighted average sales prices for the six months ended June 30, 2016 and 2015 and the last three years ended December 31.

 

		Six Months Ended June 30,
		2016				2015				2015				2014				2013
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale		$	38.93			$	49.55			$	48.14			$	90.67			$	101.02
Gulf of Mexico			39.00				52.52				46.80				91.18				103.63
Canada (1) – light			33.74				46.16				41.06				83.43				85.61
heavy			11.83				27.02				23.28				54.18				46.78
offshore			36.82				55.51				50.54				95.95				108.64
synthetic			35.58				51.27				47.56				89.51				96.09
Malaysia – Sarawak(2)		$	41.74			$	52.87			$	50.13			$	84.78			$	101.93
Block K(2)			41.97				56.96				51.50				86.50				92.37
Republic of the Congo			—				—				—				—				109.43
Discontinued operations – United Kingdom			—				—				—				—				108.67
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale			9.65				12.22				11.18				25.79				28.71
Gulf of Mexico			10.59				14.50				12.82				28.93				34.30
Canada(1)			29.38				22.31				22.31				66.19				72.68
Malaysia – Sarawak(2)			35.65				58.08				50.55				75.18				101.40
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale			1.43				2.39				2.24				3.99				3.79
Gulf of Mexico			1.62				2.48				2.36				3.98				3.85
Canada(1)			1.44				2.44				2.35				3.60				3.09
Malaysia – Sarawak(2)			3.52				4.53				4.23				5.71				6.66
Block K			0.25				0.24				0.24				0.24				0.24
Discontinued operations – United Kingdom			—				—				—				—				12.32

 

(1)

U.S. dollar equivalent.

 

(2)

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

Six months ended June 30, 2016 versus six months ended June 30, 2015

For the first six months of 2016, the Company’s sales price for crude oil and condensate averaged $38.78 per barrel, down from $51.26 per barrel in 2015. The sales price for U.S. natural gas liquids averaged $9.80 per barrel in 2016 compared to $12.77 per barrel in 2015. The average sales price for North American natural gas in the first six months of 2016 was $1.45 per MCF, down from $2.44 per MCF realized in 2015. Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.52 per MCF in 2016 compared to $4.53 per MCF in 2015.

2015 versus 2014

The Company’s average worldwide realized sales price for crude oil and condensate from continuing operations was $47.99 per barrel in 2015 compared to $87.23 per barrel in 2014 and $94.96 per barrel in 2013. The average realized crude oil sales price was 45% lower in 2015 compared to the prior year. West Texas Intermediate (WTI) crude oil averaged 48% less in 2015. Dated Brent and Kikeh oil each sold for approximately 47% less in 2015, while Light Louisiana Sweet crude oil sold at 46% below 2014 levels. The average realized sales prices for U.S. crude oil and condensate amounted to $47.84 per barrel in 2015, 47% lower than 2014. Heavy oil produced in Canada brought $23.28 per barrel in 2015, a 57% decrease from 2014, as a result of lower worldwide benchmark prices in 2015. The average sales price for crude oil produced offshore Eastern Canada declined 47% to $50.54 per barrel in 2015. The average realized sales price for the Company’s synthetic crude oil was $47.56 per barrel in 2015 down 47% from the prior year. Crude oil sold in Malaysia averaged $50.98 per barrel in 2015, 41% lower than in 2014.

 

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The average sales price for natural gas liquids (NGL) was also lower in 2015 than 2014. These NGL prices are generally weak compared to the comparable heating value of crude oil, primarily due to an oversupply of NGL with the recent drilling growth in U.S. shale plays exceeding refinery and other demand for this product. NGL was sold in the U.S. for an average of $11.55 per barrel in 2015, down 57% from the average price of $26.83 per barrel in 2014. NGL produced in Malaysia in 2015 was sold for an average of $50.55 per barrel, 33% below the 2014 average of $75.18 per barrel.

North American natural gas prices were weaker in 2015 than 2014, essentially driven by record inventory levels and a warmer than normal fourth quarter in 2015. The average posted price at Henry Hub in Louisiana was $2.61 per million British Thermal Units (MMBTU) in 2015 compared to $4.33 per MMBTU in 2014. In 2015, U.S. natural gas was sold at an average of $2.31 per thousand cubic feet (MCF), a 42% decrease compared to 2014. Natural gas sold in Canada averaged $2.35 per MCF in 2015, down 35% from 2014. Natural gas sold in 2015 from Sarawak Malaysia averaged $4.23 per MCF, down 26% from the prior year.

Based on 2015 sales volumes and deducting taxes at statutory rates, each $1.00 per barrel oil sales price fluctuation and $0.10 per MCF gas sales price fluctuation would have affected 2015 earnings from exploration and production continuing operations by $30.6 million and $10.6 million, respectively.

2014 versus 2013

The Company’s average worldwide realized sales price for crude oil and condensate from continuing operations was $87.23 per barrel in 2014 compared to $94.90 per barrel in 2013. The average realized crude oil sales price for continuing operations was 8% lower in 2014 compared to 2013. Although West Texas Intermediate (WTI) crude oil averaged 5% less in 2014, other indices on which the Company sells crude oil fell more compared to the prior year. Dated Brent and Kikeh oil each sold for 9% less in 2014, while Light Louisiana Sweet crude oil sold at 11% below 2013 levels. The average realized sales prices for U.S. crude oil and condensate amounted to $90.79 per barrel in 2014, 11% lower than 2013. Heavy oil produced in Canada brought $54.18 per barrel in 2014, a 16% increase from 2013, as a reduction in the discount for heavy oil in 2014 more than offset the impact of lower worldwide benchmark prices in 2014. The average sales price for crude oil produced offshore Eastern Canada declined 12% to $95.95 per barrel in 2014. The average realized sales price for the Company’s synthetic crude oil was $89.51 per barrel in 2014 down 7% from the prior year. Crude oil sold in Malaysia averaged $85.85 per barrel in 2014, 9% lower than in 2013.

The average sales price for NGL was lower in 2014 than 2013. NGL was sold in the U.S. for an average of $26.83 per barrel in 2014, down 11% from the average price of $30.31 per barrel in 2013. NGL produced in Malaysia in 2014 was sold for an average of $75.18 per barrel, 26% below the 2013 average of $101.40 per barrel.

North American natural gas prices were stronger in 2014 than 2013, essentially driven by higher gas energy demand due to an extremely cold winter season on the continent. The average posted price at Henry Hub in Louisiana was $4.34 per MMBTU in 2014 compared to $3.72 per MMBTU in 2013. In 2014, U.S. natural gas was sold at an average of $3.98 per thousand cubic feet (MCF), a 4% increase compared to 2013. Natural gas sold in Canada averaged $3.60 per MCF in 2014, up 17% from 2013. Natural gas sold in 2014 from Sarawak Malaysia averaged $5.71 per MCF, down 14% from the prior year.

 

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Production-related expenses for continuing exploration and production operations during the six months ended June 30, 2016 and 2015 and the last three years are shown in the following table.

 

		Six Months Ended June 30,
(Millions of dollars)		2016				2015				2015				2014				2013
Lease operating expense		$	315.6			$	459.9			$	832.3			$	1,089.9			$	1,252.9
Severance and ad valorem taxes			26.1				39.9				65.8				107.2				87.3
Depreciation, depletion and amortization			533.7				880.2				1,607.9				1,897.5				1,543.6
Total		$	875.4			$	1380.0			$	2,506.0				3,094.6				2,883.8

Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.

 

		Six Months Ended June 30,
(Dollars per equivalent barrel)		2016				2015				2015				2014				2013
United States – Eagle Ford Shale
Lease operating expense		$	8.57			$	12.21			$	10.27			$	11.25			$	11.15
Severance and ad valorem taxes			2.27				3.04				2.50				4.64				5.39
Depreciation, depletion and amortization (DD&A) expense			25.10				27.06				26.71				27.87				30.48
United States – Gulf of Mexico
Lease operating expense			8.93				9.86				9.42				11.73				17.28
DD&A expense			24.08				22.25				22.60				27.47				21.32
Canada – Conventional operations
Lease operating expense			5.06				6.91				6.18				10.37				10.50
Severance and ad valorem taxes			0.26				0.32				0.29				0.36				0.29
DD&A expense			10.80				14.15				12.74				17.00				18.58
Canada – Synthetic oil operations
Lease operating expense			41.15				42.36				38.88				53.39				47.47
Severance and ad valorem taxes			1.46				1.34				1.20				1.16				1.04
DD&A expense			9.72				12.30				11.90				12.32				11.79
Malaysia
Lease operating expense – Sarawak			6.25				8.73				7.82				7.91				9.43
– Block K			12.95				13.25				13.20				15.04				14.30
DD&A expense – Sarawak			9.60				23.15				18.78				20.30				14.01
– Block K			12.35				30.96				26.25				26.79				22.21
Total oil and gas operations
Lease operating expense			9.64				11.97				10.87				13.31				16.66
Severance and ad valorem taxes			0.80				1.04				0.86				1.31				1.16
DD&A expense			16.30				22.90				21.00				23.16				20.53

2015 versus 2014

Lease operating expenses totaled $832.3 million in 2015, compared to $1,089.9 million in 2014. Lease operating expense per equivalent barrel in the Eagle Ford Shale decreased nearly $1.00 on a per-unit basis due to lower service costs, cost-saving initiatives and higher volume produced. Gulf of Mexico cost per barrel declined $2.31 per equivalent barrel due to lower fixed charges for third party processing facility at Thunder Hawk, additional third-party cost sharing at the Thunder Hawk and Front Runner fields, cost saving initiatives, and lower major repairs, partially offset by lower volumes produced. Lease operating expense for conventional operations in Canada improved in 2015 due to lower costs in the Seal heavy oil area, increased cost sharing for third party processing in the Tupper area and a lower Canadian dollar exchange rate. Synthetic oil operations costs per barrel decreased by $14.51 per barrel primarily due to lower Canadian dollar exchange rate, cost savings efforts and lower power costs. Operating expense in Block K decreased by $1.84 on a per-unit basis and benefited from higher volumes produced at the main Kakap field.

 

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Severance and ad valorem taxes totaled $65.8 million in 2015 and $107.2 million in 2014. Severance and ad valorem taxes in the United States in 2015 were lower primarily due to weaker average commodity prices in the Eagle Ford Shale.

Depreciation, depletion and amortization expense for continuing exploration and production operations totaled $1,607.9 million in 2015 and $1,897.5 million in 2014. The $289.6 million decrease in 2015 compared to 2014 was primarily due to lower per-unit capital amortization rates and lower oil and natural gas volume sold. Eagle Ford Shale rate per equivalent barrel decreased due to reserve additions and cost improvements on 2015 drilling activities. The unit cost in the Gulf of Mexico decreased due to reserve additions, mix of production and lower unit rates due to impairment of assets. Canada conventional operations rate per barrel of oil equivalent decreased in 2015 due to a lower Canadian dollar exchange rate, higher mix of production from the Tupper area and impairment of the Seal heavy oil field. Depreciation per barrel in Sarawak improved in 2015 due to mix of production and the impairment of assets.

2014 versus 2013

Lease operating expenses totaled $1,089.9 million in 2014 and $1,252.9 million in 2013. Lease operating expense per equivalent barrel in the Eagle Ford Shale was essentially flat in 2014 and 2013, while cost per barrel in the Gulf of Mexico declined in 2014 primarily due to higher production related to start-up of the Dalmatian field and lower fixed charges for a third party processing facility at Thunder Hawk. Lease operating expense for conventional operations in Canada was down slightly in 2014 due mostly to a lower Canadian dollar exchange rate. Lease operating expense per barrel for synthetic oil operations rose in 2014 compared to the prior year due to a combination of lower net production and higher maintenance and power costs. Lease operating expense for Sarawak oil and gas operations declined in 2014 per barrel due to higher full-year 2014 volumes produced at oil fields which started up during 2013. Block K operations had higher lease operating expense per barrel in 2014 due to overall lower production, but with a benefit from start-up of the main Kakap field in the second half of the year.

Severance and ad valorem taxes totaled $107.2 million in 2014 and $87.3 million in 2013. On a per barrel equivalent basis, Eagle Ford Shale production taxes were less in 2014 than 2013 due to a lower mix of production value primarily caused by a larger increase in growth of lower value natural gas liquids in this area.

Depreciation, depletion and amortization expense for continuing exploration and production operations totaled $1,897.5 million in 2014 and $1,543.6 million in 2013. The $353.9 million increase in 2014 compared to 2013 was attributable to added production in areas that carried a higher overall capital amortization cost in 2014, in particular at Eagle Ford Shale, Dalmatian, Kakap main field and Siakap. The rate per equivalent barrel in 2014 at Eagle Ford Shale declined due to the timing of reserves migration to the proved category and cost improvements achieved on later drilling activities. The per barrel cost in the Gulf of Mexico increased in 2014 due to start-up of the Dalmatian field where costs early in the life of the field exceed the U.S. average due to the timing of migration of reserves to the proved category. Canada conventional cost per barrel declined in 2014 mostly due to a lower Canadian dollar exchange rate compared to 2013. Synthetic oil operations had a higher per barrel cost in 2014 due to straight-line depreciation costs for certain processing facilities being expensed over fewer production barrels. Depreciation per barrel rose in 2014 for both Sarawak and Block K areas due to new field production carrying a higher capital amortization cost per unit compared to the more mature fields in these areas.

Exploration expenses for continuing operations for each of the six months ended June 30, 2016 and 2015 and the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-59 and F-60 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus. Expenses other than undeveloped lease amortization are included in the capital expenditures total for exploration and production activities.

 

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		Six Months Ended June 30,
(Millions of dollars)		2016				2015				2015				2014				2013
Dry holes		$	14.3			$	99.0			$	296.8			$	270.0			$	262.9
Geological and geophysical			8.3				23.5				49.9				99.5				117.5
Other			16.0				25.4				48.8				69.7				54.9
			38.6				147.9				395.5				439.2				435.3
Undeveloped lease amortization			25.4				45.8				75.4				74.4				66.9
Total exploration expenses		$	64.0			$	193.7			$	470.9			$	513.6			$	502.2

2015 versus 2014

Dry hole expense in 2015 was $26.8 million more than 2014 primarily due to expensing of wells in the Gulf of Mexico, Australia and Malaysia. Dry hole costs in the Gulf of Mexico of $241.3 million were attributable to three unsuccessful wells in Mississippi Canyon and one well in Walker Ridge. Dry hole costs in Malaysia of $29.7 million related to unsuccessful wildcat drilling in Blocks SK 2C and H. Dry hole cost in other foreign areas of $25.8 million is attributable to three unsuccessful wells in Block WA-481-P in Australia. Geological and geophysical (G&G) expense was $49.6 million lower in 2015 primarily due to reduced spending in Namibia, Equatorial Guinea, Vietnam and Gulf of Mexico. Other exploratory costs of $48.8 million in 2015 was down $20.9 million compared to 2014. Exploration staff and office costs around the world were lower together with non-recurring costs in 2014 related to both a charge-off of shared drilling equipment improvement costs for a third-party rig that was released and a penalty associated with not drilling on a license in Indonesia.

Impairment expense in 2015 for E&P operations exceeded 2014 by $2,441.9 million. The 2015 included significant noncash impairment expense of $2,493.2 million before tax and $1,660.0 million after-tax for producing heavy oil properties in Western Canada, producing offshore properties in Malaysia, and producing and non- producing properties in the Gulf of Mexico. The 2015 impairments were the result of significant declines in current and future crude oil prices since the end of 2014.

The exploration and production business recorded expenses of $48.7 million in 2015 and $50.8 million in 2014 for accretion on discounted abandonment liabilities. Because the liability for future abandonment of wells and other facilities is carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment. The $2.1 million decrease in 2015 primarily related to lower abandonment liabilities following the sale of 30% interest in Malaysia assets and a lower Canadian dollar exchange rate.

The effective income tax rate for exploration and production continuing operations was 35.6% in 2015 and 19.4% in 2014. The effective tax rate in 2015 was above the tax rate in 2014 and near the statutory U.S. tax rate of 35.0%. The 2014 period included several items discussed below that didn’t reoccur in 2015. Through 2015, no tax benefits have thus far been recognized for costs incurred for Blocks PM 311/312, offshore Peninsular Malaysia, and Block SK 314A and Block SK 2C offshore Sarawak, Malaysia.

At December 31, 2015, 113.0 million barrels of the Company’s U.S. crude oil proved reserves, 14.7 million barrels of U.S. NGL proved reserves and 84.1 billion cubic feet of U.S. natural gas proved reserves were undeveloped. Total proved undeveloped reserves represent 38% of total proved reserves on a barrel of oil equivalent basis as of December 31, 2015. Approximately 94% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company’s Eagle Ford Shale operations in South Texas. Further drilling and facility construction are generally required to move the undeveloped reserves in the Eagle Ford Shale area to developed. The deepwaters of the Gulf of Mexico accounted for the remaining 6% of proved undeveloped reserves at December 31, 2015. In the Western Canadian Sedimentary Basin, undeveloped natural gas proved

 

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reserves totaled 456.1 billion cubic feet, with the migration of these reserves, primarily in the Tupper and Tupper West areas, dependent on both development drilling and completion of processing and transportation facilities. In Block K Malaysia, oil proved undeveloped reserves of 9.6 million barrels are primarily at the Kikeh field, where undeveloped proved oil reserves are subject to further drilling before being moved to developed. Also in Malaysia, there were billion cubic feet of undeveloped natural gas proved reserves at various offshore fields at year-end 2015. These undeveloped natural gas reserves in Malaysia are mainly associated with Block H, where a development project commenced following sanction in 2014. On a worldwide basis, the Company spent approximately $1.74 billion in 2015, $3.21 billion in 2014 and $3.40 billion in 2013 to develop proved reserves.

2014 versus 2013

Dry hole expense in 2014 was $7.1 million more than in 2013 primarily due to expensing prior-year wells in Malaysia and the Gulf of Mexico that had been previously suspended while development options were studied. Dry hole costs in Malaysia of $47.4 million for these wells were attributable to government denial of a request to extend a gas holding period for Block PM 311, while the previously suspended Gulf of Mexico dry hole for $18.8 million was caused by low year-end 2014 natural gas prices. The 2014 costs also included $103.9 million for an unsuccessful well in Cameroon. These higher 2014 costs were partially offset by the costs of unsuccessful exploration drilling conducted in Australia in 2013.

G&G expense was $18.0 million lower in 2014 due to less spending in 2014 for seismic data covering exploration prospects in Southeast Asia. Other exploratory costs were up $14.8 million in 2014 due to higher exploration staff and office costs in Southeast Asia, a charge-off in 2014 of shared drilling equipment improvement costs for a third-party rig that was released, and a penalty associated with an exploration well that was not drilled on a license in Indonesia. Undeveloped lease amortization increased $7.5 million primarily due to higher amortization related to remote unproved lease acreage released in the Eagle Ford Shale, but partially offset by no repeat in 2014 of lease costs written off in 2013 in the Kurdistan region of Iraq.

Impairment expense in 2014 for E&P operations exceeded 2013 by 29.7 million. The 2014 year charge included write-off of goodwill recorded in a business acquisition in Western Canada in 2000, and a writedown of one natural gas field in the Gulf of Mexico. Both charges in 2014 were required due to the weakness in oil and natural gas prices, which retreated severely in late 2014. The exploration and production business recorded expenses of $50.8 million in 2014 and $49.0 million in 2013 for accretion on discounted abandonment liabilities. The $1.8 million increase in 2014 primarily related to development wells added in the Gulf of Mexico during the year.

The effective income tax rate for exploration and production continuing operations was 19.4% in 2014 and 38.9% in 2013. The effective tax rate in 2014 was well below the tax rates in 2013 and the statutory U.S. tax rate of 35.0% due primarily to tax benefits in foreign areas during 2014. With the sale of 20% of the assets in Malaysia near year-end 2014, the purchaser assumed certain future Malaysian tax obligations, which essentially reduced the Company’s deferred tax liabilities by $176.6 million. Additionally, the Company recognized a $65.4 million tax benefit during 2014 for past exploratory expenses incurred in Block H, where proved reserves were added at year-end 2014 related to a new field development plan. Also, in 2014 the Company recognized U.S. income tax benefits of $95.9 million associated with investments in exploration operations in Cameroon, the Kurdistan region of Iraq, and one block in Australia, in areas where the Company is exiting. Tax jurisdictions with no current tax benefit on expenses primarily include certain non-revenue generating areas in Malaysia as well as other foreign exploration areas in which the Company operates. Each main exploration area in Malaysia is currently considered a distinct taxable entity and expenses in certain areas may not be used to offset revenues generated in other areas.

 

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Refining and Marketing—The Company has now transitioned to a fully independent oil and gas exploration and production company. Murphy formerly had a significant U.S. and U.K. refining and marketing business. On August 30, 2013, the Company spun-off to shareholders its U.S. retail marketing business. The now separate, publicly traded U.S. retail company named Murphy USA Inc. is listed on the New York Stock Exchange under the symbol “MUSA”. On September 30, 2014, Murphy Oil sold its U.K. retail marketing business. In late 2014, the Company decided to decommission and abandon the Milford Haven, Wales refinery. The Company sold the remainder of its U.K. downstream assets in June 2015. Both the U.S. and U.K. downstream businesses are reported as discontinued operations for all periods presented. Further discussion of the results of discontinued operations is included below.

Corporate—

Six months ended June 30, 2016 versus six months ended June 30, 2015

For the first half of 2016, corporate activities reflected net costs of $72.2 million compared to net costs of $53.0 million a year ago. The $19.2 million increase in net cost in the current year is primarily due to lower foreign currency exchange benefits and higher net interest cost. An after-tax gain of $21.3 million occurred in 2016 on transactions denominated in foreign currencies compared to an after-tax gain of $35.1 million a year ago.

2015 versus 2014

The after-tax costs of corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions were $244.9 million in 2015, $164.8 million in 2014 and $140.7 million in 2013.

The net costs of Corporate activities in 2015 were unfavorable to 2014 by $80.1 million mostly due to higher tax expense related to a U.S deferred tax charge of $188.5 million associated with a $2.0 billion distribution from a foreign subsidiary, partially offset by higher foreign currency exchange gains and lower administrative costs. Interest income was $3.7 million unfavorable in 2015 compared to 2014 due to lower average invested cash balances in Canada. The after-tax effects of foreign currency exchange was a gain of $86.7 million in 2015, $46.8 million higher than in 2014. These effects arose due to transactions denominated in currencies other than the respective operations predominant functional currency. The foreign currency gain recognized in 2015 was mostly realized in Malaysia, where a weaker Malaysian ringgit in 2015 led to a benefit from lower income tax obligations payable in local currency. The Malaysian operation’s functional currency is the U.S. dollar. Administrative expenses associated with corporate activities were lower in 2015 by $22.4 million, primarily due to lower employee compensation expense. Depreciation expense was $3.2 million higher in 2015 compared to 2014 due to depreciation of certain obsolete assets and installation of new software. Total provision for income taxes was higher in 2015 compared to 2014 by $142.9 million due primarily to the aforementioned deferred tax on a foreign distribution, partially offset by benefits related to changes in prior-year estimated taxes following the filing of the 2014 tax return.

2014 versus 2013

The after-tax costs of corporate activities were $164.8 million in 2014 and $140.7 million in 2013. The net cost of Corporate activities in 2014 exceeded 2013 by $24.1 million, primarily due to higher net interest expense and lower profits on foreign currency exchange, but somewhat offset by lower administrative expenses. Interest income was $3.8 million higher in 2014 than 2013 due to larger average invested cash balances in Canada and interest earned on Canadian prior-year tax installments. Net interest expense, after capitalization of finance-related costs to development projects, was higher by $43.9 million in 2014 compared to the prior year due to larger average borrowing levels in 2014 and lower amounts of interest capitalized to development projects.

 

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Administrative expenses associated with corporate activities were lower in 2014 by $56.3 million, primarily due to nonrecurring expenses incurred in 2013 related to consulting and staffing for the U.S. retail marketing operations that was spun-off to shareholders in August 2013. The after-tax effects of foreign currency exchange was a gain of $39.9 million in 2014, but $30.4 million lower than in 2013. The foreign currency gain recognized in 2014 was mostly realized in Malaysia, where a significantly weaker Malaysian ringgit in 2014 led to a benefit from lower income tax obligations payable in the local currency. However, the foreign currency gain variance in 2014 compared to the prior year was primarily related to the U.K. as an unfavorable earnings effect from the British pound sterling exchange rate in 2014 followed a favorable effect in 2013. Income tax benefits in 2014 for corporate activities were $13.4 million less than the prior year.

Discontinued Operations—The Company has presented a number of businesses as discontinued operations in its consolidated financial statements. These businesses principally include:

 

•

U.S. retail marketing operations spun-off to shareholders on August 30, 2013. Results of operations are included in the Company’s financial statements through the date of spin-off.

 

•

U.K. refining and marketing operations (R&M). The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in the second quarter of 2015 for cash proceeds of $5.5 million. The Company has accounted for the U.K. downstream business as discontinued operations for all periods presented.

 

•

U.K. oil and gas assets sold through a series of transactions in the first half of 2013. The Company’s financial statements include the results of operations through the respective dates the asset were sold, plus the cumulative gain realized upon sale.

The results of these discontinued operations for the six months ended June 30, 2016 and 2015 and the last three years are reflected in the following table.

 

		Six Months Ended June 30,
(Millions of dollars)		2016				2015				2015				2014				2013
U.S. refining and marketing		$	—			$	—			$	—				—				134.8
U.K. refining and marketing			(0.1	)			(2.6	)			(14.8	)			(120.6	)			(119.2	)
U.K. exploration and production			0.8				(0.2	)			(0.2	)			1.2				219.8
Income (loss) from discontinued operations		$	0.7			$	(2.8	)		$	(15.0	)			(119.4	)			235.4

Six months ended June 30, 2016 versus six months ended June 30, 2015

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

2015 versus 2014

The loss from U.K. refining and marketing (R&M) operations of $14.8 million was primarily related to loss on sale of assets, employee severance costs, legal fees and other abandonment costs related to closure. The Company sold the finished product terminal operations during 2015 for cash proceeds of $5.5 million. Certain costs to be paid in 2016 or beyond relate to future services and will be recognized over the applicable service period.

2014 versus 2013

The loss from U.K. R&M operations of $120.6 million in 2014 was similar to the loss in 2013. The Company sold the retail marketing fueling stations during 2014 with an associated gain of $101.7 million. Total proceeds from

 

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the sale of the retail marketing assets were $212.0 million. The Milford Haven, Wales refinery ceased processing crude oil in May 2014. This refining operation incurred an impairment charge of $269.2 million in 2014, along with losses from operations and costs related to employee severance and other abandonment activities, which were partially offset by inventory profits arising from the sale of most of the refinery’s inventory.

Capital Expenditures

Capital expenditures from continuing operations, including exploration expenditures, were $463.6 million and $1,145.1 million for the six months ended June 30, 2016 and 2015, respectively, and $2.19 billion in 2015, $3.76 billion in 2014 and $3.97 billion in 2013. These amounts excluded capital expenditures of $0.2 million in 2015, $12.3 million in 2014, $154.6 million in 2013 related to discontinued operations, which were associated with U.K. R&M operations that were either sold or shuttered at the end of 2014, U.S. retail marketing operations spun-off in August 2013, and U.K. oil and gas assets sold in the first half of 2013. Capital expenditures included $395.5 million, $439.2 million and $435.3 million, respectively, in 2015, 2014 and 2013 for exploration costs that were expensed.

Capital expenditures for exploration and production continuing operations totaled $442.9 million and $1,119.5 million for the six months ended June 30, 2016 and 2015, respectively, and $2.13 billion in 2015, $3.74 billion in 2014 and $3.94 billion in 2013.

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

E&P capital expenditures in 2015 included $12.6 million for lease acquisitions principally in the U.S., $371.9 million for exploration activities, and $1.74 billion for oil and gas project developments. U.S. lease acquisitions included acreage extensions in the Eagle Ford Shale as well as new leases acquired in the Gulf of Mexico. Exploration activities included drilling wells in the Gulf of Mexico, Malaysia, Australia and Vietnam. Additionally, exploration activities included seismic acquisition in the Gulf of Mexico and other areas, primarily related to prospects in Australia and Southeast Asia. Development capital expenditures in 2015 included $830.2 million for the drilling and completion program in the Eagle Ford Shale; $508.6 million for Gulf of Mexico development activities including Kodiak and Dalmatian South; $116.5 million for development work in the Western Canadian Sedimentary Basin; $23.6 million for the Syncrude project; $41.7 million combined for Hibernia and Terra Nova; $67.8 million for development projects in deepwater Malaysia, including Kikeh, Kakap and Siakap; $144.3 million for oil and natural gas projects offshore Sarawak Malaysia; and $23.8 million for development of a Floating Liquefied Natural Gas project for Block H Malaysia.

E&P capital expenditures in 2014 included $92.9 million for U.S. lease acquisitions, $430.1 million for exploration activities, and $3.21 billion for oil and gas project developments. U.S. lease acquisitions included acreage extensions in the Eagle Ford Shale as well as new leases acquired in the Gulf of Mexico. Exploration activities included drilling wells in the Gulf of Mexico, Cameroon, Indonesia and Vietnam. Additionally, exploration activities included seismic acquisition in the Gulf of Mexico and other areas, primarily related to prospects in Southeast Asia and West Africa. Development capital expenditures in 2014 included $1.52 billion for the drilling and completion program in the Eagle Ford Shale; $373.7 million for Gulf of Mexico development activities; $286.0 million for development work in the Western Canadian Sedimentary Basin; $92.5 million for the Syncrude project; $64.5 million combined for Hibernia and Terra Nova; $562.9 million for development projects in deepwater Malaysia, including Kikeh, Kakap and Siakap; and $299.3 million for oil and natural gas projects offshore Sarawak Malaysia.

 

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E&P capital expenditures in 2013 included $35.6 million for lease acquisitions, $493.5 million for exploration activities, and $3.41 billion for development projects. Lease acquisitions were primarily related to acreage extensions in the Eagle Ford Shale area. Exploration activities included exploratory drilling primarily in the Gulf of Mexico, Australia, Cameroon and Brunei. Exploratory activities also included seismic and other geophysical costs primarily in the U.S., Australia, Indonesia, Vietnam and West Africa. Development expenditures in 2013 included $1.48 billion for the drilling and completion program in the Eagle Ford Shale; $230.9 million for fields in the Gulf of Mexico, including Dalmatian, which started up in 2014; $156.7 million for synthetic oil operations; $140.4 million for heavy oil at Seal; $283.5 million for Kikeh; $136.7 million for Kakap-Gumusut; $214.6 million for Siakap North-Petai; $681.3 million for Sarawak oil fields; and $49.6 million for Hibernia and Terra Nova, offshore Newfoundland.

Exploration and production capital expenditures are shown by major operating area on page F-58 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus.

Capital expenditures for discontinued operations included $114.3 million in 2013 for U.S. retail marketing operations, which primarily included station construction and other improvements in each year. U.K. refining and marketing operations had capital expenditures during the years ended December 31, 2014 and 2013 of $12.3 million and $32.2 million, respectively. U.K. E&P operations had capital expenditure of $8.1 million in 2013.

Cash Flows

Operating activities—

Net cash provided by continuing operating activities was $113.4 million for the first six-months of 2016 compared to $715.2 million during the same period in 2015. The decline in cash provided by continuing operations activities in 2016 was primarily attributable to significantly lower realized sales prices for the Company’s oil and gas production and lower volume sold during the current year, offset in part by lower lease operating expenses. Changes in noncash operating working capital from continuing operations used cash of $86.8 million during the first six-months of 2016, compared to generating cash of $107.2 million in 2015. The use of cash in 2016 included $261.8 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015.

Cash provided by operating activities of continuing operations was $1.18 billion in 2015, $3.05 billion in 2014 and $3.21 billion in 2013. Cash flows associated with formerly owned U.S. downstream, U.K. oil and gas production businesses and U.K. downstream businesses have been classified as discontinued operations in the Company’s consolidated financial statements. Cash flow provided by continuing operations was $1.87 billion lower in 2015 than in 2014 due to generally weaker crude oil and natural gas sales prices in 2015, partially offset by lower lease operating expenses and lower severance and ad valorem taxes. Cash flow provided by continuing operations was $162.1 million lower in 2014 compared to 2013. The decrease in 2014 was attributable to lower crude oil sales prices plus higher payments for interest and income taxes compared to the prior year. Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $13.4 million in 2015, $36.8 million in 2014 and $51.6 million in 2013. Operating cash flows were reduced by payments of income taxes of $118.7 million in 2015, $573.8 million in 2014 and $457.0 million in 2013. The total reductions of operating cash flows for interest paid during the three years ended December 31, 2015, 2014 and 2013 were $117.7 million, $134.8 million and $113.0 million, respectively.

Investing activities—

Proceeds from sales of property and equipment generated cash of $1,153.3 million in 2016 compared to $423.1 million in 2015. The 2016 proceeds are mainly attributable to the sale of the Company’s non-operated

 

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5% interest in Syncrude Canada Ltd. (“Syncrude”) for $739.1 million and the disposition of certain midstream assets in the Tupper area of Western Canada for $414.1 million. The prior year amount primarily related to proceeds received upon sale of a 10% interest in Malaysian assets. The uses of cash for property additions and dry holes, which including amounts expensed, were $604.6 million and $1,433.6 million in the six-month period ended June 30, 2016 and 2015, respectively.

Capital expenditures of the exploration and production business represent the most significant component of investing activities. Property additions and dry hole costs for continuing operations used cash of $2.55 billion in 2015, $3.68 billion in 2014 and $3.59 billion in 2013. Cash of $911.8 million, $986.3 million and $923.5 million was spent in 2015, 2014 and 2013, respectively, to acquire Canadian government securities with maturities greater than 90 days at the time of purchase. Proceeds from maturities or sales of Canadian government securities with maturities greater than 90 days at date of acquisition were $1,129.1 million in 2015, $899.9 million in 2014 and $664.3 million in 2013. Proceeds from sales of assets generated cash of $423.9 million in 2015, $1.47 billion in 2014 and $1.7 million in 2013. The 2015 and 2014 proceeds primarily arose due to sale of 30% of the Company’s oil and gas assets in Malaysia.

Financing activities

A significant source of cash included $701.4 million in the 2016 period and $663.3 million in 2015 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The Company borrowed $823.0 million in the 2015 period to fund capital expenditures and repurchase Company stock.

Total cash dividends to shareholders amounted to $120.5 million in 2016 and $124.6 million in 2015. In the first six months of 2015, the Company expended $250.0 million to acquire 5,236,709 shares of Common stock. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $651.2 million in the 2016 period and $629.8 million in the 2015 period. The Company repaid debt in the amount of $600.0 million in the six-month period of 2016. The debt repayment was funded using proceeds from the sale of assets. The Company had no borrowings outstanding on its $2.0 billion revolving credit facility at June 30, 2016. The Company used $450.0 million of cash in the 2015 period to repay current maturities of long-term debt.

During 2015, the Company borrowed $600.0 million under bank financing arrangements. The Company used $450.0 million cash during 2015 to repay current maturities of long-term debt. Funds from Malaysia and the U.K., which were repatriated to the U.S., tempered the Company’s net borrowings during the just completed year, as the majority of these funds were used to pay down long-term debt before year-end 2015. The Company paid $250.0 million in 2015, $375.0 million in 2014 and $500.0 million in 2013 to repurchase 5.97 million shares, 6.37 million shares and 7.86 million shares, respectively, of its Common stock. Cash used for dividends to stockholders was $245.0 million in 2015, $236.4 million in 2014 and $235.1 million in 2013. The Company increased its normal dividend rate by 12% in 2014 as the annualized dividend was raised from $1.25 per share to $1.40 per share effective in the third quarter 2014. There was no change in the dividend rate during 2015. At the date of the spin-off in 2013, Murphy USA Inc. paid Murphy Oil Corporation cash of $650.0 million, which the Company primarily used to partially repay outstanding debt. In 2015, 2014 and 2013, cash of $9.0 million, $6.8 million and $16.7 million, respectively, was used to pay statutory withholding taxes on stock-based incentive awards that vested with a net-of-tax payout.

Discontinued operations

The Company’s discontinued operations in the U.K. and U.S. required operating cash flow of $15.0 million in 2015 and $39.6 million in 2014, but provided cash flow of $427.8 million in 2013. The 2015 activities primarily related to the U.K. terminal operations which were sold in June 2015. The 2014 period included the U.K. refining

 

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and marketing activities which had poor refining margins prior to shutdown of the refinery at Milford Haven in May 2014. The 2013 period included positive operating cash flow from the U.S. retail marketing operations that were spun off to shareholders on August 30, 2013. In 2015, the sale of U.K. terminal assets generated cash of $5.0 million, and in 2014, the sale of U.K. retail marketing assets generated cash of $212.0 million. In 2013, the sale of all U.K. oil and gas assets generated cash of $282.2 million. In connection with the sales of the various U.K. assets, the Company repatriated cash from the U.K. of $184 million in 2015; $250 million in 2014; and $240 million in 2013. Cash utilized for other investing activities of discontinued operations totaled $12.5 million in 2014 and $165.7 million in 2013 and these mostly related to cash payments for capital expenditures. At December 31, 2015, the Company’s U.K. discontinued operations had cash of $7.9 million. This cash is classified within Current assets held for sale on the Consolidated Balance Sheet at year-end 2015, effectively removing this amount from the Company’s reported cash balance. This cash balance was $192.6 million lower than the cash balance of $200.5 million classified as held for sale as of December 31, 2014, primarily due to repatriation of $184 million during 2015.

Financial Condition

Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 2016, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $188.7 million in Canada and $81.4 million in Malaysia. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to spur oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada collects a 5% withholding tax on any cash repatriated to the United States through a dividend to the U.S. parent.

Working capital (total current assets less total current liabilities) at June 30, 2016 was $157.1 million, $383.3 million more than December 31, 2015, with the increase attributable to lower accounts payable for deepwater rig contract exit cost and other operating activities. Working capital amounted to a deficit of $226.2 million at year-end 2015. Total working capital declined in 2015 due to a partial paydown of long-term debt with available cash proceeds plus a significant current liability recorded for exit of deepwater rig contracts at the end of the year. The Company had working capital of $131.3 million at year-end 2014. Cash and cash equivalents at the end of 2015 totaled $283.2 million compared to $1.19 billion at year-end 2014. As described in the following paragraph, a portion of this cash held at year-end 2014 was used to pay down $450.0 million current maturities of long-term debt in January 2015. In addition to the Company’s cash position, it held short-term investments in Canadian government treasury securities of $173.3 million at year-end 2015, down $288.0 million compared to 2014. These short-term investments decreased in 2015 primarily due to an intercompany loan to an affiliated company and a lower Canadian exchange rate. These slightly longer-term Canadian investments were purchased in each year because of a tight supply of shorter-term securities available for purchase in Canada. These short-term Canadian government investments could quickly be converted to cash if a need for funds in Canada arise.

At June 30, 2016, long-term debt of $2,435.5 million had decreased by $605.1 million compared to December 31, 2015. Long-term debt was paid down in 2016 using part of the sales proceeds from Canadian asset disposition.

Long-term debt at year-end 2015 was $522.9 million higher than year-end 2014. The increase in debt in 2015 was primarily due to capital expenditures, share buyback and cash dividends, which in total exceeded cash generated from operating activities. At December 31, 2015, long-term debt represented 36.4% of total capital employed. Long-term debt at year-end 2014 was $400 million lower than year-end 2013. The debt reduction in

 

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2014 was achieved by using most of the proceeds from a 20% sale of oil and gas assets in Malaysia to repay debt. Prior to the Malaysia sale in December 2014, long-term debt had risen in 2014 due to a combination of capital expenditures, share buyback and cash dividends, which in total exceeded cash generated from operating activities. At December 31, 2014, long-term debt represented 22.8% of total capital employed. Also, at December 31, 2014, current maturities of long-term debt included $450.0 million of loans that were repaid on January 15, 2015 with proceeds from the sale of Malaysian assets. Stockholders’ equity was $5.31 billion at the end of 2015, $8.57 billion at the end of 2014 and $8.60 billion at the end of 2013. Stockholders equity declined in 2015 primarily due to impairments of assets, lower commodity prices, $250.0 million of Common stock repurchases during the year and a reduction in the foreign currency translation balance due to a weaker Canadian dollar against the U.S. dollar during the year. Stockholders equity declined in 2014 primarily due to a total of $375.0 million of Common stock repurchases during the year coupled with a reduction in the balance of foreign currency translation due to a weakening of the Canadian dollar against the U.S. dollar during the year.

Other significant changes in Murphy’s year-end 2015 balance sheet compared to 2014 included a $350.6 million decrease in accounts receivable, primarily caused by lower overall average realized sales prices at year-end 2015 compared to 2014 and the completion of the sale of 10% interest in Malaysian properties. Inventory values were $75.9 million less at year-end 2015 than in 2014 mostly due to 10% sale of Malaysian properties in January 2015. Current assets held for sale amounted to $38.3 million at December 31, 2015 and $376.1 million at December 31, 2014. The year-end 2015 amount primarily included cash held by the U.K. downstream business, amounts receivable for sales of scrap metal and other materials as the refinery is dismantled and a short-term tax receivable expected to be collected in 2016. Net property, plant and equipment decreased by $3.5 billion in 2015 primarily due to impairments of assets and the disposition of 10% of Malaysia oil and gas assets in January 2015. Deferred charges and other assets increased $164.4 million in 2015 due primarily to a net deferred tax asset position in Malaysia and the U.S. as compared to a net deferred tax liability position in 2014. Assets held for sale-noncurrent decreased by $51.0 million in 2015 primarily related to disposition of the remaining U.K. downstream assets in 2015. Current maturities of long-term debt at year-end 2015 was $446.5 million lower than at the prior year-end due to payment of a short-term debt obligation of $450.0 million in January 2015.

Accounts payable decreased by $746.0 million at year-end 2015 compared to 2014 primarily due to liabilities assumed by the purchaser of 10% of the Company’s oil and gas assets in Malaysia and lower overall costs as capital expenditures were significantly reduced due to the low commodity price environment. Income taxes payable was $54.2 million lower at year-end 2015 than at the end of 2014, primarily due to tax payments in Malaysia in 2015 and lower profits. Other taxes payable decreased $14.0 million in 2015 primarily due to lower U.S. ad valorem and severance taxes owed. Current liabilities associated with assets held for sale of $7.3 million at December 31, 2015 decreased $144.3 million compared to the prior year-end primarily due to lower liabilities after sale of the remaining U.K. downstream assets in 2015, lower employee costs and lower refinery decommissioning costs.

Noncurrent deferred income tax liabilities were $954.1 million lower at year-end 2015 mostly due to impairment of assets and the assumption of certain future tax obligations by the purchaser of 10% of the Company’s oil and gas assets in Malaysia in 2015. The noncurrent liability associated with future asset retirement obligations decreased by $48.1 million at year-end 2015 also mostly due to obligations assumed by the purchaser of Malaysian assets and revisions of prior estimates together with a lower Canadian dollar exchange rate that more than offset liabilities for new wells drilled in 2015. Noncurrent liabilities associated with assets held for sale at December 31, 2015 decreased by $8.3 million primarily due to disposition of the remaining U.K. refining and marketing business. Total stockholders’ equity of the Company decreased by $3.3 billion in 2015. A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page F-8 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus.

 

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Murphy had commitments for future capital projects of approximately $501.2 million at December 31, 2015. These commitments included $283.0 million for field development and future work in Malaysia, $109.8 million for work in the Eagle Ford Shale, $30.7 million for costs to develop deepwater Gulf of Mexico fields, and $45.2 million and $15.4 million for future work commitments offshore Vietnam and Brunei.

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company uses its internally generated funds to finance the major portion of its capital and other expenditures, but it also maintains lines of credit with banks and borrows as necessary to meet spending requirements. At December 31, 2015, the Company had access to a long-term committed credit facility in the amount of $2.0 billion with $600 million outstanding under the facility. The most restrictive of covenants under this committed credit facility limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. The committed credit facility expires in May 2017 and a one and one-half year extension is currently being pursued. At December 31, 2015, the Company had uncommitted bank credit lines of approximately $300.0 million, but no borrowings were outstanding under these lines. The Company’s ratio of long-term debt to total capital was 36.4% at year-end 2015.

In October 2015, the Company renewed its shelf registration statement on file with the Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities. The current shelf registration will expire in October 2018. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. Based on the anticipated level of 2016 capital expenditures for the Company, coupled with the current low price environment for crude oil and existing annual shareholder dividend levels, the Company anticipates that it will need to borrow funds under its long-term credit facility during 2016. The Company’s earnings for the year ended December 31, 2015 were inadequate to cover fixed charges by $3.3 billion. The Company’s ratio of earnings to fixed charges was 7.9 to 1 in 2014 and 9.5 to 1 in 2013.

Cash and invested cash are maintained in several operating locations outside the United States. At December 31, 2015, cash, cash equivalents and cash temporarily invested in Canadian government securities with greater than 90 day maturities held outside the U.S. included $235 million in Canada and $138 million in Malaysia. In addition, approximately $8 million of cash was held in the U.K. and has been classified as part of Assets held for sale in the Consolidated Balance Sheet at year-end 2015. In certain cases, the Company could incur cash 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. tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in the U.S. and foreign countries in the early years of operations when accelerated tax deductions exist 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 any cash repatriated to the U.S. See Note I of the consolidated financial statements for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

Environmental Matters

Murphy faces various environmental and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environment governance program comprised of a worldwide policy, guiding principles, annual goals and a management system, with appropriate oversight at the business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and maintenance, and through emergency and oil spill response planning to address any credible and major risks it identifies through impact assessments.

Murphy and other companies in the oil and gas industry are subject to numerous international, national, state, provincial and local environmental and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to

 

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construct, maintain and upgrade equipment and facilities, and operating costs for ongoing compliance. Murphy allocates a portion of its capital expenditure program to comply with existing and anticipated environmental laws and regulations.

The principal environmental laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials, the emission and discharge of such materials to the environment, greenhouse gas emissions, wildlife, habitat and water protection and the placement, operation and decommissioning of production equipment. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations. Any violation of applicable environmental laws, regulations or permits can give rise to significant civil and criminal penalties, injunctions, construction bans and delays, and other sanctions.

These laws, regulations and permits have been subject to frequent change and tended to become more stringent over time. For example, governmental initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the U.S. government has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations.

In addition, certain jurisdictions in which the Company operates have required, or are considering requiring, more stringent permitting, chemical disclosure, transparency, water usage, disposal and well construction requirements. Regulators are also becoming increasingly focused on air emissions from the oil and gas industry, including volatile organic compound and methane emissions. For example, Alberta has announced regulations that would require Murphy’s Seal facilities to conserve solution gas associated with primary recovery of heavy oil. In the United States, the Environmental Protection Agency has implemented requirements to reduce sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for wells that are hydraulically fractured. Any current or future air emission or other environmental requirements applicable to Murphy’s businesses could curtail its operations or otherwise result in operational delays, liabilities and increased costs.

Murphy also could be subject to strict liability for environmental contamination, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors. Contamination has been identified at certain of such sites as a result of which the Company may be required to remove or remediate previously disposed wastes, clean up contaminated soil, surface water and groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations. In addition to significant investigation and remediation costs, such matters can also give rise to third party claims for fines, personal injury and property or other environmental damage.

Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were approximately $46 million in 2015. This spending is projected to be approximately $9 million in 2016 with the reduction due to a scale back in expected overall capital project spending associated with low oil and gas prices.

Climate Change

Greenhouse gas emission regulation is becoming more stringent. Murphy is currently required to report greenhouse gas emissions from certain of its operations and, in British Columbia, is subject to a carbon tax on the purchase or use of virtually all carbon-based fuels. Under the U.S. Climate Action Plan, the Environmental Protection Agency is currently assessing how best to pursue methane emission reductions from the oil and gas sector, which process may result in further voluntary or mandated methane mitigation measures. Any limitation on or further regulation of, greenhouse gases, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict the Company’s operations,

 

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curtail demand for hydrocarbons generally and/or impose increased costs, including to operate and maintain facilities, install pollution emission controls and administer and manage emissions trading programs.

Safety Matters

The Company is subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in Murphy’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that its operations are in substantial compliance with applicable safety requirements, including general industry standards, record-keeping requirements and the monitoring of occupational exposure to regulated substances.

Other Matters

Impact of inflation

General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Prices for oil field goods and services are usually affected by the worldwide prices for crude oil.

Prior to the oil price collapse in late 2014 and 2015, the cost for oil field goods and services had generally risen in the preceding years. As noted elsewhere, oil prices have been extremely volatile over the last several years, as oil prices were quite strong in recent years, before declining dramatically in the fourth quarter of 2014 and throughout 2015 due to an oversupply of crude oil in the global marketplace. With the recent decline in oil prices, the demand for goods and services has been diminished, which is leading to significant downward pressure on the prices of these goods and services. Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. North American natural gas prices have been weak due to an oversupply of natural gas in this market. The recent severe pullback in crude oil prices has led many oil companies, including Murphy, to seek price concessions from suppliers of oil field goods and services. Due to the recent severe decline in oil prices coupled with the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Contractual obligations and guarantees

The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure commitments, and other long-term liabilities. In addition, the Company expects to extend certain operating leases beyond the minimum contractual period. Total payments due after 2015 under such contractual obligations and arrangements are shown below.

 

		Amount of Obligations
(Millions of dollars)		Total				2016				2017-2018				2019-2020				After 2020
Debt including current maturities		$	3,059.5				18.9				1,172.3				29.2				1,839.1
Operating and other leases			375.9				83.3				123.2				92.3				77.1
Capital expenditures, drilling rigs and other			915.0				735.0				173.9				3.6				2.5
Other long-term liabilities, including debt interest			2,278.0				150.5				237.1				229.5				1,660.9
Total		$	6,628.4				987.7				1,706.5				354.6				3,579.6

 

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The Company has entered into agreements to lease production facilities for various producing oil fields. In addition, the Company has other arrangements that call for future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

In 2013, the Company entered into a 25-year lease for a semi-floating production system at the Kakap field offshore Sabah, Malaysia. The Company has included the required lease obligations for this production system in the contractual obligation table above.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $81.6 million as of December 31, 2015, and all of these letters of credit expire in 2016.

Material off-balance sheet arrangements

The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2015 included operating leases of floating, production, storage and offloading vessel (FPSO) for the Kikeh oil field, floating and operating lease for a production facility at the West Patricia field, drilling contracts for onshore and offshore rigs in various countries, and oil and/or natural gas transportation contracts in the U.S. and Western Canada. The leases call for future monthly net lease payments through 2016 at West Patricia and through 2022 at Kikeh. The U.S. and Western Canada transportation contracts require minimum monthly payments through 2024. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

Outlook

Average worldwide crude oil prices in July 2016 are similar to the average prices during the second quarter of 2016 with Brent and WTI trading at near parity. Non-OPEC crude oil production continues to slide, but total commercial inventories that remain at elevated levels will be slow to clear. Driven by strong seasonal power demand, North American natural gas prices improved in July 2016 relative to the second quarter of 2016 as the U.S commercial inventory excess to the prior year was trimmed by nearly 60% since the end of the withdrawal season in March. The Company expects its total oil and natural gas production to average 167,500 to 169,500 barrels of oil equivalent per day in the third quarter 2016. The Company currently anticipates total capital expenditures for the full year 2016 to be approximately $620 million, excluding the cost to acquire the Kaybob Duvernay and liquids rich Montney interests in Canada.

The Company will primarily fund its capital program and property acquisitions in 2016 using operating cash flow and proceeds from recent divestitures, but supplements funding where necessary using borrowings under available credit facilities. As of June 30, 2016, there were no funds borrowed under its revolving credit facility. The Company’s current 2016 outlook calls for no borrowings under its revolving credit agreement during the second of half of 2016. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that unanticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects. The Company’s existing revolving credit facility matures in June 2017, and the Company entered into an amendment to the existing revolving credit facility on August 10, 2016 to reduce the commitments of the existing lenders that have committed to the New Revolving Credit Facility and allow for the incurrence of the New Revolving Credit Facility.

The significant reduction in the sales prices of crude oil has caused the Company to reduce capital expenditures, including development drilling and completion operations in North America. The Company’s capital spending program in 2016 will be well below 2015 levels. The reduced level of capital expenditures, if it continues, could lead to lower production levels in future periods. A continuation of low oil and/or gas prices or further

 

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deterioration therein, could lead to negative future effects on the Company, which could include reductions in proved reserves, additional impairment charges, the necessity for further cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its Common stock.

As of August 3, 2016 the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

 

Commodities		Contract or Location		Dates		Average Volumes per Day		Average Prices
U.S. Oil		West Texas Intermediate		July – Dec. 2016		25,000 bbls/d		$50.67 per bbl.
U.S. Oil		West Texas Intermediate		Jan - Dec. 2017		7,000 bbls/d		$50.10 per bbl.
Canadian Natural Gas		TCPL–NOVA System		July – Dec. 2016		99 mmcf/d		C$3.00 per mcf
Canadian Natural Gas		TCPL–NOVA System		Jan. 2017 – Dec. 2020		59 mmcf/d		C$2.81 per mcf

Prices for the Company’s primary products are often quite volatile. The price for crude oil is primarily affected by the levels of supply and demand for energy. Anticipated future variances between the predicted demand for crude oil and the projected available supply can lead to significant movement in the price of crude oil. In January 2016, West Texas Intermediate crude oil traded in a band between about $28.46 and $36.76 per barrel and averaged about $31.78 for the full month. NYMEX natural gas traded in a band of $2.12 to $2.53 per MMBTU, with an average of $2.27 during this same time. Both these oil and natural gas prices are well below the average prices achieved in 2015. The Company continually monitors the prices for its main products and often alters its operations and spending plans based on these prices.

Geographically, the current estimate of E&P capital in 2016 is spread approximately as follows: 38% for the United States, 22% for Malaysia, 19% for Canada and 21% for all other areas. Spending in the U.S. is primarily associated with development programs in the Eagle Ford Shale area of South Texas. In Malaysia, the majority of the spending is for continued development of the Kikeh, Kakap-Gumusut and Siakap North-Petai fields in Block K, oil development projects offshore Sarawak in Blocks SK 309/311 and development of a FLNG project in Block H. Canadian spending is primarily associated with natural gas development operations in Western Canada, plus ongoing operations at East Coast offshore areas. Capital and other expenditures will be routinely reviewed during 2016 and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

The Company currently expects production in 2016 to average between 173,000 and 177,000 barrels of oil equivalent per day. This level of production is less than 2015 due primarily to a significantly lower capital spending program in 2016. A key assumption in projecting the level of 2016 Company production is the anticipated well decline rate following a period of reduced drilling activity in the Eagle Ford Shale area of South Texas where a major drilling and completion operation has been scaled back due to weak oil prices. Other key factors in meeting 2016 production targets is the rate of decline of natural gas wells at the Tupper area in Western Canada, continued reliability of production at significant operations such as Kikeh, Syncrude, Hibernia and Terra Nova, and the continued customer demand for natural gas from the Company’s offshore Malaysia fields.

At year-end 2015, the Company had two deepwater drilling rigs under contract in the Gulf of Mexico that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The contract originally scheduled to expire in November 2016 was terminated by the Company. The remaining day rate commitments payable in the first quarter of 2016 under both contracts total approximately $271 million.

 

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In the falling commodity price environment during 2015, the Company gained price concessions from many of its vendors that supply oil field goods and services. Certain costs are expected to retreat further in 2016 at the current level of oil and gas prices. It is unclear how successful the Company will be with achieving additional meaningful reductions in the cost of oil field goods and services.

In April 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received by Murphy upon closing of the transaction was $414.1 million. A gain on sale of approximately $187 million is being deferred and recognized over the next 20 years in the Canadian operating segment. The Company amortized $1.8 million of the deferred gain in the second quarter of 2016. The remaining deferred gain is included as a component of deferred credits and other liabilities on the Company’s Consolidated Balance Sheet.

In a separate transaction, the same subsidiary signed a definitive agreement to acquire a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Montney lands in Alberta, the majority of which is unproven. Under the terms of the joint venture the total consideration amounts to approximately $375 million, of which Murphy will pay approximately $206.7 million in cash at closing and the remaining $168 million in the form of a carry for a period of up to five years. This transaction closed in May 2016.

As of December 31, 2015, Murphy’s long-term debt was rated “BBB” with a negative outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a negative outlook by Moody’s Investor Services (Moody’s). In February 2016, S&P, Fitch, and Moody’s each downgraded the Company’s credit rating on its outstanding notes. The Company’s long-term debt ratings are currently “BBB-” with stable outlook by S&P, “BB+” with stable outlook by Fitch, and “B1” with negative outlook by Moody’s. Fitch’s and Moody’s actions reduced the Company’s credit rating to below investment grade status. These downgrades could adversely affect our cost of capital and our ability to raise debt in public markets in future periods. Based on the downgrade by Moody’s, the coupon rates on $1.5 billion of the Company’s outstanding notes were increased by 1.00% effective June 1, 2016.

Accounting changes and recent accounting pronouncements

Presentation of Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs. The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability. These costs have historically been recorded as an asset, rather than a direct reduction of debt. This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense. The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted. The Company elected to adopt this ASU early, effective with the first quarter of 2015. This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances. A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption. The retrospective adjustment to the December 31, 2014 Balance Sheet is shown below:

 

(Thousands of dollars)		As Previously Reported December 31, 2014				Adjustment Effect				December 31, 2014 As Adjusted
Deferred charges and other assets		$	81,151				(18,569	)			62,582
Long-term debt			(2,536,238	)			18,569				(2,517,669	)

Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an ASU that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current

 

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requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. The Company will adopt this guidance in 2016 and does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures.

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of this revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Significant accounting policies—In preparing the Company’s consolidated financial statements in accordance with U.S. GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.

 

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Oil and gas proved reserves—Oil and gas proved reserves are defined by the SEC as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether a deterministic method or probabilistic method is used for the estimation. Proved developed reserves of oil and gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use an unweighted average of the oil and gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations. Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional

 

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information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities.

Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and gas reserves revisions that will be required in future periods. The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented elsewhere in this prospectus supplement. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish “reasonable certainty” of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high-degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2015 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

 

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Successful efforts accounting—The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development capital expenditures are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company’s engineers. In some cases, a determination of whether a drilled well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. Under current accounting rules, the Company holds well costs in Property, Plant and Equipment in the Consolidated Balance Sheet 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.

Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred. In 2015, the costs associated with one well in the Gulf of Mexico, which was drilled in 2009, was expensed due to it being unlikely to be

 

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developed due to distressed commodity prices. In 2014, the costs associated with four wells offshore Block PM 311 in Malaysia, which were drilled in 2004 and 2005, were written off due to denial of the Company’s request to the Malaysian government for an extension to the gas holding period. Additionally, the cost of one well in the Gulf of Mexico, which was drilled in 2008, was written off because low-expected futures prices for natural gas at year-end 2014 rendered development opportunities for the field to be uneconomic. In 2013, two wells offshore Sarawak drilled in 2005 and 2006 were expensed when the Company decided not to move forward with development plans for this area.

 

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Impairment of long-lived assets—The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment (PPE) in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its PPE for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. Goodwill is evaluated for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital and abandonment costs, and future inflation levels. The need to test a long-lived asset for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental regulations or tax laws. All of these same factors must be considered when evaluating a property’s carrying value for possible impairment.

In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events, which include projections of future sales prices, future capital expenditures and future operating expenses. Future marketing or operating decisions, such as closing or selling certain assets, and future regulatory or tax changes could also impact the Company’s conclusion about potential asset impairment.

The Company recorded impairment expense of $2,493.2 million in 2015 to reduce the carrying value of producing heavy oil properties in Western Canada, producing offshore properties in Malaysia, and producing and non-producing properties in the Gulf of Mexico to their estimated fair value due to significant declines in future oil and gas prices since the end of 2014. 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 Company recorded impairment expense of $14.3 million in 2014 for one producing gas field in the Gulf of Mexico due to low year-end natural gas futures prices

 

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that would not permit full recovery of the investment in the field. Additionally, in 2014 the Company recorded an impairment charge of $37.0 million to write-off the remaining goodwill originally recorded with a business acquired in Western Canada in 2000. Low oil and gas prices at year-end 2014 led to the conclusion that this goodwill was no longer recoverable. The Company recorded writedowns of $269.2 million in 2014 and $73.0 million in 2013 for discontinued U.K. refining and marketing operations based on a fair value assessment of these assets being abandoned and/or held for sale at year-ends 2014 and 2013. Murphy recorded impairment expense of $21.6 million in 2013 related to the sale of Kainai properties in Western Canada at less than carrying value.

Based on an evaluation of expected future cash flows from properties at year-end 2015, the Company did not have any other significant properties with carrying values that were impaired at that date. The expected future sales prices for crude oil and natural gas used in the evaluation were based on quoted future prices for the respective production periods. These quoted prices are based on market expectations for future hydrocarbon prices, which can often be significantly higher or lower in future periods compared to current spot prices. If quoted prices for future years had been weaker, the lower level of projected cash flows for properties could have led to additional impairment charges being recorded for certain properties in 2015. In addition, one or a combination of other factors such as lower future oil and/or natural gas prices, lower future production volumes, higher future costs, or the actions of government authorities could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.

 

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Income taxes—The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets mostly relating to basis differences for property, equipment and inventories, and liabilities for dismantlement and retirement benefit plan obligations. The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization. A valuation allowance has been recognized for deferred tax assets related to basis differences for Blocks PM 311/312 and SK 314A in Malaysia, for exploration licenses in certain areas, the largest of which are Australia, Indonesia and Brunei, and for certain basis differences in the U.K. due to management’s belief that these assets cannot be deemed to be realizable with any degree of confidence at this time.

In 2015, Murphy recognized $188.5 million in noncash tax expense primarily associated with using a U.S. deferred tax asset that would otherwise have carried forward to future years with a dividend from a foreign subsidiary. In 2014, the Company recognized U.S. income tax benefits of $95.9 million related to tax deductions associated with investments in upstream operations in Cameroon, Kurdistan and certain permits in Australia where the Company is exiting operations, as well as a Malaysian tax benefit of $65.4 million related to recognition of the expected future realization of tax deductions for prior-year Block H exploration expenses following sanction of the development plan for this field during 2014. In 2013, the Company recognized U.S. income tax benefits of $133.5 million related to tax deductions associated with investments in upstream operations in Republic of the Congo and Kurdistan, where the Company is exiting operations.

 

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Accounting for retirement and postretirement benefit plans—Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most full-time employees. Effective with the spin-off of the Company’s former U.S. retail marketing operation (MUSA) on August 30, 2013, significant modifications were made to the U.S. defined benefit pension plan. Certain employees’ benefits under

 

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the U.S. plan were frozen at that time. No further benefit service will accrue for the affected employees, however, the plan will recognize future compensation increases after the spin-off. In addition, all previously unvested benefits became fully vested at the spin-off date. For those affected active employees of the Company, additional U.S. retirement plan benefits will accrue in future periods under a cash balance formula. Upon the spin-off of MUSA, the Company retained all vested pension defined benefit and other postretirement benefit obligations associated with current and former employees of this business. No additional benefit will accrue for employees of MUSA under the Company’s retirement plan after the separation date.

The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is determined by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Upon disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of separation from Murphy.

Based on bond yields at December 31, 2015, the Company has used a weighted average discount rate of 4.55% at year-end 2015 for the primary U.S. plans. This weighted average discount rate is 0.43% higher than a year earlier, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago. Although the Company presently assumes a return on plan assets of 6.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tends to buffer the current year’s retirement plan expenses from wide swings in liabilities and asset valuations. The Company’s retirement and postretirement plan expenses in 2016 are expected be higher than 2015 due to larger costs associated with previously unrecognized actuarial losses at year-end 2015. However, cash contributions are anticipated to be lower in 2016 particularly associated with its domestic retirement plan. In 2015, the Company paid $31.4 million into various retirement plans and $3.8 million into postretirement plans. In 2016, the Company is expecting to fund payments of approximately $8.5 million into various retirement plans and $5.4 million for postretirement plans.

The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected. Although Congress passed the Moving Ahead for Progress in the 21st Century Act, which permits certain companies to reduce retirement plan contributions in the near term, this Act does not reduce the Company’s overall funding requirements in the long-

 

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term. As described above, the Company’s retirement and postretirement expenses are sensitive to certain assumptions, primarily related to discount rates and assumed return on plan assets. A 0.5% decline in the discount rate would increase 2016 annual retirement and postretirement expenses by $2.9 million and $0.6 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2016 retirement expense by $2.5 million.

 

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Legal, environmental and other contingent matters—A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company.

 

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

 

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

 

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Revenue from Contracts with Customers—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

 

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Business and properties

Summary

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. For reporting purposes, Murphy’s exploration and production activities are subdivided into four geographic segments, including the United States, Canada, Malaysia and all other countries. Additionally, “Corporate” activities include interest income, interest expense, foreign exchange effects and administrative costs not allocated to the segments. The Company’s corporate headquarters are located in El Dorado, Arkansas.

The Company has transitioned from an integrated oil company to an enterprise entirely focused on oil and gas exploration and production activities. This transition was finalized through the sale of our United Kingdom retail marketing assets during 2014, followed by the sale of our remaining downstream assets in the U.K. in the second quarter of 2015.

At December 31, 2015, Murphy had 1,258 employees.

Exploration and Production

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide. The Company’s exploration and production management team directs the Company’s worldwide exploration and production activities. This business maintains upstream operating offices in other locations around the world, with the most significant of these including Houston, Texas, Calgary, Alberta and Kuala Lumpur, Malaysia.

During 2015, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company—USA (Murphy Expro USA), in Malaysia, Australia, Brunei, Vietnam, and Namibia by wholly owned Murphy Exploration & Production Company—International (Murphy Expro International) and its subsidiaries, and in Western Canada and offshore Eastern Canada by wholly- owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries. Murphy’s hydrocarbon production in 2015 was in the United States, Canada and Malaysia. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in northern Alberta. In December 2014 the Company sold 20% of its interests in Malaysia; a further sale of an additional 10% of its interests in Malaysia was completed in January 2015. Unless otherwise indicated, all references to the Company’s oil, natural gas liquids and natural gas production volumes and proved crude oil, natural gas liquids and natural gas reserves are net to the Company’s working interest excluding applicable royalties. Also, unless otherwise indicated, references to oil throughout this prospectus supplement could include crude oil, condensate and natural gas liquids where applicable volumes includes a combination of these products.

Murphy’s worldwide crude oil, condensate and natural gas liquids production in 2015 averaged 136,634 barrels per day. As described above, the Company sold 30% of its working interest in Malaysia in late 2014 and early 2015. While total liquids production decreased 10% in 2015 compared to 2014, production for the twelve month period ended December 31, 2015 was slightly above the 2014 period as adjusted for the sale in Malaysia. The increase in 2015 when adjusted for the sale was primarily due to higher crude oil and natural gas liquids production in the Eagle Ford Shale area of South Texas. The Company’s worldwide sales volume of natural gas averaged 428 million cubic feet (MMCF) per day in 2015. While the Company’s worldwide sales volume of natural gas in 2015 was down 4% from 2014 levels production for the twelve month period ended December 31, 2015 increased 11% compared to the 2014 period as adjusted for the Malaysia sale. The increase in natural gas sales volume in 2015 when adjusted for the sale was primarily attributable to higher gas production volumes in the Eagle Ford Shale area of South Texas and Tupper area in Western Canada. Growth in oil and gas production volumes occurred due to further development drilling in the Eagle Ford Shale and Tupper area. Total worldwide

 

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2015 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 207,903 barrels per day, a decrease of 8% compared to 2014, but when adjusted for the sale in Malaysia increased 4% compared to 2014. If the combined sale of 30% interest in Malaysia had occurred on January 1, 2014, total pro forma daily oil and natural gas production volumes would have been approximately 135,100 barrels and 386 MMCF, respectively, in 2014. The 30% sale in Malaysia in late 2014 and early 2015 represented 2014 production of approximately 26,600 barrels of oil equivalent per day (boepd); excluding these volumes, pro forma 2014 production would have been approximately 199,400 boepd.

Total production in 2016 is currently expected to average between 173,000 and 177,000 boepd. Through June 30, 2016, total production in 2016 averaged 182,604 boepd. The projected production decrease in 2016 is primarily due to lower anticipated overall capital spending of more than 70% during the year, excluding the acquisition cost for the Kaybob Duvernay and liquids rich Montney.

United States

In the United States, Murphy primarily has production of crude oil, natural gas liquids and natural gas from fields in the Eagle Ford Shale area of South Texas and in the deepwater Gulf of Mexico. The Company produced 70,675 barrels of crude oil and gas liquids per day and approximately 87 MMCF of natural gas per day in the U.S. in 2015. These amounts represented 52% of the Company’s total worldwide oil and 20% of worldwide natural gas production volumes. The Company holds rights to approximately 157 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and gas play. Total 2015 oil and natural gas production in the Eagle Ford area was 54,883 barrels per day and approximately 38 MMCF per day, respectively. On a barrel of oil equivalent basis, Eagle Ford production accounted for 72% of our total U.S. production volumes in 2015. Due to scale back of drilling and infrastructure development activities related to weak oil prices, production in the Eagle Ford Shale is forecast to decline and average approximately 41,200 barrels of oil and gas liquids per day and 30 MMCF of natural gas per day in 2016. At December 31, 2015, the Company’s proved reserves in the Eagle Ford Shale area totaled 207.9 million barrels of crude oil, 32.1 million barrels of natural gas liquids, and 166 billion cubic feet of natural gas.

During 2015, approximately 28% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico. Approximately 84% of Gulf of Mexico production in 2015 was derived from four fields, including Dalmatian, Medusa, Front Runner and Thunder Hawk. The Company holds a 70% interest in Dalmatian in DeSoto Canyon Blocks 4, 48 and 134, 60% interest in Medusa in Mississippi Canyon Blocks 538/582, and 62.5% working interests in the Front Runner field in Green Canyon Blocks 338/339 and the Thunder Hawk field in Mississippi Canyon Block 734. During 2014, the Company acquired a 29.1% non-operated interest in the Kodiak field in Mississippi Canyon Blocks 727/771. Total daily production in the Gulf of Mexico in 2015 was 15,792 barrels of oil and approximately 49 MMCF of natural gas. Production in the Gulf of Mexico in 2016 is expected to total approximately 14,000 barrels of oil and gas liquids per day and 23 MMCF of natural gas per day. At December 31, 2015, Murphy had total proved reserves for Gulf of Mexico fields of 34.2 million barrels of oil and gas liquids and 66 billion cubic feet of natural gas. Total U.S. proved reserves at December 31, 2015 were 238.9 million barrels of crude oil, 35.4 million barrels of natural gas liquids, and 232 billion cubic feet of natural gas.

Canada

In Canada, the Company holds one wholly-owned heavy oil area and one wholly-owned natural gas area in the Western Canadian Sedimentary Basin (WCSB). In addition, the Company owns interests in three non-operated assets—the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin and Syncrude Canada Ltd. in northern Alberta. Daily production in 2015 in the WCSB averaged 5,456 barrels of mostly heavy oil and approximately 197 MMCF of natural gas. The Company has 101 thousand net acres of Montney mineral rights, which includes the Tupper natural gas producing area located in northeast British Columbia. The Company has 267 thousand net acres of mineral rights in the Seal field located in the Peace River oil sands area

 

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of northwest Alberta. Oil and natural gas daily production for 2016 in Western Canada, excluding Syncrude, is expected to average 3,600 barrels and approximately 212 MMCF, respectively. The expected decrease in oil production in 2016 arises from well declines and selective economic related well shut-ins in the Seal area due to lower heavy oil prices. The expected increase in natural gas volumes in 2016 is primarily the result of new wells brought on line in the Tupper area and improved performance. Total WCSB proved liquids and natural gas reserves at December 31, 2015, excluding Syncrude, were approximately 4.6 million barrels and 894 billion cubic feet, respectively.

Murphy has a 6.5% working interest in Hibernia, while at Terra Nova the Company’s working interest is 10.475%. Oil production in 2015 was about 4,400 barrels of oil per day at Hibernia and 3,000 barrels per day at Terra Nova. Hibernia production declined in 2015 due to maturity of existing wells, while Terra Nova production was slightly higher in 2015 due to higher uptime. Oil production for 2016 at Hibernia and Terra Nova is anticipated to be approximately 5,200 barrels per day and 2,700 barrels per day, respectively. Total proved oil reserves at December 31, 2015 at Hibernia and Terra Nova were approximately 16.3 million barrels and 7.4 million barrels, respectively.

As of December 31, 2015, Murphy owned a 5% non-operated working interest in Syncrude Canada Ltd. (“Syncrude”), a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets, which include three coking units, to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Production in 2015 was about 11,700 net barrels of synthetic crude oil per day. Total proved synthetic oil reserves for Syncrude at year-end 2015 were 114.8 million barrels. Murphy closed the sale of its 5% interest in Syncrude to Suncor Energy Inc. in June 2016 for a purchase price of $739.1 million.

Malaysia

In Malaysia, the Company has majority interests in eight separate production sharing contracts (PSCs). The Company serves as the operator of all these areas other than the unitized Kakap-Gumusut field. The production sharing contracts cover approximately 3.68 million gross acres. In December 2014 and January 2015, the Company sold 30% of its interest in most of its Malaysian oil and gas assets.

Murphy has a 59.5% interest in oil and natural gas discoveries in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. Approximately 15,900 barrels of oil and gas liquids per day were produced in 2015 at Blocks SK 309/311. Oil and gas liquids production in 2016 at fields in Blocks SK 309/311 is anticipated to total about 13,500 barrels of oil per day, with the reduction from 2015 primarily related to natural field decline. The Company has a gas sales contract for the Sarawak area with PETRONAS, the Malaysian state-owned oil company, and has an ongoing multi-phase development plan for several natural gas discoveries on these blocks. The gas sales contract allows for gross sales volumes of 250 MMCF per day through September 2021, but allows the Company to deliver higher sales volumes as requested. Total net natural gas sales volume offshore Sarawak was about 122 MMCF per day during 2015 (gross 272 MMCF per day). Sarawak net natural gas sales volumes are anticipated to be approximately 114 MMCF per day in 2016. Total proved reserves of liquids and natural gas at December 31, 2015 for Blocks SK 309/311 were 13.3 million barrels and approximately 203 billion cubic feet, respectively.

The Company made a major discovery at the Kikeh field in deepwater Block K, offshore Sabah, Malaysia, in 2002 and added another discovery at Kakap in 2004. An additional discovery was made in Block K at Siakap North in 2009. The Company has interests in three Block K discovered fields, which include Kikeh (56%), Kakap (8.6%) and Siakap North (22.4%) (hereafter “Siakap”). Total gross acreage held by the Company in Block K as of December 31, 2015 was approximately 82,000 acres. Production volumes at Kikeh averaged approximately 14,700 barrels of oil per day during 2015. Oil production at Kikeh is anticipated to average approximately

 

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10,500 barrels per day in 2016. The reduction in Kikeh oil production in 2016 is primarily attributable to overall field decline. The Kakap field in Block K is operated by another company and was jointly developed with the Gumusut field owned by others. Early production began in late 2012 at Kakap via a temporary tie-back to the Kikeh production facility. The primary Kakap main field production facility was completed and full-field production started up in October 2014.

Kakap oil production in 2015 totaled about 7,000 net barrels of oil per day. In 2016, Kakap production is expected to average near 9,100 barrels of oil per day. The Siakap oil discovery was developed as a unitized area with the Petai field owned by others, and the combined development is operated by Murphy, with a tie-back to the Kikeh field. Production began in 2014 at Siakap, and daily production averaged near 4,000 barrels of oil for 2015 at this field. In 2016, Siakap field production is expected to average 2,600 barrels of oil per day. The Company has a Block K natural gas sales contract with PETRONAS that calls for gross sales volumes of up to 120 MMCF per day. Gas production in Block K will continue until the earlier of lack of available commercial quantities of associated gas reserves or expiry of the Block K production sharing contract. Natural gas production in Block K in 2015 totaled approximately 22 MMCF per day. Daily gas production in 2016 in Block K is expected to average about 12 MMCF per day. Total proved reserves booked in Block K as of year-end 2015 were 61.8 million barrels of crude oil and about 33 billion cubic feet of natural gas.

The Company also has an interest in deepwater Block H offshore Sabah. In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H. The Company followed up Rotan with several other nearby discoveries. Following the partial sell down, Murphy’s interests in Block H range between 42% and 56%. Total gross acreage held by the Company at year-end 2015 in Block H was 15.99 million acres. In early 2014, PETRONAS and the Company sanctioned a Floating Liquefied Natural Gas (FLNG) project for Block H, and agreed terms for sales of natural gas to be produced with prices tied to an oil index. First production is currently expected at Block H in 2018. At December 31, 2015, total natural gas proved reserves for Block H were approximately 311 billion cubic feet.

The Company has a 42% interest in a gas holding area covering approximately 2,000 gross acres in Block P. This interest can be retained until January 2018.

In May 2013, the Company acquired an interest in shallow-water Malaysia Block SK 314A. The PSC covers a three year exploration period. The Company’s working interest in Block SK 314A is 59.5%. This block includes 1.12 million gross acres. The Company has a 70% carry of a 15% partner in this concession through the minimum work program. The first exploration wells were drilled in 2015 for this block.

In February 2015, the Company acquired a 50% interest in offshore Block SK 2C. The Company operates the block, which includes 1.08 million gross acres. The concession carries one well commitment during the one-year exploration period. The first exploration period has been extended for six months. At the expiration of the first exploration period, the Company can opt to extend for two additional years by agreeing to drill another well.

Murphy has a 75% interest in gas holding agreements for Kenarong and Pertang discoveries made in Block PM 311 located offshore peninsular Malaysia. An application for an extension of a gas holding agreement was presented to PETRONAS in 2014, but the application was rejected. Due to the uncertainty of the future production of the gas discovered in Block PM 311, in 2014 the Company wrote off the prior-year well costs of $47.4 million related to Kenarong and Pertang. The Company never included natural gas for Block PM 311 in its proved gas reserves.

Australia

In Australia, the Company holds eight offshore exploration permits and serves as operator of six of them.

 

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The first permit was acquired in 2007 with a 40% interest in Block AC/P36 in the Browse Basin. Murphy renewed the exploration permit for an additional five years and in that process relinquished 50% of the gross acreage; the license now covers 482 thousand gross acres and expires in 2019. In 2012, Murphy increased its working interest in the remaining acreage to 100% and subsequently farmed out a 50% working interest and operatorship. The existing work commitment for this license includes further geophysical work.

In May 2012, Murphy was awarded permit WA-476-P in the Carnarvon Basin, offshore Western Australia. The Company holds 100% working interest in the permit which covers 177 thousand gross acres. The WA-476-P permit has a primary term work commitment consisting of seismic data purchase and geophysical studies, and all primary term commitments have been completed for this permit. This permit expires in 2018.

The Company also acquired permit WA-481-P in the Perth Basin, offshore Western Australia, in August 2012. Murphy holds a 40% working interest and operatorship of the permit, which covers approximately 4.30 million gross acres. The work commitment calls for 2D and 3D seismic acquisition and processing, geophysical work and three exploration wells. Three wells were drilled on the license in 2015. All three wells were unsuccessful and costs were expensed. This permit expires in 2018.

In November 2012, Murphy acquired a 20% non-operated working interest in permit WA-408-P in the Browse Basin. The permit comprises approximately 417 thousand gross acres and expires in 2016. Two wells were drilled on the license in 2013. The first well found hydrocarbon but was deemed commercially unsuccessful and was written off to expense. The second well was also unsuccessful and costs were expensed in 2013.

The Company was awarded permit EPP43 in the Ceduna Basin, offshore South Australia, in October 2013. The Company operates the concession and holds a 50% working interest in the permit covering approximately 4.08 million gross acres. The exploration permit has commitments for 2D and 3D seismic, to which acquisition was completed in the first half of 2015. This permit expires in 2020.

In April 2014 and June 2014, Murphy was awarded licenses AC/P57 and AC/P58 in the Vulcan Sub Basin, offshore Western Australia. The respective blocks cover approximately 82 thousand and 692 thousand gross acres, respectively. These exploration permits cover six years each and require 3D seismic reprocessing and a gravity survey.

In March 2015, Murphy was awarded AC/P59 license, another acreage position in the Vulcan Sub Basin, offshore Western Australia. The block covers approximately 300 thousand gross acres. The exploration permit covers six years and requires 3D seismic reprocessing, which began in December 2015.

Brunei

In late 2010, the Company entered into two production sharing agreements for properties offshore Brunei. The Company had a 5% working interest in Block CA-1 and a 30% working interest in Block CA-2. In 2015, the Company exercised a preemptive right that increased its working interest in Block CA-1 to 8.051%. The CA-1 and CA-2 blocks cover 1.44 million and 1.49 million gross acres, respectively. Three successful wells were drilled in Block CA-1 in 2012 and three wells were successfully drilled in Block CA-2 in 2013. The partnership group is evaluating development options for these blocks.

Vietnam

In November 2012, the Company signed a PSC with Vietnam National Oil and Gas Group and PetroVietnam Exploration Production Company, whereby it acquired 65% interest and operatorship of Blocks 144 and 145. The blocks cover approximately 6.55 million gross acres and are located in the outer Phu Khanh Basin. The Company acquired 2D seismic for these blocks in 2013.

 

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In June 2013, the Company acquired a 60% working interest and operatorship of Block 11-2/11 under a PSC. The block covers 677 thousand gross acres. The Company acquired 3D seismic and performed other geological and geophysical studies in this block in 2013. This concession carries a three-well commitment.

In June 2014, the Company farmed into Block 13-03. The Company has a 20% working interest in this concession which covers 853 thousand gross acres. Murphy expensed an unsuccessful exploration well drilled in the block in 2014.

In August 2015, the Company signed a farm-in agreement to acquire 35% of Block 15-1/05 that is pending government approval and assignment.

Indonesia

The Company has interests in two exploration licenses in Indonesia and serves as operator of these concessions. In December 2010, Murphy entered into a PSC in the Wokam II block, offshore West Papua, Moluccas and Papua. Murphy has a 100% interest in the block covering 1.22 million gross acres. The three-year work commitment called for seismic acquisition and processing, which the Company completed in 2013. The Company requested relinquishment of this license in 2015 and final government approval is pending.

In November 2011, the Company acquired a 100% interest in a PSC in the Semai IV block, offshore West Papua. The concession includes 873 thousand gross acres, and the agreement called for work commitments of seismic acquisition and processing, which were undertaken in 2014. The Company requested relinquishment of this license in 2015 and final government approval is pending.

In November 2008, Murphy entered into a PSC in the Semai II block, offshore West Papua. The Company has a 28.3% interest in the block which covered about 543 thousand gross acres after a required partial relinquishment of acreage during 2012. 3D seismic was acquired in 2010 and three unsuccessful exploration wells have been drilled in the block. The Company requested relinquishment of this license in 2014 and final government approval is pending.

In May 2008, the Company entered into a production sharing agreement at a 100% interest in the South Barito block in south Kalimantan on the island of Borneo. Following contractually mandated acreage relinquishment in 2012, the block covered approximately 745 thousand gross acres. The contract granted a six-year exploration term with an optional four-year extension. The Company requested relinquishment of this license in 2014 and final government approval is pending.

Equatorial Guinea

In December 2012, Murphy signed a PSC for block “W” offshore Equatorial Guinea, with a 45% working interest and operatorship. The government ratified the contract in April 2013. The block is located offshore mainland Equatorial Guinea and encompasses 557 thousand gross acres with water depths ranging from 1,200 to 2,000 meters. The initial exploration period of five years is divided into two sub-periods, a first sub-period of three years and a second sub-period of two years. The first sub-period may be extended one year, and the extension carries an obligation to drill one well. Entering into the second sub-period carries an obligation to drill an additional well. In early 2014, Murphy completed acquisition of new 3D seismic over the entire block. The Company withdrew from this block in 2015 and is currently awaiting government approval to assign its interest to the joint venture partner.

Namibia

In March 2014, the Company acquired a 40% working interest and operatorship of Blocks 2613 A/B. The Company acquired the working interest through a farm-out arrangement under the existing petroleum

 

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agreement entered into in October 2011. The block encompasses 2,734 thousand gross acres with water depths ranging from 400 to 2,500 meters. The initial exploration period of four years may be extended one year. Entering the first renewal period has the obligation to drill an exploration well. Entering the second renewal period has the obligation to drill an additional well. In 2014, Murphy completed acquisition of new 3D seismic over the block. Using the available seismic data, the Company is evaluating the potential for drilling.

Cameroon

In October 2011, Murphy was granted government approval to acquire a 50% working interest and operatorship of the Ntem concession. The working interest was acquired through a farm-out agreement of the existing production sharing contract. The Ntem block, situated in the Douala Basin offshore Cameroon, encompasses 573 thousand gross acres, with water depths ranging from 300 to 1,900 meters. The concession was in force majeure until January 2014. With force majeure lifted, the Company drilled an unsuccessful exploration well on the Ntem prospect in 2014. The Company declared force majeure again in May 2014. The Company withdrew from this block in 2015.

Suriname

In December 2011, Murphy signed a PSC with Suriname’s state oil company, Staatsolie Maatschappij Suriname N.V. (Staatsolie), whereby it acquired a 100% working interest and operatorship of Block 48 offshore Suriname. The block encompasses 794 thousand gross acres with water depths ranging from 1,000 to 3,000 meters. In early 2014, Murphy farmed out a portion of its working interest in Block 48, thereby reducing its interest from 100% to 50% and in early 2015 Murphy relinquished its license in this block.

Republic of the Congo

The Company formerly had interests in Production Sharing Agreements covering two offshore blocks in Republic of the Congo—Mer Profonde Sud (MPS) and Mer Profonde Nord (MPN). In 2005, Murphy made an oil discovery at Azurite Marine #1 in the southern block, MPS. Total oil production in 2013 averaged 1,000 barrels per day at Azurite for the Company’s 50% interest. The field was shut down and ceased production in the fourth quarter of 2013 and abandonment operations were completed in 2014. Abandonment and other exit charges of $82.5 million were recorded in 2013 associated with the earlier than anticipated shutdown of the Azurite field. The MPN block exploration license expired on December 30, 2012 and MPS block exploration license expired in March 2013. Murphy decommissioned the Azurite field upon completion of abandonment in 2014 and has exited the country.

United Kingdom—Discontinued Operations

Murphy produced oil and natural gas in the United Kingdom sector of the North Sea for many years. In 2013, Murphy sold all of its oil and gas properties in the U.K. with an after-tax gain of $216.1 million on the sale. Total 2013 production in the U.K. on a full-year basis amounted to about 600 barrels of oil per day and 1 MMCF of natural gas per day. The Company has accounted for U.K. oil and gas activities as discontinued operations for all periods presented.

Ecuador—Discontinued Operations

Murphy sold its 20% working interest in Block 16, Ecuador in March 2009.

 

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Proved Reserves

Total proved reserves for crude oil, synthetic oil, natural gas liquids and natural gas as of December 31, 2015 are presented in the following table.

 

		Proved Reserves
		Crude Oil				Synthetic Oil				Natural Gas Liquids				Natural Gas
		(millions of barrels)												(billions of cubic feet)
Proved Developed Reserves:
United States			125.9				—				20.7				148.3
Canada(1)			23.8				114.8				0.3				453.5
Malaysia			62.1				—				0.6				181.7
Total proved developed reserves(1)			211.8				114.8				21.6				783.5
Proved Undeveloped Reserves:
United States			113.0				—				14.7				84.1
Canada			4.1				—				0.1				456.1
Malaysia			12.5				—				—				365.1
Total proved undeveloped reserves			129.6				—				14.8				905.3
Total proved reserves(1)			341.4				114.8				36.4				1,688.8

 

(1)

Murphy’s proved reserves of synthetic oil as of December 31, 2015 were attributable to Murphy’s equity interest in Syncrude. Murphy completed the sale of its interest in Syncrude to Suncor Energy Inc. in June 2016, and does not currently own any proved reserves of synthetic crude oil.

Murphy Oil’s total proved reserves and proved undeveloped reserves increased during 2015 as presented in the table that follows:

 

(Millions of oil equivalent barrels)		Total Proved Reserves				Total Proved Undeveloped Reserves
Beginning of year			756.5				279.5
Revisions of previous estimates			16.2				(29.8	)
Improved recovery			2.7				—
Extension and discoveries			98.6				98.6
Conversion to proved developed reserves			—				(42.7	)
Purchases of properties			—				—
Sales of properties			(24.1	)			(10.3	)
Production			(75.9	)			—
End of year			774.0				295.3

During 2015, Murphy added proved reserves of 17.5 million barrels of oil equivalent (MMBOE). The most significant adds to total proved reserves related to drilling and well performance in the Montney gas area of Western Canada that added 20.0 MMBOE, and drilling and well performance in the Eagle Ford Shale that added 78.0 MMBOE. The Company sold an additional 10% of its oil and gas assets in Malaysia during the year which reduced its proved reserves by 24.1 MMBOE. Murphy’s total proved undeveloped reserves at December 31, 2015 increased 15.8 MMBOE from a year earlier. The conversion of non-proved reserves to newly reported proved undeveloped reserves reported in the table as extensions and discoveries during 2015 was predominantly attributable to two areas – drilling in the Eagle Ford Shale area of South Texas and the Montney area in Western Canada as these areas had active development work ongoing during the year. The majority of proved

 

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undeveloped reserves reductions associated with revisions of previous estimates were the result of lower oil and gas prices causing these volumes to either become uneconomical or expire due to reallocated capital. The majority of the proved undeveloped reserves migration to the proved developed category occurred in the Eagle Ford Shale, Gulf of Mexico and Montney, attributed to drilling.

The Company sold an additional 10% interest in its Malaysian oil and gas properties in early 2015 which led to a reduction of proved undeveloped reserves of 10.3 MMBOE during the year. The Company spent approximately $800.0 million in 2015 to convert proved undeveloped reserves to prove developed reserves. The Company expects to spend about $400 million in 2016, $400 million in 2017 and $500 million in 2018 to move currently undeveloped proved reserves to the developed category. The anticipated level of spend in 2016 primarily includes drilling in the Eagle Ford Shale and Tupper gas areas. In computing MMBOE, natural gas is converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) to one barrel of oil.

At December 31, 2015, proved reserves are included for several development projects, including oil developments at the Eagle Ford Shale in South Texas and the Kakap, Kikeh and Siakap fields, offshore Sabah, Malaysia, as well as natural gas developments offshore Sarawak and offshore Block H, Malaysia. Total proved undeveloped reserves associated with various development projects at December 31, 2015 were approximately 295 MMBOE, which is 38% of the Company’s total proved reserves. Certain development projects have proved undeveloped reserves that will take more than five years to bring to production. The Company operates deepwater fields in the Gulf of Mexico that have three undeveloped locations that exceed this five-year window. Total reserves associated with the three locations amount to less than 1% of the Company’s total proved reserves at year-end 2015. The development of certain of these reserves stretches beyond five years due to limited well slots available, thus making it necessary to wait for depletion of other wells prior to initiating further development of these locations. The second project that will take more than five years to develop is offshore Malaysia and makes up approximately 1% of the Company’s total proved reserves at year-end 2015. This project is an extension of the Sarawak natural gas project and is expected to be on production in 2018 once current project production volumes decline. Additionally, the Block H development project has undeveloped proved reserves that make up 7% of the Company’s total proved reserves at year-end 2015. This operated project will take longer than five years from discovery to completely develop due to construction of floating LNG facilities and the remote location offshore deep waters in Sabah Malaysia. Field start up is expected to occur in 2018, which is less than five years beyond the period that proved undeveloped reserves were first recorded.

Murphy Oil’s Reserves Processes and Policies

The Company employs a Manager of Corporate Reserves (Manager) who is independent of the Company’s oil and gas management. The Manager reports to the Senior Vice President, Corporate Planning & Services, of Murphy Oil Corporation, who in turn reports directly to the President and Chief Executive Officer of Murphy Oil. The Manager makes presentations to the Board of Directors periodically about the Company’s reserves. The Manager reviews and discusses reserves estimates directly with the Company’s reservoir engineering staff in order to make every effort to ensure compliance with the rules and regulations of the SEC and industry. The Manager coordinates and oversees reserves audits. These audits are performed annually and target coverage of approximately one-third of Company reserves each year. The audits are performed by the Manager and qualified engineering staff from areas of the Company other than the area being audited. The Manager may also utilize qualified independent reserves consultants to assist with the internal audits or to perform separate audits as considered appropriate.

Each significant exploration and production office maintains one or more Qualified Reserve Estimators (QRE) on staff. The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area. The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others. A QRE is professionally qualified to perform these

 

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reserves estimates due to having sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment.

Normally, this requires a minimum of three years practical experience in petroleum engineering or petroleum production geology, with at least one year of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.

Larger offices of the Company also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs. The RRC is usually a senior QRE that has the primary responsibility for coordinating and submitting reserves information to senior management.

The Company’s QREs maintain files containing pertinent data regarding each significant reservoir. Each file includes sufficient data to support the calculations or analogies used to develop the values. Examples of data included in the file, as appropriate, include: production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the conclusion of the QRE stating, that in their opinion, the reserves have been calculated, reviewed, documented and reported in compliance with the regulations and guidelines contained in the reserves training manual. The Company’s reserves are maintained in an industry recognized reservoir engineering software system, which has adequate access controls to avoid the possibility of improper manipulation of data. When reserves calculations are completed by QREs and appropriately reviewed by RRCs and the Manager, the conclusions are reviewed and discussed with the head of the Company’s exploration and production business and other senior management as appropriate. The Company’s Controller’s department is responsible for preparing and filing reserves schedules within the Form 10-K report.

Murphy provides annual training to all company reserves estimators to ensure SEC requirements associated with reserves estimation and Form 10-K reporting are fulfilled. The training includes materials provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserves estimation.

Qualifications of Manager of Corporate Reserves

The Company believes that it has qualified employees preparing oil and gas reserves estimates. Mr. F. Michael Lasswell serves as Corporate Reserves Manager after joining the Company in 2012. Prior to joining Murphy, Mr. Lasswell was employed as a Regional Coordinator of reserves at a major integrated oil company. He worked in several capacities in the reservoir engineering department with the oil company from 2002 to 2012. Mr. Lasswell earned a Bachelor’s of Science degree in Civil Engineering and a Masters of Science degree in Geotechnical Engineering from Brigham Young University. Mr. Lasswell has experience working in the reservoir engineering field in numerous areas of the world, including the North Sea, the U.S. Arctic, the Middle East and Asia Pacific. He serves on the Society of Petroleum Engineers (SPE) Oil and Gas Reserves Committee (OGRC) and is also co-author of a paper on the Recognition of Reserves which was published by the SPE. Mr. Lasswell has also attended numerous industry training courses.

More information regarding Murphy’s estimated quantities of proved reserves of crude oil, natural gas liquids and natural gas for the last three years are presented by geographic area on pages F-55 through F-61 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus. Murphy has not filed and is not required to file any estimates of its total proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of

 

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properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.

Crude oil, condensate and natural gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the three years ended December 31, 2015 are shown on pages S-37, S-38 and S-41 of this prospectus supplement. In 2015, the Company’s production of oil and natural gas represented approximately 0.1% of worldwide totals.

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page S-43 of this prospectus supplement. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-53 through F-68 of the financial statements included elsewhere and incorporated by reference in this prospectus supplement and the accompanying prospectus.

At December 31, 2015, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres attributable to Murphy’s interest.

 

		Developed								Undeveloped								Total
Area (Thousands of acres)		Gross				Net				Gross				Net				Gross				Net
United States—Onshore			107				98				50				49				157				147
– Gulf of Mexico			14				6				918				563				932				569
Total United States			121				104				968				612				1,089				716
Canada—Onshore, excluding oil sands			77				77				407				385				484				462
– Offshore			101				8				43				2				144				10
– Oil sands—Syncrude			96				5				160				8				256				13
Total Canada			274				90				610				395				884				485
Malaysia			260				152				3,423				1,752				3,683				1,904
Australia			—				—				10,517				4,898				10,517				4,898
Brunei			—				—				2,935				563				2,935				563
Vietnam			—				—				8,094				4,843				8,094				4,843
Namibia			—				—				2,734				1,094				2,734				1,094
Indonesia			—				—				3,079				2,690				3,079				2,690
Equatorial Guinea			—				—				557				251				557				251
Spain			—				—				36				6				36				6
Totals			655				346				32,953				17,104				33,608				17,450

Certain acreage held by the Company will expire in the next three years. Scheduled expirations in 2016 include 918 thousand net acres in Wokam II Block in Indonesia; 745 thousand net acres in South Barito Block in Indonesia; 218 thousand net acres in Semai IV Block in Indonesia; 670 thousand net acres in Block SK 314A in Malaysia; 36 thousand net acres in Block PM 311 in Malaysia; 427 thousand net acres in Blocks 144 and 145 in Vietnam; 81 thousand net acres in Block 11-2/11 in Vietnam; 135 thousand net acres in the United States; and 97 thousand net acres in Western Canada. Scheduled acreage expirations in 2017 include 154 thousand net acres in Semai II Block in Indonesia; 42 thousand net acres in Block WA-408-P in Australia; 51 thousand net acres in the United States; and 41 thousand net acres in Western Canada. Acreage currently scheduled to expire in 2018 include 655 thousand net acres in Semai IV Block in Indonesia; 142 thousand net acres in the United States; 34 thousand net acres in Blocks 13-03 in Vietnam; and 10 thousand net acres in Western Canada.

 

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As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells. An “exploratory” well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area. A “development” well is drilled within the proved area of an oil or natural gas reservoir that is known to be productive.

The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2015.

 

		Oil Wells								Gas Wells
Country		Gross				Net				Gross				Net
United States			769				654				19				15
Canada			433				390				219				219
Malaysia			98				51				56				35
Totals			1,300				1,095				294				269

Murphy’s net wells drilled in the last three years are shown in the following table.

 

		United States								Canada								Malaysia								Other								Totals
		Pro- ductive				Dry				Pro- ductive				Dry				Pro- ductive				Dry				Pro- ductive				Dry				Pro- ductive				Dry
2015
Exploratory			—				2.2				—				—				2.0				1.2				—				1.2				2.0				4.6
Development			109.6				—				7.0				—				15.9				—				—				—				132.5				—
2014
Exploratory			1.0				0.8				—				—				—				—				—				1.9				1.0				2.7
Development			187.2				—				48.0				11.0				16.2				—				—				—				251.4				11.0
2013
Exploratory			15.2				0.4				—				1.0				—				—				0.9				1.4				16.1				2.8
Development			161.2				—				22.0				19.0				16.3				—				—				—				199.5				19.0

The Canadian dry development wells shown above in 2013 and 2014 are stratigraphic wells used to obtain information about Seal area heavy oil reservoirs. These wells will not be used to produce oil.

Murphy’s drilling wells in progress at December 31, 2015 are shown in the following table. The year-end well count includes wells awaiting various completion operations. The U.S. net wells included below are essentially all located in the Eagle Ford Shale area of South Texas.

 

		Exploratory								Development								Total
Country		Gross				Net				Gross				Net				Gross				Net
United States			—				—				38				36.0				38				36.0
Canada			—				—				2				2.0				2				2.0
Malaysia			—				—				1				0.6				1				0.6
Totals			—				—				41				38.6				41				38.6

Refining and Marketing—Discontinued Operations

The Company completed the separation of its former retail marketing business in the United States on August 30, 2013, through a distribution of 100% of the shares of Murphy USA Inc. (MUSA) to shareholders of Murphy Oil. MUSA is a stand-alone, publicly owned company which is listed on the New York Stock Exchange under the ticker symbol “MUSA.”

 

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The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in the second quarter of 2015 for cash proceeds of $5.5 million. The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented.

All of the results of the U.S. and U.K. downstream businesses have been reported as discontinued operations for all periods presented in this prospectus supplement.

Environmental

Murphy’s businesses are subject to various international, national, state, provincial and local environmental laws and regulations that govern the manner in which the Company conducts its operations. The Company anticipates that these requirements will continue to become more complex and stringent in the future.

Further information on environmental matters and their impact on Murphy are contained in Management’s discussion and analysis of financial condition and results of operations on pages S-28 through S-65 of this prospectus supplement.

 

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Description of other indebtedness

Revolving Credit Facility

At June 30, 2016, we had a $2.0 billion committed credit facility with a major banking consortium that expires in 2017 (the “Existing Revolving Credit Facility”). Borrowings under the Existing Revolving Credit Facility bear interest at 1.45% above LIBOR based on the Company’s current credit rating as of June 30, 2016. In addition, facility fees of 0.30% are charged on the full $2.0 billion commitment. At June 30, 2016, we had no borrowings under the Existing Revolving Credit Facility. We had outstanding letters of credit of approximately $88 million issued under our Existing Revolving Credit Facility at June 30, 2016, which reduced the available borrowing capacity under the agreement. At June 30, 2016, we also had uncommitted credit lines that had estimated total borrowing capacity of approximately $195 million of which no amounts were outstanding under these uncommitted credit lines.

On August 10, 2016, we entered into a new revolving credit facility that matures in August 2019 (the “New Revolving Credit Facility”) in an aggregate principal amount of up to $1.2 billion. Borrowings under the New Revolving Credit Facility will initially bear interest at 4.50% above LIBOR and thereafter be subject to step-downs based on consolidated leverage ratios. In addition, facility fees of 0.50% are charged on the full $1.2 billion commitment. In addition, on August 10, 2016, we amended the Existing Revolving Credit Facility to reduce the commitments of the exiting lenders that have committed to the New Revolving Credit Facility and allow for the incurrence of the New Revolving Credit Facility. Lenders under the Existing Credit Facility that did not become lenders under the New Revolving Credit Facility will remain lenders under our Existing Revolving Credit Facility, with aggregate commitments of $630 million, until its currently scheduled maturity in June 2017.

The New Revolving Credit Facility is guaranteed by certain of our material subsidiaries and contains customary financial maintenance covenants, including requirements to meet a maximum total leverage ratio and a minimum interest coverage ratio and maintain minimum domestic liquidity coverage. Additionally, our New Revolving Credit Facility contains customary negative covenants, including limitations on additional indebtedness, guarantees and liens. These financial and negative covenants will be subject to customary thresholds and exceptions. In addition, if our total leverage ratio falls below a specified ratio, we will be obligated to provide, subject to certain exceptions, a pledge of substantially all of our tangible and intangible assets, as well as the tangible and intangible assets of the guarantors.

Consummation of this offering is a condition precedent to the effectiveness of the New Revolving Facility.

Existing Notes

On May 4, 1999, we issued $250 million aggregate principal amount of 7.05% Notes due 2029 (the “2029 Notes”) under an indenture dated as of May 4, 1999 between us and SunTrust Bank, Nashville, N.A., as trustee and a supplemental indenture thereto dated as of May 4, 1999.

On May 18, 2012, we issued $500 million aggregate principal amount of 4.00% Notes due 2022 (the “2022 Notes”) under an indenture dated as of May 18, 2012 between us and U.S. Bank National Association, as trustee, and the first supplemental indenture thereto dated as of May 18, 2012.

On November 30, 2012, we issued $550 million aggregate principal amount of 2.500% Notes due 2017 (the “2017 Notes”), $600 million aggregate principal amount of 3.700% Notes due 2022 (the “2022 Notes”) and $350 million aggregate principal amount of 5.125% Notes due 2042 (the “2042 Notes” and together with the 2029 Notes, the 2022 Notes, the 2017 Notes and the 2022 Notes, the “Existing Notes”) under the indenture dated as of May 18, 2012 between us and U.S. Bank National Association, as trustee, and the second supplemental indenture thereto dated as of November 30, 2012.

 

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The indentures for our Existing Notes contain certain restrictions, including a limitation that restricts our ability and the ability of our restricted subsidiaries to incur liens and enter into sale and leaseback transactions. The indentures also restrict our ability to merge or consolidate with any other corporation or sell or convey all or substantially all of its assets.

 

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Description of the notes

 

We have summarized selected provisions of the notes below. This summary supplements and replaces, where inconsistent, the description of the general terms and provisions of debt securities under the caption “Description of Debt Securities” in the accompanying prospectus. As used in the description below, the terms “Murphy Oil Corporation,” “we,” “our,” “us,” “the Company,” “Murphy Oil” and “Murphy” refer to Murphy Oil Corporation only and not to any of its subsidiaries. Certain terms used in this description are defined under the subheading “—Certain definitions.”

General

The notes will be issued as a separate series of notes under the senior indenture dated as of May 18, 2012 and a supplement to the indenture, to be dated as of August 17, 2016 and hereafter collectively referred to as “the indenture,” between Murphy Oil and U.S. Bank National Association, as trustee. The notes offered hereby will vote as a separate class from the other series of notes issued under the indenture, except as otherwise provided in the indenture.

The notes will initially be limited to an aggregate principal amount of $550,000,000.

The notes will mature on August 15, 2024 and will bear interest at 6.875% per year. Interest on the notes will accrue from August 17, 2016.

We:

 

•

will pay interest on the notes semiannually on February 15 and August 15 of each year, commencing February 15, 2017;

 

•

will pay interest on the notes to the person in whose name a note is registered at the close of business on the February 1 or August 1 preceding the interest payment date;

 

•

will compute interest on the notes on the basis of a 360-day year consisting of twelve 30-day months;

 

•

will make payments on the notes at the offices of the trustee; and

 

•

may make payments by wire transfer for notes held in book-entry form or by check for notes held in certificated form mailed to the address of the person entitled to the payment as it appears in the note register.

We will issue the notes only in fully registered form, without coupons, in denominations of $2,000 and any integral multiple of $1,000 in excess thereof. The notes will not be subject to any sinking fund, and will be subject to redemption at our option, as described below.

Further issuances

We may from time to time, without the consent of the existing holders, create and issue additional notes having the same terms and conditions as the notes offered by this prospectus supplement in all respects, except for the issue date, issue price and, under some circumstances, the date of the first payment of interest on the notes, provided that if the additional notes are not fungible with the notes offered by this prospectus supplement for U.S. federal income tax purposes, such additional notes will have a different CUSIP. Additional notes issued in this manner will be consolidated with and form a single series with the previously outstanding notes of this series.

 

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Optional redemption

If the notes are redeemed at any time prior to August 15, 2019, the notes may be redeemed by us, in whole or in part at our option, at a redemption price equal to the greater of:

 

•

100% of the principal amount of notes to be redeemed; or

 

•

the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (not including any portion of such payments of interest accrued and unpaid to the date of redemption) discounted to the date of redemption on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 50 basis points,

plus accrued and unpaid interest on the principal amount of the notes being redeemed to, but not including, the redemption date.

On or after August 15, 2019, the notes may be redeemed by us, in whole or in part at our option, at the redemption prices set forth below (expressed in percentages of principal amount of the Notes on the redemption date), plus accrued and unpaid interest on the principal amount of the notes being redeemed to, but not including, the redemption date, if redeemed during the 12-month period commencing on August 15 of the years set forth below.

 

Period		Redemption Price
2019			105.156%
2020			103.438%
2021			101.719%
2022 and thereafter			100.000%

“Treasury rate” means, with respect to any redemption date:

 

•

the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities,” for the maturity corresponding to the comparable treasury issue (if no maturity is within three months before or after the remaining life (as defined below), yields for the two published maturities most closely corresponding to the comparable treasury issue will be determined and the treasury rate will be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month); or

 

•

if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semi-annual equivalent yield to maturity of the comparable treasury issue, calculated using a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date.

The treasury rate will be calculated on the third business day next preceding the date fixed for redemption (the “calculation date”).

“Comparable treasury issue” means the U.S. Treasury security selected by an independent investment banker as having a maturity comparable to the remaining term (“remaining life”) of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes.

“Comparable treasury price” means, with respect to any redemption date, (1) the average of four reference treasury dealer quotations for such redemption date, after excluding the highest and lowest reference treasury

 

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dealer quotations, or (2) if the independent investment banker obtains fewer than four such reference treasury dealer quotations, the average of all such quotations.

“Independent investment banker” means one of J.P. Morgan Securities LLC or its successors, as specified by us, or, if such firm is unwilling or unable to select the comparable treasury issue, an independent investment banking institution of national standing appointed by us.

“Reference treasury dealer” means each of (1) J.P. Morgan Securities LLC or its successors, provided, however, that if the foregoing shall cease to be a primary U.S. government securities dealer in the United States (a “primary treasury dealer”), we will substitute therefor another primary treasury dealer and (2) any three other primary treasury dealers selected by us after consultation with an independent investment banker.

“Reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the calculation date.

We will mail a notice of redemption to each holder of notes to be redeemed by first-class mail at least 30 and not more than 60 days prior to the date fixed for redemption. Unless we default on payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on and after the redemption date. If fewer than all of the notes are to be redeemed, the trustee will select, not more than 60 days prior to the redemption date, the particular notes or portions thereof for redemption from the outstanding notes not previously called by such method as the trustee deems fair and appropriate. The redemption price will be calculated by the independent investment banker and we, the trustee and any paying agent for the notes will be entitled to rely on such calculation.

Except as described above, the notes will not be redeemable by us prior to maturity and will not be entitled to the benefit of any sinking fund.

Repurchase upon a change of control triggering event

Upon the occurrence of a change of control triggering event with respect to the notes, unless the Company has exercised its right to redeem all of the notes as described under “—Optional redemption,” each holder of the notes will have the right to require the Company to purchase all or a portion of such holder’s notes pursuant to the offer described below (the “change of control offer”), at a purchase price in cash (the “change of control payment”) equal to 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of purchase, provided that any payment of interest becoming due on or prior to the change of control payment date (as defined below) shall be payable to the holders of such notes registered as such on the relevant record date.

Within 30 days following the date upon which the change of control triggering event occurs, or at the Company’s option, prior to any change of control but after the public announcement of the pending change of control, the Company will be required to send, by first class mail, a notice to each holder of the notes, with a copy to the trustee, which notice will govern the terms of the change of control offer and describe the change of control triggering event. Such notice will state, among other things, the purchase date, which must be no earlier than 30 days nor later than 60 days from the date such notice is mailed, other than as may be required by law (the “change of control payment date”). The notice, if mailed prior to the date of consummation of the change of control, will state that the change of control offer is conditioned on the change of control being consummated on or prior to the change of control payment date.

Upon the change of control payment date, the Company will, to the extent lawful:

 

•

accept for payment all notes or portions of notes properly tendered and not withdrawn pursuant to the change of control offer;

 

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•

deposit with the paying agent an amount equal to the change of control payment in respect of all notes or portions of notes properly tendered; and

 

•

deliver, or cause to be delivered, to the trustee the notes properly accepted together with a certificate, executed by the Company’s officers, stating the aggregate principal amount of notes or portions thereof being purchased.

The Company will not be required to make a change of control offer if a third party makes such an offer in the manner, at the times and otherwise in compliance with the requirements for such an offer made by the Company and such third party purchases all notes properly tendered and not withdrawn under its offer.

If holders of not less than 90% in aggregate principal amount of the outstanding notes validly tender and do not withdraw such notes in a change of control offer and we, or any third party making a change of control offer in lieu of us, as described above, purchase all of the notes validly tendered and not withdrawn by such holders, we will have the right, upon not less than 30 nor more than 60 days’ prior notice, with such notice given not more than 30 days following the change of control payment date, to redeem all notes that remain outstanding following such purchase at a redemption price equal to the change of control payment plus, to the extent not included in the change of control payment, accrued and unpaid interest, if any, on the notes that remain outstanding to the date of redemption provided that any payment of interest becoming due on or prior to the redemption date shall be payable to the holders of such notes registered as such on the relevant record date.

“Change of control” means the occurrence of any of the following:

 

(1)

the consummation of any transaction or series of related transactions (including, without limitation, any merger or consolidation) the result of which is that any “person” (for purposes of this definition, as that term is used in Section 13(d)(3) of the Exchange Act), other than the Company, any of its subsidiaries, any of the Murphy family or any employee benefit plan of the Company or any of its subsidiaries (each such person, an “excluded party”), becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of more than 50% of the combined voting power of the Company’s voting stock or other voting stock into which the Company’s voting stock is reclassified, consolidated, exchanged or changed, measured by voting power rather than number of shares; provided that the consummation of any such transaction will not be considered to be a change of control if (a) the Company becomes a direct or indirect wholly-owned subsidiary of a holding company and (b) immediately following such transaction, (x) the direct or indirect holders of the voting stock of the holding company are substantially the same as the holders of our voting stock immediately prior to such transaction or (y) no person (other than the excluded parties) is the beneficial owner, directly or indirectly, of more than 50% of the voting stock of such holding company;

 

(2)

the Company consolidates with, or merges with or into, any person, or any person consolidates with, or merges with or into, the Company, in any such event pursuant to a transaction in which any of the Company’s outstanding voting stock or the voting stock of such other person is converted into or exchanged for cash, securities or other property, other than any such transaction where the shares of the Company’s voting stock outstanding immediately prior to such transaction constitute, or are converted into or exchanged for, a majority of the voting stock of the surviving person or any direct or indirect parent company of the surviving person, measured by voting power rather than number of shares, immediately after giving effect to such transaction; or

 

(3)

the adoption by the board of directors of the Company of a plan relating to the Company’s liquidation or dissolution.

“Change of control triggering event” means (1) the ratings of the notes is downgraded by any two of the ratings agencies during the 60-day period (the “trigger period”) commencing on the earlier of (i) the occurrence of a

 

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change of control or (ii) the first public announcement of the occurrence of a change of control or the Company’s intention to effect a change of control (which trigger period will be extended so long as the ratings of the notes is under publicly announced consideration for possible downgrade by any of the ratings agencies) and (2) the notes of are rated below an investment grade rating by any two of the ratings agencies on any date during the trigger period; provided that a change of control triggering event will not be deemed to have occurred in respect of a particular change of control if each ratings agency does not publicly announce or confirm or inform the trustee in writing at our request that the reduction was the result, in whole or in part, of any event or circumstance comprised of or arising as a result of, or in respect of, the change of control (whether or not the applicable change of control has occurred at the time of the change of control triggering event). Notwithstanding the foregoing, no change of control triggering event will be deemed to have occurred in connection with any particular change of control unless and until such change of control has actually been consummated.

“Fitch” means Fitch Ratings, Inc. and its successors.

“Immediate family” of a person means such person’s spouse, children, siblings, parents, mother-in-law and father-in-law, sons-in-law, daughters-in-law, brothers-in-law and sisters-in-law.

“Investment grade” means a rating of Baa3 or better by Moody’s (or its equivalent under any successor rating category of Moody’s), a rating of BBB- or better by S&P (or its equivalent under any successor rating category of S&P), a rating of BBB- or better by Fitch (or its equivalent under any successor rating category of Fitch) or an equivalent investment grade rating from any replacement ratings agency appointed by the Company.

“Moody’s” means Moody’s Investors Service, Inc., and its successors.

“Murphy family” means (1) (i) the C.H. Murphy Family Investments Limited Partnership; (ii) the estate and descendants of C.H. Murphy, Jr.; (iii) the siblings of the late C.H. Murphy, Jr. and their respective estates and descendants; (iv) the respective immediate family of, immediate family of descendants of and descendants of immediate family of, any individual included in clause (ii) or (iii); (v) any trust established for the benefit of any of the foregoing or any charitable trust or foundation established by any of the foregoing, and the respective trustees, fiduciaries and beneficiaries of any such trust or foundation; and (vi) any corporation, limited partnership, limited liability company or other entity owned by any of the foregoing, or organized to achieve estate planning objectives of any of the foregoing; and (2) any affiliate (as defined in Rule-12b-2 under the Exchange Act) or successor of any of the foregoing.

“Ratings agency” means each of Fitch, Moody’s and S&P; provided, that if any of Fitch, Moody’s and S&P ceases to rate the notes or fails to make a rating of the notes publicly available for reasons outside of the Company’s control, the Company may appoint a replacement for such ratings agency that is a “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act with respect to the notes.

“S&P” means Standard & Poor’s Global Ratings, a division of S&P Global Inc., and its successors.

“Voting stock” of any specified person as of any date means the capital stock of such person that is at the time entitled to vote generally in the election of the board of directors of such person.

The Company will comply with the applicable requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a change of control triggering event. To the extent that the provisions of any securities laws or regulations conflict with the change of control offer provisions of the notes, the Company will comply with those securities laws and regulations and will not be deemed to have breached its obligations under the change of control offer provisions of the notes by virtue of any such conflict.

 

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Unless the Company defaults in the change of control payment, on and after the change of control payment date, interest will cease to accrue on the notes or portions of the notes tendered for repurchase pursuant to the change of control offer.

Ranking

The notes will be our senior unsecured obligations and will rank equally in right of payment with all of our other senior unsecured and unsubordinated indebtedness from time to time outstanding.

We currently conduct substantially all of our operations through our subsidiaries, and our subsidiaries generate substantially all of our operating income and cash flow. As a result, distributions or advances from our subsidiaries are the principal source of the funds we use to meet our debt service obligations. Laws or contractual provisions, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from our subsidiaries that we require to pay our debt service obligations, including payments on the notes. The notes will not be guaranteed by any of our subsidiaries and therefore will be structurally subordinated to all obligations of our subsidiaries, including trade payables and any of our obligations that are guaranteed by any of our subsidiaries. This means that holders of the notes will have a junior position to the claims of creditors of our subsidiaries on their assets and earnings. The notes will also be effectively subordinated to any secured debt we may incur, to the extent of the value of the assets securing that debt. The indenture restricts the amount of debt our subsidiaries can incur or guarantee and restricts our ability to incur secured debt, subject to the limitations described under “Covenants—Limitations on Subsidiary Indebtedness” and “Covenants—Limitations on Liens” below, respectively.

As of June 30, 2016, Murphy Oil had approximately $2.44 billion of senior unsecured indebtedness outstanding and approximately $178.6 million of issued and undrawn letters of credit outstanding. As of June 30, 2016 our subsidiaries had approximately $798.1 million of indebtedness, trade payables and other accrued current liabilities outstanding.

Covenants

Limitations on Liens.    Neither we nor any subsidiary will issue, assume or guarantee any Debt secured by a mortgage, lien, pledge or other encumbrance, which are collectively called “mortgages” in the indenture, on any principal property or on any Debt or capital stock of any subsidiary which owns any principal property without providing that the notes will be secured equally and ratably or prior to the Debt.

However, the limitation on liens shall not apply to the following:

 

(1)

mortgages existing on the issue date (other than Debt outstanding under the Revolving Credit Facilities);

 

(2)

mortgages existing at the time an entity becomes a subsidiary of ours or is merged into or consolidated with us or a subsidiary of ours and not Incurred in contemplation of such transaction;

 

(3)

mortgages in favor of Murphy Oil or any subsidiary of ours;

 

(4)

mortgages on property to secure Debt Incurred prior to, at the time of or within 180 days after the construction, development or improvement of the property or after the completion of construction of the property, for the purpose of financing all or part of the cost of construction, development or improvement (provided that such mortgages are limited to such property and improvements thereon);

 

(5)

mortgages on property, shares of stock or Debt to secure Debt Incurred prior to, at the time of or within 180 days after the acquisition of the property, shares of stock or Debt, for the purpose of financing all or part of the purchase price of the property, shares of stock or Debt (provided that such mortgages are limited to such property and improvements thereon or the shares of stock or Debt so acquired);

 

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(6)

mortgages in favor of the United States of America, any state, any other country or any political subdivision to secure partial, progress, advance or other payments pursuant to any contract or statute;

 

(7)

mortgages on property of Murphy Oil or any subsidiary securing Debt Incurred in connection with financing all or part of the cost of operating, constructing or acquiring projects, as long as recourse is only to the property (other than Debt permitted to be Incurred under clause 15 below);

 

(8)

specific marine mortgages or foreign equivalents on property or assets of Murphy Oil or any subsidiary;

 

(9)

mortgages or easements on property of Murphy Oil or any subsidiary Incurred to finance the property on a tax-exempt basis that do not materially detract from the value of or materially impair the use of the property or assets;

 

(10)

mortgages on equipment of Murphy Oil or any subsidiary granted in the ordinary course of business to Murphy Oil’s or such subsidiary’s client at which such equipment is located;

 

(11)

mortgages securing Debt Incurred in the ordinary course of business in an aggregate principal amount that, when taken together with Indebtedness Incurred pursuant to clause (8) of the covenant described under the caption “Limitations on Subsidiary Indebtedness”, does not exceed $50,000,000 at any one time outstanding;

 

(12)

mortgages in favor of the notes;

 

(13)

mortgages in respect to letters of credit, bank guarantees or similar instruments issued in the ordinary course of business;

 

(14)

any extension, renewal or replacement of any mortgage referred to in the preceding items or of any Debt secured by those mortgages as long as the extension, renewal or replacement secures the same or a lesser principal amount of Debt (plus any premium or fee payable in connection with such extension, renewal or replacement) and is limited to substantially the same property (plus improvements) which secured the mortgage;

 

(15)

mortgages securing Debt in respect of any Project Financing Incurred by any Project Financing Subsidiary (provided that such mortgages may not be on any (i) principal property or (ii) proved oil and gas reserves, in each case owned or held by Murphy Oil or any subsidiary as of the issue date); and

 

(16)

other mortgages on principal property or on any Debt or capital stock of any subsidiary securing Debt the aggregate principal amount of which, when taken together with the aggregate principal amount of all other then outstanding Aggregate Debt, does not exceed the greater of (a) 10% of our consolidated net assets or (b) $1,750,000,000 at the time of creation, Incurrence or assumption of such mortgages after giving effect to the receipt and application of the proceeds of the Debt secured thereby.

Limitations on Subsidiary Indebtedness.    We will not permit any of our subsidiaries to Incur any Indebtedness.

However, the limitation on Indebtedness of our subsidiaries shall not apply to the following:

 

(1)

Indebtedness existing on the issue date (other than Indebtedness outstanding under the Revolving Credit Facilities) and any Refinancing Indebtedness with respect to such Indebtedness;

 

(2)

intercompany loans and advances between Murphy Oil and our subsidiaries; provided that (a) if the obligor on such intercompany loan or advance is Murphy Oil, then such Indebtedness must be expressly subordinated to the prior payment in full of the notes; and (b) at the time of (i) any subsequent issuance or

 

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transfer of capital stock that results in any such Indebtedness being held by a person other than the Company or one of our subsidiaries or (ii) any sale or other transfer of any such Indebtedness to a person that is neither Murphy Oil nor a subsidiary of Murphy Oil, such Indebtedness will no longer be permitted to be Incurred under this clause (2);

 

(3)

Indebtedness of an entity existing at the time such entity becomes a subsidiary of Murphy Oil or is merged, consolidated or amalgamated with or into any subsidiary of Murphy Oil and not Incurred in contemplation of such transaction, and any Refinancing Indebtedness with respect thereto;

 

(4)

Indebtedness in respect to letters of credit, bank guarantees or similar instruments issued in the ordinary course of business;

 

(5)

Indebtedness Incurred prior to, at the time of or within 180 days after the construction, development or improvement of property or after the completion of construction of property, for the purpose of financing all or part of the cost of construction, development or improvement, and any Refinancing Indebtedness with respect to such Indebtedness;

 

(6)

Indebtedness Incurred prior to, at the time of or within 180 days after the acquisition of property, shares of stock or Debt for the purpose of financing all or part of such purchase price of property, shares of stock or Debt, and any Refinancing Indebtedness with respect to such Indebtedness;

 

(7)

Indebtedness in respect of workers’ compensation claims or self-insurance and respect of performance, bid and surety bonds and completion guarantees provided in the ordinary course of business;

 

(8)

Indebtedness Incurred in the ordinary course of business in an aggregate principal amount that, when taken together with Indebtedness secured by mortgages Incurred pursuant to clause (11) of the covenant described under the caption “Limitations on Liens” does not exceed $50,000,000 at any one time outstanding;

 

(9)

Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;

 

(10)

customer deposits and advance payments received in the ordinary course of business or consistent with past practice from customers for goods or services purchased in the ordinary course of business or consistent with past practice not to exceed $50,000,000 at any one time outstanding;

 

(11)

cash management obligations, cash management services and other Indebtedness in respect of netting services, automatic clearing house arrangements, employees’ credit or purchase cards, overdraft protections and similar arrangements and otherwise in connection with depositary accounts and repurchase agreements;

 

(12)

Indebtedness in respect of any Project Financing Incurred by any Project Financing Subsidiary (provided that such Project Financing Subsidiary may not own or hold (i) any principal property or (ii) any proved oil and gas reserves, in each case owned or held by Murphy Oil or any subsidiary as of the issue date); and

 

(13)

other Indebtedness the aggregate principal amount of which, when taken together with the aggregate principal amount of all other then outstanding Aggregate Debt, does not exceed the greater of (a) 10% of our consolidated net assets or (b) $1,750,000,000 at the time of Incurrence of such Indebtedness after giving effect to the receipt and application of the proceeds therefrom.

 

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Limitations on Sale and Lease-Back Transactions.    Neither we nor any subsidiary will lease any principal property for more than three years from the purchaser or transferee of such principal property (a “Sale and Lease-Back Transaction”). However, the limitation on this type of arrangement shall not apply if:

 

(1)

we or our subsidiary could Incur Debt in a principal amount equal to the Attributable Indebtedness with respect to such Sale and Lease-Back Transaction secured by a mortgage on the property subject to such Sale and Lease-Back Transaction, as permitted under clause (16) of the covenant under “Limitations on Liens” above, without equally and ratably securing the notes under the indenture; or

 

(2)

we apply the greater of the proceeds from the sale or transfer and the fair value of the leased property to the defeasance or retirement of any senior debt for borrowed money within 180 days of the Sale and Lease-Back Transaction, in both cases reduced by the lesser of any amounts spent to purchase unencumbered principal property and the fair value of unencumbered principal property so acquired, in each case during the one year prior to or 180 days after any Sale and Lease-Back Transaction.

Consolidation, merger or sale of assets

We will not merge or consolidate with any other corporation or sell or convey all or substantially all of our assets to any person, unless (i) either we are the continuing corporation, or the successor corporation or the person which acquires by sale or conveyance substantially all our assets (if other than us) will be a corporation organized under the laws of the United States of America or any state thereof and will expressly assume the due and punctual payment of the principal of and interest on all debt securities under the indenture, according to their tenor, and the due and punctual performance and observance of all of the covenants and conditions of the indenture to be performed or observed by us, by supplemental indenture in form reasonably satisfactory to the trustee, executed and delivered to the trustee by such corporation, and (ii) we or our successor corporation, as the case may be, are not, immediately after such merger or consolidation, or such sale or conveyance, in default in the performance of any such covenant or condition of the indenture.

In case of any such consolidation, merger, sale or conveyance, and following such an assumption by the successor corporation, such successor corporation will succeed to and be substituted for us, with the same effect as if it had been named in the indenture. Such successor corporation may cause to be signed, and may issue either in its own name or in our name prior to such succession any or all of the debt securities issuable under the indenture which theretofore had not been signed by us and delivered to the trustee; and, upon the order of such successor corporation instead of us and subject to all the terms, conditions and limitations prescribed in the indenture, the trustee will authenticate and will deliver any debt securities which previously were signed and delivered by our officers to the trustee for authentication, and any debt securities which such successor corporation thereafter causes to be signed and delivered to the trustee for that purpose. All of the debt securities so issued will in all respects have the same legal rank and benefit under the indenture as the debt securities theretofore or thereafter issued in accordance with the terms of the indenture as though all of such debt securities had been issued at the date of the execution of the indenture.

In the event of any such sale or conveyance (other than a conveyance by way of lease) we or any successor corporation which has become such in the manner described above will be discharged from all obligations and covenants under the indenture and the debt securities issued thereunder and may be liquidated and dissolved.

Amendment and Waivers

We and the Trustee may from time to time and at any time enter into supplemental indentures without the consent of any holder for one or more of the following purposes:

 

•

to convey, transfer, assign, mortgage or pledge to the Trustee as security for the notes any property or assets;

 

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•

to evidence the succession of another corporation to Murphy Oil, or successive successions, and the assumption by the successor corporation of the covenants, agreements and obligations of Murphy Oil pursuant to the covenant set forth under the caption “Consolidation, merger or sale of assets”;

 

•

to add to the covenants of Murphy Oil such further covenants, restrictions, conditions or provisions as its board of directors and the Trustee consider to be for the protection of the holders of notes, and to make the occurrence, or the occurrence and continuance, of a default in any such additional covenants, restrictions, conditions or provisions an event of default permitting the enforcement of all or any of the several remedies provided for in the indenture; provided, that in respect of any such additional covenant, restriction, condition or provision such supplemental indenture may provide for a particular period of grace after default (which period may be shorter or longer than that allowed in the case of other defaults) or may provide for an immediate enforcement upon such an event of default or may limit the remedies available to the Trustee upon such an event of default or may limit the right of the holders of a majority of the notes to waive such an event of default;

 

•

to cure any ambiguity or to correct or supplement any provision contained in the indenture or any supplemental indenture, which may be defective or inconsistent with any other provision contained in the indenture or in any supplemental indenture; or to make such other provisions in regard to matters or questions arising under the indenture or under any supplemental indenture as the board of directors may deem necessary or desirable; provided that no such action shall adversely affect the interests of the holders of the notes in any material respect;

 

•

to establish the form or terms of the notes as permitted by the indenture;

 

•

to conform the text of the to conform the text of the indenture to this “Description of notes” to the extent that such provision in this “Description of notes” was intended to be a verbatim recitation of a provision of the indenture;

 

•

to evidence and provide for the acceptance of appointment by a successor trustee with respect to notes and to add to or change any of the provisions of the indenture as necessary to provide for or facilitate the administration of the trusts by more than one trustee.

With the consent of holders of not less than a majority in aggregate principal amount of the notes outstanding, we and the Trustee may, from time to time and at any time, enter into one or more supplemental indentures for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of the indenture or of modifying in any manner the rights of the holders of notes. Notwithstanding the preceding sentence, no supplemental indenture may (a) extend the final maturity, or reduce the principal amount, or reduce the rate or extend the time of payment of interest, or reduce any amount payable on redemption of any note or any right of repayment at the option of the holder without the consent of the holder so affected, or (b) reduce the required percentage of holders, the consent of which is required for any such supplemental indenture, without the consent of the holders so affected.

It will not be necessary for the consent of holders to approve the particular form of any proposed supplemental indenture, but it will be sufficient if such consent approves the substance thereof.

Events of default, notice and waiver

“Event of default” means any of the following in relation to the notes:

 

•

failure to pay interest on the notes for 30 days after the interest becomes due;

 

•

failure to pay the principal on the notes when due;

 

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•

failure to perform or breach of any other covenant or warranty in the indenture that continues for 90 days after our being given notice from the trustee or the holders of at least 25% in aggregate principal amount of the outstanding notes;

 

•

default in the payment when due of (a) other Indebtedness (other than Project Financing) in an aggregate principal amount in excess of $75,000,000 and such default is not cured within 30 days after written notice to us and the trustee by the holders of at least 25% in principal amount of the outstanding notes or (b) interest, principal, premium or a sinking fund or redemption payment under any such other Indebtedness, causing the Indebtedness to become due prior to its stated maturity, which acceleration is not stayed, rescinded or annulled within 10 days after written notice to us and the trustee by the holders of at least 25% in principal amount of the outstanding notes; provided, however, that if such event of default under such indenture or instrument is remedied or cured by us or waived by the holders of such debt before any judgment or decree for the payment of the moneys due is obtained or entered, then this event of default will also be deemed to have been remedied, cured or waived without further action upon the part of either the trustee or any of the holders of the notes;

 

•

a creditor commences involuntary bankruptcy, insolvency or similar proceedings against us and we are unable to obtain a stay or dismissal of that proceeding within 60 days; or

 

•

we voluntarily seek relief under bankruptcy, insolvency or similar laws or we consent to a court entering an order for relief against us under those laws.

If any event of default relating to the outstanding notes occurs and is continuing, either the trustee or the holders of at least 25% in principal amount of the outstanding notes may declare the principal and accrued interest of all of the outstanding notes to be due and immediately payable; provided, however, that if an event of default occurs pertaining to events of bankruptcy, insolvency or similar proceedings, the principal amount and accrued interest shall be immediately due and payable without any declaration or other act by the trustee or any holder.

The indenture provides that the holders of at least a majority in principal amount of the outstanding notes may direct the time, method and place of conducting any proceeding for any remedy available to the trustee, or of exercising any trust or power conferred on the trustee, with respect to the notes. The trustee may act in any way that is consistent with those directions and may decline to act if any of the directions is contrary to law or to the indenture or would involve the trustee in personal liability.

The indenture provides that the holders of at least a majority in principal amount of the notes may on behalf of the holders of all of the outstanding notes waive any past default (and its consequences) under the indenture, except a default (a) in the payment of the principal of or interest on any of the notes, (b) with respect to voluntary or involuntary bankruptcy, insolvency or similar proceedings, or (c) with respect to a covenant or provision of such indenture which, under the terms of such indenture, cannot be modified or amended without the consent of the holders of all of the outstanding notes. In the case of clause (b) above, the holders of at least a majority of all outstanding debt securities under the indenture (voting as one class) may on behalf of all such holders waive a default.

The indenture contains provisions entitling the trustee, subject to the duty of the trustee during an event of default to act with the required standard of care, to be indemnified by the holders of the notes before proceeding to exercise any right or power under the indenture at the request of those holders.

The indenture requires the trustee to, within 90 days after the occurrence of a default known to it with respect to the notes, give the holders of the notes notice of the default if uncured and unwaived. However, the trustee may withhold this notice if it in good faith determines that the withholding of this notice is in the interest of those holders. However, the trustee may not withhold this notice in the case of a default in payment of principal

 

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of or interest on the notes. The term “default” for the purpose of this provision means any event that is, or after notice or lapse of time, or both, would become, an event of default with respect to the notes.

The indenture requires us to file annually with the trustee a certificate, executed by our officers, indicating whether any of the officers has knowledge of any default under the indenture.

Notices

We will mail notices and communications to the holder’s address shown on the register of the notes.

Paying agents and transfer agents

The trustee will be the paying agent and transfer agent for the notes.

The trustee

U.S. Bank National Association is the trustee under the indenture. The trustee is a lender under the Company’s revolving credit facility.

Book-entry delivery and settlement

The Depository Trust Company (“DTC”), New York, New York, will act as securities depository for the notes. The notes will be issued as fully-registered securities registered in the name of Cede & Co. (DTC’s partnership nominee) or such other name as may be requested by an authorized representative of DTC. One or more fully-registered certificates will be issued for the notes, in the aggregate principal amount of such issue, and will be deposited with DTC.

DTC has advised us as follows:

 

•

DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934, as amended;

 

•

DTC holds and provides asset servicing for U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments that DTC’s participants (“direct participants”) deposit with DTC. DTC also facilitates the post-trade settlement among direct participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between direct participants’ accounts, thereby eliminating the need for physical movement of securities certificates;

 

•

direct participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations, including the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”);

 

•

DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”), and DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies; DTCC is owned by the users of its regulated subsidiaries;

 

•

access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations, including Euroclear and Clearstream, that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly; and

 

•

the rules applicable to DTC and its participants are on file with the SEC.

 

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We have provided the following descriptions of the operations and procedures of DTC solely as a matter of convenience. These operations and procedures are solely within the control of DTC and are subject to change by them from time to time.

We expect that under the procedures established by DTC:

 

•

upon deposit of the global notes with DTC or its custodian, DTC will credit on its internal system the accounts of direct participants designated by the underwriters with portions of the principal amounts of the global notes; and

 

•

ownership of the notes will be shown on, and the transfer of ownership of the notes will be effected only through, records maintained by DTC or its nominee, with respect to interests of direct participants, and the records of direct and indirect participants, with respect to interests of persons other than participants.

The foregoing information concerning DTC and DTC’s book-entry system has been obtained from sources that we believe to be reliable, but none of Murphy Oil, the underwriters or the trustee takes any responsibility for the accuracy of the foregoing information, and you are urged to contact DTC or its participants directly to discuss these matters.

Euroclear and Clearstream will hold interests in the notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositaries, which are Euroclear Bank, S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream.

The laws of some jurisdictions require that purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer interests in the notes represented by a global note to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person having an interest in notes represented by a global note to pledge or transfer those interests to persons or entities that do not participate in DTC’s system, or otherwise to take actions in respect of such interest, may be affected by the lack of a physical definitive security in respect of such interest.

So long as DTC or its nominee is the registered owner of a global note, DTC or that nominee will be considered the sole owner or holder of the notes represented by that global note for all purposes under the indenture and under the notes. Except as provided below, owners of beneficial interests in a global note will not be entitled to have notes represented by that global note registered in their names, will not receive or be entitled to receive physical delivery of certificated notes and will not be considered the owners or holders thereof under the indenture or under the notes for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee. Accordingly, each holder owning a beneficial interest in a global note must rely on the procedures of DTC and, if that holder is not a direct or indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of notes under the indenture or the global note.

Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to the notes.

Payments on the notes represented by the global notes will be made to DTC or its nominee, as the case may be, as the registered owner of the notes. We expect that DTC or its nominee, upon receipt of any payment on the notes represented by a global note, will credit participants’ accounts with payments in amounts proportionate to their respective beneficial interests in the global note as shown in the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the global note held through such

 

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participants will be governed by standing instructions and customary practice as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. The participants will be responsible for those payments.

Payments on the notes represented by the global notes will be made in immediately available funds. Transfers between participants in DTC will be effected in accordance with DTC rules and will be settled in immediately available funds.

Cross-market transfers between participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their depositaries. Cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in that system in accordance with the rules and procedures and within the established deadlines (Brussels time) of that system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositaries to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a global note from a participant in DTC will be credited and reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a global note by or through a Euroclear or Clearstream participant to a participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Certificated notes

We will issue certificated notes to each person that DTC identifies as the beneficial owner of the notes represented by global notes upon surrender by DTC of such global notes if:

 

•

DTC notifies us that it is no longer willing or able to act as a depositary for such global notes, and we have not appointed a successor depositary within 90 days of that notice;

 

•

an event of default has occurred with respect to the notes and is continuing, and DTC requests the issuance of certificated notes with respect to the notes; or

 

•

we determine not to have the notes represented by a global note.

Neither we nor the trustee will be liable for any delay by DTC, its nominee or any direct or indirect participant in identifying the beneficial owners of the related notes. We and the trustee may conclusively rely on, and will be protected in relying on, instructions from DTC or its nominee for all purposes, including with respect to the registration and delivery, and the respective principal amounts, of the notes to be issued.

Certain definitions

“Aggregate Debt” means the sum of the following as of the date of determination: (a) the then outstanding aggregate principal amount of Debt secured by mortgages permitted by clauses (4), (5), (14) (to the extent the extension, renewal or replacement relates to Debt secured by mortgages Incurred pursuant to clause (4) or (5)) and (16) under “Covenants—Limitations on Liens” above, (b) the then outstanding aggregate principal amount

 

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of Indebtedness Incurred by our subsidiaries permitted by clauses (5), (6) and (13) under “Covenants—Limitations on Subsidiary Indebtedness” above and (c) the then outstanding aggregate principal amount of Attributable Indebtedness of all outstanding Sale and Lease-Back Transactions permitted under “Covenants—Limitations on Sale and Lease-Back Transactions” above.

“Attributable Indebtedness” means, with respect to any particular Sale and Lease-Back Transaction and at any date as of which the amount thereof is to be determined, the present value of the total net amount of rent required to be paid by such person under the lease during the primary term thereof (including any period for which such lease has been extended or may, at the option of the lessee, be extended), discounted from the respective due dates thereof at such date at the rate of interest per annum implicit in the terms of the lease (as determined in good faith by the Company).

“Consolidated net assets” means the total of all assets (less depreciation and amortization reserves and other valuation reserves and loss reserves) which, under generally accepted accounting principles, would appear on the asset side of our consolidated balance sheet, less the aggregate of all liabilities, deferred credits, minority shareholders’ interests in subsidiaries, reserves and other items which, under such principles, would appear on the liability side of such consolidated balance sheet, except debt for borrowed money and stockholders’ equity; provided, however, that in determining consolidated net assets, there shall not be included as assets, (a) all assets (other than goodwill, which shall be included) which would be classified as intangible assets under generally accepted accounting principles, including, without limitation, patents, trademarks, copyrights and unamortized debt discount and expense, (b) any treasury stock carried as an asset, or (c) any write-ups of capital assets (other than write-ups resulting from the acquisition of stock or assets of another corporation or business).

“Debt” means debt for money borrowed.

“Existing Revolving Credit Facility” means that certain 5- Year Revolving Credit Agreement, dated as of June 14, 2011, among Murphy Oil Corporation, Canam Offshore Limited and Murphy Oil Company Ltd., as borrowers, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, including any related notes, as the same may be amended, restated, refinanced, replaced, modified or otherwise supplemented from time to time.

“Indebtedness” means any liability of any person (i) for borrowed money, or (ii) evidenced by a bond, note, debenture or similar instrument (other than a trade payable or liabilities arising in the ordinary course of business), (iii) for the payment of money relating to a capital lease obligation, or (iv) any liability of others described in the preceding clauses (i), (ii) or (iii) that the person has guaranteed; in each case, solely to the extent such indebtedness would appear as a liability on the balance sheet of such person in accordance with GAAP. Notwithstanding the foregoing, Indebtedness shall exclude the contractual carry of a portion of the development costs of Athabasca Oil Corporation’s interest in the Kaybob Duvernay lands in an aggregate amount not to exceed Cdn $219,000,000. For the avoidance of doubt, surety bonds and similar instruments shall not be deemed Indebtedness.

“GAAP” means generally accepted accounting principles in the United States of America as in effect as of the issue date.

“Incur” means create, incur, issue, assume or guarantee. The term “Incurrence” when used as a noun shall have a correlative meaning.

“issue date” means August 17, 2016.

 

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“New Revolving Credit Facility” means that certain Credit Agreement dated August 10, 2016 among Murphy Oil Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, including any related notes, guarantees and collateral documents as the same may be amended, restated, refinanced, replaced, modified or otherwise supplemented from time to time.

“Principal property” means all property and equipment directly engaged in our exploration, production and transportation activities.

“Project Financing” means any Indebtedness that is Incurred to finance or refinance the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance, operation, securitization or monetization, in respect of all or any portion of any project, any group of projects, or any asset related thereto, and any guaranty with respect thereto, other than such portion of such Indebtedness or guaranty that expressly provides for direct recourse to us or any of our subsidiaries (other than a Project Financing Subsidiary) or any of their respective property other than recourse to the equity in, Indebtedness or other obligations of, or properties of, one or more Project Financing Subsidiaries; provided, however, that support such as limited guaranties or obligations to provide or guaranty equity contributions or to make subordinated loans that are customary in similar financing arrangements shall not be considered direct recourse for the purpose of this definition.

“Project Financing Subsidiary” means any of our subsidiaries whose principal purpose is to Incur Project Financing or to become a direct or indirect partner, member or other equity participant or owner in a person so created, and substantially all the assets of such subsidiary are limited to (i) those assets for which the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance, operation, securitization or monetization is being financed in whole or in part by one or more Project Financings, or (ii) the equity in, indebtedness or other obligations of, one or more other such subsidiaries or persons.

“Refinancing Indebtedness” means, in respect of any Indebtedness (the “Original Indebtedness”) any extension, renewal or refinancing thereof so long as (a) the principal amount of such Refinancing Indebtedness does not exceed the then existing principal amount of the Original Indebtedness (other than amounts Incurred to pay accrued and unpaid interest, fees and expenses (including original issue discount and upfront fees) and prepayment premiums on such Original Indebtedness or costs of such extension, renewal or refinancing), (b) the scheduled maturity date thereof is not shorter that the scheduled maturity date of the Original Indebtedness, (c) any remaining scheduled amortization of principal thereunder prior to the maturity date of the notes is not shortened, (d) such Refinancing Indebtedness shall not constitute an obligation (including pursuant to a guarantee) of any of our subsidiaries that shall not have been an obligor in respect of such Original Indebtedness, (e) if such Original Indebtedness shall have been subordinated to the notes, such Refinancing Indebtedness shall also be subordinated to the notes, (f) such Refinancing Indebtedness shall not be secured by any mortgage on any asset other than the assets that secured such Original Indebtedness.

“Revolving Credit Facilities” means, collectively, the Existing Revolving Credit Facility and the New Revolving Credit Facility.

“subsidiary” means (a) any corporation of which more than 50% of the total voting power of shares of capital stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors thereof is at the time directly or indirectly owned by Murphy Oil or by one or more of our subsidiaries, and (b) any limited partnership in which Murphy Oil or a subsidiary is a general partner and in which more than 50% of the capital accounts, distribution rights and voting interests thereof is at the time directly or indirectly owned by Murphy Oil or by one or more of our subsidiaries.

 

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Material U.S. federal income tax considerations for Non-U.S. Holders

The following are the material U.S. federal income tax consequences to non-U.S. Holders (as defined below) of owning and disposing of notes purchased in this offering at the “issue price,” which is the first price at which a substantial amount of the notes is sold to the public, and held as capital assets for U.S. federal income tax purposes.

This discussion does not describe all of the tax consequences that may be relevant to you in light of your particular circumstances, including alternative minimum tax and “Medicare contribution tax” consequences and differing tax consequences applicable to you if you are, for instance:

 

•

a financial institution;

 

•

a regulated investment company;

 

•

a dealer or trader in securities;

 

•

holding notes as part of a “straddle” or integrated transaction;

 

•

a partnership for U.S. federal income tax purposes; or

 

•

a tax-exempt entity.

If you are a partnership for U.S. federal income tax purposes, the U.S. federal income tax treatment of your partners will generally depend on the status of the partners and your activities. If you are such a partnership and are considering the purchase of notes, or if you are a partner in such a partnership, you are urged to consult your tax advisors about the U.S. federal income tax consequences of purchasing, owning and disposing of the notes.

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), to the date hereof, administrative pronouncements, judicial decisions and final, temporary and proposed Treasury Regulations, changes to any of which subsequent to the date of this prospectus supplement may affect the tax consequences described herein. If you are considering the purchase of notes, you should consult your tax adviser with regard to the application of the U.S. federal tax laws to your particular situation, as well as any tax consequences arising under the laws of any state, local or non-U.S. taxing jurisdiction.

As used herein, the term “non-U.S. Holder” means a beneficial owner of a note that is, for U.S. federal income tax purposes:

 

•

a non-resident alien individual;

 

•

a foreign corporation; or

 

•

a foreign estate or trust.

You are not a non-U.S. Holder if you are a non-resident alien individual present in the United States for 183 days or more in the taxable year of disposition, or if you are a former citizen or former resident of the United States, in which case you should consult your tax adviser regarding the U.S. federal income tax consequences of owning or disposing of a note.

 

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Payments on the notes

Subject to the discussion below under “—Effectively connected income,” “—Backup withholding and information reporting,” and “—FATCA” Payments of principal and interest on the notes by the Company or any paying agent to you will not be subject to U.S. federal income or withholding tax, provided that, in the case of interest,

 

•

you do not own, actually or constructively, ten percent or more of the total combined voting power of all classes of stock of the Company entitled to vote;

 

•

you are not a controlled foreign corporation related, directly or indirectly, to the Company through stock ownership;

 

•

you certify on a properly executed Internal Revenue Service (“IRS”) the relevant Form W-8BEN, as applicable, under penalties of perjury, that you are not a United States person; and

 

•

such interest is not effectively connected with your conduct of a trade or business in the United States as described below.

If you cannot satisfy one of the first three requirements described above and interest on the notes is not effectively connected with your conduct of a trade or business in the United States as described below, payments of interest on the notes generally will be subject to withholding tax at a rate of 30%, subject to an applicable income tax treaty providing for a reduced rate.

Sale or other taxable disposition of the notes

You generally will not be subject to U.S. federal income or withholding tax on gain realized on a sale, redemption or other taxable disposition of notes, unless the gain is effectively connected with your conduct of a trade or business in the United States as described below, provided however that any amounts attributable to accrued interest will be treated as described above under “—Payments on the Notes.”

Effectively connected income

If interest or gain on a note is effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment maintained by you), you will generally be taxed in the same manner as a United States person. In this case, you will be exempt from the withholding tax on interest discussed above, although you will be required to provide a properly executed
IRS Form W-8ECI in order to claim an exemption from withholding. You are urged to consult your tax adviser with respect to other U.S. tax consequences of the ownership and disposition of notes, including the possible imposition of a branch profits tax at a rate of 30% (or a lower treaty rate) if you are a corporation.

Backup withholding and information reporting

Information returns are required to be filed with the IRS in connection with payments of interest on the notes. Unless you comply with certification procedures to establish that you are not a United States person, information returns may also be filed with the IRS in connection with the proceeds from a sale or other disposition of a note. You may be subject to backup withholding on payments on the notes or on the proceeds from a sale or other disposition of the notes unless you comply with certification procedures to establish that you are not a United States person or otherwise establish an exemption. The certification procedures required to claim the exemption from withholding tax on interest described above under “—Payments on the notes,” will satisfy the certification requirements necessary to avoid backup withholding as well. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to you will be allowed as a credit against your U.S. federal income tax liability and may entitle you to a refund, provided that the required information is timely furnished to the IRS.

 

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FATCA

Under Sections 1471 through 1474 of the Code (such sections commonly referred to as “FATCA”), a 30% U.S. federal withholding tax may apply to payments to certain non-U.S. entities of interest on the notes and, beginning after
December 31, 2018, gross proceeds from the sale or other disposition of notes. FATCA imposes a 30% withholding tax on such payments to a “foreign financial institution,” as specially defined under such rules, unless the foreign financial institution enters into an agreement with the U.S. Treasury or, in the case of a foreign financial institution in a jurisdiction that has entered into an intergovernmental agreement with the United States, complies with the requirements of such agreement. In addition, FATCA imposes a 30% withholding tax on the same types of payments to a foreign non-financial entity unless the entity certifies that it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner. You should consult your tax adviser regarding FATCA.

 

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Underwriting

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, the underwriters named below, for whom J.P. Morgan Securities LLC is acting as representative, have severally agreed to purchase, and we have agreed to sell to such underwriters, the principal amount of the notes set forth opposite the names of such underwriters.

 

Underwriter		Notes
J.P. Morgan Securities LLC		$	132,000,000
Merrill Lynch, Pierce, Fenner & Smith                    Incorporated		$	82,500,000
BNP Paribas Securities Corp.		$	49,500,000
DNB Markets, Inc.		$	49,500,000
MUFG Securities Americas Inc.		$	49,500,000
Scotia Capital (USA) Inc.		$	49,500,000
Wells Fargo Securities, LLC		$	49,500,000
Regions Securities LLC		$	33,000,000
Capital One Securities, Inc.		$	27,500,000
Goldman, Sachs & Co.		$	27,500,000
Total		$	550,000,000

The underwriting agreement provides that the obligations of the several underwriters to purchase the notes included in this offering are subject to approval of certain legal matters by counsel and to certain other conditions. The underwriters are obligated to purchase all the notes if they purchase any of the notes. The underwriters may offer and sell the notes through one or more affiliates.

The underwriters propose to offer some of the notes directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the notes to certain dealers at the public offering price less a concession not in excess of 0.375% of the principal amount of the notes. The underwriters may allow, and such dealers may reallow, a concession not in excess of 0.250% of the principal amount of the notes on sales to certain other dealers. After the initial offering of the notes to the public, the public offering price and such concessions may be changed.

The following table shows the underwriting discount to be paid to the underwriters by us in connection with this offering.

 

		Per Note				Total
6.875% Notes due 2024			1.500	%		$	8,250,000

The notes are a new issue of securities with no established trading market. We do not currently intend to apply for the listing of the notes on any securities exchange or for quotation of the notes in any dealer quotation system. We have been advised by the underwriters that one or more of them intends to make a market in the notes, but the underwriters are not obligated to do so and may discontinue any market-making activities at any time without notice. We can give no assurance as to the liquidity of the trading market for the notes.

We estimate that our total expenses for this offering, excluding the underwriting discount, will be approximately $0.8 million.

 

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In connection with the offering, the representative, on behalf of the underwriters, may purchase and sell notes in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves syndicate sales of notes in excess of the principal amount of notes to be purchased by the underwriters in the offering, which creates a syndicate short position. Syndicate covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover syndicate short positions. Stabilizing transactions consist of certain bids or purchases of notes made for the purpose of preventing or retarding a decline in the market price of the notes while the offering is in progress.

Any of these activities may cause the price of the notes to be higher than the price that otherwise would exist in the open market in the absence of such transactions. These transactions may be effected in the over-the-counter market or otherwise and, if commenced, may be discontinued at any time.

We have agreed to indemnify the underwriters against certain liabilities, including certain liabilities under the Securities Act of 1933, as amended, or to contribute to payments the underwriters may be required to make in respect of any of those liabilities.

We have also agreed that, for a period of 15 days from the closing of the offering contemplated by this prospectus supplement, we will not, without the prior written consent of J.P. Morgan Securities LLC, as representative to the underwriters, offer, sell, contract to sell, pledge, or otherwise dispose of (or enter into any transaction which is designed to, or might reasonably be expected to result in the disposition (whether by actual disposition or effective economic disposition due to cash settlement or otherwise) by the Company or any affiliate of the Company or any person in privity with the Company or any affiliate of the Company), including the filing of a registration statement with the SEC in respect of, or establish or increase a put equivalent position or liquidate or decrease a call equivalent position within the meaning of Section 16 of the Exchange Act, any debt securities issued or guaranteed by the Company except for the notes, or publicly announce an intention to effect any such transaction.

In the ordinary course of their respective businesses, certain of the underwriters and the trustee and some of their affiliates have performed and may in the future perform various financial advisory, investment and commercial banking and lending services for us from time to time, including serving as counterparties to certain derivative and hedging arrangements, for which they have received or will receive customary fees. Some of the underwriters or affiliates of some of the underwriters, including affiliates of the representative, J.P. Morgan Securities LLC, and the trustee are lenders under our existing revolving credit facility and hold commitments under our New Revolving Credit Facility.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and instruments of ours or our affiliates. In particular, some of the underwriters or their affiliates may hold our 2.5% notes due 2017 for their own account or for the account of their customers. To the extent we use proceeds of this offering to repay, repurchase or redeem our 2.5% notes due 2017, such underwriters or their affiliates may receive a portion of the proceeds. If any of the underwriters or their affiliates has a lending relationship with us, certain of those underwriters and their affiliates routinely hedge, and certain other of those underwriters or their affiliates are likely to hedge, their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities, including potentially the notes offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the notes offered hereby. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent

 

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research views in respect of such securities or financial instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

Notice to prospective investors in the European Economic Area

In relation to each member state of the European Economic Area (each, a “Relevant Member State”), no offer of notes which are the subject of the offering has been, or will be made to the public in that Relevant Member State, other than under the following exemptions under the Prospectus Directive:

(A) to any legal entity which is a qualified investor as defined in the Prospectus Directive;

(B) to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), subject to obtaining the prior consent of the representative for any such offer; or

(C) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of notes referred to in (a) to (c) above shall result in a requirement for us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive, or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

This prospectus supplement and the accompanying prospectus have been prepared on the basis that any offer of notes in any Relevant Member State will be made pursuant to an exemption under the Prospectus Directive from the requirement to publish a prospectus for offers of notes. Accordingly any person making or intending to make an offer in that Relevant Member State of notes which are the subject of the offering contemplated in this prospectus supplement and the accompanying prospectus may only do so in circumstances in which no obligation arises for us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive in relation to such offer. Neither we nor any underwriter have authorized, nor do we or they authorize, the making of any offer of notes in circumstances in which an obligation arises for us or the underwriters to publish a prospectus for such offer.

For the purposes of this provision, the expression “an offer of notes to the public” in relation to any notes in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the notes to be offered so as to enable an investor to decide to purchase or subscribe the notes, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive that Relevant Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (as amended) and includes any relevant implementing measure in each Relevant Member State.

The above selling restriction is in addition to any other selling restrictions set out below.

Notice to prospective investors in the United Kingdom

In addition, in the United Kingdom, this prospectus supplement and the accompanying prospectus are being distributed only to, and are directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus supplement must not be acted on or relied on in the United Kingdom by persons who are not relevant persons. In the United Kingdom, any investment or investment activity to which this prospectus supplement relates is only available to, and will be engaged in with, relevant persons.

 

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Notice to prospective investors in Canada

The notes may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the notes must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 (or, in the case of securities issued or guaranteed by the government of a non-Canadian jurisdiction, section 3A.4) of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

 

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Legal matters

The validity of the notes will be passed on for us by Davis Polk & Wardwell LLP, New York, New York. Certain other legal matters in connection with this offering will be passed upon for the underwriters by Cravath, Swaine & Moore LLP, New York, New York.

Experts

The consolidated financial statements and schedule of Murphy Oil Corporation and subsidiaries as of December 31, 2015 and 2014, and for each of the years in the three-year period ended December 31, 2015, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2015, have been included herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

The audit report on the consolidated financial statements of Murphy Oil Corporation also refers to a change in method of accounting for debt issuance costs effective January 1, 2014.

Estimates of the proved reserves, future production and income attributable to leasehold properties of Murphy Oil Corporation located in the Eagle Ford Shale in south Texas in the United States as of December 31, 2015 included and incorporated by reference in this prospectus supplement are confirmed in the audit report prepared by Ryder Scott Company, L.P., independent petroleum engineers. We have included and incorporated by reference this audit report in reliance on the authority of such firm as an expert in such matters.

 

 

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Index to financial statements

 

Audited financial statements:
Report of management—consolidated financial statements			F-1
Report of management—internal control over financial reporting			F-1
Report of independent registered public accounting firm			F-2
Report of independent registered public accounting firm			F-3
Consolidated balance sheets as of December 31, 2015 and 2014			F-4
Consolidated statements of operations for the years ended December 31, 2015, 2014 and 20134			F-5
Consolidated statements of comprehensive income (loss) for the years ended December  31, 2015, 2014 and 2013			F-6
Consolidated statements of cash flows for the years ended December 31, 2015, 2014 and 2013			F-7
Consolidated statements of stockholders’ equity for the years ended December 31, 2015, 2014 and 2013			F-8
Notes to consolidated financial statements			F-9
Supplemental oil and gas information (unaudited)			F-53
Supplemental quarterly information (unaudited)			F-69
Unaudited financial statements:
Consolidated balance sheets as of June 31, 2016 and December 31, 2015			F-72
Consolidated statements of operations for the three months ended March  31, 2016 and 2015 and the six months ended June 30, 2016 and 2015			F-73
Consolidated statements of comprehensive income (loss) for the three months ended March  31, 2016 and 2015 and the six months ended June 30, 2016 and 2015			F-74
Consolidated statements of cash flows for the six months ended June 30, 2016 and 2015			F-75
Consolidated statements of stockholders’ equity for the six months ended June 30, 2016 and 2015			F-76
Notes to unaudited consolidated financial statements			F-77

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Report of management—consolidated financial statements

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with U.S. generally accepted accounting principles (GAAP) appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the Company’s consolidated financial statements. The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders. KPMG LLP’s opinion covering the Company’s consolidated financial statements can be found on page F-2.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

Report of management—internal control over financial reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. GAAP. All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.

Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2015.

KPMG LLP has performed an audit of the Company’s internal control over financial reporting and their opinion thereon can be found on page F-3.

 

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Report of independent registered public accounting firm

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2015. In connection with our audits of the consolidated financial statements, we also have audited financial statement Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. GAAP. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note B to the financial statements, Murphy Oil Corporation changed its method of accounting for debt issuance costs effective January 1, 2014 due to the adoption of FASB ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 26, 2016

 

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Report of independent registered public accounting firm

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Murphy Oil Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Murphy Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Murphy Oil Corporation as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2015, and our report dated February 26, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 26, 2016

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Consolidated balance sheets

 

December 31 (thousands of dollars)		2015				2014*
Assets
Current assets
Cash and cash equivalents		$	283,183				1,193,308
Canadian government securities with maturities greater than 90 days at the date of acquisition			173,288				461,313
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2015 and $1,609 in 2014			522,672				873,277
Inventories, at lower of cost or market			166,788				242,733
Prepaid expenses			212,962				77,281
Deferred income taxes			51,183				55,107
Assets held for sale			38,340				376,130
Total current assets			1,448,416				3,279,149
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,924,193 in 2015 and $9,503,524 in 2014			9,818,365				13,331,047
Deferred charges and other assets			227,031				62,582
Assets held for sale			—				50,960
Total assets		$	11,493,812				16,723,738
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt		$	18,881				465,388
Accounts payable			1,529,848				2,275,830
Income taxes payable			4,819				59,054
Other taxes payable			38,498				52,457
Other accrued liabilities			75,286				143,610
Liabilities associated with assets held for sale			7,297				151,548
Total current liabilities			1,674,629				3,147,887
Long-term debt, including capital lease obligation			3,040,594				2,517,669
Deferred income taxes			239,811				1,193,864
Asset retirement obligations			793,474				841,526
Deferred credits and other liabilities			438,576				441,048
Liabilities associated with assets held for sale			—				8,310
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 2015 and 195,040,149 shares in 2014			195,056				195,040
Capital in excess of par value			910,074				906,741
Retained earnings			6,212,201				8,728,032
Accumulated other comprehensive loss			(704,542	)			(170,255	)
Treasury stock			(1,306,061	)			(1,086,124	)
Total stockholders’ equity			5,306,728				8,573,434
Total liabilities and stockholders’ equity		$	11,493,812				16,723,738

 

*Reclassified

to conform to current presentation.

See notes to consolidated financial statements, page F-9.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of operations

 

Years ended December 31 (thousands of dollars except per share amounts)		2015				2014				2013
Revenues
Sales and other operating revenues		$	2,787,116				5,288,933				5,312,686
Gain (loss) on sale of assets			154,155				138,903				(87	)
Interest and other income			91,809				48,248				77,490
Total revenues			3,033,080				5,476,084				5,390,089
Costs and Expenses
Lease operating expenses			832,306				1,089,888				1,252,812
Severance and ad valorem taxes			65,794				107,215				87,331
Exploration expenses, including undeveloped lease amortization			470,924				513,600				502,215
Selling and general expenses			306,663				364,004				379,167
Depreciation, depletion and amortization			1,619,824				1,906,247				1,553,394
Impairment of assets			2,493,156				51,314				21,587
Accretion of asset retirement obligations			48,665				50,778				48,996
Deepwater rig contract exit costs			282,001				—				—
Interest expense			124,665				136,424				124,423
Interest capitalized			(7,290	)			(20,605	)			(52,523	)
Other expense			78,634				24,949				—
Total costs and expenses			6,315,342				4,223,814				3,917,402
Income (loss) from continuing operations before income taxes			(3,282,262	)			1,252,270				1,472,687
Income tax expense (benefit)			(1,026,490	)			227,297				584,550
Income (loss) from continuing operations			(2,255,772	)			1,024,973				888,137
Income (loss) from discontinued operations, net of income taxes			(15,061	)			(119,362	)			235,336
Net Income (Loss)		$	(2,270,833	)			905,611				1,123,473
Per Common Share—Basic
Income (loss) from continuing operations		$	(12.94	)			5.73				4.73
Income (loss) from discontinued operations			(0.09	)			(0.67	)			1.25
Net income (loss)		$	(13.03	)			5.06				5.98
Per Common Share—Diluted
Income (loss) from continuing operations		$	(12.94	)			5.69				4.69
Income (loss) from discontinued operations			(0.09	)			(0.66	)			1.25
Net income (loss)		$	(13.03	)			5.03				5.94
Average Common shares outstanding—basic			174,351,227				178,852,942				187,921,062
Average Common shares outstanding—diluted			174,351,227				180,070,984				189,271,398

See notes to consolidated financial statements, page F-9.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of comprehensive income (loss)

 

Years ended December 31 (thousands of dollars)		2015				2014				2013
Net income (loss)		$	(2,270,833	)			905,611				1,123,473
Other comprehensive loss, net of tax
Net loss from foreign currency translation			(546,705	)			(271,491	)			(308,300	)
Retirement and postretirement benefit plans			10,492				(72,796	)			69,583
Deferred loss on interest rate hedges reclassified to interest expense.			1,926				1,913				1,935
Other comprehensive loss			(534,287	)			(342,374	)			(236,782	)
Comprehensive income (loss)		$	(2,805,120	)			563,237				886,691

See notes to consolidated financial statements, page F-9.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of cash flows

 

Years ended December 31 (thousands of dollars)		2015				2014				2013
Operating Activities
Net income (loss)		$	(2,270,833	)			905,611				1,123,473
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:
Loss (income) from discontinued operations			15,061				119,362				(235,336	)
Depreciation, depletion and amortization			1,619,824				1,906,247				1,553,394
Impairment of assets			2,493,156				51,314				21,587
Amortization of deferred major repair costs			7,296				8,345				8,464
Dry hole costs			296,845				269,986				262,876
Amortization of undeveloped leases			75,312				74,438				66,891
Accretion of asset retirement obligations			48,665				50,778				48,996
Deferred and noncurrent income tax charges (benefits)			(978,030	)			(170,915	)			158,108
Pretax (gains) losses from disposition of assets			(154,155	)			(138,903	)			87
Net decrease (increase) in noncash operating working capital			35,064				(3,729	)			266,329
Other operating activities, net			(4,836	)			(23,895	)			(64,174	)
Net cash provided by continuing operations activities			1,183,369				3,048,639				3,210,695
Investing Activities
Property additions and dry hole costs1			(2,549,736	)			(3,679,464	)			(3,590,344	)
Proceeds from sales of property, plant and equipment			423,911				1,467,046				1,650
Purchase of investment securities2			(911,787	)			(986,328	)			(923,497	)
Proceeds from maturity of investment securities2			1,129,139				899,857				664,258
Other investing activities, net			(13,648	)			(18,929	)			291
Net cash required by investing activities			(1,922,121	)			(2,317,818	)			(3,847,642	)
Financing Activities
Borrowings of debt1			600,000				100,000				350,000
Repayments of debt			(450,000	)			—				—
Capital lease obligation payments			(10,434	)			(25,265	)			—
Purchase of treasury stock			(250,000	)			(375,000	)			(500,000	)
Proceeds from exercise of stock options and employee stock purchase plans			—				210				3,409
Withholding tax on stock-based incentive awards			(8,976	)			(6,786	)			(16,727	)
Cash dividends paid			(244,998	)			(236,371	)			(235,108	)
Separation of U.S. retail marketing business:
Cash distributed to Murphy Oil by Murphy USA			—				—				650,000
Cash held and retained by Murphy USA upon separation			—				—				(55,506	)
Other financing activities, net			(153	)			(1,498	)			(2,473	)
Net cash provided (required) by financing activities			(364,561	)			(544,710	)			193,595
Cash Flows from Discontinued Operations
Operating activities			(15,005	)			(39,563	)			427,792
Investing activities			5,314				199,541				116,463
Changes in cash included in current assets held for sale			192,585				100,790				(301,302	)
Net increase in cash and cash equivalents of discontinued operations			182,894				260,768				242,953
Effect of exchange rate changes on cash and cash equivalents			10,294				(3,726	)			3,238
Net increase (decrease) in cash and cash equivalents			(910,125	)			443,153				(197,161	)
Cash and cash equivalents at January 1			1,193,308				750,155				947,316
Cash and cash equivalents at December 31		$	283,183				1,193,308				750,155

 

1

Excludes noncash asset and long-term obligation of $357,991 in 2013 associated with lease commencement for production equipment at the Kakap field offshore Malaysia.

 

2

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

See notes to consolidated financial statements, page F-9.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of stockholders’ equity

 

Years ended December 31 (thousands of dollars)		2015				2014				2013
Cumulative Preferred Stock—par $100, authorized 400,000 shares, none issued		$	—				—				—
Common Stock—par $1.00, authorized 450,000,000 shares at December 31, 2015, 2014 and 2013, issued 195,055,724 shares at December 31, 2015, 195,040,149 shares at December 31, 2014 and 194,920,155 shares at December 31, 2013
Balance at beginning of year			195,040				194,920				194,616
Exercise of stock options			16				120				304
Balance at end of year			195,056				195,040				194,920
Capital in Excess of Par Value
Balance at beginning of year			906,741				902,633				873,934
Exercise of stock options, including income tax benefits			(376	)			(11,422	)			563
Restricted stock transactions and other			(38,415	)			(27,920	)			(28,339	)
Stock-based compensation			42,322				43,490				56,622
Other			(198	)			(40	)			(147	)
Balance at end of year			910,074				906,741				902,633
Retained Earnings
Balance at beginning of year			8,728,032				8,058,792				7,717,389
Net income (loss) for the year			(2,270,833	)			905,611				1,123,473
Cash dividends—$1.40 per share in 2015, $1.325 per share in 2014 and $1.25 per share in 2013			(244,998	)			(236,371	)			(235,108	)
Distribution of common stock of Murphy USA Inc. to shareholders			—				—				(546,962	)
Balance at end of year			6,212,201				8,728,032				8,058,792
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of year			(170,255	)			172,119				408,901
Foreign currency translation losses, net of income taxes			(546,705	)			(271,491	)			(308,300	)
Retirement and postretirement benefit plans, net of income taxes			10,492				(72,796	)			69,583
Deferred loss on interest rate hedges, reclassified to interest expense, net of income taxes			1,926				1,913				1,935
Balance at end of year			(704,542	)			(170,255	)			172,119
Treasury Stock
Balance at beginning of year			(1,086,124	)			(732,734	)			(252,805	)
Purchase of treasury shares			(250,000	)			(375,000	)			(500,000	)
Sale of stock under employee stock purchase plans			491				420				1,015
Awarded restricted stock			29,572				21,190				19,056
Balance at end of year—23,021,013 shares of Common Stock in 2015, 17,540,636 shares of Common Stock in 2014 and 11,513,642 shares of Common Stock in 2013			(1,306,061	)			(1,086,124	)			(732,734	)
Total Stockholders’ Equity		$	5,306,728				8,573,434				8,595,730

See notes to consolidated financial statements, page F-9.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements

Note A—Significant accounting policies

NATURE OF BUSINESS—Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company has an interest in a Canadian synthetic oil operation. On August 30, 2013, the Company spun off Murphy USA Inc. (MUSA) to its shareholders. In addition, Murphy Oil sold its remaining downstream assets in the United Kingdom in 2015, U.K. retail marketing assets during 2014 and its U.K. oil and natural gas producing assets during 2013. See Note C regarding more information regarding the spin-off and sale of these assets.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated.

REVENUE RECOGNITION—Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2015 and 2014, the liabilities for natural gas balancing were immaterial.

CASH EQUIVALENTS—Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.

MARKETABLE SECURITIES—The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2015, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $173,288,000. These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.

ACCOUNTS RECEIVABLE—At December 31, 2015 and 2014, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

INVENTORIES—Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment.

PROPERTY, PLANT AND EQUIPMENT—The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete.

Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. During 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2015, the Company recognized a pretax impairment charge of approximately $2,493,200,000 to reduce the carrying value of certain producing properties in the Gulf of Mexico, Western Canada and Malaysia to their estimated fair value. See also Note E for further discussion of impairment charges.

The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.

 

F-10

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves; unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia and Canada are being depreciated on a straight-line basis over its estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in income (loss) as a separate component of revenues.

Turnarounds for coking units at Syncrude Canada Ltd. are scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varies depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease Operating Expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized.

CAPITALIZED INTEREST—Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statement of Operations and is added to the cost of the underlying asset for the development project in Property, Plant and Equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.

GOODWILL—Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired. Goodwill is not amortized, but is assessed annually for recoverability of the carrying value. The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties with the carrying value of these net assets including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company recorded an impairment charge of $37,047,000 in 2014 and reduced the carrying amount to zero.

ENVIRONMENTAL LIABILITIES—A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized.

INCOME TAXES—The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. The Company does not provide U.S. deferred taxes for the portion of undistributed earnings of foreign subsidiaries

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

when these earnings are considered indefinitely reinvested in the respective foreign operations. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.

FOREIGN CURRENCY—Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES—The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in other comprehensive loss until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in other comprehensive loss is recognized immediately in earnings.

FAIR VALUE MEASUREMENTS—The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

STOCK-BASED COMPENSATION

Equity-Settled Awards—The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock prices. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

stock on the date of grant and expense is recognized over the three-year vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.

Cash-Settled Awards—The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards.

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS—The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Statement of Operations are recorded net of tax in Accumulated Other Comprehensive Loss. The remaining amounts in Accumulated Other Comprehensive Loss as of December 31, 2015 include net actuarial losses and prior service costs.

NET INCOME (LOSS) PER COMMON SHARE—Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.

RECLASSIFICATIONS—The Consolidated Balance Sheet for 2014 has been reclassified to conform to the 2015 presentation within deferred charges and other assets and long-term debt.

USE OF ESTIMATES—In preparing the financial statements of the Company in conformity with U.S. GAAP, 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.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Note B—New accounting principles and recent accounting pronouncements

Accounting principle adopted

Presentation of debt issuance costs.    In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs. The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability. These costs have historically been recorded as an asset, rather than a direct reduction of debt. The ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense. The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted. The Company elected to adopt this ASU early, effective with the first quarter of 2015. This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances. A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption. The retrospective adjustment to the December 31, 2014 Balance Sheet is shown below:

 

(thousands of dollars)		As previously reported December 31, 2014				Adjustment effect				December 31, 2014 as adjusted
Deferred charges and other assets		$	81,151				(18,569	)			62,582
Long-term debt			(2,536,238	)			18,569				(2,517,669	)

Recent accounting pronouncements

Balance sheet classification of deferred taxes.    In November 2015, the FASB issued an ASU that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. The Company will adopt this guidance in 2016 and does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures.

Revenue from contracts with customers.    In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of this revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Note C—Discontinued operations

Separation of U.S. downstream business

On August 30, 2013, Murphy Oil Corporation (the “Company”) distributed 100% of the outstanding common stock of Murphy USA Inc. (“MUSA”) to its shareholders in a generally tax-free spin-off for U.S. federal income tax purposes. Prior to the separation, MUSA held all of the Company’s U.S. downstream operations, including retail gasoline stations and other marketing assets, plus two ethanol production facilities. In connection with the separation, Murphy Oil USA, Inc., MUSA’s 100% owned primary operating subsidiary, distributed $650,000,000 to the Company in the form of a cash dividend. The Company has no continuing involvement with MUSA operations. Accordingly, the operating results and the cash flows for these former U.S. downstream operations have been reported as discontinued operations for all periods presented in the consolidated financial statements.

In order to effect the separation and govern the Company’s relationship with MUSA after the separation, both parties entered into a series of agreements governing each party’s rights and obligations after the separation. Among such agreements, the Separation and Distribution Agreement governs the separation of the U.S. downstream business, the transfer of assets, cross-indemnities between the Company and MUSA, handling of claims subject to indemnification and related matters, and other matters related to the Company’s relationship with MUSA.

The Tax Matters Agreement governs the respective rights, responsibilities and obligations of the Company and MUSA with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Matters Agreement imposes certain restrictions on MUSA and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the tax-free status of the distribution.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of the Company and MUSA, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of MUSA will no longer participate in benefit plans sponsored or maintained by the Company. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and that the Company will be responsible for liabilities relating to former employees who left prior to the separation. The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.

The Transition Service Agreement sets forth the terms on which the Company and MUSA will provide certain services or functions to the other party. Transition services include administration, payroll, human resources, data processing, environmental health and safety, audit support, financial transaction support, and other support services, information technology systems and various other corporate services. The agreement provided for the provision of specified services, generally for a period of up to 18 months, with a possible extension of six months (an aggregate of 24 months), on a full cost basis. The Transition Service Agreement expired in 2015.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Other discontinued operations

The Company sold all of its U.K. oil and natural gas production assets during 2013, and recognized an after-tax gain of $216,147,000 on sale of these assets. The results of these operations have been reported as discontinued operations for all periods presented in these consolidated financial statements.

On September 30, 2014, the Company sold its U.K. retail marketing operations and associated inventories with total proceeds of $211,965,000. The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in the second quarter of 2015 for cash proceeds of $5,500,000. The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented.

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2015 and 2014.

 

(thousands of dollars)		2015				2014
Current assets
Cash		$	7,927				200,512
Accounts receivable			12,037				97,568
Inventories			—				42,161
Other			18,376				35,889
Total current assets held for sale		$	38,340				376,130
Non-current assets
Property, plant and equipment, net		$	—				50,947
Other			—				13
Total non-current assets held for sale		$	—				50,960
Current liabilities
Accounts payable		$	2,433				59,023
Other accrued taxes payable			—				40,653
Accrued compensation and severance			2,179				30,872
Refinery decommissioning cost			2,685				21,000
Total current liabilities associated with assets held for sale		$	7,297				151,548
Non-current liabilities
Deferred income taxes payable		$	—				3,873
Deferred credits and other liabilities			—				4,437
Total non-current liabilities associated with assets held for sale		$	—				8,310

In 2014 and 2013, the Company wrote down its net investment in the held for sale U.K. refining and marketing assets by $269,200,000 and $73,000,000, respectively. The 2014 writedown was based on estimated salvage value of remaining refining and terminal assets as of the end of the year. The 2013 write down was based on an assessment of the fair value of these assets based on the status of the ongoing sale process at that time. The Company benefited in 2014 from a LIFO inventory liquidation credit of $209,600,000 and a gain on sale of the U.K. retail marketing assets of $101,700,000. These charges and benefits have been included in the results of discontinued operations.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Discontinued operations inventories accounted for under the LIFO method totaled $10,954,000 at December 31, 2014 and these amounts were $44,881,000 less than such inventories would have been valued using the FIFO method. These inventories are carried in Current Assets Held for Sale in the Consolidated Balance Sheet at December 31, 2014. In association with the shutdown of the Milford Haven, Wales, refinery in 2014, most crude oil inventories and a large portion of the refinery’s finished products were liquidated at market values. This reduction in LIFO inventory reserve benefited discontinued operating results in 2014 as noted above.

The results of operations associated with all discontinued operations are presented in the following table.

 

(thousands of dollars)		2015				2014				2013
Revenues		$	381,747				2,786,394				17,586,236
Income (loss) from operations before income taxes		$	(6,758	)			(261,873	)			119,984
Gain (loss) on sale before income taxes			(4,990	)			101,684				130,991
Total income (loss) from discontinued operations before taxes			(11,748	)			(160,189	)			250,975
Income tax expense (benefit)			3,313				(40,827	)			15,639
Income (loss) from discontinued operations		$	(15,061	)			(119,362	)			235,336

Note D—Inventories

Inventories consisted of the following at December 31, 2015 and 2014.

 

		December 31,
(thousands of dollars)		2015				2014
Unsold crude oil		$	25,583				51,810
Materials and supplies			141,205				190,923
		$	166,788				242,733

Note E—Property, plant and equipment

 

		December 31, 2015								December 31, 2014
(thousands of dollars)		Cost				Net				Cost				Net
Exploration and production1		$	21,607,962				9,723,222	2			22,731,220				13,277,985	2
Corporate and other			134,596				95,143				103,351				53,062
		$	21,742,558				9,818,365				22,834,571				13,331,047
1       Includes mineral rights as follows:		$	1,075,040				612,518				924,253				410,482
2.      Includes $50,924 in 2015 and $58,334 in 2014        related to administrative assets and support equipment.

In late 2014 and early 2015, the Company sold a total of 30% of its oil and gas assets in Malaysia. In January 2015, the Company sold 10% of its assets and received net cash proceeds of $417,200,000. The Company recorded an after-tax gain of $218,800,000 in 2015 on the sale of the 10%. In December 2014, the Company sold 20% of its oil and gas assets in Malaysia and received net cash proceeds of $1,460,425,000. The Company recorded an after-tax gain on this sale of $321,454,000 in 2014.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Under 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 December 31, 2015, 2014 and 2013, the Company had total capitalized drilling costs pending the determination of proved reserves of $130,514,000, $120,455,000 and $393,030,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2015.

 

(thousands of dollars)		2015				2014				2013
Beginning balance at January 1		$	120,455				393,030				445,697
Additions to capitalized exploratory well costs pending the determination of proved reserves			64,578				2,874				57,716
Reclassifications to proved properties based on the determination of proved reserves			—				(91,236	)			(93,936	)
Reduction of capitalized exploratory well costs due to partial asset sale in Malaysia			—				(122,175	)			—
Capitalized exploratory well costs charged to expense			(54,519	)			(62,038	)			(16,447	)
Ending balance at December 31		$	130,514				120,455				393,030

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 has been capitalized. The projects are aged based on the last well drilled in the project.

 

		2015												2014												2013
(thousands of dollars)		Amount				No. of wells				No. of projects				Amount				No. of wells				No. of projects				amount				No. of wells				No. of projects
Aging of capitalized well costs:
Zero to one year		$	66,032				7				6			$	—				—				—			$	56,499				3				1
One to two years			—				—				—				59,330				3				1				60,787				7				1
Two to three years			57,876				3				—				6,606				3				—				—				—				—
Three years or more			6,606				3				—				54,519				2				2				275,744				22				7
		$	130,514				13				6			$	120,455				8				3			$	393,030				32				9

Exploratory well costs capitalized more than one year at December 31, 2015 are in Brunei. In Brunei, development options are under review for these multiple gas discoveries. The capitalized well costs charged to expense in 2015 included one well in the Gulf of Mexico in which development of the well could not be justified due to uncommercial hydrocarbon quantities found in the sidetrack and one project in the Gulf of Mexico deemed unlikely to be developed due to distressed commodity prices. The capitalized well costs charged to expense in 2014 included four gas wells in Peninsula Malaysia and one well in the Gulf of Mexico. The Company’s application to extend the gas holding period for the Malaysia wells was denied by the Malaysian government in 2014. Development of the well in the Gulf of Mexico could not be justified due to the low prices for natural gas at year-end 2014. The capitalized well costs charged to expense in 2013 included two wells offshore Sarawak Malaysia that were written off due to the Company’s decision not to move forward with development of the wells.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

During the second half of 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments, the Company recognized pretax noncash impairment charges of $2,493,156,000 to reduce the carrying value of certain offshore producing and non-producing properties in the Gulf of Mexico, producing offshore properties in Malaysia and for Western Canada onshore heavy oil producing properties to their estimated fair value. At year-end 2014, the Company recorded an impairment writedown in the amount of $14,267,000 related to one gas well in the Gulf of Mexico, and in 2013 an impairment writedown of $21,587,000 was recorded for properties in Western Canada. 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 following table reflects the recognized impairments for the three years ended December 31, 2015.

 

		December 31,
(thousands of dollars)		2015				2014				2013
Gulf of Mexico		$	328,982				14,267				—
Western Canada—Heavy Oil			683,574				37,047	*			21,587
Malaysia			1,480,600				—				—
		$	2,493,156				51,314				21,587

 

*

This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000.

Note F—Financing arrangements

At December 31, 2015, the Company had a $2.0 billion committed credit facility with a major banking consortium that expires in May 2017. Borrowings under this facility bear interest at 1.45% above LIBOR based on the Company’s current credit rating as of February 15, 2016. In addition, facility fees of 0.25% are charged on the full $2.0 billion commitment. At December 31, 2015, the Company had borrowings of $600,000,000 under this committed facility. At December 31, 2015, the Company also had uncommitted credit lines that had estimated total borrowing capacity of approximately $300,000,000. No borrowings were outstanding under these uncommitted credit lines at December 31, 2015. If necessary, the Company believes it could borrow funds under all or certain of these uncommitted lines with various financial institutions in future periods. On October 16, 2015, the Company renewed its 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.

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 2029. Current maturities and long-term debt on the Consolidated Balance Sheet included $18,881,000 and $209,817,000, respectively, associated with this lease at December 31, 2015.

 

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Notes to consolidated financial statements—continued

 

Note G—Long-term debt

 

		December 31,
(thousands of dollars)		2015				2014*
Notes payable
2.50% notes, due December 2017		$	550,000				550,000
4.00% notes, due June 2022			500,000				500,000
3.70% notes, due December 2022			600,000				600,000
7.05% notes, due May 2029			250,000				250,000
5.125% notes, due December 2042			350,000				350,000
Notes payable to banks, 1.4375% at December 31, 2015			600,000				450,000
Total notes payable			2,850,000				2,700,000
Unamortized discount on notes payable			(19,223	)			(23,522	)
Total notes payable, net of unamortized discount			2,830,777				2,676,478
Capitalized lease obligation, due through June 2029			228,698				306,579
Total debt including current maturities			3,059,475				2,983,057
Current maturities			(18,881	)			(465,388	)
Total long-term debt		$	3,040,594				2,517,669

*

Reclassified to current presentation

The amount of debt repayable over each of the next five years and thereafter are as follows: $18,881,000 in 2016, $1,158,785,000 in 2017, $13,554,000 in 2018, $14,233,000 in 2019, $14,988,000 in 2020 and $1,839,034,000 thereafter.

The capitalized lease obligation included in the above table is associated with production facilities at the Kakap field, offshore Sabah, Malaysia. The facilities are utilized by the Company under a 25-year lease that extends through 2038. Payments under this lease are owed through 2029.

Based on a downgrade of the credit rating for the Company’s notes by Moody’s Investor Service in February 2016, the coupon rates on notes maturing in December 2017, December 2022 and December 2042 will each increase by 1.00% effective June 1, 2016. The coupon rates on the June 2022 and May 2029 notes are not changed by the recent Moody’s rating action.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Note H—Asset retirement obligations

The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2015 and 2014 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment.

A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2015 and 2014 is shown in the following table.

 

(thousands of dollars)		2015				2014
Balance at beginning of year		$	875,728				880,003
Accretion expense			48,665				50,778
Liabilities incurred			76,775				70,568
Revisions of previous estimates			(85,504	)			8,278
Liabilities settled			(13,359	)			(36,818	)
Liabilities assumed by purchaser of oil and gas assets			(33,448	)			(69,416	)
Changes due to translation of foreign currencies			(43,545	)			(27,665	)
Balance at end of year			825,312				875,728
Current portion of liability at end of year*			(31,838	)			(34,202	)
Noncurrent portion of liability at end of year		$	793,474				841,526

 

*

Included in Other Accrued Liabilities on the Consolidated Balance Sheet.

The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Note I—Income taxes

The components of income (loss) from continuing operations before income taxes for each of the three years ended December 31, 2015 and income tax expense (benefit) attributable thereto were as follows.

 

(thousands of dollars)		2015				2014				2013
Income (loss) from continuing operations before income taxes
United States		$	(1,259,268	)			179,484				(5,810	)
Foreign			(2,022,994	)			1,072,786				1,478,497
Total		$	(3,282,262	)			1,252,270				1,472,687
Income tax expense (benefit)
Federal—Current		$	(9,435	)			25,151				(56,790	)
—Deferred			(241,127	)			25,444				65,883
			(250,562	)			50,595				9,093
State			(5,294	)			8,840				7,141
Foreign—Current			(40,550	)			359,502				477,715
—Deferred			(730,084	)			(191,640	)			90,601
			(770,634	)			167,862				568,316
Total		$	(1,026,490	)			227,297				584,550

The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.

 

(thousands of dollars)		2015				2014				2013
Income tax expense (benefit) based on the U.S. statutory tax rate		$	(1,148,792	)			438,295				515,440
Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate			49,739				20,562				31,752
State income taxes, net of federal benefit			(3,441	)			5,746				4,642
U.S. tax benefit on certain foreign upstream investments			(16,939	)			(95,838	)			(133,526	)
Current tax on distribution of foreign earnings			—				52,724				—
Deferred tax on distribution of foreign earnings			188,461				—				—
Tax effects on sale of Malaysian assets			(122,559	)			(227,241	)			—
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures			40,788				37,712				129,588
Impairment or abandonment of Azurite field with no tax benefit			—				—				35,475
Other, net			(13,747	)			(4,663	)			1,179
Total		$	(1,026,490	)			227,297				584,550

In December 2015, one of the company’s foreign subsidiaries declared a $2,000,000,000 dividend payable to its parent. The dividend represented substantially all of the foreign subsidiary’s accumulated retained earnings under U.S. GAAP. The foreign subsidiary’s dividend was settled with an $800,000,000 cash payment plus issuance of a $1,200,000,000 note payable to its U.S. parent to be paid over 10 years. The dividend was

 

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Notes to consolidated financial statements—continued

 

completed without a U.S. current tax impact due to the utilization of the 2015 U.S. tax net operating loss combined with the shareholder’s ability to use allowed foreign tax credits that attached to the dividend. Based on the usage of the 2015 U.S. tax net operating loss, a non-cash tax expense of $188,461,000 was recorded in 2015, primarily associated with using a U.S. deferred tax asset that would otherwise have carried forward to future years without the dividend.

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2015 and 2014 showing the tax effects of significant temporary differences follows.

 

(thousands of dollars)		2015				2014
Deferred tax assets
Property and leasehold costs		$	587,517				379,577
Liabilities for dismantlements			114,565				85,544
Postretirement and other employee benefits			226,217				208,600
Alternative minimum tax			39,683				46,792
Foreign tax credit carryforwards			855				44,061
Other deferred tax assets			127,165				22,426
Total gross deferred tax assets			1,096,002				787,000
Less valuation allowance			(294,406	)			(306,463	)
Net deferred tax assets			801,596				480,537
Deferred tax liabilities
Property, plant and equipment			—				(479,677	)
Accumulated depreciation, depletion and amortization			(793,972	)			(1,123,864	)
Other deferred tax liabilities			(21,095	)			(15,753	)
Total gross deferred tax liabilities			(815,067	)			(1,619,294	)
Net deferred tax liabilities		$	(13,471	)			(1,138,757	)

In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions and foreign tax credit carryforwards. In the judgment of management at the present time, these tax assets are not likely to be realized. The foreign tax credit carryforwards expire in 2016 through 2025. The valuation allowance decreased $12,057,000 in 2015. The deferred tax valuation allowance decreased by $43,206,000 in 2015 due to foreign tax credit carry forwards realization of U.S. tax benefits on cash repatriated to the U.S. in 2015, partially offset by increases related to other certain deferred tax assets. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.

The Company has not recognized a deferred tax liability for undistributed earnings of its Canadian, and Malaysian operating subsidiaries because such earnings are considered indefinitely reinvested in foreign countries. As of December 31, 2015, undistributed earnings of the Company’s subsidiaries considered indefinitely reinvested were approximately $2,866,000,000. The unrecognized deferred tax liability is dependent on many factors including withholding taxes under current tax treaties and foreign tax credits and is

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

estimated to be approximately $440,000,000. The Company does not consider undistributed earnings from certain other international operations to be indefinitely reinvested. Although the Company does not foresee repatriating earnings considered indefinitely reinvested, under present law, it would incur a 5% withholding tax on any monies repatriated from Canada to the United States.

Uncertain income tax positions

The FASB’s rules for accounting for income tax uncertainties clarify the criteria for recognizing uncertain income tax benefits and require additional disclosures about uncertain tax positions. Under current rules the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon audit by the applicable taxing authority. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheet. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years ended December 31, 2015 is shown in the following table.

 

(thousands of dollars)		2015				2014				2013
Balance at January 1		$	6,011				6,366				16,611
Additions for tax positions related to current year			821				988				2,486
Settlements due to lapse of time			—				(1,225	)			(12,731	)
Foreign currency translation effect			(201	)			(118	)			—
Balance at December 31		$	6,631				6,011				6,366

All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded liabilities as of December 31, 2015 and 2014 for interest and penalties of $233,000 and $142,000, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2015, 2014 and 2013 included net benefits for interest and penalties of $91,000, $4,000 and $829,000, respectively, associated with uncertain tax positions.

During the next twelve months, the Company currently expects to add between $1,000,000 and $2,000,000 to the liability for uncertain taxes for 2016 events. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2016.

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 December 31, 2015, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2011; Canada – 2008; Malaysia – 2008; and United Kingdom – 2014.

 

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Notes to consolidated financial statements—continued

 

Note J—Incentive plans

Murphy utilizes cash-based and/or share-based incentive plans to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the financial statements using a grant date fair value-based measurement method over the periods that the awards vest. For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.

At December 31, 2015, the Company has cash and incentive awards issued to employees under the 2007 Long-Term Incentive Plan (2007 Long-Term Plan), 2012 Long-Term Incentive Plan (2012 Long-Term Plan) and the 2012 Annual Incentive Plan (2012 Annual Plan). The 2012 Annual Plan authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2012 Long-Term 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, 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 may be granted in future years. Based on awards made to date, approximately 4,673,000 shares remained available for grant under the 2012 Long-Term Plan at December 31, 2015. 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. Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.

 

(thousands of dollars)		2015				2014				2013
Compensation charged against income (loss) before income tax benefit		$	44,021				53,157				66,976
Related income tax benefit recognized in income			13,583				15,604				19,321

As of December 31, 2015, there were $55,540,000 in compensation costs to be expensed over approximately the next two years related to unvested share-based compensation arrangements granted by the Company. Beginning January 1, 2014, employees receive net shares, after applicable statutory withholding taxes, upon each stock option exercise. Cash received from options exercised under all share-based payment arrangements for the year ended December 31, 2013 was $2,395,000. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $36,000, $5,364,000 and $7,435,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Share-settled awards

STOCK OPTIONS—The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan and the 2007 Long-Term Plan has been

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.

The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.

 

		2015		2014		2013
Fair value per option grant		$10.97 – $11.08		$12.84		$15.81 – $20.62
Assumptions
Dividend yield		2.40% – 2.50%		2.00%		2.10% – 2.30%
Expected volatility		29.00% – 30.00%		29.00%		34.00% – 36.00%
Risk-free interest rate		1.34% – 1.60%		1.62%		0.96% – 2.00%
Expected life		5.30 yrs.		5.35 yrs.		5.25 yrs. – 6.50 yrs.

Changes in stock options outstanding during the last three years are presented in the following table.

 

		Number of shares				Average exercise price
Outstanding at December 31, 2012			5,907,359			$	55.17
Granted at FMV			1,320,176				55.26
Exercised			(1,335,355	)			45.84
Forfeited			(228,576	)			58.01
Surrendered in connection with separation of Murphy USA Inc.			(272,936	)			55.99
Murphy USA Inc. spin-off adjustment			615,917				52.09
Outstanding at December 31, 2013			6,006,585				56.80
Granted at FMV			772,900				55.82
Exercised			(862,407	)			49.27
Forfeited			(314,828	)			54.53
Outstanding at December 31, 2014			5,602,250				57.95
Granted at FMV			991,000				49.67
Exercised			(32,349	)			40.80
Forfeited			(1,117,613	)			31.99
Outstanding at December 31, 2015			5,443,288				52.93
Exercisable at December 31, 2012			2,474,636			$	54.43
Exercisable at December 31, 2013			2,435,322				51.79
Exercisable at December 31, 2014			3,030,105				53.10
Exercisable at December 31, 2015			3,542,352				52.26

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Additional information about stock options outstanding at December 31, 2015 is shown below.

 

		Options outstanding												Options exercisable
Range of exercise prices per option		No. of options				Avg. life remaining in years				Aggregate intrinsic value				No. of options				Avg. life remaining in years				Aggregate intrinsic value
$37.44 to $45.48			771,906				0.9			$	—				771,906				0.9			$	—
$49.65 to $51.63			2,067,449				4.3				—				1,219,449				3.0				—
$54.21 to $62.98			2,603,933				3.5				—				1,550,997				2.7				—
			5,443,288				3.4			$	—				3,542,352				2.4			$	—

The total intrinsic value of options exercised during 2015, 2014 and 2013 was $221,000, $12,003,000 and $25,284,000, respectively. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s Common stock.

In February 2013, the Committee reduced the exercise price of all outstanding stock options by $2.50 per share to reflect the impact of the special dividend of the same amount paid in December 2012. The exercise prices in the preceding tables beginning in 2013 reflect this $2.50 reduction in exercise price approved in 2013. The effect on the Statement of Operations from this reduced exercise price was an expense of $6,454,000 in 2013.

In order to preserve the economic value of unexercised stock options following the spin-off of MUSA on August 30, 2013, the number of outstanding stock options was increased by 10.7% and the exercise price of stock options was reduced by 10.7%. The number of options and the exercise prices in the preceding tables reflect these adjustments related to the MUSA spin-off. There was no immediate impact on the expense for stock options recognized in 2013 related to this exercise price adjustment.

PERFORMANCE-BASED RESTRICTED STOCK UNITS—Performance-based restricted stock units (PRSUS) to be settled in Common shares were granted in each of the last three years under the 2012 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PRSUS will not vest, but recognized compensation cost associated with the stock award would not be reversed. For past awards, the performance conditions were based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. During the performance period, PRSUS are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid or voting rights exist on awards of PRSUS prior to their settlement.

Upon the separation of MUSA on August 30, 2013, adjustments to outstanding PRSUS were made to the number of units outstanding to preserve the economic value of these awards.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

Changes in PRSUS outstanding for each of the last three years are presented in the following table.

 

(number of share units)		2015				2014				2013
Outstanding at beginning of year			1,397,040				1,560,292				1,426,238
Granted			455,000				464,300				521,776
Awarded			(521,800	)			(473,186	)			(380,150	)
Forfeited			(226,254	)			(154,366	)			(39,573	)
Surrendered in connection with separation of Murphy USA Inc.			—				—				(116,568	)
Murphy USA Inc. spin-off adjustment			—				—				148,569
Outstanding at end of year			1,103,986				1,397,040				1,560,292

The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period. The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 2015, 2014 and 2013 are presented in the following table.

 

		2015		2014		2013
Fair value per share at grant date		$44.03 – $48.12		$33.90 – $51.30		$39.50 – $68.01
Assumptions
Expected volatility		26.00%		29.00%		31.00% – 32.00%
Risk-free interest rate		0.85%		0.65%		0.41% – 0.62%
Stock beta		0.813		0.843		0.907 – 0.908
Expected life		3.0 yrs.		3.0 yrs.		3.0 yrs.

TIME-LAPSE RESTRICTED STOCK UNITS—Time-lapsed restricted stock units (TSUS) have been granted to the Company’s Non-Employee Directors under the Directors Plan and, to certain employees under the 2012 Long-Term Plan. These awards vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $49.67 per share in 2015, $55.20 to $60.85 per share in 2014 and $60.30 to $69.67 per share in 2013. To retain economic value at the time of spin-off of Murphy USA Inc., the number of TSUS was increased by 10.7% for each unit outstanding on August 30, 2013.

Changes in TSUS outstanding for each of the last three years are presented in the following table.

 

(number of share units)		2015				2014				2013
Outstanding at beginning of year			321,789				112,881				98,477
Granted			282,065				278,892				38,184
Vested and issued			(69,610	)			(54,884	)			(34,696	)
Forfeited			(57,000	)			(15,100	)			—
Murphy USA Inc. spin-off adjustment			—				—				10,916
Outstanding at end of year			477,244				321,789				112,881

 

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Notes to consolidated financial statements—continued

 

EMPLOYEE STOCK PURCHASE PLAN (ESPP)—The Company has an ESPP under which the Company’s Common stock can be purchased by eligible U.S. and Canadian employees. Each quarter, an eligible employee may elect to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. The ESPP will terminate on the earlier of the date that employees have purchased all 980,000 authorized shares or June 30, 2017. Employee stock purchases under the ESPP were 8,387 shares at an average price of $34.93 per share in 2015, 6,739 shares at an average price of $56.22 per share in 2014 and 16,020 shares at an average price of $54.14 per share in 2013. At December 31, 2015, 271,815 shares remained available for sale under the ESPP. Compensation costs related to the ESPP are estimated based on the value of the 10% discount and the fair value of the option that provides for the refund of participant withholdings, and such expenses were $29,000 in 2015, $55,000 in 2014, and $143,000 in 2013. The fair value per share issued under the ESPP was approximately $5.74, $6.49 and $6.72 for the years ended December 31, 2015, 2014 and 2013, respectively.

Cash-settled awards

The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SAR), Performance-based restricted stock units (PRSUC), Time-based restricted stock units (TRSUC) and Phantom units.

SAR awards have terms similar to stock options, PRSUC terms are similar to other performance-based restricted stock awards and TRSUC and Phantom units are generally settled on the third anniversary of the date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares. Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $1,594,000 in 2015, $9,667,000 in 2014 and $9,436,000 in 2013.

Upon the separation of Murphy USA Inc. on August 30, 2013, adjustments to outstanding PRSUC were made to the number of units outstanding to preserve the economic value of these awards.

The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $26,393,000, $38,000,000 and $53,250,000 was recorded in 2015, 2014 and 2013, respectively, for these plans.

Note K—Employee and retiree benefit plans

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

Effective with the spin-off of Murphy’s former U.S. retail marketing operation, Murphy USA Inc. (MUSA), on August 30, 2013, significant modifications were made to the U.S. defined benefit pension plan. Certain Murphy employees’ benefits under the U.S. plan were frozen at that time. No further benefit service will accrue for the

 

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Notes to consolidated financial statements—continued

 

affected employees, however, the plan will recognize future earnings after the spin-off. In addition, all previously unvested benefits became fully vested at the spin-off date. For those affected active employees of the Company, additional U.S. retirement plan benefits will accrue in future periods under a cash balance formula. Additionally, new hires of Murphy after the MUSA spin-off are not eligible to participate in the Company’s postretirement health care and life insurance benefit plans. Upon the spin-off of MUSA, Murphy retained all vested pension defined benefit and other postretirement benefit obligations associated with current and former employees of this separated business. No additional benefit will accrue for any employees of MUSA under the Company’s retirement plans after the spin-off date.

Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.

GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss.

 

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Notes to consolidated financial statements—continued

 

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2015 and 2014 and a statement of the funded status as of December 31, 2015 and 2014.

 

		Pension benefits								Other postretirement benefits
(thousands of dollars)		2015				2014				2015				2014
Change in benefit obligation
Obligation at January 1		$	825,552				707,254				118,496				107,001
Service cost			17,948				22,470				3,180				2,459
Interest cost			33,168				33,680				4,883				4,617
Plan amendments			8,297				—				—				—
Participant contributions			4				5				1,276				1,406
Actuarial loss (gain)			(48,019	)			122,824				(7,436	)			8,150
Medicare Part D subsidy			—				—				510				404
Exchange rate changes			(15,337	)			(14,614	)			(112	)			(55	)
Benefits paid			(35,936	)			(35,044	)			(5,575	)			(5,486	)
Special termination benefits			8,606				—				—				—
Curtailments			306				(11,023	)			—				—
Obligation at December 31			794,589				825,552				115,222				118,496
Change in plan assets
Fair value of plan assets at January 1			560,978				533,108				—				—
Actual return on plan assets			(18,718	)			31,340				—				—
Employer contributions			31,442				47,279				3,789				3,676
Participant contributions			4				5				1,276				1,406
Medicare Part D subsidy			—				—				510				404
Exchange rate changes			(14,104	)			(13,284	)			—				—
Benefits paid			(35,936	)			(35,044	)			(5,575	)			(5,486	)
Other			(1,984	)			(2,426	)			—				—
Fair value of plan assets at December 31			521,682				560,978				—				—
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets			7,463				7,899				—				—
Other accrued liabilities			(7,487	)			(5,996	)			(5,370	)			(5,515	)
Deferred credits and other liabilities			(272,883	)			(266,477	)			(109,852	)			(112,981	)
Funded status and net plan liability recognized at December 31		$	(272,907	)			(264,574	)			(115,222	)			(118,496	)

 

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Notes to consolidated financial statements—continued

 

The significant actuarial gain in 2015 for pension benefits was primarily due to a combination of a higher discount rate and a reduction in assumed future salary increases. The significant actuarial loss in 2014 for pension benefits was primarily due to a combination of a lower discount rate and revised actuarial mortality assumptions newly adopted by the Society of Actuaries in 2014. The 2014 mortality assumption changes reflected the expectation of generally longer lives for U.S. participants based on the latest study by the Society of Actuaries.

At December 31, 2015, amounts included in accumulated other comprehensive loss (AOCL), before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.

 

(thousands of dollars)		Pension benefits				Other postretirement benefits
Net actuarial loss		$	(242,809	)			(13,495	)
Prior service (cost) credit			(8,903	)			207
		$	(251,712	)			(13,288	)

Amounts included in AOCL at December 31, 2015 that are expected to be amortized into net periodic benefit expense during 2016 are shown in the following table.

 

(thousands of dollars)		Pension benefits				Other postretirement benefits
Net actuarial loss		$	(14,527	)			(155	)
Prior service (cost) credit			(1,295	)			82
		$	(15,822	)			(73	)

The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.

 

		Projected benefit obligations								Accumulated benefit obligations								Fair value of plan assets
(thousands of dollars)		2015				2014				2015				2014				2015				2014
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets		$	630,587				658,618				622,841				597,918				500,695				533,165
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets			148,019				147,018				140,544				127,200				—				—
Unfunded other postretirement plans			115,222				118,496				115,222				118,496				—				—

 

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Notes to consolidated financial statements—continued

 

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2015.

 

		Pension benefits												Other postretirement benefits
(thousands of dollars)		2015				2014				2013				2015				2014				2013
Service cost		$	17,948				22,470				26,346				3,180				2,459				4,566
Interest cost			33,168				33,680				30,903				4,883				4,617				5,189
Expected return on plan assets			(34,016	)			(33,723	)			(28,974	)			—				—				—
Amortization of prior service cost (credit)			1,560				899				1,006				(82	)			(82	)			(143	)
Amortization of transitional (asset) liability			(1	)			(480	)			(514	)			—				—				8
Recognized actuarial loss			15,147				9,471				17,338				992				5				1,484
			33,806				32,317				46,105				8,973				6,999				11,104
Termination benefits expense			8,606				—				849				—				—				—
Curtailment expense (benefit)			306				—				1,365				—				—				(442	)
Net periodic benefit expense		$	42,718				32,317				48,319				8,973				6,999				10,662

Termination and curtailment expenses in 2015 were primarily related to plan amendments made upon early retirement of certain employees during 2015. Termination and curtailment expenses in 2013 primarily related to plan amendments made at the time of separation of MUSA.

The preceding tables in this note include the following amounts related to foreign benefit plans.

 

		Pension benefits								Other postretirement benefits
(thousands of dollars)		2015				2014				2015				2014
Benefit obligation at December 31		$	197,549				222,497				643				648
Fair value of plan assets at December 31			193,933				202,305				—				—
Net plan liabilities recognized			3,616				20,192				643				648
Net periodic benefit expense			4,703				12,968				152				152

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2015 and 2014 and net periodic benefit expense for 2015 and 2014.

 

		Benefit obligations																Net periodic benefit expense
		Pension benefits								Other postretirement benefits								Pension benefits								Other postretirement benefits
		December 31								December 31								Year								Year
		2015				2014				2015				2014				2015				2014				2015				2014
Discount rate			4.37%				3.94%				4.61%				4.12%				4.04%				4.56%				4.12%				4.91%
Expected return on plan assets			6.00%				6.11%				—				—				6.00%				6.11%				—				—
Rate of compensation increase			3.74%				3.69%				—				—				3.74%				3.69%				—				—

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

 

The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.

Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.

 

(thousands of dollars)		Pension benefits				Other postretirement benefits
2016		$	37,255				6,251
2017			37,744				6,445
2018			38,649				6,683
2019			39,931				6,955
2020			40,903				7,246
2021-2025			222,198				40,661

For purposes of measuring postretirement benefit obligations at December 31, 2015, the future annual rates of increase in the cost of health care were assumed to be 7.2% for 2016 decreasing each year to an ultimate rate of 4.5% in 2028 and thereafter.

Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects.

 

(thousands of dollars)		1% Increase				1% Decrease
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2015		$	1,451				(1,094	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2015			17,284				(13,806	)

During 2015, the Company made contributions of $15,752,000 to its domestic defined benefit pension plans, $15,690,000 to its foreign defined benefit pension plans, $3,758,000 to its domestic postretirement benefits plan and $31,000 to its foreign postretirement benefits plan. The Company currently expects during 2016 to make contributions of $6,910,000 to its domestic defined benefit pension plans, $1,555,000 to its foreign defined benefit pension plans, $5,343,000 to its domestic postretirement benefits plan and $27,000 to its foreign postretirement benefits plan.

U.S. Health Care Reform—In March 2010, the United States Congress enacted a health care reform law. Along with other provisions, the law (a) eliminated the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b) imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c) eliminated

 

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lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposed a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010. The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The law did not significantly affect the Company’s consolidated financial statements for any of the three years ended December 31, 2015. The Company continues to evaluate the various components of the law as guidance is issued and cannot predict with certainty all the ways it may impact the Company. However, based on information available to date, the Company currently believes that the health care reform law will not have a material effect on its financial condition, net income (loss) or cash flow in future periods.

Plan Investments—Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee). Members of the Committee are appointed by the Board of Directors. The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement. The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities. The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation. The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities. The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans. The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70%; fixed income securities of between 30% and 60%; long/short equity of between 0% and 15%; and cash and equivalents of between 0% and 15%. The Committee is authorized to direct investments within these parameters. Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds. Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term. Generally no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100 million. Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets. Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity. The fixed income portfolio should not exceed an average maturity of 11 years. The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds. The Committee routinely reviews the investment performance of Investment Managers.

For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees. The trustees have hired an investment consultant to manage the assets of the plan within the parameters of the Investment Policy Implementation Document (Document). The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Document while limiting the risk for the funded position of the plan. The Document specifies a strategy with an allocation goal of

 

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60% equities and 40% bonds. The Document allows for ranges of equity investments from 27% to 98%, fixed income securities may range from 25% to 60%, and cash can be held for up to 5% of investments. Approximately one-half of the equity allocation is to be invested in U.K. securities and the remainder split between North American, European, Japanese and other Pacific Basin securities. A minimum of 95% of the fixed income allocation is to be invested in U.K. securities with up to 5% in international or high yield bonds. Tolerance ranges are specified in the Document within the general equity/bond allocation guidelines. Asset performance is compared to a benchmark return based on the allocation guidelines and is targeted to outperform the benchmark by 0.75% per annum over a rolling three-year period. Small working cash balances are permitted to facilitate daily management of payments and receipts within the plan. The trustees routinely review the investment performance of the plan.

For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets. A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio. The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash. The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation. The normal allocation includes total equity securities of 60% with a range of 40% to 75% of total assets. Fixed income securities have a normal allocation of 35% with a range of 25% to 45%. Cash will normally have an allocation of 5% with a range of 0% to 15%. The Policy calls for diversification norms within the investment portfolios of both equity securities and fixed income securities.

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2015 and 2014 are presented in the following table.

 

		December 31,
		2015				2014
Equity securities			64.4%				66.6%
Fixed income securities			34.0				32.5
Cash equivalents			1.6				0.9
			100.0%				100.0%

The Company’s weighted average expected return on plan assets was 6.00% in 2015 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 6.00% expected return was based on an expected average future equity securities return of 8.00% and a fixed income securities return of 3.71% and is net of average expected investment expenses of 0.53%. Over the last 10 years, the return on funded retirement plan assets has averaged 5.72%.

 

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At December 31, 2015, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.

 

						Fair value measurements using
(thousands of dollars)		Fair value at December 31, 2015				Quoted prices in active markets for identical assets (level 1)				Significant other observable inputs (level 2)				Significant unobservable inputs (level 3)
Domestic Plans
Equity securities:
U.S. core equity		$	51,878				51,878				—				—
U.S. small/midcap			26,964				26,964				—				—
Hedged funds and other alternative strategies			50,878				—				16,949				33,929
International commingled trust fund			72,205				—				72,205				—
Emerging market commingled equity fund			16,873				—				16,873				—
Fixed income securities:
U.S. fixed income			80,681				—				80,681				—
International commingled trust fund			15,332				—				15,332				—
Emerging market mutual fund			6,439				—				6,439				—
Cash and equivalents			6,499				6,499				—				—
Total Domestic Plans			327,749				85,341				208,479				33,929
Foreign Plans
Equity securities funds			104,718				—				104,718				—
Fixed income securities funds			67,494				—				67,494				—
Diversified pooled fund			20,987				—				20,987				—
Cash and equivalents			734				734				—				—
Total Foreign Plans			193,933				734				193,199				—
Total		$	521,682				86,075				401,678				33,929

 

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Notes to consolidated financial statements—continued

 

At December 31, 2014, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.

 

						Fair value measurements using
(thousands of dollars)		Fair Value at December 31, 2014				Quoted prices in active markets for identical assets (level 1)				Significant other observable inputs (level 2)				Significant unobservable inputs (level 3)
Domestic Plans
Equity securities:
U.S. core equity		$	67,863				67,863				—				—
U.S. small/midcap			33,709				33,709				—				—
Hedged funds and other alternative strategies			52,905				—				18,953				33,952
International commingled trust fund			75,702				—				75,702				—
Emerging market commingled equity fund			19,908				—				19,908				—
Fixed income securities:
U.S. fixed income			80,577				—				80,577				—
International commingled trust fund			17,559				—				17,559				—
Emerging market mutual fund			8,069				—				8,069				—
Cash and equivalents			2,381				2,381				—				—
Total Domestic Plans			358,673				103,953				220,768				33,952
Foreign Plans
Equity securities funds			106,694				—				106,694				—
Fixed income securities funds			66,435				—				66,435				—
Diversified pooled fund			27,813				—				27,813				—
Cash and equivalents			1,363				1,363				—				—
Total Foreign Plans			202,305				1,363				200,942				—
Total		$	560,978				105,316				421,710				33,952

The definition of levels within the fair value hierarchy in the tables above is included in Note Q.

For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market. Hedged funds and other alternative strategies funds consist of three investments. One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90-day notice, and the third investment is also valued monthly based on net asset values and has a three year lock-up period and a 95-day notice following the lock-up period. International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges. The emerging market commingled equity fund is valued monthly based on net asset value. These commingled equity funds can be withdrawn monthly and have a 10-day notice period. U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset

 

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values. International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values. The fixed income emerging market mutual fund is valued daily based on net asset value. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash.

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

 

(thousands of dollars)		Hedged funds and other alternative strategies
Total at December 31, 2013		$	32,788
Actual return on plan assets:
Relating to assets held at the reporting date			1,164
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2014			33,952
Actual return on plan assets:
Relating to assets held at the reporting date			(23	)
Relating to assets sold during the period			—
Purchases, sales and settlements			—
Total at December 31, 2015		$	33,929

THRIFT PLANS—Most full-time U.S. and U.K. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6%. Amounts charged to expense for these plans were $7,607,000 in 2015, $10,229,000 in 2014 and $13,839,000 in 2013.

Note L—Financial instruments and risk management

DERIVATIVE INSTRUMENTS—Murphy uses derivative instruments to manage certain risks related to commodity prices, interest rates and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were

 

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Notes to consolidated financial statements—continued

 

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 until the anticipated transactions occur.

Commodity Purchase Price Risks—The Company is subject to commodity price risk related to crude oil it produces and sells. During 2015, the Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to hedge a portion of its United States production for 2015. Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At December 31, 2015, the fair value of WTI contracts were assets of $89.4 million included in accounts receivable. At December 31, 2015, the Company had 20,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. The impact of marking to market these commodity derivative contracts reduced the loss before income taxes by $77.3 million for the year ended December 31, 2015. There were no open WTI contracts at December 31, 2014.

Foreign Currency Exchange Risks—The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At December 31, 2015 and 2014, short-term derivative instruments were outstanding in Canada for approximately $4,800,000 and $21,000,000, respectively, to manage the currency risk of U.S. dollar accounts receivable balances associated with sale of Canadian crude oil in both years and a U.S. dollar intercompany accounts receivable balance at year-end 2014. The fair values of open foreign currency derivative contracts were liabilities of $29,000 at December 31, 2015 and $25,000 at December 31, 2014.

At December 31, 2015 and 2014, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

		December 31, 2015																December 31, 2014
		Asset derivatives								Liability derivatives								Asset derivatives								Liability derivatives
(thousands of dollars)		Balance sheet location				Fair value				Balance sheet location				Fair value				Balance sheet location				Fair value				Balance sheet location				Fair value
Type of Derivative Contract
Commodity			Accounts Receivable			$	89,358				—				—				Accounts Receivable			$	23,168				—				—
Foreign exchange			—				—				Accounts Payable			$	29				—				—				Accounts Payable			$	25

 

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Notes to consolidated financial statements—continued

 

For the years ended December 31, 2015 and 2014, 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.

 

		Year ended December 31, 2015								Year ended December 31, 2014
(thousands of dollars)		Location of gain (loss) recognized in income on derivative				Amount of gain (loss) recognized in income on derivative				Location of gain (loss) recognized in income on derivative				Amount of gain (loss) recognized in income on derivative
Type of Derivative Contract
Commodity			Sale and Other Operating Revenues			$	129,064				Sale and Other Operating Revenues			$	17,887
Foreign exchange			Interest and Other Income				(4	)			Interest and Other Income				4,226
						$	129,060							$	22,113

Interest Rate Risks—In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350,000,000 of notes that were sold in 2012. These interest rate swaps matured in May 2012. Under hedge accounting rules, the Company deferred a loss on these contracts to match the payment of interest on these notes through 2022. During each of the three years shown, $2,963,000 of the deferred loss on the interest rate swaps was charged to interest expense in the Consolidated Statements of Operations. The remaining loss deferred on these matured contracts at December 31, 2015 was $18,889,000, which is recorded, net of income taxes of $6,611,000, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet. The Company expects to charge approximately $2,963,000 of this deferred loss to Interest expense in the Consolidated Statement of Operations during 2016.

CREDIT RISKS—The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S., Canada and Malaysia, and cost sharing amounts of operating and capital costs billed to partners for oil and natural gas fields operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level. Cash equivalents are placed with several major financial institutions, which limit the Company’s exposure to credit risk. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions.

 

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Notes to consolidated financial statements—continued

 

Note M—Stockholders’ equity

During the last three years, the Company has repurchased Common Stock under variable term, capped accelerated share repurchase transactions (ASR) as authorized by the Board of Directors. These share repurchases during the last three years were as follows:

 

		2015				2014				2013
Purchase of Treasury Stock		$	250,000,000			$	375,000,000			$	500,000,000
Shares repurchased			5,967,313				6,373,718				7,855,419

There are no open share buyback programs as of December 31, 2015. The shares acquired under the various buyback programs are carried as Treasury Stock in the Consolidated Balance Sheet.

Note N—Earnings per share

Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2015. The following table reconciles the weighted-average shares outstanding used for these computations.

 

(weighted-average shares)		2015				2014				2013
Basic method			174,351,227				178,852,942				187,921,062
Dilutive stock options and restricted stock units *			—				1,218,042				1,350,336
Diluted method			174,351,227				180,070,984				189,271,398

 

*

Due to a net loss recognized by the Company for the year ended December 31, 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2015, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.

 

		2015				2014				2013
Antidilutive stock options excluded from diluted shares			5,443,288				1,893,364				1,026,900
Weighted average price of these options		$	52.93			$	55.21			$	54.54

Note O—Other financial information

DEEPWATER RIG CONTRACT EXIT COSTS—At year-end 2015, the Company had two deepwater drilling rigs under contract in the Gulf of Mexico that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The Company reported a pre-tax charge to earnings in 2015 totaling $282,001,000 that included both the costs incurred in 2015 during which the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016. The contract originally scheduled to expire in November 2016 was terminated by the Company. The remaining day rate commitments payable in the first quarter of 2016 under both contracts total approximately $271,000,000.

 

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Notes to consolidated financial statements—continued

 

GAIN FROM FOREIGN CURRENCY TRANSACTIONS—Net gains from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $87,961,000 in 2015, $40,596,000 in 2014 and $73,732,000 in 2013.

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2015 as shown in the following table.

 

(thousands of dollars)		2015				2014				2013
Accounts receivable		$	297,625				175,820				224,281
Inventories			(15,340	)			25,697				14,166
Prepaid expenses			(144,845	)			6,575				195,013
Deferred income tax assets			3,924				6,884				15,510
Accounts payable and accrued liabilities			(36,887	)			(54,785	)			(176,543	)
Current income tax liabilities			(69,413	)			(163,920	)			(6,098	)
Net (increase) decrease in noncash operating working capital		$	35,064				(3,729	)			266,329
Supplementary disclosures (including discontinued operations):
Cash income taxes paid, net of refunds		$	118,667				573,799				457,006
Interest paid, net of amounts capitalized			110,386				114,232				60,501
Non-cash investing activities, related to continuing operations:
Asset retirement costs capitalized		$	76,775				70,568				172,488
Decrease (increase) in capital expenditure accrual			462,474				93,080				(197,054	)

 

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Notes to consolidated financial statements—continued

 

Note P—Accumulated other comprehensive income (loss)

The components of Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets at December 31, 2015 and December 31, 2014 and the changes during 2015 and 2014 are presented net of taxes in the following table.

 

(thousands of dollars)		Foreign currency translation gains (losses)1				Retirement and postretirement benefit plan adjustments1				Deferred loss on interest rate derivative hedges1				Total1
Balance at December 31, 2013		$	305,192				(116,956	)			(16,117	)			172,119
2014 components of other comprehensive income (loss):
Before reclassifications to income			(271,491	)			(79,403	)			—				(350,894	)
Reclassifications to income			—				6,6073				1,9134				8,520
Net other comprehensive income (loss)			(271,491	)			(72,796	)			1,913				(342,374	)
Balance at December 31, 2014			33,701				(189,752	)			(14,204	)			(170,255	)
2015 components of other comprehensive income (loss):
Before reclassifications to income			(588,450	)			(5,468	)			—				(593,918	)
Reclassifications to income			41,745	2			15,960	3			1,926	4			59,631
Net other comprehensive income (loss)			(546,705	)			10,492				1,926				(534,287	)
Balance at December 31, 2015		$	(513,004	)			(179,260	)			(12,278	)			(704,542	)

 

1

All amounts are presented net of income taxes.

2

Reclassification for the year ended December 31, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K.

3

Reclassifications before taxes of $9,813 and $21,721 are included in the computation of net periodic benefit expense in 2014 and 2015, respectively. See Note K for additional information. Related income taxes of $3,206 and $5,761 are included in income tax expense in 2014 and 2015, respectively.

4

Reclassifications before taxes of $2,963 are included in Interest expense in both 2014 and 2015. Related income taxes of $1,028 and $1,037 are included in income tax expense in 2014 and 2015, respectively.

Note Q—Assets and liabilities measured at fair value

Fair values—recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. 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.

 

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Notes to consolidated financial statements—continued

 

The fair value measurements for these assets and liabilities at December 31, 2015 and 2014 are presented in the following table.

 

		December 31, 2015																December 31, 2014
(thousands of dollars)		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets:
Commodity derivative contracts			—				89,358				—				89,358				—				23,168				—				23,168
		$	—				89,358				—				89,358				—				23,168				—				23,168
Liabilities:
Nonqualified employee savings plans		$	12,971				—				—				12,971				14,408				—				—				14,408
Foreign currency exchange derivative contracts			—				29				—				29								25				—				25
		$	12,971				29				—				13,000				14,408				25				—				14,433

The fair value of West Texas Intermediate (WTI) crude oil contracts in 2015 and 2014 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 date. The income effect of changes in fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses.

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 December 31, 2015 and 2014.

 

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Notes to consolidated financial statements—continued

 

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2015 and 2014. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The carrying value of Canadian government securities is determined based on cost plus earned interest. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

 

		At December 31,
		2015								2014
(thousands of dollars)		Carrying amount				Fair value				Carrying amount				Fair value
Financial assets (liabilities):
Canadian government securities with maturities greater than 90 days at the date of acquisition		$	173,288				173,234				461,313				462,056
Current and long-term debt			(3,059,475	)			(2,189,858	)			(2,983,057	)			(2,757,671	)

Fair values—nonrecurring

As a result of significantly lower commodity prices during the second half of 2015, the Company recognized approximately $2,493,156,000 in pretax noncash impairment charges related primarily to producing properties. The fair value information associated with these impaired properties is presented in the following table.

 

		Year ended December 31, 2015
		Fair value												Net book value prior to impairment				Total pretax (noncash) impairment expense
(thousands of dollars)		Level 1				Level 2				Level 3
Assets:
Impaired proved properties
Gulf of Mexico		$	—				—				316,106				645,088				328,982
Western Canada			—				—				23,526				707,100				683,574
Malaysia			—				—				1,200,900				2,681,500				1,480,600
		$	—				—				1,540,532				4,033,688				2,493,156

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.

 

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Notes to consolidated financial statements—continued

 

Note R—Commitments

The Company leases production and other facilities under operating leases. The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field and a production facility at the West Patricia field. During each of the next five years, expected future rental payments under all operating leases are approximately $83,272,000 in 2016, $66,770,000 in 2017, $56,393,000 in 2018, $45,525,000 in 2019 and $46,761,000 in 2020. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $111,425,000 in 2015, $144,981,000 in 2014, and $192,482,000 in 2013. A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note G.

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2015. These rigs will primarily be utilized for drilling operations onshore U.S. and Canada, and offshore Malaysia. Future commitments under these contracts, all of which expire by 2017, total $60,816,000. A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods. See Note O regarding expense associated with exit costs for two deepwater rig contracts at the end of 2015.

The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada. These agreements require minimum monthly or annual payments for processing and/or transportation charges through 2024. Future required minimum monthly payments for the next five years are $30,307,000 in 2016, $25,649,000 in 2017, $17,542,000 in 2018, $978,000 in 2019 and $1,003,000 in 2020. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total costs incurred under these service arrangements were $32,473,000 in 2015, $34,597,000 in 2014, and $40,254,000 in 2013.

In 2006, the Company committed to fund an educational assistance program known as the “El Dorado Promise.” Under this commitment, the Company will pay $5,000,000 per year for ten years through 2016 to provide scholarships for a specified amount of college expenses for eligible graduates of El Dorado High School in Arkansas. The final committed payment was made in January 2016. Total accretion cost included in Selling and General Expenses in the Consolidated Statement of Operations was $172,000 in 2015, $541,000 in 2014, and $805,000 in 2013.

Commitments for capital expenditures were approximately $501,217,000 at December 31, 2015, including $283,017,000 for field development and future work commitments in Malaysia, $109,800,000 for work in the Eagle Ford Shale, $30,661,000 for costs to develop deepwater Gulf of Mexico fields, and $45,179,000 and $15,376,000 for future work commitments in Vietnam and Brunei, respectively.

Note S—Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the

 

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promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

ENVIRONMENTAL MATTERS—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. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. 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.

The U.S. Environmental Protection Agency (EPA) formerly considered the Company to be a Potentially Responsible Party (PRP) at one Superfund site. Based on evidence provided by the Company, the EPA has determined that the Company is no longer considered a PRP at this site. Accordingly, the Company has not recorded a liability for remedial costs at the Superfund site at December 31, 2015. The potential total cost to all parties to perform necessary remedial work at the site may be substantial. The Company believes that its share of the ultimate costs to remediate the Superfund site will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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. The Company has not yet established a complete estimate of the

 

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Notes to consolidated financial statements—continued

 

costs to remediate the site. Based on the assessments done to date, the Company recorded $43.9 million in Other Expense in the 2015 Consolidated Statement of Operations associated with the estimated costs of remediating the site. The Company spent $30.6 million during 2015. Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible fines from regulators and insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through 2015.

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.

LEGAL MATTERS—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.

Note T—Common stock issued and outstanding

Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2015 is shown below.

 

(number of shares outstanding)		2015				2014				2013
At beginning of year			177,499,513				183,406,513				190,641,317
Stock options exercised*			15,575				119,994				303,685
Restricted stock awards*			478,549				339,985				300,910
Employee stock purchase and thrift plans			8,387				6,739				16,020
Treasury shares purchased			(5,967,313	)			(6,373,718	)			(7,855,419	)
At end of year			172,034,711				177,499,513				183,406,513

 

*

Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Note U—Subsequent events

In January 2016, a Canadian subsidiary of the Company signed a definitive agreement to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration to Murphy upon closing of the transaction, anticipated near the end of the first quarter 2016, is expected to be C$538 million.

In a separate transaction, the same Canadian subsidiary signed a definitive agreement to acquire a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Montney lands in Alberta. Under the terms of the joint venture the total consideration amounts to C$475 million, of which Murphy will pay approximately C$250 million in cash at closing and the remaining C$225 million in the form of a carried interest for a period of up to five years. The transaction is expected to close near the end of the first quarter of 2016.

 

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As of December 31, 2015, Murphy’s long-term debt was rated “BBB” with a negative outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a negative outlook by Moody’s Investor Services (Moody’s). In February 2016, S&P, Fitch, and Moody’s each downgraded the Company’s credit rating on its outstanding notes. The Company’s long-term debt ratings are currently “BBB-” with stable outlook by S&P, “BB+” with stable outlook by Fitch, and “B1” with negative outlook by Moody’s. Fitch’s and Moody’s actions reduced the Company’s credit rating to below investment grade status. These downgrades could adversely affect our cost of capital and our ability to raise debt in public markets in future periods. Based on the downgrade by Moody’s, the coupon rates on $1.5 billion of the Company’s outstanding notes will increase by 1.00% effective June 1, 2016.

See Note O for further discussion of rig contract exit costs.

Note V—Business segments

Murphy’s reportable segments are organized into geographic areas of operations. The Company’s exploration and production activity is subdivided into segments for the United States, Canada, Malaysia and all other countries. Each of these segments derives revenues primarily from the sale of crude oil and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. Intersegment transfers of crude oil, natural gas and petroleum products are at market prices and intersegment services are recorded at cost.

The Company completed the sale of its U.K. downstream assets during 2015. The Company sold its retail marketing operations in the United Kingdom on September 30, 2014. At December 31, 2015 and 2014, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the consolidated balance sheet. These operations have been reported as discontinued operations for all periods presented in these consolidated financial statements.

The Company sold all of its oil and natural gas producing assets in the United Kingdom during the first half of 2013. The Company also completed the separation of its U.S. retail marketing business on August 30, 2013. Both of these operations have also been reported as discontinued operations for all periods presented in these consolidated financial statements.

The Company has several customers that purchase a significant portion of its oil and natural gas production. During 2015, sales to Phillips 66 and affiliated companies represented approximately 17% of the Company’s total sales revenue. During 2014, sales to Shell Oil and affiliated companies and Phillips 66 and affiliated companies represented approximately 20% and 14%, respectively, of the Company’s total sales revenue. During 2013, sales to Phillips 66 and affiliated companies and Shell Oil and its affiliates represented approximately 17% and 14%, respectively, of the Company’s total sales revenue. Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.

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 and other activities, including interest income, miscellaneous gains and losses, interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the table on the following page, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets, and goodwill and other intangible assets.

 

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Segment information

 

		Exploration and production
(millions of dollars)		United States				Canada				Malaysia				Other				Total E&P
Year ended December 31, 2015
Segment loss		$	(615.7	)			(583.4	)			(653.2	)			(158.6	)			(2,010.9	)
Revenues from external customers			1,253.6				549.7				1,131.4				—				2,934.7
Interest income			—				—				—				—				—
Interest expense, net of capitalization			—				—				—				—				—
Income tax expense (benefit)			(337.0	)			(188.8	)			(567.9	)			(17.3	)			(1,111.0	)
Significant noncash charges (credits)
Depreciation, depletion and amortization			794.9				261.9				544.9				6.2				1,607.9
Accretion of asset retirement obligations			20.2				12.6				15.9				—				48.7
Amortization of undeveloped leases			59.2				14.4				—				1.8				75.4
Impairment of assets			329.0				683.6				1,480.6				—				2,493.2
Deferred and noncurrent income taxes			(187.7	)			(146.0	)			(579.2	)			(4.6	)			(917.5	)
Additions to property, plant, equipment			1,263.1				184.9				244.4				39.2				1,731.6
Total assets at year-end			5,717.8				2,460.6				2,537.2				147.7				10,863.3
Year ended December 31, 2014
Segment income (loss)		$	387.1				156.5				896.2				(250.0	)			1,189.8
Revenues from external customers			2,196.4				1,044.1				2,183.5				(1.3	)			5,422.7
Interest income			—				—				—				—				—
Interest expense, net of capitalization			—				—				—				—				—
Income tax expense (benefit)			214.8				64.2				102.6				(95.9	)			285.7
Significant noncash charges (credits)
Depreciation, depletion and amortization			840.7				316.7				735.0				5.1				1,897.5
Accretion of asset retirement obligations			17.5				15.2				18.1				—				50.8
Amortization of undeveloped leases			50.1				19.4				—				4.9				74.4
Impairment of assets			14.3				37.0				—				—				51.3
Deferred and noncurrent income taxes			39.7				43.3				(235.1	)			—				(152.1	)
Additions to property, plant, equipment			2,028.7				445.9				818.0				10.7				3,303.3
Total assets at year-end			5,745.7				3,769.8				4,887.1				138.7				14,541.3
Year ended December 31, 2013
Segment income (loss)		$	435.4				180.8				786.4				(373.8	)			1,028.8
Revenues from external customers			1,803.8				1,144.7				2,280.5				83.6				5,312.6
Interest income			—				—				—				—				—
Interest expense, net of capitalization			—				—				—				—				—
Income tax expense (benefit)			241.6				57.8				477.7				(120.8	)			656.3
Significant noncash charges (credits)
Depreciation, depletion and amortization			576.3				374.6				588.2				4.5				1,543.6
Accretion of asset retirement obligations			13.5				16.2				15.0				4.3				49.0
Amortization of undeveloped leases			30.3				21.0				—				15.6				66.9
Impairment of assets			—				21.6				—				—				21.6
Deferred and noncurrent income taxes			99.6				26.1				48.1				—				173.8
Additions to property, plant, equipment			1,785.9				334.5				1,323.4				64.8				3,508.6
Total assets at year-end			4,530.0				4,087.8				6,121.0				180.4				14,919.2

Geographic information

 

		Certain long-lived assets at December 31
(millions of dollars)		United States				Canada				Malaysia				United Kingdom				Other				Total
2015		$	5,484.7				2,310.6				1,912.0				—				111.1				9,818.4
2014			5,419.5				3,574.6				4,258.8				0.4				78.1				13,331.4
2013			4,267.9				3,834.9				5,301.7				0.4				76.6				13,481.5

 

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Segment information—continued

 

(millions of dollars)		Corporate and other				Discontinued operations				Consolidated total
Year ended December 31, 2015
Segment loss		$	(244.9	)			(15.0	)			(2,270.8	)
Revenues from external customers			98.4				—				3,033.1
Interest income			4.0				—				4.0
Interest expense, net of capitalization			117.4				—				117.4
Income tax expense (benefit)			84.5				—				(1,026.5	)
Significant noncash charges (credits)
Depreciation, depletion and amortization			11.9				—				1,619.8
Accretion of asset retirement obligations			—				—				48.7
Amortization of undeveloped leases			—				—				75.4
Impairment of assets			—				—				2,493.2
Deferred and noncurrent income taxes			(60.5	)			—				(978.0	)
Additions to property, plant, equipment			59.9				—				1,791.5
Total assets at year-end			592.2				38.3				11,493.8
Year ended December 31, 2014
Segment income (loss)		$	(164.8	)			(119.4	)			905.6
Revenues from external customers			53.4				—				5,476.1
Interest income			7.7				—				7.7
Interest expense, net of capitalization			115.8				—				115.8
Income tax expense (benefit)			(58.4	)			—				227.3
Significant noncash charges (credits)
Depreciation, depletion and amortization			8.7				—				1,906.2
Accretion of asset retirement obligations			—				—				50.8
Amortization of undeveloped leases			—				—				74.4
Impairment of assets			—				—				51.3
Deferred and noncurrent income taxes			(18.8	)			—				(170.9	)
Additions to property, plant, equipment			14.5				—				3,317.8
Total assets at year-end			1,773.9				427.1				16,742.3
Year ended December 31, 2013
Segment income (loss)		$	(140.7	)			235.4				1,123.5
Revenues from external customers			77.5				—				5,390.1
Interest income			3.9				—				3.9
Interest expense, net of capitalization			71.9				—				71.9
Income tax expense (benefit)			(71.7	)			—				584.6
Significant noncash charges (credits)
Depreciation, depletion and amortization			9.8				—				1,553.4
Accretion of asset retirement obligations			—				—				49.0
Amortization of undeveloped leases			—				—				66.9
Impairment of assets			—				—				21.6
Deferred and noncurrent income taxes			(15.7	)			—				158.1
Additions to property, plant, equipment			15.5				8.1				3,532.2
Total assets at year-end			1,265.2				1,325.1				17,509.5

Geographic information

 

		Revenues from external customers for the year
(millions of dollars)		United States				Canada				Malaysia				Other				Total
2015		$	1,260.0				557.3				1,210.9				4.9				3,033.1
2014			2,201.5				1,052.4				2,233.0				(10.8	)			5,476.1
2013			1,798.5				1,150.2				2,337.5				103.9				5,390.1

 

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Supplemental oil and gas information (unaudited)

The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning five of the schedules.

SCHEDULE 1—SUMMARY OF PROVED CRUDE OIL AND SYNTHETIC OIL RESERVES

SCHEDULE 2—SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 3—SUMMARY OF PROVED NATURAL GAS RESERVES

Reserves of crude oil, synthetic oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic productibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analogue based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

Murphy includes synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. This operation involves a process of mining tar sands and converting the raw bitumen into a pipeline-quality crude. The proved reserves associated with this project are estimated through a combination of core-hole drilling and realized process efficiencies. The high-density core-hole drilling, at a spacing of less than 500 meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content. The bitumen generally constitutes approximately 10% of the total bulk tar sand that is mined. The bitumen extraction process is fairly efficient and removes about 90% of the bitumen that is contained within the tar sand. The final step of the process converts the 8.4° API bitumen into 30°-34° API crude oil. A catalytic cracking process is used to crack the long hydrocarbon chains into shorter ones yielding a final crude oil that can be shipped via pipelines. The cracking process has an efficiency ranging from 85% to 90%. Overall, it takes approximately two metric tons of oil sand to produce one barrel of synthetic crude oil. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.

Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.

 

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Supplemental oil and gas information (unaudited)—continued

 

All crude oil and synthetic reserves, natural gas liquids reserves and natural gas reserves are from consolidated subsidiaries and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.

All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. Liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 75.2 million barrels and 546.8 billion cubic feet, respectively, at December 31, 2015. Approximately 33.0 billion cubic feet of natural gas proved reserves in Malaysia at December 31, 2015 relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet.

SCHEDULE 5—RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

Results of operations from exploration and production activities by geographic area for 2013 and 2014 are reported as if these activities were not part of an operation that also refines crude oil and sells refined products.

SCHEDULE 6—STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2015.

 

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Supplemental oil and gas information (unaudited)—continued

 

Schedule 1—Summary of proved crude oil and synthetic oil reserves based on average prices for 2012—2015

 

		Crude & synthetic oil				Crude oil																				Synthetic oil
(millions of barrels)		Total				Total				United States				Canada				Malaysia				United Kingdom				Canada
Proved developed and undeveloped crude oil / synthetic oil reserves:
December 31, 2012			414.8				295.7				142.6				36.8				95.7				20.6				119.1
Revisions of previous estimates			27.4				24.8				13.1				8.4				3.3				—				2.6
Improved recovery			27.4				27.4				—				—				27.4				—				—
Extensions and discoveries			69.6				69.6				52.4				0.2				17.0				—				—
Sales of properties			(20.4	)			(20.4	)			—				—				—				(20.4	)			—
Production			(47.6	)			(42.9	)			(16.6	)			(6.7	)			(19.4	)			(0.2	)			(4.7	)
December 31, 2013			471.2				354.2				191.5				38.7				124.0				—				117.0
Revisions of previous estimates			(9.3	)			(2.3	)			(3.2	)			2.7				(1.8	)			—				(7.0	)
Improved recovery			7.5				7.5				—				—				7.5				—				—
Extensions and discoveries			42.6				42.6				32.7				2.4				7.5				—				—
Purchases of properties			6.1				6.1				6.1				—				—				—				—
Sales of properties			(24.3	)			(24.3	)			(0.3	)			(0.5	)			(23.5	)			—				—
Production			(52.0	)			(47.6	)			(21.9	)			(5.9	)			(19.8	)			—				(4.4	)
December 31, 2014			441.8				336.2				204.9				37.4				93.9				—				105.6
Revisions of previous estimates			5.3				(8.2	)			(7.6	)			(4.8	)			4.2				—				13.5
Improved recovery			2.4				2.4				—				—				2.4				—				—
Extensions and discoveries			63.8				63.8				63.8				—				—				—				—
Sales of properties			(11.0	)			(11.0	)			—				—				(11.0	)			—				—
Production			(46.1	)			(41.8	)			(22.2	)			(4.7	)			(14.9	)			—				(4.3	)
December 31, 2015			456.2				341.4				238.9				27.9				74.6				—				114.8
Proved developed crude oil / synthetic oil reserves:
December 31, 2012			267.7				148.6				48.0				29.5				67.0				4.1				119.1
December 31, 2013			289.9				172.9				75.8				31.6				65.5				—				117.0
December 31, 2014			324.1				218.5				106.2				32.4				79.9				—				105.6
December 31, 2015			326.6				211.8				125.9				23.8				62.1				—				114.8
Proved undeveloped crude oil / synthetic oil reserves:
December 31, 2012			147.1				147.1				94.6				7.3				28.7				16.5				—
December 31, 2013			181.3				181.3				115.7				7.1				58.5				—				—
December 31, 2014			117.7				117.7				98.7				5.0				14.0				—				—
December 31, 2015			129.6				129.6				113.0				4.1				12.5				—				—

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 1—Summary of proved crude oil and synthetic oil reserves based on average prices for 2012—2015—continued

2015 Comments for proved crude oil and synthetic oil reserves changes

Revision of previous estimate –The 2015 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes, partially offset by improved Eagle Ford Shale performance, improved Eagle Ford Shale lifting costs, and drilling activity in the Gulf of Mexico. The negative Canadian conventional oil reserves revision in 2015 was result of lower heavy oil prices partially offset by increases at both Hibernia and Terra Nova due to development drilling and lower government royalty effects. The positive synthetic oil revision in the current period is due predominantly to lower government royalty effects due to lower oil prices. The positive revision for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices.

Improved recovery—The 2015 Malaysia crude oil proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries—In 2015, the U.S. added proved oil reserves primarily for planned drilling activities in the Eagle Ford Shale.

Sales of properties—The proved crude oil reserves reduction in Malaysia was associated with the 2015 sale of 10% of the Company’s oil and gas assets.

2014 Comments for proved crude oil and synthetic oil reserves changes

Revisions of previous estimates—The 2014 negative crude oil revision in the U.S. was primarily attributed to a new downspacing drilling strategy at the Eagle Ford Shale, which recognizes incrementally greater reserves as an Extension for 2014. The positive Canadian conventional oil reserves revision in 2014 was based on Hibernia well performance and stronger heavy oil prices during 2014. The negative synthetic oil revision in 2014 was based on a review of the recoverable bitumen area coupled with the impact of a lower oil price. The negative revision for crude oil reserves in Malaysia in 2014 was attributable to an updated decline curve analysis for the Kikeh field, partially offset by a benefit for performance associated with field ramp up at Kakap.

Improved recovery—This 2014 Malaysia crude oil proved reserves add was associated with favorable impacts for waterflood activities at the Kikeh, Siakap North and Sarawak oil fields.

Extensions and discoveries—In 2014, the U.S. added proved oil reserves primarily for substantial drilling activities in the Eagle Ford Shale. Canadian proved oil reserves adds in 2014 were associated with drilling activities in the Seal heavy oil area and at the Hibernia field. The crude oil proved reserves adds in 2014 in Malaysia were mostly for drilling activities at the Siakap North and Sarawak oil fields.

Purchases of properties—The proved crude oil reserves adds in the U.S. were due to acquisition of an interest in the Kodiak field in the Gulf of Mexico.

Sales of properties—The proved crude oil reserves reduction in Malaysia was associated with the late 2014 sale of 20% of the Company’s oil and gas assets.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 1—Summary of proved crude oil and synthetic oil reserves based on average prices for 2012—2015—continued

2013 Comments for proved crude oil and synthetic oil reserves changes

Revisions of previous estimates—The positive revision for proved crude oil reserves in 2013 in the U.S. was attributable to better well performance in the Eagle Ford Shale area in South Texas, plus minor adds to several fields in the Gulf of Mexico. The positive revision for conventional oil in Canada was caused by well performance at the Hibernia and Terra Nova fields. Synthetic oil revisions were positive primarily due to revised cost recovery factors for bitumen extraction following renegotiated royalty terms with the government. Positive revisions in Malaysia were primarily attributable to well performance at Kikeh.

Improved recovery—The positive effect from improved recovery in Malaysia was at the Kikeh field where waterflood has led to better than anticipated response in certain reservoirs.

Extensions and discoveries—The U.S. proved crude oil reserve additions were all in the Eagle Ford Shale where the Company has used reliable technology to add offset locations associated with well downspacing in certain areas. Proved oil adds in Canada were associated with extensions at Seal. Additions to oil reserves in Malaysia primarily related to four new oil fields offshore Sarawak which were put on production during the second half of 2013.

Sales of properties—The Company sold all its oil fields in the U.K. during the first half of 2013.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 2—Summary of proved natural gas liquids (NGL) reserves based on average prices for 2012—2015

 

(millions of barrels)		Total				United States				Canada				Malaysia
Proved developed and undeveloped NGL reserves:
December 31, 2012			—				—				—				—
Revisions of previous estimates			15.7				15.6				—				0.1
Improved recovery			—				—				—				—
Extensions and discoveries			10.0				8.7				0.1				1.2
Production			(1.3	)			(1.1	)			—				(0.2	)
December 31, 2013			24.4				23.2				0.1				1.1
Revisions of previous estimates			5.1				5.0				—				0.1
Improved recovery			—				—				—				—
Extensions and discoveries			4.7				4.0				0.6				0.1
Sales of properties			(0.2	)			—				—				(0.2	)
Production			(3.4	)			(3.1	)			—				(0.3	)
December 31, 2014			30.6				29.1				0.7				0.8
Revisions of previous estimates			2.0				2.2				(0.3	)			0.1
Improved recovery			—				—				—				—
Extensions and discoveries			7.6				7.6				—				—
Sales of properties			(0.1	)			—				—				(0.1	)
Production			(3.7	)			(3.5	)			—				(0.2	)
December 31, 2015			36.4				35.4				0.4				0.6
Proved developed NGL reserves:
December 31, 2012			—				—				—				—
December 31, 2013			14.2				13.1				—				1.1
December 31, 2014			17.5				16.5				0.2				0.8
December 31, 2015			21.6				20.7				0.3				0.6
Proved undeveloped NGL reserves:
December 31, 2012			—				—				—				—
December 31, 2013			10.2				10.1				0.1				—
December 31, 2014			13.1				12.6				0.5				—
December 31, 2015			14.8				14.7				0.1				—

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 2—Summary of proved natural gas liquids (NGL) reserves based on average prices for 2012—2015—continued

2015 Comments for proved natural gas liquids reserves changes

Revision of previous estimates—The positive 2015 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale area based on improved performance.

Extensions and discoveries—In 2015, the U.S. added NGL reserves primarily for additional drilling activities in the Eagle Ford Shale.

Sales of properties—The Company sold 10% of its oil and gas assets in Malaysia in January 2015.

2014 Comments for proved natural gas liquids reserves changes

Revisions of previous estimates—The positive 2014 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale based on an overall review of oil and gas mix for this production area.

Extensions and discoveries—The 2014 proved NGL reserves add in the U.S. was primarily attributable to drilling activities in the Eagle Ford Shale. The proved reserves add for Canadian NGL in 2014 was primarily associated with the drilling program in the Tupper and Tupper West areas.

Sales of properties—The Company sold 20% of its oil and gas assets in Malaysia in late 2014.

2013 Comments for proved natural gas liquids reserves changes

Revisions of previous estimates—The positive U.S. revision to NGL proved reserves in 2013 was primarily due to well productivity in the Eagle Ford Shale, plus initial recognition of proved reserves quantities for NGL.

Extensions and discoveries—The NGL proved reserves add in 2013 in the U.S. was primarily attributable to development drilling in the Eagle Ford Shale.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 3—Summary of proved natural gas reserves based on average prices for 2012—2015

 

(billions of cubic feet)		Total				United States				Canada				Malaysia				United Kingdom
Proved developed and undeveloped natural gas reserves:
December 31, 2012			1,137.0				209.7				550.4				357.6				19.3
Revisions of previous estimates			33.7				(38.6	)			34.0				38.3				—
Improved recovery			3.2				—				—				3.2				—
Extensions and discoveries			153.4				33.3				42.5				77.6				—
Sales of properties			(19.0	)			—				—				—				(19.0	)
Production			(154.7	)			(19.4	)			(64.1	)			(70.9	)			(0.3	)
December 31, 2013			1,153.6				185.0				562.8				405.8				—
Revisions of previous estimates			167.2				47.7				105.6				13.9				—
Improved recovery			7.0				—				—				7.0				—
Extensions and discoveries			696.8				24.1				231.5				441.2				—
Purchases of properties			5.5				5.5				—				—				—
Sales of properties			(162.6	)			(3.7	)			—				(158.9	)			—
Production			(162.8	)			(32.3	)			(57.1	)			(73.4	)			—
December 31, 2014			1,704.7				226.3				842.8				635.6				—
Revisions of previous estimates			53.5				(5.2	)			18.9				39.8				—
Improved recovery			1.8				—				—				1.8				—
Extensions and discoveries			162.9				43.2				119.7				—				—
Sales of properties			(78.0	)			—				—				(78.0	)			—
Production			(156.1	)			(31.9	)			(71.8	)			(52.4	)			—
December 31, 2015			1,688.8				232.4				909.6				546.8				—
Proved developed natural gas reserves:
December 31, 2012			706.0				78.8				415.8				197.3				14.1
December 31, 2013			786.2				112.6				384.0				289.6				—
December 31, 2014			812.1				145.6				467.4				199.1				—
December 31, 2015			783.5				148.3				453.5				181.7				—
Proved undeveloped natural gas reserves:
December 31, 2012			431.0				130.9				134.6				160.3				5.2
December 31, 2013			367.4				72.4				178.8				116.2				—
December 31, 2014			892.6				80.7				375.4				436.5				—
December 31, 2015			905.3				84.1				456.1				365.1				—

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 3—Summary of proved natural gas reserves based on average prices for 2012—2015—continued

2015 Comments for proved natural gas reserves changes

Revision of previous estimates—The 2015 negative natural gas revision in the U.S. was primarily attributable to performance declines in certain fields in the Gulf of Mexico offset in part by the overall positive performance in the Eagle Ford Shale area. The positive revisions in Canada were attributable to updated well type curves and field development techniques in the Montney area of Western Canada. The positive revision for natural gas reserves in Malaysia was attributable to lower government entitlement under the terms of the respective production sharing contracts due to lower natural gas prices.

Improved recovery—The 2015 Malaysia natural gas proved reserve add was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries—In 2015, the U.S. added natural gas reserves primarily for planned developmental drilling activities in the Eagle Ford Shale while the gas reserve adds in Canada were attributable to developmental drilling activities in the Tupper area.

Sales of properties—The Company sold 10% of its oil and gas assets in Malaysia in January 2015.

2014 Comments for proved natural gas reserves changes

Extensions and discoveries—The proved reserves of natural gas added in the U.S. in 2014 was primarily associated with the development drilling program in the Eagle Ford Shale, while the add in Canada in 2014 was attributable to drilling in the Tupper and Tupper West areas in Western Canada. The proved natural gas reserves added in Malaysia in 2014 was mostly associated with approval and sanction of the plan for a floating liquefied natural gas development in Block H, offshore Sabah, during 2014.

Purchases of properties—The Company acquired an interest in the Kodiak field in the Gulf of Mexico in 2014, which added proved reserves of natural gas during 2014.

Sales of properties—The Company sold its interests in South Louisiana gas fields in 2014, plus it sold a 20% interest in oil and gas assets in Malaysia late in 2014.

2013 Comments for proved natural gas reserves changes

Revisions of previous estimates—The U.S. natural gas proved reserves revisions in 2013 were unfavorable due to converting gas liquids volumes within the gas stream to proved NGL reserves. Positive revisions in Canada were mostly attributable to better well performance in the Tupper West area. Malaysia had positive gas revisions principally due to better well performance at gas fields offshore Sarawak and positive revisions due to better overall well production at the Kikeh field.

Improved recovery—The reserves add in Malaysia was attributable to better waterflood response at the Kikeh field due to better overall well production.

Extensions and discoveries—U.S. proved reserves of gas had adds in the Eagle Ford Shale due to additional offsets based on use of reliable technology with narrower downspacing in certain areas. The gas reserve adds in Canada were at the Tupper West and Tupper areas primarily caused by drilling activities and recognition of offset undeveloped locations. Natural gas proved reserve were added in Malaysia primarily due to initial booking of reserves of associated gas at three oil fields offshore Sarawak.

Sales of properties—The Company sold all of its U.K. oil and gas fields in the first half of 2013.

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 4—Costs incurred in oil and gas property acquisition, exploration and development activities

 

(millions of dollars)		United States				Canada				Malaysia				United Kingdom1				Other				Total
Year Ended December 31, 2015
Property acquisition costs
Unproved		$	10.1				2.5				—				—				—				12.6
Proved			—				—				—				—				—				—
Total acquisition costs			10.1				2.5				—				—				—				12.6
Exploration costs2			166.8				0.7				69.0				—				135.4				371.9
Development costs2			1,375.1				231.5				210.0				—				2.8				1,819.4
Total costs incurred			1,552.0				234.7				279.0				—				138.2				2,203.9
Charged to expense
Dry hole expense			241.3				—				29.7				—				25.8				296.8
Geophysical and other costs			16.9				0.7				7.9				—				73.2				98.7
Total charged to expense			258.2				0.7				37.6				—				99.0				395.5
Property additions		$	1,293.8				234.0				241.4				—				39.2				1,808.4
Year Ended December 31, 2014
Property acquisition costs
Unproved		$	92.9				—				—				—				—				92.9
Proved			7.4				—				—				—				—				7.4
Total acquisition costs			100.3				—				—				—				—				100.3
Exploration costs2			160.0				1.7				6.3				—				262.1				430.1
Development costs2			1,934.7				413.8				926.6				—				7.6				3,282.7
Total costs incurred			2,195.0				415.5				932.9				—				269.7				3,813.1
Charged to expense
Dry hole expense			92.1				—				47.4				—				130.5				270.0
Geophysical and other costs			37.7				1.7				1.3				—				128.5				169.2
Total charged to expense			129.8				1.7				48.7				—				259.0				439.2
Property additions		$	2,065.2				413.8				884.2				—				10.7				3,373.9

 

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Supplemental oil and gas information (unaudited)—continued

Schedule 4—Costs incurred in oil and gas property acquisition, exploration and development activities—continued

 

(millions of dollars)		United States				Canada				Malaysia				United Kingdom1				Other				Total
Year Ended December 31, 2013
Property acquisition costs
Unproved		$	32.4				—				—				—				3.2				35.6
Proved			13.2				—				—				—				—				13.2
Total acquisition costs			45.6				—				—				—				3.2				48.8
Exploration costs2			112.4				21.8				14.9				—				344.6				493.7
Development costs2			1,773.2				351.6				1,787.7	3			8.1				19.0				3,939.6
Total costs incurred			1,931.2				373.4				1,802.6				8.1				366.8				4,482.1
Charged to expense
Dry hole expense			46.1				32.1				20.7				—				164.0				262.9
Geophysical and other costs			29.1				0.7				4.6				—				138.0				172.4
Total charged to expense			75.2				32.8				25.3				—				302.0				435.3
Property additions		$	1,856.0				340.6				1,777.3				8.1				64.8				4,046.8
1       The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first half of 2013.   2       Includes non-cash asset retirement costs as follows:
2015
Exploration costs		$	—				—				—				—				—				—
Development costs			30.7				49.1				(3.0	)			—				—				76.8
		$	30.7				49.1				(3.0	)			—				—				76.8
2014
Exploration costs		$	—				—				—				—				—				—
Development costs			36.5				(32.1	)			66.2				—				—				70.6
		$	36.5				(32.1	)			66.2				—				—				70.6
2013
Exploration costs		$	—				0.2				—				—				—				0.2
Development costs			70.1				5.9				95.9				—				—				171.9
		$	70.1				6.1				95.9				—				—				172.1
3       Includes property costs associated with non-cash capital lease of $358.0 million at the Kakap field.

 

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Supplemental oil and gas information (unaudited)—continued

 

Schedule 5—Results of operations for oil and gas producing activities*

 

						Canada
(millions of dollars)		United States				Conventional				Synthetic				Malaysia				Other				Total
Year Ended December 31, 2015
Revenues
Crude oil and natural gas liquids sales		$	1,176.9				181.0				203.0				790.6				—				2,351.5
Natural gas sales			70.4				167.7				—				185.4								423.5
Total oil and gas revenues			1,247.3				348.7				203.0				976.0				—				2,775.0
Other operating revenues			6.3				(2.4	)			0.4				155.4				—				159.7
Total revenues			1,253.6				346.3				203.4				1,131.4				—				2,934.7
Costs and expenses
Lease operating expenses			312.0				102.4				166.0				251.9				—				832.3
Severance and ad valorem taxes			55.9				4.8				5.1				—				—				65.8
Exploration costs charged to expense			258.2				0.7				—				37.6				99.0				395.5
Undeveloped lease amortization			59.2				14.4				—				—				1.8				75.4
Depreciation, depletion and amortization			794.9				211.2				50.7				544.9				6.2				1,607.9
Accretion of asset retirement obligations			20.2				7.2				5.4				15.9				—				48.7
Impairment of assets			329.0				683.6				—				1,480.6				—				2,493.2
Deepwater rig contract exit costs			282.0				—				—				—				—				282.0
Selling and general expenses			88.2				25.5				1.0				5.7				56.8				177.2
Other expenses			6.7				43.9				—				15.9				12.1				78.6
Total costs and expenses			2,206.3				1,093.7				228.2				2,352.5				175.9				6,056.6
Results of operations before taxes			(952.7	)			(747.4	)			(24.8	)			(1,221.1	)			(175.9	)			(3,121.9	)
Income tax expense (benefit)			(337.0	)			(191.2	)			2.4				(567.9	)			(17.3	)			(1,111.0	)
Results of operations		$	(615.7	)			(556.2	)			(27.2	)			(653.2	)			(158.6	)			(2,010.9	)
Year Ended December 31, 2014
Revenues
Crude oil and natural gas liquids sales		$	2,062.1				453.3				391.5				1,680.2				—				4,587.1
Natural gas sales			127.2				201.3				—				357.5				—				686.0
Total oil and gas revenues			2,189.3				654.6				391.5				2,037.7				—				5,273.1
Other operating revenues			7.1				(2.4	)			0.4				145.8				(1.3	)			149.6
Total revenues			2,196.4				652.2				391.9				2,183.5				(1.3	)			5,422.7
Costs and expenses
Lease operating expenses			345.5				160.3				233.8				350.3				—				1,089.9
Severance and ad valorem taxes			96.5				5.6				5.1				—				—				107.2
Exploration costs charged to expense			129.8				1.7				—				48.7				259.0				439.2
Undeveloped lease amortization			50.1				19.4				—				—				4.9				74.4
Depreciation, depletion and amortization			840.7				262.7				54.0				735.0				5.1				1,897.5
Accretion of asset retirement obligations			17.5				6.0				9.2				18.1				—				50.8
Impairment of assets			14.3				37.0				—				—				—				51.3
Selling and general expenses			95.2				26.7				0.9				15.7				73.5				212.0
Other expense			4.9				1.0				—				16.9				2.1				24.9
Total costs and expenses			1,594.5				520.4				303.0				1,184.7				344.6				3,947.2
Results of operations before taxes			601.9				131.8				88.9				998.8				(345.9	)			1,475.5
Income tax expense (benefit)			214.8				42.4				21.8				102.6				(95.9	)			285.7
Results of operations		$	387.1				89.4				67.1				896.2				(250.0	)			1,189.8

 

*

Results exclude corporate overhead, interest and discontinued operations.

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 5—Results of operations for oil and gas producing activities*—continued

 

						Canada
(millions of dollars)		United States				Conventional				Synthetic				Malaysia				Other				Total
Year ended December 31, 2013
Revenues
Crude oil and natural gas liquids sales		$	1,724.7				507.2				441.0				1,875.0				83.6				4,631.5
Natural gas sales			72.7				198.1				—				404.0				—				674.8
Total oil and gas revenues			1,797.4				705.3				441.0				2,279.0				83.6				5,306.3
Other operating revenues			6.4				(1.9	)			0.3				1.5				—				6.3
Total revenues			1,803.8				703.4				441.3				2,280.5				83.6				5,312.6
Costs and expenses
Lease operating expenses			273.6				180.5				223.4				384.4				191.0				1,252.9
Severance and ad valorem taxes			77.5				5.0				4.8				—				—				87.3
Exploration costs charged to expense			75.2				32.8				—				25.3				302.0				435.3
Undeveloped lease amortization			30.3				21.0				—				—				15.6				66.9
Depreciation, depletion and amortization			576.3				319.2				55.4				588.2				4.5				1,543.6
Accretion of asset retirement obligations			13.5				5.9				10.3				15.0				4.3				49.0
Impairment of assets			—				21.6				—				—				—				21.6
Selling and general expenses			80.4				25.3				0.9				3.5				60.8				170.9
Total costs and expenses			1,126.8				611.3				294.8				1,016.4				578.2				3,627.5
Results of operations before taxes			677.0				92.1				146.5				1,264.1				(494.6	)			1,685.1
Income tax expense (benefit)			241.6				19.9				37.9				477.7				(120.8	)			656.3
Results of operations		$	435.4				72.2				108.6				786.4				(373.8	)			1,028.8

 

*

Results exclude corporate overhead, interest and discontinued operations.

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 6—Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

 

(millions of dollars)		United States				Canada				Malaysia				Total
December 31, 2015
Future cash inflows		$	12,373.9				8,922.0				6,143.1				27,439.0
Future development costs			(2,620.5	)			(1,145.4	)			(957.8	)			(4,723.7	)
Future production costs			(4,955.4	)			(5,892.7	)			(3,290.5	)			(14,138.6	)
Future income taxes			(339.7	)			(504.8	)			(216.2	)			(1,060.7	)
Future net cash flows			4,458.3				1,379.1				1,678.6				7,516.0
10% annual discount for estimated timing of cash flows			(2,430.0	)			(666.8	)			(560.1	)			(3,656.9	)
Standardized measure of discounted future net cash flows		$	2,028.3				712.3				1,118.5				3,859.1
December 31, 2014
Future cash inflows		$	20,767.4				16,257.0				11,909.7				48,934.1
Future development costs			(3,151.4	)			(1,810.5	)			(1,920.8	)			(6,882.7	)
Future production costs			(6,378.5	)			(7,770.2	)			(4,575.6	)			(18,724.3	)
Future income taxes			(2,930.1	)			(1,389.6	)			(1,249.9	)			(5,569.6	)
Future net cash flows			8,307.4				5,286.7				4,163.4				17,757.5
10% annual discount for estimated timing of cash flows			(3,729.1	)			(2,595.3	)			(1,527.9	)			(7,852.3	)
Standardized measure of discounted future net cash flows		$	4,578.3				2,691.4				2,635.5				9,905.2
December 31, 2013
Future cash inflows		$	20,638.6				16,112.9				13,399.0				50,150.5
Future development costs			(3,833.9	)			(1,882.3	)			(1,445.3	)			(7,161.5	)
Future production costs			(5,244.7	)			(7,073.0	)			(4,490.4	)			(16,808.1	)
Future income taxes			(3,368.3	)			(1,472.8	)			(1,855.1	)			(6,696.2	)
Future net cash flows			8,191.7				5,684.8				5,608.2				19,484.7
10% annual discount for estimated timing of cash flows			(4,020.2	)			(2,999.1	)			(1,620.7	)			(8,640.0	)
Standardized measure of discounted future net cash flows		$	4,171.5				2,685.7				3,987.5				10,844.7

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 6—Standardized measure of discounted future net cash flows relating to proved oil and gas reserves—continued

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.

 

(millions of dollars)		2015				2014				2013
Net changes in prices and production costs		$	(11,365.5	)			(2,697.8	)			267.8
Net changes in development costs			591.4				(2,317.3	)			(3,456.8	)
Sales and transfers of oil and gas produced, net of production costs			(1,876.9	)			(4,076.0	)			(3,972.4	)
Net change due to extensions and discoveries			1,145.8				3,251.6				4,608.9
Net change due to purchases and sales of proved reserves			(287.4	)			(1,041.0	)			(135.6	)
Development costs incurred			1,725.4				3,169.3				3,326.8
Accretion of discount			1,289.5				1,462.5				1,109.3
Revisions of previous quantity estimates			163.3				518.9				1,646.0
Net change in income taxes			2,568.3				790.3				(662.1	)
Net increase (decrease)			(6,046.1	)			(939.5	)			2,731.9
Standardized measure at January 1			9,905.2				10,844.7				8,112.8
Standardized measure at December 31		$	3,859.1				9,905.2				10,844.7

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental oil and gas information (unaudited)—continued

 

Schedule 7—Capitalized costs relating to oil and gas producing activities

 

(millions of dollars)		United States				Canada				Malaysia				Other				Subtotal				Synthetic oil—Canada				Total
December 31, 2015
Unproved oil and gas properties		$	570.3				283.1				28.6				128.5				1,010.5				—				1,010.5
Proved oil and gas properties			9,010.0				4,062.2				6,216.0				—				19,288.2				1,174.7				20,462.9
Gross capitalized costs			9,580.3				4,345.3				6,244.6				128.5				20,298.7				1,174.7				21,473.4
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties			(220.8	)			(219.4	)			—				(22.4	)			(462.6	)			—				(462.6	)
Proved oil and gas properties			(4,004.9	)			(2,586.0	)			(4,336.9	)			—				(10,927.8	)			(410.7	)			(11,338.5	)
Net capitalized costs		$	5,354.6				1,539.9				1,907.7				106.1				8,908.3				764.0				9,672.3
December 31, 2014
Unproved oil and gas properties		$	634.9				424.1				—				168.1				1,227.1				—				1,227.1
Proved oil and gas properties			7,810.9				4,515.4				6,917.7				737.8				19,981.8				1,386.9				21,368.7
Gross capitalized costs			8,445.8				4,939.5				6,917.7				905.9				21,208.9				1,386.9				22,595.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties			(171.6	)			(245.6	)			—				(96.6	)			(513.8	)			—				(513.8	)
Proved oil and gas properties			(2,944.0	)			(2,082.1	)			(2,665.3	)			(737.8	)			(8,429.2	)			(433.1	)			(8,862.3	)
Net capitalized costs		$	5,330.2				2,611.8				4,252.4				71.5				12,265.9				953.8				13,219.7

 

Note:

Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.

 

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Murphy Oil Corporation and consolidated subsidiaries

Supplemental quarterly information (unaudited)

 

(millions of dollars except per share amounts)		First quarter				Second quarter				Third quarter				Fourth quarter				Year
Year Ended December 31, 2015
Sales and other operating revenues		$	749.2				718.6				665.6				653.7				2,787.1
Income (loss) from continuing operations before income taxes			(117.7	)			(110.1	)			(2,408.0	)			(646.5	)			(3,282.3	)
Income (loss) from continuing operations			3.5				(89.0	)			(1,587.1	)			(583.2	)			(2,255.8	)
Net income (loss)			(14.5	)			(73.8	)			(1,595.4	)			(587.1	)			(2,270.8	)
Income (loss) from continuing operations per Common share
Basic			0.02				(0.51	)			(9.22	)			(3.39	)			(12.94	)
Diluted			0.02				(0.51	)			(9.22	)			(3.39	)			(12.94	)
Net income (loss) per Common share
Basic			(0.08	)			(0.42	)			(9.26	)			(3.41	)			(13.03	)
Diluted			(0.08	)			(0.42	)			(9.26	)			(3.41	)			(13.03	)
Cash dividend per Common share			0.35				0.35				0.35				0.35				1.40
Market price of Common Stock*
High			51.77				50.56				41.42				31.03				51.77
Low			43.40				41.42				23.76				21.71				21.71
Year Ended December 31, 2014
Sales and other operating revenues		$	1,281.2				1,357.9				1,431.0				1,218.8				5,288.9
Income from continuing operations before income taxes			334.2				304.6				396.5				217.0				1,252.3
Income from continuing operations			169.3				142.7				271.0				442.0				1,025.0
Net income			155.3				129.4				245.7				375.2				905.6
Income from continuing operations per Common share
Basic			0.94				0.80				1.52				2.49				5.73
Diluted			0.93				0.79				1.51				2.48				5.69
Net income per Common share
Basic			0.86				0.72				1.38				2.11				5.06
Diluted			0.85				0.72				1.37				2.10				5.03
Cash dividend per Common share			0.3125				0.3125				0.35				0.35				1.325
Market price of Common Stock*
High			63.70				66.82				67.75				56.13				67.75
Low			55.68				59.61				56.18				44.39				44.39

 

*

Prices are as quoted on the New York Stock Exchange.

 

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Murphy Oil Corporation and consolidated subsidiaries

Schedule II—Valuation accounts and reserves

 

(millions of dollars)		Balance at January 1				Charged (credited) to expense				Deductions				Other*				Balance at December 31
2015
Deducted from asset accounts:
Allowance for doubtful accounts		$	1.6				—				—				—				1.6
Deferred tax asset valuation allowance			306.5				40.8				—				(52.9	)			294.4
2014
Deducted from asset accounts:
Allowance for doubtful accounts		$	1.6				—				—				—				1.6
Deferred tax asset valuation allowance			633.7				37.7				—				(364.9	)			306.5
2013
Deducted from asset accounts:
Allowance for doubtful accounts		$	6.7				0.4				(0.4	)			(5.1	)			1.6
Deferred tax asset valuation allowance			524.0				115.4				—				(5.7	)			633.7

 

*

Amount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carry forwards. Amount in 2014 for deferred tax asset valuation allowance is primarily associated with final abandonment of certain foreign investments in 2014, essentially offsetting changes in deferred tax assets. Amounts in 2013 primarily arose due to separation of Murphy USA Inc. and presentation of U.K. downstream operations as assets held for sale.

 

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Murphy Oil Corporation and consolidated subsidiaries

Schedule II—Valuation accounts and reserves—continued

 

Glossary of terms
3D seismic   three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons   bitumen or oil sands   tar-like hydrocarbon-bearing substance that occurs naturally in certain areas at the Earth’s surface or at relatively shallow depths and which can be recovered, processed and upgraded into a light, sweet synthetic crude oil   deepwater   offshore location in greater than 1,000 feet of water   downstream   refining and marketing operations   dry hole   an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense		exploratory   wildcat and delineation, e.g., exploratory wells   hydrocarbons   organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products   synthetic oil   a light, sweet crude oil produced by upgrading bitumen recovered from oil sands   upstream   oil and natural gas exploration and production operations, including synthetic oil operation   wildcat   well drilled to target an untested or unproved geologic formation

 

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and consolidated subsidiaries

Consolidated balance sheets (unaudited)

(Thousands of dollars)

 

		June 30, 2016				December 31, 2015
ASSETS
Current assets
Cash and cash equivalents		$	267,483				283,183
Canadian government securities with maturities greater than 90 days at the date of acquisition			131,224				173,288
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2016 and 2015			293,312				522,672
Inventories, at lower of cost or market
Crude oil			8,654				25,583
Materials and supplies			145,413				141,205
Prepaid expenses			113,563				212,962
Deferred income taxes			46,093				51,183
Assets held for sale			32,113				38,340
Total current assets			1,037,855				1,448,416
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,241,549 in 2016 and $11,924,193 in 2015			8,565,485				9,818,365
Deferred charges and other assets			311,292				227,031
Total assets		$	9,914,632				11,493,812
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt		$	20,011				18,881
Accounts payable and accrued liabilities			843,787				1,643,632
Income taxes payable			12,816				4,819
Liabilities associated with assets held for sale			4,135				7,297
Total current liabilities			880,749				1,674,629
Long-term debt, including capital lease obligation			2,435,486				3,040,594
Deferred income taxes			46,749				239,811
Asset retirement obligations			746,361				793,474
Deferred credits and other liabilities			633,594				438,576
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued			—				—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2016 and 2015			195,056				195,056
Capital in excess of par value			914,236				910,074
Retained earnings			5,895,794				6,212,201
Accumulated other comprehensive loss			(536,659	)			(704,542	)
Treasury stock, 22,856,616 shares of Common Stock in 2016 and 23,021,013 shares of Common Stock in 2015, at cost			(1,296,734	)			(1,306,061	)
Total stockholders’ equity			5,171,693				5,306,728
Total liabilities and stockholders’ equity		$	9,914,632				11,493,812

See notes to consolidated financial statements, page F-77.

 

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Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of operations (unaudited)

(Thousands of dollars, except per share amounts)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015
REVENUES
Sales and other operating revenues		$	411,217				718,621				840,311				1,467,771
Gain on sale of assets			3,809				18,246				3,831				154,123
Interest and other income			22,436				1,423				23,615				38,143
Total revenues			437,462				738,290				867,757				1,660,037
COSTS AND EXPENSES
Lease operating expenses			156,530				227,489				315,633				459,910
Severance and ad valorem taxes			13,439				19,043				26,076				39,834
Exploration expenses, including undeveloped lease amortization			37,128				64,959				64,044				193,693
Selling and general expenses			67,113				79,176				140,620				166,143
Depreciation, depletion and amortization			255,239				403,390				541,388				884,417
Impairment of assets			—				—				95,088				—
Accretion of asset retirement obligations			12,346				11,750				24,471				23,519
Interest expense			35,058				30,466				67,119				59,936
Interest capitalized			(608	)			(1,823	)			(2,449	)			(3,208	)
Other expense (benefit)			(7,516	)			13,931				(7,932	)			63,612
Total costs and expenses			568,729				848,381				1,264,058				1,887,856
Loss from continuing operations before income taxes			(131,267	)			(110,091	)			(396,301	)			(227,819	)
Income tax benefit			(134,172	)			(21,105	)			(199,721	)			(142,363	)
Income (loss) from continuing operations			2,905				(88,986	)			(196,580	)			(85,456	)
Income (loss) from discontinued operations, net of income taxes			25				15,152				708				(2,819	)
NET INCOME (LOSS)		$	2,930				(73,834	)			(195,872	)			(88,275	)
PER COMMON SHARE—BASIC
Income (loss) from continuing operations		$	0.02				(0.51	)			(1.14	)			(0.48	)
Income (loss) from discontinued operations			—				0.09				—				(0.02	)
Net income (loss)		$	0.02				(0.42	)			(1.14	)			(0.50	)
PER COMMON SHARE—DILUTED
Income (loss) from continuing operations		$	0.02				(0.51	)			(1.14	)			(0.48	)
Income (loss) from discontinued operations			—				0.09				—				(0.02	)
Net income (loss)		$	0.02				(0.42	)			(1.14	)			(0.50	)
Average Common shares outstanding
Basic			172,196,914				174,488,842				172,149,791				176,343,309
Diluted			172,799,827				174,488,842				172,149,791				176,343,309

See notes to consolidated financial statements, page F-77.

 

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Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of comprehensive income (loss) (unaudited)

(Thousands of dollars)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015
Net income (loss)		$	2,930				(73,834	)			(195,872	)			(88,275	)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation			13,222				31,981				161,891				(266,614	)
Retirement and postretirement benefit plans			2,513				2,695				5,029				5,989
Deferred loss on interest rate hedges reclassified to interest expense			481				481				963				963
Other comprehensive income (loss)			16,216				35,157				167,883				(259,662	)
COMPREHENSIVE INCOME (LOSS)		$	19,146				(38,677	)			(27,989	)			(347,937	)

See notes to consolidated financial statements, page F-77.

 

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Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of cash flows (unaudited)

(Thousands of dollars)

 

		Six Months Ended June 30,
		2016				2015
OPERATING ACTIVITIES
Net loss		$	(195,872	)			(88,275	)
Adjustments to reconcile net loss to net cash provided by continuing operations activities:
(Income) loss from discontinued operations			(708	)			2,819
Depreciation, depletion and amortization			541,388				884,417
Impairment of assets			95,088				—
Amortization of deferred major repair costs			3,798				3,404
Dry hole costs			14,270				99,023
Amortization of undeveloped leases			25,419				45,825
Accretion of asset retirement obligations			24,471				23,519
Deferred and noncurrent income tax benefits			(316,201	)			(194,240	)
Pretax gains from disposition of assets			(3,831	)			(154,123	)
Net (increase) decrease in noncash operating working capital			(86,793	)1			107,171
Other operating activities, net			12,349				(14,329	)
Net cash provided by continuing operations activities			113,378				715,211
INVESTING ACTIVITIES
Property additions and dry hole costs			(604,587	)			(1,433,615	)
Proceeds from sales of property, plant and equipment			1,153,325				423,106
Purchase of investment securities2			(651,218	)			(629,763	)
Proceeds from maturity of investment securities2			701,378				663,343
Other investing activities, net			(7,640	)			(20,568	)
Net cash provided (required) by investing activities			591,258				(997,497	)
FINANCING ACTIVITIES
Borrowings of debt			—				823,000
Repayments of debt			(600,000	)			(450,000	)
Capital lease obligation payments			(5,172	)			(4,703	)
Purchase of treasury stock			—				(250,000	)
Withholding tax on stock-based incentive awards			(1,138	)			(8,976	)
Cash dividends paid			(120,535	)			(124,581	)
Other financing activities, net			—				(152	)
Net cash required by financing activities			(726,845	)			(15,412	)
CASH FLOWS FROM DISCONTINUED OPERATIONS
Operating activities			5,185				(85,445	)
Investing activities			—				5,322
Changes in cash included in current assets held for sale			(5,185	)			89,226
Net increase in cash and cash equivalents of discontinued operations			—				9,103
Effect of exchange rate changes on cash and cash equivalents			6,509				4,555
Net decrease in cash and cash equivalents			(15,700	)			(284,040	)
Cash and cash equivalents at January 1			283,183				1,193,308
Cash and cash equivalents at June 30		$	267,483				909,268

 

1

2016 balance includes payments for deepwater rig contract exit of $261.8 million.

 

2

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

See notes to consolidated financial statements, page F-77.

 

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Murphy Oil Corporation and consolidated subsidiaries

Consolidated statements of stockholders’ equity (unaudited)

(Thousands of dollars)

 

		Six Months Ended June 30,
		2016				2015
Cumulative Preferred Stock—par $100, authorized 400,000 shares,none issued		$	—				—
Common Stock—par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares at June 30, 2016 and June 30, 2015
Balance at beginning of period			195,056				195,040
Exercise of stock options			—				16
Balance at end of period			195,056				195,056
Capital in Excess of Par Value
Balance at beginning of period			910,074				906,741
Exercise of stock options, including income tax benefits			—				(376	)
Restricted stock transactions and other			(10,078	)			(38,032	)
Stock-based compensation			14,454				24,285
Other			(214	)			(65	)
Balance at end of period			914,236				892,553
Retained Earnings
Balance at beginning of period			6,212,201				8,728,032
Net loss for the period			(195,872	)			(88,275	)
Cash dividends			(120,535	)			(124,581	)
Balance at end of period			5,895,794				8,515,176
Accumulated Other Comprehensive Loss
Balance at beginning of period			(704,542	)			(170,255	)
Foreign currency translation gain (loss), net of income taxes			161,891				(266,614	)
Retirement and postretirement benefit plans, net of income taxes			5,029				5,989
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes			963				963
Balance at end of period			(536,659	)			(429,917	)
Treasury Stock
Balance at beginning of period			(1,306,061	)			(1,086,124	)
Purchase of treasury shares			—				(250,000	)
Sale of stock under employee stock purchase plans			334				246
Awarded restricted stock, net of forfeitures			8,993				29,056
Balance at end of period—22,856,616 shares of Common Stock in 2016 and 22,303,782 shares of Common Stock in 2015, at cost			(1,296,734	)			(1,306,822	)
Total Stockholders’ Equity		$	5,171,693				7,866,046

See notes to consolidated financial statements, page F-77.

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements

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

Note A—Nature of Business and Interim Financial Statements

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

INTERIM FINANCIAL STATEMENTS—In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2016 and December 31, 2015, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2016 and 2015, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2015 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the six-month period ended June 30, 2016 are not necessarily indicative of future results.

Note B—Property, Plant and Equipment

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

At June 30, 2016, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $128.1 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2016 and 2015.

 

(Thousands of dollars)		2016				2015
Beginning balance at January 1		$	130,514				120,455
Additions pending the determination of proved reserves			800				1,620
Other adjustments			(3,205	)			—
Balance at June 30		$	128,109				122,075

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—continued

Note B—Property, Plant and Equipment—(Continued)

 

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.

 

		June 30,
		2016												2015
(Thousands of dollars)		Amount				No. of Wells				No. of Projects				Amount				No. of Wells				No. of Projects
Aging of capitalized well costs:
Zero to one year		$	63,617				5				5			$	217				2				1
One to two years			—				—				—				32,192				2				1
Two to three years			31,627				2				—				27,842				2				—
Three years or more			32,865				4				—				61,824				4				2
		$	128,109				11				5			$	122,075				10				4

Exploratory well costs capitalized more than one year at June 30, 2016 are in Brunei, and development options are under review for these multiple gas discoveries.

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

In April 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received by Murphy upon closing of the transaction was $414.1 million. A gain on sale of approximately $187 million is being deferred and recognized over the next 20 years in the Canadian operating segment. The Company amortized $1.8 million of the deferred gain in the second quarter of 2016. The remaining deferred gain is included as a component of deferred credits and other liabilities on the Company’s Consolidated Balance Sheet.

In a separate transaction, the same Canadian subsidiary signed a definitive agreement to acquire a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Montney lands in Alberta, the majority of which is unproved. Under the terms of the joint venture the total consideration amounts to approximately $375 million, of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and the remaining $168 million in the form of a carried interest for a period of up to five years. The transaction closed in the second quarter of 2016.

During the first quarter of 2016, declines in crude oil and natural gas prices from year end 2015 provided indications of possible impairments in certain of the company’s producing properties. As a result of management’s assessments, the Company recognized pretax non-cash impairments charges of $95.1 million in the six-month period ended June 30, 2016, to reduce the carrying value to their estimated fair value for its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. The fair

 

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Table of Contents

Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note B—Property, Plant and Equipment—(Continued)

 

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

During the six-month period ended June 30, 2015, the Company completed the sale of 10% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million. The Company recorded an after-tax gain of $199.5 million on the sale in the 2015 six-month period.

Note C—Discontinued Operations

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented. The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter of 2015 and results subsequent to the sale are related to winding up of these operations.

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
(Thousands of dollars)		2016				2015				2016				2015
Revenues		$	151				153,107				835				382,496
Income before income taxes		$	25				21,046				708				337
Income tax benefit			—				5,894				—				3,156
Income (loss) from discontinued operations		$	25				15,152				708				(2,819	)

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at June 30, 2016 and December 31, 2015.

 

(Thousands of dollars)		June 30, 2016				December 31, 2015
Current assets
Cash		$	3,007				7,927
Accounts receivable			12,403				12,037
Other			16,703				18,376
Total current assets held for sale		$	32,113				38,340
Current liabilities
Accounts payable		$	488				2,433
Accrued compensation and severance			—				2,179
Refinery decommissioning cost			3,647				2,685
Total current liabilities associated with assets held for sale		$	4,135				7,297

 

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Notes to consolidated financial statements—(Continued)

 

Note D—Financing Arrangements and Debt

The Company has a $2.0 billion committed credit facility with a major banking consortium that expires in June 2017. Borrowings under the facility bear interest at 1.45% above LIBOR based on the Company’s current credit rating as of June 30, 2016. In addition, facility fees of 0.30% are charged on the full $2.0 billion commitment. At June 30, 2016, the company had no borrowings under this committed facility. The Company also had outstanding letters of credit of approximately $88 million issued under its revolving credit facility at June 30, 2016, which reduced the available borrowing capacity under the agreement. At June 30, 2016, the Company also had uncommitted credit lines that had an estimated total borrowing capacity of approximately $195 million of which no amounts were outstanding under these uncommitted credit lines. If necessary, the Company believes it could borrow funds under all or certain of these uncommitted lines with various financial institutions in future periods. 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.

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 June 2028. Current maturities and long-term debt on the Consolidated Balance Sheet included $20.0 million and $202.7 million, respectively, associated with this lease at June 30, 2016.

Note E—Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.

 

		Six Months Ended June 30
(Thousands of dollars)		2016				2015
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Decrease in accounts receivable		$	109,105				284,542
Increase in inventories			(4,659	)			(25,547	)
Decrease (increase) in prepaid expenses			99,524				(40,191	)
Decrease in deferred income tax assets			5,564				5,092
Decrease in accounts payable and accrued liabilities			(337,302	)			(84,781	)
Increase (decrease) in current income tax liabilities			40,975				(31,944	)
Net (increase) decrease in noncash operating working capital		$	(86,793	)			107,171
Supplementary disclosures:
Cash income taxes paid (refunded), net		$	(4,367	)			90,419
Interest paid, net of amounts capitalized							55,658
Non-cash investing activities:
Asset retirement costs capitalized		$	8,693				6,703
Decrease in capital expenditure accrual			165,329				336,952

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

 

Note F—Employee and Retiree Benefit Plans

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

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

 

		Three Months Ended June 30,
		Pension Benefits								Other Postretirement Benefits
(Thousands of dollars)		2016				2015				2016				2015
Service cost		$	2,770				4,772				675				828
Interest cost			8,865				7,971				1,107				1,192
Expected return on plan assets			(9,698	)			(8,724	)			—				—
Amortization of prior service cost			321				198				(20	)			(20	)
Amortization of transitional asset			—				274				2				3
Recognized actuarial loss			3,718				3,891				36				190
			5,976				8,382				1,800				2,193
Special termination benefits			—				8,606				—				—
Curtailments			—				306				—				—
Net periodic benefit expense		$	5,976				17,294				1,800				2,193

 

		Six Months Ended June 30,
		Pension Benefits								Other Postretirement Benefits
(Thousands of dollars)		2016				2015				2016				2015
Service cost		$	5,923				9,853				1,348				1,656
Interest cost			14,473				15,921				2,215				2,384
Expected return on plan assets			(15,083	)			(17,411	)			—				—
Amortization of prior service cost			640				393				(41	)			(41	)
Amortization of transitional asset			—				545				2				3
Recognized actuarial loss			7,247				7,782				75				385
			13,200				17,083				3,599				4,387
Special termination benefits			—				8,606				—				—
Curtailments			822				306				(19	)			—
Net periodic benefit expense		$	14,022				25,995				3,580				4,387

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note F—Employee and Retiree Benefit Plans—(Continued)

 

Curtailment expense for the six months ended June 30, shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016. During the six-month period ended June 30, 2016, the Company made contributions of $6.7 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 2016 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.3 million.

Note G—Incentive Plans

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

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

In February 2016, the Committee granted stock options for 862,000 shares at an exercise price of $17.57 per share. The Black-Scholes valuation for these awards was $5.03 per option. The Committee also granted 394,000 performance-based RSU and 200,000 time-based RSU in February. The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $12.21 to $16.34 per unit. The fair value of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which was $17.57 per share. Additionally, the Committee granted 708,200 SAR and 507,470 units of cash-settled RSU (RSU-C) to certain employees. The SAR and RSU-C are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of these SAR was equivalent to the stock options granted, while the initial value of RSU-C was equivalent to equity-settled restricted stock units granted. Also in February, the Committee granted 85,679 shares of time-based RSU to the Company’s Directors under the Non-employee Director Plan. These shares vest on the third anniversary of the date of grant. The estimated fair value of these awards was $19.26 per unit on date of grant. In April 2016, the Company awarded an additional 217,500 time-based RSU. The fair value of these time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which was $24.075 per share.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note G—Incentive Plans—(Continued)

 

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

 

		Six Months Ended June 30,
(Thousands of dollars)		2016				2015
Compensation charged against income before tax benefit		$	24,288				31,230
Related income tax benefit recognized			8,210				9,691

Note H—Earnings per Share

Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for the three-months and six-month periods ended June 30, 2016 and 2015. The following table reconciles the weighted-average shares outstanding used for these computations.

 

		Three Months Ended June 30,								Six Months Ended June 30,
(Weighted-average shares)		2016				2015				2016				2015
Basic method			172,196,914				174,488,842				172,149,791				176,343,309
Dilutive stock options*			602,913				—				—				—
Diluted method			172,799,827				174,488,842				172,149,791				176,343,309

 

*

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015
Antidilutive stock options excluded from diluted shares			5,084,395				5,988,668				5,799,268				5,767,975
Weighted average price of these options		$	54.22			$	53.12				50.17				53.31

Note I—Income Taxes

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

 

		2016				2015
Three months ended June 30			102.2%				19.2%
Six months ended June 30			50.4%				62.5%

The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income

 

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Notes to consolidated financial statements—(Continued)

Note I—Income Taxes—(Continued)

 

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

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of June 30, 2016, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States—2011; Canada—2008; Malaysia—2009; and United Kingdom—2014.

Note J—Financial Instruments and Risk Management

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

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil, natural gas liquids and natural gas it produces and sells. The Company had open derivative contracts at June 30, 2016 and 2015. The impact from marking to market these commodity derivative contracts increased the loss before income taxes by $2.6 million for the six-month period ended June 30, 2016 and reduced the loss before income taxes by $7.4 million for the six-month period ended June 30, 2015.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note J—Financial Instruments and Risk Management—(Continued)

 

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

 

		Volumes
At June 30, 2016		(barrels per day)				Swap Prices
July—December 2016			25,000			$	50.67 per barrel
January—December 2017			7,000			$	50.16 per barrel
At June 30, 2015
July—September 2015			15,000			$	62.84 per barrel
October—December 2015			15,000			$	63.30 per barrel

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At June 30, 2016 and 2015 short-term derivative instruments were outstanding in Canada for approximately $5.8 million and $8.0 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil. The impact from marking to market these foreign currency derivative contracts was insignificant for the six-month periods ended June 30, 2016 and 2015, respectively.

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

At June 30, 2016 and December 31, 2015, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

June 30, 2016

December 31, 2015

(Thousands of dollars)

Asset (Liability) Derivatives

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

$

1,709

Accounts receivable

$

89,358

Foreign exchange

Accounts payable

(1

)

Accounts payable

(29

)

 

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Notes to consolidated financial statements—(Continued)

Note J—Financial Instruments and Risk Management—(Continued)

 

For the three-month and six-month periods ended June 30, 2016 and 2015, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

 

				Gain (Loss)
(Thousands of dollars)				Three Months Ended June 30,								Six Months Ended June 30,
Type of Derivative Contract		Statement of Operations Location		2016				2015				2016				2015
Commodity		Sales and other operating revenues			$(47,738)				7,419				(34,549)				7,419
Foreign exchange		Interest and other income			26,481				(49)				26,786				14
					$(21,257)				7,370				(7,763)				7,433

Interest Rate Risks

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012. These interest rate swaps matured in May 2012. Under hedge accounting rules, the Company deferred the net cost associated with these contracts to match the payment of interest on these notes through 2022. During each of the six-month periods ended June 30, 2016 and 2015, $1.5 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss deferred on these matured contracts at June 30, 2016 was $11.3 million, which was recorded, net of income taxes of $6.1 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet. The Company expects to charge approximately $1.5 million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining six months of 2016.

Fair Values—Recurring

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

 

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Notes to consolidated financial statements—(Continued)

Note J—Financial Instruments and Risk Management—(Continued)

 

The carrying value of assets and liabilities recorded at fair value on a recurring basis at June 30, 2016 and December 31, 2015 are presented in the following table.

 

		June 30, 2016																December 31, 2015
(Thousands of dollars)		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets:
Commodity derivative contracts			—				1,709				—				1,709				—				89,358				—				89,358
		$	—				1,709				—				1,709				—				89,358				—				89,358
Liabilities:
Nonqualified employee savings plans		$	13,256				—				—				13,256				12,971				—				—				12,971
Foreign currency exchange derivative contracts			—				1				—				1				—				29				—				29
		$	13,256				1				—				13,257				12,971				29				—				13,000

The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date. The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues in the Consolidated Statements of Operations while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses in the Consolidated Statements of Operations. The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at June 30, 2016 and December 31, 2015.

Fair Values—Nonrecurring

As a result of significantly lower commodity prices in early 2016, the Company recognized $95.1 million in pretax noncash impairment charges related to producing properties during the six-month period ended June 30, 2016. The fair value information associated with these impaired properties is presented in the following table.

 

June 30, 2016

Fair Value

Net Book Value Prior to Impairment

Total Pretax (Noncash) Impairment Loss

(Thousands of dollars)

Level 1

Level 2

Level 3

Assets:

Impaired proved properties

Canada

$

—

—

71,967

167,055

95,088

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note J—Financial Instruments and Risk Management—(Continued)

 

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

Note K—Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2015 and June 30, 2016 and the changes during the six-month period ended June 30, 2016 are presented net of taxes in the following table.

 

(Thousands of dollars)		Foreign Currency Translation Gains (Losses)1				Retirement and Postretirement Benefit Plan Adjustments1				Deferred Loss on Interest Rate Derivative Hedges1				Total1
Balance at December 31, 2015		$	(513,004	)			(179,260	)			(12,278	)			(704,542	)
Components of other comprehensive income:
Before reclassifications to income			161,891				(3	)			—				161,888
Reclassifications to income			—				5,032	2			963	3			5,995
Net other comprehensive income			161,891				5,029				963				167,883
Balance at June 30, 2016		$	(351,113	)			(174,231	)			(11,315	)			(536,659	)

 

1

All amounts are presented net of income taxes.

2

Reclassifications before taxes of $7,741 for the six-month period ended June 30, 2016 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $2,709 for the six-month period ended June 30, 2016 are included in Income tax expense.

3

Reclassifications before taxes of $1,482 for the six-month period ended June 30, 2016 are included in Interest expense. Related income taxes of $519 for the six-month period ended June 30, 2016 are included in Income tax expense.

Note L—Environmental and Other Contingencies

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

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws,

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

Note L—Environmental and Other Contingencies—(Continued)

 

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 believes costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period.

During 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers have been notified. The Company has not yet established a complete estimate of the costs to remediate the site. Based on the assessments done to date, the Company recorded $43.9 million in other expense during 2015 associated with the estimated costs of remediating the site. The Company has spent $32.7 million to date associated with this event. Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through June 30, 2016.

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

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

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

 

Note M—Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2016 to 2020 natural gas sales volumes in Western Canada. The natural gas sales contracts call for deliveries during the last six months of 2016 of approximately 99 million cubic feet per day (MMCFD) at C$3.00 per MCF and 40 MMCFD at C$2.71 per MCF from January 2017 through December 2020. In July 2016, the Company entered into an additional 19 MMCFD of natural gas sales contracts for the January 2017 through December 2020 period at C$3.00 per MCF. These natural gas contracts have been accounted for as normal sales for accounting purposes.

Note N—Business Segments

 

		Total Assets				Three Months Ended June 30, 2016								Three Months Ended June 30, 2015
(Millions of dollars)		at June 30, 2016				External Revenues				Income (Loss)				External Revenues				Income (Loss)
Exploration and production*
United States		$	5,479.2				143.6				(65.7	)			339.8				(16.5	)
Canada			1,580.3				77.4				55.3				152.9				(32.2	)
Malaysia			2,130.4				190.5				47.7				244.5				27.6
Other			133.2				(0.1	)			(5.1	)			—				(30.1	)
Total exploration and production			9,323.1				411.4				32.2				737.2				(51.2	)
Corporate			559.4				26.1				(29.3	)			1.1				(37.8	)
Assets/revenue/income (loss) from continuing operations			9,882.5				437.5				2.9				738.3				(89.0	)
Discontinued operations, net of tax			32.1				—				—				—				15.2
Total		$	9,914.6				437.5				2.9				738.3				(73.8	)

 

		Six Months Ended June 30, 2016								Six Months Ended June 30, 2015
(Millions of dollars)		External Revenues				Income (Loss)				External Revenues				Income (Loss)
Exploration and production*
United States		$	318.3				(131.4	)			619.9				(110.4	)
Canada			183.5				(31.9	)			305.2				(70.7	)
Malaysia			338.8				70.1				690.2				250.7
Other			—				(31.2	)			—				(102.1	)
Total exploration and production			840.6				(124.4	)			1,615.3				(32.5	)
Corporate			27.2				(72.2	)			44.7				(53.0	)
Revenue/income (loss) from continuing operations			867.8				(196.6	)			1,660.0				(85.5	)
Discontinued operations, net of tax			—				0.7				—				(2.8	)
Total		$	867.8				(195.9	)			1,660.0				(88.3	)

 

*

Additional details about results of oil and gas operations are presented in the tables on pages 26 and 27.

 

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Murphy Oil Corporation and consolidated subsidiaries

Notes to consolidated financial statements—(Continued)

 

Note O—New Accounting Principles and Recent Accounting Pronouncements

Leases

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

Compensation-Stock Compensation

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

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Note P—Subsequent Event

On August 3, 2016, the Board of Directors of Murphy Oil Corporation declared a quarterly cash dividend on its common stock of $0.25 per share. The dividend is payable September 1, 2016 to holders of record August 15, 2016.

 

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PROSPECTUS

Murphy Oil Corporation

COMMON STOCK

PREFERRED STOCK

DEPOSITARY SHARES

SENIOR DEBT SECURITIES

SUBORDINATED DEBT SECURITIES

WARRANTS

PURCHASE CONTRACTS

UNITS

 

 

We may offer from time to time common stock, preferred stock, depositary shares representing preferred stock, senior debt securities, subordinated debt securities, warrants, purchase contracts, and units. Specific terms of these securities will be provided in supplements to this prospectus. You should read this prospectus and any supplement carefully before you invest.

Our common stock is listed on the New York Stock Exchange and trades under the ticker symbol “MUR.”

We may sell the securities offered under this prospectus through agents; through underwriters or dealers; directly to one or more purchasers; or through a combination of any of these methods of sale. For each offering of securities under this prospectus, we will identify the specific plan of distribution, including any underwriters, dealers, agents or direct purchasers, and their compensation, in the related prospectus supplement.

 

 

Investing in these securities involves certain risks. See “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 and in our most recent Quarterly Report on Form 10-Q subsequent to such Annual Report, each of which is incorporated by reference herein.

 

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is October 16, 2015

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You should rely only on the information contained in or incorporated by reference in this prospectus, the accompanying prospectus supplement, and any free writing prospectus that we file with the Securities and Exchange Commission (the “SEC”) in connection with the offering described in such prospectus supplement. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in or incorporated by reference in this prospectus is accurate as of any date other than the date on the front of this prospectus.

The terms “we,” “our,” “us,” “its,” “the Company,” “Murphy Oil” and “Murphy Oil Corporation” refer to Murphy Oil Corporation and its consolidated subsidiaries unless the context indicates otherwise, and except as provided in the next sentence. In the descriptions of securities contained herein, the terms “we,” “our,” “us,” “its,” “the Company,” “Murphy Oil” and “Murphy Oil Corporation” refer to Murphy Oil Corporation only.

 

 

TABLE OF CONTENTS

 

		Page
About this Prospectus			2
Murphy Oil Corporation			2
Where You Can Find More Information			3
Special Note on Forward-Looking Statements			3
Ratio of Earnings to Fixed Charges			4
Use of Proceeds			4
Description of Common Stock			5
Description of Preferred Stock			7
Description of Depositary Shares			8
Description of Debt Securities			10
Description of Warrants			19
Description of Purchase Contracts			20
Description of Units			21
Forms of Securities			22
Plan of Distribution			23
Validity of Securities			23
Experts			23

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the SEC utilizing a “shelf” registration process. Under this shelf process, we may sell any combination of the securities described in this prospectus in one or more offerings. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read both this prospectus and any prospectus supplement together with additional information described under the heading “Where You Can Find More Information.”

MURPHY OIL CORPORATION

Murphy Oil Corporation is an international oil and gas company that conducts business through various operating subsidiaries. The Company produces oil and/or natural gas in the United States, Canada and Malaysia and conducts exploration activities worldwide. The Company also has an interest in a Canadian synthetic oil operation.

Murphy Oil is headquartered in El Dorado, Arkansas. The Company’s subsidiary Murphy Exploration & Production Company, through various operating subsidiaries and affiliates, is engaged in crude oil and natural gas production activities in the United States and Malaysia and explores for oil and natural gas worldwide. Its headquarters is in Houston, Texas and it conducts business from offices in numerous locations around the world. The Company’s subsidiary Murphy Oil Company Ltd. is engaged in crude oil and natural gas exploration and production in Western Canada and offshore Eastern Canada, as well as the sale of synthetic crude oil from oil sands. Its office is located in Calgary, Alberta, and it is operated as a component of the Company’s worldwide exploration and production operation directed from Houston.

 

 

Our principal executive offices are located at 200 Peach Street, P.O. Box 7000, El Dorado, Arkansas 71731-7000, and our telephone number is (870) 862-6411. Our capital stock is listed on the New York Stock Exchange under the symbol “MUR.” We maintain a website at http://www.murphyoilcorp.com where general information about us is available. We are not incorporating the contents of the website into this prospectus.

 

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document that we file at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site at http://www.sec.gov, from which interested persons can electronically access our SEC filings, including the registration statement and the exhibits and schedules thereto.

The SEC allows us to “incorporate by reference” the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede this information. We incorporate by reference each document listed below and all documents subsequently filed with the SEC pursuant to Section 13(a), 13(c), 14, or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), prior to the termination of the offering under this prospectus:

 

•

Our Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 27, 2015;

 

•

Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015, filed on May 7, 2015 and August 5, 2015, respectively;

 

•

Our Definitive Proxy Statement on Schedule 14A filed on March 27, 2015 (solely to the extent incorporated by reference into Part III of our Annual Report on Form 10-K); and

 

•

Our Current Reports on Form 8-K or 8-K/A filed on February 3, 2015, February 6, 2015, February 11, 2015, May 14, 2015, and May 20, 2015.

We are not incorporating by reference any Current Report on Form 8-K that is furnished to the SEC pursuant to Items 2.02, 7.01 or 9.01 of Form 8-K.

You may request a copy of these filings at no cost, by writing or telephoning the office of the Corporate Secretary, Murphy Oil Corporation, P.O. Box 7000, El Dorado, Arkansas 71731-7000, (870) 862-6411.

SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS

This prospectus, including the documents we incorporate by reference, contain statements of Murphy Oil’s expectations, intentions, plans and beliefs that are forward-looking, including statements regarding the possible separation of our U.S. downstream business, and are dependent on certain events, risks and uncertainties that may be outside of Murphy Oil’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Murphy Oil’s actual results could differ materially from those expressed or implied by these statements due to a number of factors, including, but not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, customer demand for our products, political and regulatory instability, and uncontrollable natural hazards, as well as those contained under the caption “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 and in our most recent Quarterly Report on Form 10-Q subsequent to such Annual Report.

 

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the periods indicated. We have computed the ratio of earnings to fixed charges by dividing earnings by fixed charges. For this purpose, “earnings” consist of income from continuing operations before income taxes adjusted for (1) distributions (less than) greater than equity in earnings of affiliates, (2) previously capitalized interest charged to earnings during the period, (3) interest and expense on indebtedness, excluding capitalized interest and (4) the interest portion of rentals (calculated as one-third of rentals). “Fixed charges” consist of (1) interest and expense on indebtedness, excluding capitalized interest, (2) capitalized interest and (3) the interest portion of rentals (calculated as one-third of rentals).

 

Six Months Ended June 30, 2015		Years Ended December 31,
		2014		2013		2012		2011		2010
—(1)		7.9		9.5		15.1		13.0		12.6

 

(1)	Earnings for the six-month period ended June 30, 2015 were inadequate to cover fixed charges by approximately $215 million.

USE OF PROCEEDS

Unless otherwise stated in the prospectus supplement accompanying this prospectus, we will use the net proceeds we receive from the sale of the securities offered by this prospectus and any accompanying prospectus supplement for general corporate purposes. General corporate purposes may include additions to working capital, capital expenditures, repayment of debt or the financing of possible acquisitions.

 

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DESCRIPTION OF COMMON STOCK

The following description of our capital stock is based upon our certificate of incorporation (“Certificate of Incorporation”), our bylaws (“Bylaws”) and applicable provisions of law. We have summarized certain portions of the Certificate of Incorporation and Bylaws below. The summary is not complete. The Certificate of Incorporation and Bylaws are incorporated by reference in the registration statement for these securities that we have filed with the SEC and have been filed as exhibits to our Annual Report on Form 10-K for the year ended December 31, 2014. You should read the Certificate of Incorporation and Bylaws for the provisions that are important to you.

Certain provisions of the Delaware General Corporation Law (“DGCL”), the Certificate of Incorporation and the Bylaws summarized in the following paragraphs may have an anti-takeover effect. This may delay, defer or prevent a tender offer or takeover attempt that a shareholder might consider in its best interests, including those attempts that might result in a premium over the market price for its shares.

Authorized Capital Stock

Our Certificate of Incorporation authorizes us to issue 450,400,000 shares of stock of all classes, of which 450,000,000 shares shall be common stock, par value $1.00 per share, and 400,000 shares shall be cumulative preferred stock, par value $100 per share. No shares of stock of any class have any preemptive or preferential right to purchase or subscribe to any shares of stock of any class or any notes, debentures, bonds, or other securities convertible into or carrying options or warrants to purchase shares of any class, other than such rights as the Board of Directors may grant and at such prices as the Board of Directors may fix. The Board of Directors may issues shares of stock of any class, or any notes, debentures, bonds or other securities convertible into or carrying options or warrants to purchase shares of stock of any class, without offering any such shares of stock of any class, either in whole or in part, to the existing stockholders of any class.

Common Stock

As of June 30, 2015, there were 172,751,942 shares of common stock outstanding. Except as provided by our Certificate of Incorporation or by law, each holder of common stock shall have the right, to the exclusion of all other classes of stock, to one vote for each share of stock standing in the name of such holder on the books of the Company. Subject to preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the Board of Directors out of funds legally available therefor. In the event of liquidation, dissolution or winding up of Murphy Oil, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock, if any, then outstanding. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The common stock is listed on the New York Stock Exchange. The transfer agent and registrar for the common stock is Computershare Investor Services, LLC.

Preferred Stock

The Board of Directors has the authority to issue the preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, dividend rates, conversion or exchange rights, voting rights, terms of redemption, redemption prices, liquidation preferences, use of purchase, retirement or sinking funds and the number of shares constituting any series of the designation of such series, without further vote or action by the shareholders. The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control of Murphy Oil without further action by the shareholders and may adversely affect the voting and other rights of the holders of common stock. We may further amend from time to time our Certificate of Incorporation to increase the number of authorized shares of preferred stock. An amendment would require the approval of the holders of a majority of the outstanding shares of our preferred stock. As of the date of this prospectus, we have not issued any preferred stock.

 

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Certain Anti-Takeover Effects of Delaware Law

We are subject to Section 203 of the DGCL (“Section 203”). In general, Section 203 prohibits a publicly held Delaware corporation from engaging in various “business combination” transactions with any interested stockholder for a period of three years following the date of the transactions in which the person became an interested stockholder, unless:

 

•

the transaction is approved by the board of directors prior to the date the interested stockholder obtained such status;

 

•

upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

 

•

on or subsequent to such date the business combination is approved by the board and authorized at an annual or special meeting of stockholders by the affirmative vote of at least 66 2/3% of the outstanding voting stock which is not owned by the interested stockholder.

A “business combination” is defined to include mergers, asset sales, and other transactions resulting in financial benefit to a stockholder. In general, an “interested stockholder” is a person who, together with affiliates and associates, owns (or within three years, did own) 15% or more of a corporation’s voting stock. The statute could prohibit or delay mergers or other takeover or change in control attempts with respect to Murphy Oil and, accordingly, may discourage attempts to acquire Murphy Oil even though such a transaction may offer Murphy Oil’s stockholders the opportunity to sell their stock at a price above the prevailing market price.

 

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DESCRIPTION OF PREFERRED STOCK

When we offer to sell a particular series of preferred stock, if the terms of any series of preferred stock being offered differ from the terms set forth in this prospectus, we will describe the specific terms of the securities in a supplement to this prospectus. The preferred stock will be issued under a certificate of designations relating to each series of preferred stock and is also subject to our Certificate of Incorporation.

Our Board of Directors may issue authorized shares of preferred stock, as well as authorized but unissued shares of common stock, without further shareholder action, unless shareholder action is required by applicable law or by the rules of a stock exchange or quotation system on which any series of our stock may be listed or quoted. All shares of preferred stock offered will be fully paid and non-assessable.

The transfer agent for each series of preferred stock will be described in the prospectus supplement.

Dividend Rights

The preferred stock will be preferred over our common stock as to payment of dividends. Before we declare and set apart for payment or pay any dividends or distributions (other than dividends or distributions payable in common stock) on our common stock, the holders of shares of each series of preferred stock will be entitled to receive dividends when, as and if declared by our board of directors. We will pay those dividends either in cash, shares of common stock or preferred stock or otherwise, at the rate and on the date or dates set forth in the prospectus supplement. With respect to each series of preferred stock, the dividends on each share of the series will be cumulative from the date of issue of the share unless some other date is set forth in the prospectus supplement relating to the series. Accruals of dividends will not bear interest.

Rights upon Liquidation

The preferred stock will be preferred over the common stock as to asset distributions so that the holders of each series of preferred stock will be entitled to be paid, upon our voluntary or involuntary liquidation, dissolution or winding up and before any distribution is made to the holders of common stock, the liquidation preference per share plus the amount of accumulated dividends and, in the event of a voluntary liquidation, any premium, as set forth in the applicable prospectus supplement. However, in this case the holders of preferred stock will not be entitled to any other or further payment. If upon any liquidation, dissolution or winding up our net assets are insufficient to permit the payment in full of the respective amounts to which the holders of all outstanding preferred stock are entitled, our entire remaining net assets will be distributed among the holders of each series of preferred stock in amounts proportional to the full amounts to which the holders of each series are entitled.

Redemption

All shares of any series of preferred stock will be redeemable to the extent set forth in the prospectus supplement relating to the series. All shares of any series of preferred stock will be convertible into shares of common stock or into shares of any other series of preferred stock to the extent set forth in the applicable prospectus supplement.

Other Provisions of our Certificate of Incorporation

In the event of a proposed merger or tender offer, proxy contest or other attempt to gain control of Murphy Oil which is not approved by the board of directors of Murphy Oil, the board of directors of Murphy Oil may authorize the issuance of one or more series of preferred stock with voting rights or other rights and preferences which could impede the success of the proposed merger, tender offer, proxy contest or other attempt to gain control of Murphy Oil. While the ability of the board of directors of Murphy Oil to do this may be limited by applicable law, our restated certificate of incorporation and the applicable rules of the stock exchanges upon which our common stock is listed, the consent of the holders of common stock would not be required for any issuance of preferred stock in such a situation.

 

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DESCRIPTION OF DEPOSITARY SHARES

We may, at our option, elect to offer fractional shares of preferred stock, rather than full shares of preferred stock. If we exercise this option, we will issue to the public receipts for depositary shares, and each of these depositary shares will represent a fraction, as set forth in the applicable prospectus supplement, of a share of a particular series of preferred stock. The shares of any series of preferred stock underlying the depositary shares will be deposited under a deposit agreement between us and a bank or trust company selected by us. The depositary will have its principal office in the United States and a combined capital and surplus of at least $50,000,000.

Subject to the terms of the deposit agreement, each owner of a depositary share will be entitled, in proportion to the applicable fraction of a share of preferred stock underlying that depositary share, to all the rights and preferences of the preferred stock underlying that depositary share. Those rights include dividend, voting, redemption and liquidation rights. The depositary shares will be evidenced by depositary receipts issued pursuant to the deposit agreement. Depositary receipts will be distributed to those persons purchasing the fractional shares of preferred stock underlying the depositary shares, in accordance with the terms of the offering. Copies of the deposit agreement and depositary receipt will be filed with the SEC in connection with the offering of specific depositary shares.

Dividends and Other Distributions

The depositary will distribute all cash dividends or other cash distributions received with respect to the preferred stock to the record holders of depositary shares relating to the preferred stock in proportion to the number of depositary shares owned by those holders.

If there is a distribution other than in cash, the depositary will distribute property received by it to the record holders of depositary shares that are entitled to receive the distribution, unless the depositary determines that it is not feasible to make the distribution. If this occurs, the depositary may, with our approval, sell the property and distribute the net proceeds from the sale to the applicable holders.

Redemption of Depositary Shares

If a series of preferred stock represented by depositary shares is subject to redemption, the depositary shares will be redeemed from the proceeds received by the depositary resulting from the redemption, in whole or in part, of that series of preferred stock held by the depositary. The redemption price per depositary share will be equal to the applicable fraction of the redemption price per share payable with respect to that series of the preferred stock.

Whenever we redeem shares of preferred stock that are held by the depositary, the depositary will redeem, as of the same redemption date, the number of depositary shares representing the shares of preferred stock so redeemed. If fewer than all the depositary shares are to be redeemed, the depositary will select the depositary shares to be redeemed by lot or pro rata, as the depositary may determine.

Voting the Preferred Stock

Upon receipt of notice of any meeting at which the holders of the preferred stock are entitled to vote, the depositary will mail the information contained in the notice to the record holders of the depositary shares underlying the preferred stock. Each record holder of the depositary shares on the record date (which will be the same date as the record date for the preferred stock) will be entitled to instruct the depositary as to the exercise of the voting rights pertaining to the amount of the preferred stock represented by the holder’s depositary shares. The depositary will then try, as far as practicable, to vote the number of shares of preferred stock underlying those depositary shares in accordance with these instructions, and we agree to take all actions deemed necessary by the depositary to enable the depositary to do so. The depositary will not vote the shares of preferred stock to the extent it does not receive specific instructions from the holders of depositary shares underlying the preferred stock.

 

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Amendment and Termination of the Depositary Agreement

The form of depositary receipt evidencing the depositary shares and any provision of the deposit agreement may at any time be amended by agreement between us and the depositary. However, any amendment which materially and adversely alters the rights of the holders of depositary shares will not be effective unless the holders of at least a majority of the depositary shares then outstanding approve the amendment. We or the depositary may terminate the deposit agreement only if (a) all outstanding depositary shares have been redeemed or (b) there has been a final distribution of the underlying preferred stock in connection with our liquidation, dissolution or winding up and the preferred stock has been distributed to the holders of depositary receipts.

Charges of Depositary

We will pay all transfer and other taxes and governmental charges arising solely from the existence of the depositary arrangements. We will also pay charges of the depositary in connection with the initial deposit of the preferred stock and any redemption of the preferred stock. Holders of depositary receipts will pay other transfer and other taxes and governmental charges and those other charges, including a fee for the withdrawal of shares of preferred stock upon surrender of depositary receipts, as are expressly provided in the deposit agreement to be for their accounts.

Miscellaneous

The depositary will forward to holders of depositary receipts all reports and communications from us that we deliver to the depositary and that we are required to furnish to the holders of the preferred stock.

Neither we nor the depositary will be liable if either of us is prevented or delayed by law or any circumstance beyond our control in performing our respective obligations under the deposit agreement. Our obligations and those of the depositary will be limited to performance in good faith of our respective duties under the deposit agreement. Neither we nor they will be obligated to prosecute or defend any legal proceeding in respect of any depositary shares or preferred stock unless satisfactory indemnity is furnished. We and the depositary may rely upon written advice of counsel or accountants, or upon information provided by persons presenting preferred stock for deposit, holders of depositary receipts or other persons believed to be competent and on documents believed to be genuine.

Resignation and Removal of Depositary

The depositary may resign at any time by delivering notice to us of its election to resign. We may remove the depositary at any time. Any resignation or removal will take effect upon the appointment of a successor depositary and its acceptance of the appointment. We must appoint the successor depositary within 60 days after delivery of the notice of resignation or removal and it must be a bank or trust company having its principal office in the United States and having a combined capital and surplus of at least $50,000,000.

 

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DESCRIPTION OF DEBT SECURITIES

This prospectus describes certain general terms and provisions that could apply to the debt securities. The debt securities will constitute either senior or subordinated debt of Murphy Oil. Each prospectus supplement will state the particular terms that actually will apply to the debt securities included in the supplement.

In addition to the following summary, you should refer to the applicable provisions of the following documents for more detailed information:

 

•

the senior indenture dated as of May 18, 2012 between Murphy Oil and U.S. Bank National Association, as trustee, which has been filed as an exhibit to the registration statement of which this prospectus is a part, and

 

•

the subordinated indenture, a form of which has been filed as an exhibit to the registration statement of which this prospectus is a part.

Neither indenture limits the aggregate principal amount of debt securities that we may issue under that indenture. We may authorize the issuance of the debt securities in one or more series at various times. All debt securities will be unsecured. The senior securities will have the same rank as all of our other unsecured and unsubordinated debt. The subordinated securities will be subordinated to senior indebtedness as described under “Subordinated Securities” in this prospectus. The prospectus supplement relating to the particular series of debt securities being offered will specify the amounts, prices and terms of those debt securities. These terms may include:

 

•

whether the debt securities are senior securities or subordinated securities;

 

•

the title and the limit on the aggregate principal amount of the debt securities;

 

•

the maturity date or dates;

 

•

the interest rate (which may be fixed or variable), or the method of determining any interest rates, at which the debt securities may bear interest;

 

•

the dates from which interest shall accrue and the dates on which interest will be payable;

 

•

the currencies in which the debt securities are denominated and principal and interest may be payable;

 

•

any redemption or sinking fund terms;

 

•

any event of default or covenant with respect to the debt securities of a particular series, if not set forth in this prospectus;

 

•

whether the debt securities are to be issued, in whole or in part, in the form of one or more global securities and the depositary for the global securities;

 

•

whether the debt securities would be convertible into our common stock; and

 

•

any other terms of the series, which will not conflict with the terms of the applicable indenture.

We may issue debt securities of any series at various times and we may reopen any series for further issuances from time to time without notice to existing holders.

We will issue the debt securities in fully registered form without coupons. Unless we specify otherwise in the applicable prospectus supplement, we will issue debt securities denominated in U.S. dollars in denominations of $1,000 or multiples of $1,000.

We will describe special Federal income tax and other considerations relating to debt securities denominated in foreign currencies and “original issue discount” debt securities (debt securities issued at a substantial discount below their principal amount because they pay no interest or pay interest that is below market rates at the time of issuance) in the applicable prospectus supplement.

 

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Unless we specify otherwise in the applicable prospectus supplement, the covenants contained in the indentures and the debt securities will not provide special protection to holders of debt securities if we enter into a highly leveraged transaction, recapitalization or restructuring.

Exchange, Registration and Transfer

You may exchange debt securities of any series that are not global securities for other debt securities of the same series and of like aggregate principal amount and tenor in different authorized denominations. In addition, you may present debt securities for registration of transfer, together with a duly executed form of transfer, at the office of the security registrar or at the office of any transfer agent designated by us for that purpose with respect to any series of debt securities and referred to in the applicable prospectus supplement. No service charge is required for any transfer or exchange of debt securities but we may require payment of any taxes and other governmental charges. The security registrar or the transfer agent will effect the transfer or exchange upon being satisfied with the documents of title and identity of the person making the request. We have appointed the applicable trustee as security registrar for the applicable indenture. We may at any time designate additional transfer agents with respect to any series of debt securities.

In the event of any redemption in part, we will not be required to:

 

•

issue, register the transfer of or exchange debt securities of any series during a period beginning at the opening of business 15 days before the mailing of notice of redemption of debt securities of that series to be redeemed and ending at the close of business on the mailing date;

 

•

register the transfer of or exchange any debt security, or portion thereof, called for redemption, except the unredeemed portion of any registered security being redeemed in part.

For a discussion of restriction on the exchange, registration and transfer of global securities, see “Global Securities.”

Payment and Paying Agents

Unless we specify otherwise in the applicable prospectus supplement, payment of principal, any premium and any interest on debt securities will be made at the offices of the paying agents that we designate at various times.

However, at our option, we may make interest payments by check mailed to the address, as it appears in the security register, of the person entitled to the payments. Unless we specify otherwise in the applicable prospectus supplement, we will make payment of any installment of interest on debt securities to the person in whose name that registered security is registered at the close of business on the regular record date for such interest.

We will specify in the applicable prospectus supplement, the agency which will be designated as our paying agent for payments with respect to debt securities.

Modification of the Indentures

Under each indenture our rights and obligations and the rights of the holders may be modified with our consent and the consents of the trustee under that indenture and the holders of at least a majority in principal amount of the then outstanding debt securities of each series affected by the modification.

However, the consent of each affected holder is needed to:

 

•

extend the maturity, reduce the interest rate or extend the payment schedule of any of the debt securities;

 

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•

reduce the principal amount or any amount payable on redemption of any debt security;

 

•

reduce the amount of principal of an original issue discount security payable upon acceleration of maturity or in bankruptcy;

 

•

change the conversion provisions of either indenture in a manner adverse to the holders;

 

•

change the subordination provisions of the subordinated indenture in a manner adverse to the holders of subordinated debt;

 

•

reduce the percentage required for modifications or waivers of compliance with the indentures; or

 

•

impair the right of repayment at the holder’s option or the right of a holder to institute suit for repayment on or with respect to any debt security.

In addition, the subordinated provisions of the subordinated indenture cannot be modified to the detriment of any of our senior indebtedness without the consent of the holders of the senior indebtedness.

Any actions we or the trustee may take toward adding to our covenants, adding events of default or establishing the structure or terms of the debt securities as permitted by the indentures will not require the approval of any holder of debt securities. In addition, we or the trustee may cure ambiguities or inconsistencies in the indentures or make other provisions without the approval of any holder as long as no holder’s interests are materially and adversely affected.

Consolidation, Merger or Sale of Assets

We will not merge or consolidate with any other corporation or sell or convey all or substantially all of our assets to any Person, unless (i) either we are the continuing corporation, or the successor corporation or the Person which acquires by sale or conveyance substantially all our assets (if other than us) will be a corporation organized under the laws of the United States of America or any State thereof and will expressly assume the due and punctual payment of the principal of and interest on all the debt securities, according to their tenor, and the due and punctual performance and observance of all of the covenants and conditions of the indenture to be performed or observed by us, by supplemental indenture in form reasonably satisfactory to the trustee, executed and delivered to the trustee by such corporation, and (ii) we or our successor corporation, as the case may be, are not, immediately after such merger or consolidation, or such sale or conveyance, in default in the performance of any such covenant or condition of the indenture.

In case of any such consolidation, merger, sale or conveyance, and following such an assumption by the successor corporation, such successor corporation will succeed to and be substituted for us, with the same effect as if it had been named in the indenture. Such successor corporation may cause to be signed, and may issue either in its own name or in our name prior to such succession any or all of the debt securities issuable under the indenture which theretofore had not been signed by us and delivered to the trustee; and, upon the order of such successor corporation instead of us and subject to all the terms, conditions and limitations prescribed in the indenture, the trustee will authenticate and will deliver any debt securities which previously were signed and delivered by our officers to the trustee for authentication, and any debt securities which such successor corporation thereafter causes to be signed and delivered to the trustee for that purpose. All of the debt securities so issued will in all respects have the same legal rank and benefit under the indenture as the debt securities theretofore or thereafter issued in accordance with the terms of the indenture as though all of such debt securities had been issued at the date of the execution of the indenture.

In the event of any such sale or conveyance (other than a conveyance by way of lease) we or any successor corporation which has become such in the manner described above will be discharged from all obligations and covenants under the indenture and the debt securities and may be liquidated and dissolved.

 

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Our U.S. downstream business does not constitute substantially all of our assets, and for the avoidance of doubt the senior indenture provides that the covenant described above will not apply in the event we determine to dispose of our U.S. downstream business.

Events of Default, Notice and Waiver

“Event of Default,” when used in an indenture, will mean any of the following in relation to a series of debt securities:

 

•

failure to pay interest on any debt security for 30 days after the interest becomes due;

 

•

failure to pay the principal on any debt security when due;

 

•

failure to deposit any sinking fund payment after such payment becomes due;

 

•

failure to perform or breach of any other covenant or warranty in the indenture or any debt security that continues for 90 days after our being given notice from the trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of the affected series;

 

•

default in the payment when due of (a) other indebtedness in an aggregate principal amount in excess of $75,000,000 and such default is not cured within 30 days after written notice to us and the trustee by the holders of at least 25% in principal amount of the outstanding debt securities of the series and (b) interest, principal, premium or a sinking fund or redemption payment under any such other indebtedness, causing the indebtedness to become due prior to its stated maturity, which acceleration is not stayed, rescinded or annulled within 10 days after written notice to us and the trustee by the holders of at least 25% in principal amount of the outstanding debt securities of the series;

 

•

a creditor commences involuntary bankruptcy, insolvency or similar proceedings against us and we are unable to obtain a stay or dismissal of that proceeding within 60 days;

 

•

we voluntarily seek relief under bankruptcy, insolvency or similar laws or we consent to a court entering an order for relief against us under those laws; or

 

•

any other event of default provided for debt securities of that series.

If any event of default relating to outstanding debt securities of any series occurs and is continuing, either the trustee or the holders of at least 25% in principal amount of the outstanding debt securities of that series may declare the principal and accrued interest of all of the outstanding debt securities of such series to be due and immediately payable.

The indentures provide that the holders of at least a majority in principal amount of the outstanding debt securities of any series may direct the time, method and place of conducting any proceeding for any remedy available to the trustee, or of exercising any trust or power conferred on the trustee, with respect to the debt securities of that series. The trustee may act in any way that is consistent with those directions and may decline to act if any of the directions is contrary to law or to the indentures or would involve the trustee in personal liability.

The indentures provide that the holders of at least a majority in principal amount of the outstanding debt securities of any series may on behalf of the holders of all of the outstanding debt securities of the series waive any past default (and its consequences) under the indentures relating to the series, except a default (a) in the payment of the principal of, interest on or sinking fund installment of any of the debt securities of the series, (b) with respect to voluntary or involuntary bankruptcy, insolvency or similar proceedings, or (c) with respect to a covenant or provision of such indentures which, under the terms of such indentures, cannot be modified or amended without the consent of the holders of all of the outstanding debt securities of the series affected. In the case of clause (b) above, the holders of at least a majority of all outstanding debt securities (voting as one class) may on behalf of all holders waive a default.

 

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The indentures contain provisions entitling the trustee, subject to the duty of the trustee during an event of default to act with the required standard of care, to be indemnified by the holders of the debt securities of the relevant series before proceeding to exercise any right or power under the indentures at the request of those holders.

The indentures require the trustee to, within 90 days after the occurrence of a default known to it with respect to any series of outstanding debt securities, give the holders of that series notice of the default if uncured and unwaived. However, the trustee may withhold this notice if it in good faith determines that the withholding of this notice is in the interest of those holders. However, the trustee may not withhold this notice in the case of a default in payment of principal of, interest on or sinking fund installment with respect to any debt securities of the series. The term “default” for the purpose of this provision means any event that is, or after notice or lapse of time, or both, would become, an event of default with respect to the debt securities of that series.

Each indenture requires us to file annually with the trustee a certificate, executed by our officers, indicating whether any of the officers has knowledge of any default under the indenture.

Replacement of Securities

We will replace any mutilated debt security at the expense of the holder, if we so choose, upon surrender of the mutilated debt security to the appropriate trustee. We will replace debt securities that are destroyed, stolen or lost at the expense of the holder upon delivery to the appropriate trustee of evidence of the destruction, loss or theft of the debt securities satisfactory to us and to the trustee. In the case of a destroyed, lost or stolen debt security, an indemnity satisfactory to the appropriate trustee and us may be required at the expense of the holder of the debt security before a replacement debt security will be issued.

Defeasance

The indentures contain a provision that permits us to elect to defease and be discharged from all of our obligations (subject to limited exceptions) with respect to any series of debt securities then outstanding provided the following conditions, among others, have been satisfied:

 

•

we have deposited in trust with the trustee (a) money, (b) U.S. government obligations, or (c) a combination thereof, in each case, in an amount sufficient to pay and discharge the principal of and interest on the outstanding debt securities of any series;

 

•

no event of default has occurred or is continuing with respect to the securities of any series being defeased;

 

•

defeasance will not result in a breach or violation of, or constitute a default under any agreement to which we are a party or by which we are bound; and

 

•

we have delivered to the trustee (a) an officers’ certificate and an opinion of counsel that all conditions precedent relating to the defeasance have been complied with and (b) an opinion of counsel that the holders will not recognize income, gain or loss for Federal income tax purposes.

Governing Law

The indentures and the debt securities will be governed by, and construed in accordance with, the laws of the State of New York.

The Trustee

U.S. Bank National Association is trustee under the senior indenture dated as of May 18, 2012. We will specify the trustee for each issue of debt securities in the applicable prospectus supplement, as well as any material relationship we may have with such trustee.

 

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Senior Securities

Limitations on Liens. Neither we nor any restricted subsidiary will issue, assume or guarantee any debt secured by a mortgage, lien, pledge or other encumbrance, which are collectively called “mortgages” in the indenture, on any principal property or on any debt or capital stock of any restricted subsidiary which owns any principal property without providing that the senior securities will be secured equally and ratably or prior to the debt. A “restricted subsidiary” is a 50% or more owned subsidiary owning principal property and having stockholder’s equity greater than 2% of our consolidated net assets.

“Principal property” is all property and equipment directly engaged in our exploration, production, refining, marketing and transportation activities.

“Consolidated net assets” means the total of all assets of Murphy Oil, excluding intangible assets (other than goodwill), treasury stock carried as an asset or write-ups of non- acquisition-related capital assets, less depreciation, amortization and other similar reserves, less the total of all liabilities, deferred credits, minority shareholders’ interests in subsidiaries, reserves and other similar items of Murphy Oil, excluding certain acquisition-related debt or stockholders’ equity, as calculated on our consolidated balance sheet.

However, the limitation on liens shall not apply to the following:

 

•

mortgages existing on the date of the senior indenture;

 

•

mortgages existing at the time an entity becomes a restricted subsidiary of ours;

 

•

mortgages securing debt of a restricted subsidiary in favor of Murphy Oil or any subsidiary of ours;

 

•

mortgages on property, shares of stock or indebtedness (a) existing at the time of the acquisition of the property, shares of stock or indebtedness, (b) to secure payment of all or part of the purchase price of the property, shares of stock or indebtedness, or (c) to secure debt incurred prior to, at the time of or within 120 days after the acquisition of the property, shares of stock or indebtedness or after the completion of construction of the property, for the purpose of financing all or part of the purchase price of the property, shares of stock or indebtedness or the cost of construction;

 

•

mortgages in favor of the United States of America, any state, any other country or any political subdivision required by contract or statute;

 

•

mortgages on property of Murphy Oil or any restricted subsidiary securing all or part of the cost of operating, constructing or acquiring projects, as long as recourse is only to the property;

 

•

specific marine mortgages or foreign equivalents on property or assets of Murphy Oil or any restricted subsidiary;

 

•

mortgages or easements on property of Murphy Oil or any restricted subsidiary incurred to finance the property on a tax-exempt basis that do not materially detract from the value of or materially impair the use of the property or assets; or

 

•

any extension, renewal or replacement of any mortgage referred to in the preceding items or of any debt secured by those mortgages as long as the extension, renewal or replacement secures the same or a lesser amount of debt and is limited to substantially the same property (plus improvements) which secured the mortgage.

Notwithstanding anything mentioned above, we and any of our restricted subsidiaries may issue, assume or guarantee debt secured by mortgages on principal property or on any indebtedness or capital stock of any restricted subsidiary (other than the debt secured by mortgages permitted above) which does not exceed 10% of our consolidated net assets.

 

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Limitations on Sale and Lease-Back Transactions. Neither we nor any restricted subsidiary will lease any principal property for more than three years from the purchaser or transferee of such principal property. However, the limitation on this type of arrangement shall not apply if:

 

•

we or our restricted subsidiary could incur debt secured by a mortgage on the property to be leased, as permitted above, without equally and ratably securing the senior securities of any series; or

 

•

we apply the greater of the proceeds from the sale or transfer and the fair value of the leased property to any senior acquisition-related debt within 120 days of the sale and lease-back transaction, in both cases less any amounts spent to purchase unencumbered principal property during the one year prior to or 120 days after any sale and lease-back transaction.

Subordinated Securities

Under the subordinated indenture, payment of the principal of, interest on and any premium on the subordinated securities will generally be subordinated in right of payment to the prior payment in full of all of our senior indebtedness.

“Senior indebtedness” is defined as the principal of, any premium and accrued and unpaid interest on the following items, whether outstanding on or created, incurred or assumed after the date of execution of the subordinated indenture:

 

•

our indebtedness for money borrowed (other than the subordinated securities);

 

•

our guarantees of indebtedness for money borrowed of any other person; and

 

•

indebtedness evidenced by notes, debentures, bonds or other instruments of indebtedness for the payment of which we are responsible or liable, by guarantees or otherwise.

Senior indebtedness also includes modifications, renewals, extensions and refundings of any of the types of indebtedness, liabilities, obligations or guarantees listed above, unless the relevant instrument states that the indebtedness, liability, obligation or guarantee, or modification, renewal, extension or refunding, is not senior in right of payment to the subordinated securities.

We may not make any payment of principal of, interest on or any premium on the subordinated securities except for sinking fund payments as described below if:

 

•

any default or event of default with respect to any senior indebtedness occurs and is continuing, or

 

•

any judicial proceeding is pending with respect to any default in payment of senior indebtedness.

We may make sinking fund payments during a suspension of principal or interest payments on subordinated debt if we make these sinking fund payments by redeeming or acquiring securities prior to the default or by converting the securities.

If any subordinated security is declared due and payable before its specified date, or if we pay or distribute any assets to creditors upon our dissolution, winding up, liquidation or reorganization, we must pay all principal of, any premium and interest due or to become due on all senior indebtedness in full before the holders of subordinated securities are entitled to receive or take any payment. Subject to the payment in full of all senior indebtedness, the holders of the subordinated securities are to be subrogated to the rights of the holders of senior indebtedness to receive payments or distribution of our assets applicable to senior indebtedness until the subordinated securities are paid in full.

By reason of this subordination, in the event of insolvency, our creditors who are holders of senior indebtedness, as well as some of our general creditors, may recover more, ratably, than the holders of the subordinated securities.

The subordinated indenture will not limit the amount of senior indebtedness or debt securities which we may issue.

 

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Conversion Rights

The prospectus supplement will provide if a series of securities is convertible into our common stock and the initial conversion price per share at which the securities may be converted.

If we have not redeemed a convertible security, the holder of the convertible security may convert the security, or any portion of the principal amount in integral multiples of $1,000, at the conversion price in effect at the time of conversion, into shares of Murphy Oil common stock. Conversion rights expire at the close of business on the date specified in the prospectus supplement for a series of convertible securities. Conversion rights expire at the close of business on the redemption date in the case of any convertible securities that we call for redemption.

In order to exercise the conversion privilege, the holder of the convertible security must surrender to us, at any office or agency maintained for that purpose, the security with a written notice of the election to convert the security, and, if the holder is converting less than the entire principal amount of the security, the amount of security to be converted. In addition, if the convertible security is converted during the period between a record date for the payment of interest and the related interest payment date, the person entitled to convert the security must pay us an amount equal to the interest payable on the principal amount being converted.

We will not pay any interest on converted securities on any interest payment date after the date of conversion except for those securities surrendered during the period between a record date for the payment of interest and the related interest payment date.

Convertible securities shall be deemed to have been converted immediately prior to the close of business on the day of surrender of the security. We will not issue any fractional shares of stock upon conversion, but we will make an adjustment in cash based on the market price at the close of business on the date of conversion.

The conversion price will be subject to adjustment in the event of:

 

•

payment of stock dividends or other distributions on our common stock;

 

•

issuance of rights or warrants to all our stockholders entitling them to subscribe for or purchase our stock at a price less than the market price of our common stock;

 

•

the subdivision of our common stock into a greater or lesser number of shares of stock;

 

•

the distribution to all stockholders of evidences of our indebtedness or assets, excluding stock dividends or other distributions and rights or warrants; or

 

•

the reclassification of our common stock into other securities.

We may also decrease the conversion price as we consider necessary so that any event treated for Federal income tax purposes as a dividend of stock or stock rights will not be taxable to the holders of our common stock.

We will pay any and all transfer taxes that may be payable in respect of the issue or delivery of shares of common stock on conversion of the securities.

We are not required to pay any tax which may be payable in respect of any transfer involved in the issue and delivery of shares in a name other than that of the holder of the security to be converted and no issue and delivery shall be made unless and until the person requesting the issue has paid the amount of any such tax or established to our satisfaction that such tax has been paid.

After the occurrence of:

 

•

consolidation with or merger of Murphy Oil into any other corporation,

 

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•

any merger of another corporation into Murphy Oil, or

 

•

any sale or transfer of substantially all of the assets of Murphy Oil,

which results in any reclassification, change or conversion of our common stock, the holders of any convertible securities will be entitled to receive on conversion the kind and amount of shares of common stock or other securities, cash or other property receivable upon such event by a holder of our common stock immediately prior to the occurrence of the event.

 

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DESCRIPTION OF WARRANTS

We may issue securities warrants for the purchase of debt securities, preferred stock or common stock. Securities warrants may be issued independently or together with debt securities, preferred stock or common stock and may be attached to or separate from any offered securities. We will issue each series of securities warrants under a separate warrant agreement to be entered into between us and a bank or trust company, as warrant agent. The securities warrant agent will act solely as our agent in connection with the securities warrants and will not assume any obligation or relationship of agency or trust for or with any registered holders of securities warrants or beneficial owners of securities warrants. In addition to this summary, you should refer to the securities warrant agreement, including the form of securities warrant certificate, relating to the specific securities warrants being offered for the complete terms of the securities warrant agreement and the securities warrants. The securities warrant agreement, together with the terms of securities warrant certificate and securities warrants, will be filed with the SEC in connection with the offering of the specific securities warrants.

We will describe the particular terms of any issue of securities warrants in the prospectus supplement relating to the issue. Those terms may include:

 

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the designation, aggregate principal amount, currencies, denominations and terms of the series of debt securities purchasable upon exercise of securities warrants to purchase debt securities and the price at which the debt securities may be purchased upon exercise;

 

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the designation, number of shares, stated value and terms (including, without limitation, liquidation, dividend, conversion and voting rights) of the series of preferred stock purchasable upon exercise of securities warrants to purchase shares of preferred stock and the price at which such number of shares of preferred stock of such series may be purchased upon such exercise;

 

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the number of shares of common stock purchasable upon the exercise of securities warrants to purchase shares of common stock and the price at which such number of shares of common stock may be purchased upon such exercise;

 

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the date on which the right to exercise the securities warrants will commence and the date on which the right will expire;

 

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the Federal income tax consequences applicable to the securities warrants; and

 

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any other terms of the securities warrant.

Securities warrants for the purchase of preferred stock and common stock will be offered and exercisable for U.S. dollars only. Securities warrants will be issued in registered form only. The exercise price for securities warrants will be subject to adjustment in accordance with the applicable prospectus supplement.

Each securities warrant will entitle its holder to purchase the principal amount of debt securities or the number of shares of preferred stock or common stock at the exercise price set forth in, or calculable as set forth in, the applicable prospectus supplement. The exercise price may be adjusted upon the occurrence of events as set forth in the prospectus supplement. After the close of business on the expiration date, unexercised securities warrants will become void. We will specify the place or places where, and the manner in which, securities warrants may be exercised in the applicable prospectus supplement.

Prior to the exercise of any securities warrants to purchase debt securities, preferred stock or common stock, holders of the securities warrants will not have any of the rights of holders of the debt securities, preferred stock or common stock purchasable upon exercise, including:

 

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in the case of securities warrants for the purchase of debt securities, the right to receive payments of principal of, any premium or interest on the debt securities purchasable upon exercise or to enforce covenants in the applicable indenture; or

 

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in the case of securities warrants for the purchase of preferred stock or common stock, the right to vote or to receive any payments of dividends on the preferred stock or common stock purchasable upon exercise.

 

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DESCRIPTION OF PURCHASE CONTRACTS

We may issue purchase contracts for the purchase or sale of:

 

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debt or equity securities issued by us or securities of third parties, a basket of such securities, an index or indices or such securities or any combination of the above as specified in the applicable prospectus supplement;

 

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currencies; or

 

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commodities.

Each purchase contract will entitle the holder thereof to purchase or sell, and obligate us to sell or purchase, on specified dates, such securities, currencies or commodities at a specified purchase price, which may be based on a formula, all as set forth in the applicable prospectus supplement. We may, however, satisfy our obligations, if any, with respect to any purchase contract by delivering the cash value of such purchase contract or the cash value of the property otherwise deliverable or, in the case of purchase contracts on underlying currencies, by delivering the underlying currencies, as set forth in the applicable prospectus supplement. The applicable prospectus supplement will also specify the methods by which the holders may purchase or sell such securities, currencies or commodities and any acceleration, cancellation or termination provisions or other provisions relating to the settlement of a purchase contract.

The purchase contracts may require us to make periodic payments to the holders thereof or vice versa, which payments may be deferred to the extent set forth in the applicable prospectus supplement, and those payments may be unsecured or prefunded on some basis. The purchase contracts may require the holders thereof to secure their obligations in a specified manner to be described in the applicable prospectus supplement. Alternatively, purchase contracts may require holders to satisfy their obligations thereunder when the purchase contracts are issued. Our obligation to settle such pre-paid purchase contracts on the relevant settlement date may constitute indebtedness. Accordingly, pre-paid purchase contracts will be issued under either the senior indenture or the subordinated indenture.

 

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DESCRIPTION OF UNITS

As specified in the applicable prospectus supplement, we may issue units consisting of one or more shares of common stock, shares of preferred stock, depositary shares representing preferred stock, senior debt securities, subordinated debt securities, warrants, purchase contracts or any combination of such securities. The applicable supplement will describe:

 

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the terms of the units and of the securities comprising the units, including whether and under what circumstances the securities comprising the units may be traded separately;

 

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a description of the terms of any unit agreement governing the units; and

 

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a description of the provisions for the payment, settlement, transfer or exchange of the units.

 

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FORMS OF SECURITIES

Each debt security and warrant will be represented either by a certificate issued in definitive form to a particular investor or by one or more global securities representing the entire issuance of securities. Certificated securities in definitive form and global securities will be issued in registered form. Definitive securities name you or your nominee as the owner of the security, and in order to transfer or exchange these securities or to receive payments other than interest or other interim payments, you or your nominee must physically deliver the securities to the trustee, registrar, paying agent or other agent, as applicable. Global securities name a depositary or its nominee as the owner of the debt securities or warrants represented by these global securities. The depositary maintains a computerized system that will reflect each investor’s beneficial ownership of the securities through an account maintained by the investor with its broker/dealer, bank, trust company or other representative, as we explain more fully below.

Global Securities

We may issue the debt securities and warrants in the form of one or more fully registered global securities that will be deposited with a depositary or its nominee identified in the applicable prospectus supplement and registered in the name of that depositary or nominee. In those cases, one or more registered global securities will be issued in a denomination or aggregate denominations equal to the portion of the aggregate principal or face amount of the securities to be represented by registered global securities. Unless and until it is exchanged in whole for securities in definitive registered form, a registered global security may not be transferred except as a whole by and among the depositary for the registered global security, the nominees of the depositary or any successors of the depositary or those nominees.

If not described below, any specific terms of the depositary arrangement with respect to any securities to be represented by a registered global security will be described in the prospectus supplement relating to those securities. We anticipate that the following provisions will apply to all depositary arrangements.

Ownership of beneficial interests in a registered global security will be limited to persons, called participants, that have accounts with the depositary or persons that may hold interests through participants. Upon the issuance of a registered global security, the depositary will credit, on its book-entry registration and transfer system, the participants’ accounts with the respective principal or face amounts of the securities beneficially owned by the participants. Any dealers, underwriters or agents participating in the distribution of the securities will designate the accounts to be credited. Ownership of beneficial interests in a registered global security will be shown on, and the transfer of ownership interests will be effected only through, records maintained by the depositary, with respect to interests of participants, and on the records of participants, with respect to interests of persons holding through participants. The laws of some states may require that some purchasers of securities take physical delivery of these securities in definitive form. These laws may impair your ability to own, transfer or pledge beneficial interests in registered global securities.

So long as the depositary, or its nominee, is the registered owner of a registered global security, that depositary or its nominee, as the case may be, will be considered the sole owner or holder of the securities represented by the registered global security for all purposes under the applicable indenture or warrant agreement. Except as described below, owners of beneficial interests in a registered global security will not be entitled to have the securities represented by the registered global security registered in their names, will not receive or be entitled to receive physical delivery of the securities in definitive form and will not be considered the owners or holders of the securities under the applicable indenture or warrant agreement. Accordingly, each person owning a beneficial interest in a registered global security must rely on the procedures of the depositary for that registered global security and, if that person is not a participant, on the procedures of the participant through which the person owns its interest, to exercise any rights of a holder under the applicable indenture or warrant agreement. We understand that under existing industry practices, if we request any action of holders or if an owner of a beneficial interest in a registered global security desires to give or take any action that a holder is

 

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entitled to give or take under the applicable indenture or warrant agreement, the depositary for the registered global security would authorize the participants holding the relevant beneficial interests to give or take that action, and the participants would authorize beneficial owners owning through them to give or take that action or would otherwise act upon the instructions of beneficial owners holding through them.

Principal, premium, if any, and interest payments on debt securities, and any payments to holders with respect to warrants, represented by a registered global security registered in the name of a depositary or its nominee will be made to the depositary or its nominee, as the case may be, as the registered owner of the registered global security. None of Murphy Oil, the trustees, the warrant agents, or any other agent of Murphy Oil, agent of the trustees or agent of the warrant agents will have any responsibility or liability for any aspect of the records relating to payments made on account of beneficial ownership interests in the registered global security or for maintaining, supervising or reviewing any records relating to those beneficial ownership interests.

We expect that the depositary for any of the securities represented by a registered global security, upon receipt of any payment of principal, premium, interest or other distribution of underlying securities or other property to holders on that registered global security, will immediately credit participants’ accounts in amounts proportionate to their respective beneficial interests in that registered global security as shown on the records of the depositary. We also expect that payments by participants to owners of beneficial interests in a registered global security held through participants will be governed by standing customer instructions and customary practices, as is now the case with the securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of those participants.

If the depositary for any of these securities represented by a registered global security is at any time unwilling or unable to continue as depositary or ceases to be a clearing agency registered under the Exchange Act, and a successor depositary registered as a clearing agency under the Exchange Act is not appointed by us within 90 days, we will issue securities in definitive form in exchange for the registered global security that had been held by the depositary. Any securities issued in definitive form in exchange for a registered global security will be registered in the name or names that the depositary gives to the relevant trustee, warrant agent or other relevant agent of ours or theirs. It is expected that the depositary’s instructions will be based upon directions received by the depositary from participants with respect to ownership of beneficial interests in the registered global security that had been held by the depositary.

PLAN OF DISTRIBUTION

We may sell the securities offered under this prospectus through agents; through underwriters or dealers; directly to one or more purchasers; or through a combination of any of these methods of sale. For each offering of securities under this prospectus, we will identify the specific plan of distribution, including any underwriters, dealers, agents or direct purchasers, and their compensation, in the related prospectus supplement.

VALIDITY OF SECURITIES

The validity of the securities will be passed on for us by Davis Polk & Wardwell LLP, New York, New York, and for any underwriters by the law firm named in the applicable prospectus supplement.

EXPERTS

The consolidated financial statements and schedule of Murphy Oil Corporation and subsidiaries as of December 31, 2014 and 2013, and for each of the years in the three-year period ended December 31, 2014, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2014, have been incorporated by reference herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, incorporated by reference herein, and upon the authority of said firm as experts in accounting and auditing.

 

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$550,000,000

 

6.875% NOTES DUE 2024

 

 

Prospectus Supplement

August 12, 2016

 

 

Joint Physical Book-Running Managers

 

J.P. Morgan		BofA Merrill Lynch

 

 

Joint Book-Running Managers

 

BNP PARIBAS		DNB Markets

 

Scotiabank		MUFG

 

Wells Fargo Securities		Goldman, Sachs & Co.

 

 

Co-Managers

 

 

Regions Securities LLC		Capital One Securities