UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended September 30, 2013
OR
For the transition period from to
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
200 Peach Street
P.O. Box 7000, El Dorado, Arkansas
(870) 862-6411
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No
Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2013 was 186,982,610.
TABLE OF CONTENTS
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II – Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 6. Exhibits
Signature
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents
Canadian government securities with maturities greater than 90 days at the date of acquisition
Accounts receivable, less allowance for doubtful accounts of $2,051 in 2013 and $6,697 in 2012
Inventories, at lower of cost or market
Crude oil
Finished products
Materials and supplies
Prepaid expenses
Deferred income taxes
Assets held for sale
Total current assets
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,660,920 in 2013 and $8,138,587 in 2012
Goodwill
Deferred charges and other assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Accounts payable and accrued liabilities
Income taxes payable
Liabilities associated with assets held for sale
Total current liabilities
Long-term debt
Asset retirement obligations
Deferred credits and other liabilities
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 194,861,200 shares in 2013 and 194,616,470 shares in 2012
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Treasury stock, 7,878,590 shares of Common Stock in 2013 and 3,975,153 shares of Common Stock in 2012, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 7.
The Exhibit Index is on page 34.
2
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
REVENUES
Sales and other operating revenues
Loss on sale of assets
Interest and other income (expense)
Total revenues
COSTS AND EXPENSES
Crude oil and product purchases
Operating expenses
Exploration expenses, including undeveloped lease amortization
Selling and general expenses
Depreciation, depletion and amortization
Impairment of properties
Accretion of asset retirement obligations
Interest expense
Interest capitalized
Total costs and expenses
Income from continuing operations before income taxes
Income tax expense
Income from continuing operations
Income from discontinued operations, net of taxes
NET INCOME
INCOME PER COMMON SHARE – BASIC
Income from discontinued operations
Net income
INCOME PER COMMON SHARE – DILUTED
Average common shares outstanding
Basic
Diluted
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation
Retirement and postretirement benefit plan amounts reclassified to net income
Deferred loss on interest rate hedges:
Increase in deferred loss associated with contract revaluation and settlement
Amount of loss reclassified to interest expense in consolidated statements of income
COMPREHENSIVE INCOME
4
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
OPERATING ACTIVITIES
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of assets
Amortization of deferred major repair costs
Expenditures for asset retirements
Dry hole costs
Amortization of undeveloped leases
Deferred and noncurrent income tax charges
Pretax loss from disposition of assets
Net (increase) decrease in noncash operating working capital
Other operating activities, net
Net cash provided by continuing operations
Net cash provided by discontinued operations
Net cash provided by operating activities
INVESTING ACTIVITIES
Property additions and dry hole costs2
Proceeds from sales of assets
Purchase of investment securities3
Proceeds from maturity of investment securities3
Expenditures for major repairs
Investing activities of discontinued operations:
Sales proceeds
Other
Other, net
Net cash required by investing activities
FINANCING ACTIVITIES
Borrowings of long-term debt2
Maturities of notes payable
Purchase of treasury stock
Proceeds from exercise of stock options and employee stock purchase plans
Excess tax benefits related to exercise of stock options
Withholding tax on stock-based incentive awards
Issue cost of notes payable and debt facility
Cash dividends paid
Separation of retail business:
Cash distributed to Murphy Oil by Murphy USA
Cash held and retained by Murphy USA upon separation
Net cash provided by financing activities
Effect of exchange rate changes on cash and cash equivalents
Net increase in cash and cash equivalents
Cash and cash equivalents at January 1
Cash and cash equivalents at September 30
Reclassified to conform to current presentation.
Excludes non-cash asset and long-term obligation of $354,818 in 2013 associated with lease commencement for production equipment at the Kakap field offshore Malaysia.
Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.
5
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued
Common Stock – par $1.00, authorized 450,000,000 shares, issued 194,861,200 at September 30, 2013 and 194,452,935 shares at September 30, 2012
Balance at beginning of period
Exercise of stock options
Awarded restricted stock
Balance at end of period
Capital in Excess of Par Value
Exercise of stock options, including income tax benefits
Restricted stock transactions and other
Stock-based compensation
Sale of stock under employee stock purchase plans
Retained Earnings
Net income for the period
Cash dividends
Distribution of common stock of Murphy USA Inc. to shareholders
Accumulated Other Comprehensive Income
Foreign currency translation gains, net of income taxes
Retirement and postretirement benefit plan adjustments, net of income taxes
Change in deferred loss on interest rate hedges, net of income taxes
Treasury Stock
Purchase of treasury shares
Awarded restricted stock, net of forfeitures
Total Stockholders’ Equity
See notes to consolidated financial statements, page 7.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.
Note A – Interim Financial Statements
The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2012. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2013, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2013 and 2012, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, 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 2012 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2013 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 September 30, 2013, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $421.0 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2013 and 2012.
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties based on the determination of proved reserves
Capitalized exploratory well costs charged to expense
Balance at September 30
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.
Aging of capitalized well costs:
Zero to one year
One to two years
Two to three years
Three years or more
Of the $384.6 million of exploratory well costs capitalized more than one year at September 30, 2013, $262.1 million is in Malaysia, $115.9 million is in the U.S. and $6.6 million is in Brunei. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the U.S. drilling and development operations are planned. In Brunei field development plans are being prepared by the operator.
See also Note E for discussion regarding a capital lease of production equipment at the Kakap field.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Inventories
Inventories are carried at the lower of cost or market. The cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. At September 30, 2013 and December 31, 2012, the carrying value of inventories under the LIFO method was $285.9 million and $571.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.
Note D – Discontinued Operations
The Company sold its oil and gas assets in the United Kingdom during 2013. After-tax gains on sale of the assets were $216.2 million in the nine-months ended September 30, 2013. The Company has accounted for these U.K. upstream operations as discontinued operations in its consolidated financial statements for all periods presented.
In addition, the Company completed the spin-off of its U.S. retail marketing business on August 30, 2013. The spin-off was effected through a distribution of all shares of Murphy USA Inc. (MUSA) at a rate of one share of MUSA for every four shares of the Company held. Immediately prior to the spin-off, MUSA paid a cash dividend of $650.0 million to the Company. MUSA is now a separate, publicly owned company. The Company has accounted for these U.S. retail operations as discontinued operations for all periods presented.
The results of operations associated with these discontinued operations for the three-month and nine-month periods ended September 30, 2013 and 2012 were as follows:
Revenues
Income before income taxes, including pretax gain on disposals of $130,568 during the nine-month periods in 2013
In July 2012, the United Kingdom enacted tax changes that limited tax relief on oil and gas decommissioning costs to 50%, a reduction from the 62% tax relief previously allowed for these costs. This tax rate change led to a net increase in tax expense of discontinued operations of $5.5 million in the three-month and nine-month periods of 2012.
The Company has previously announced that its Board of Directors had approved plans to exit the U.K. refining and marketing business. These operations are presented as the U.K. refining and marketing segment in Note P. The sale process for the U.K. downstream assets continues in 2013. Based on current market conditions, it is possible that the Company could incur a loss when the U.K. downstream assets are sold. If the sale of the U.K. downstream assets continues to progress, the results of these operations are likely to be presented as discontinued operations beginning in a future period.
Note E – Financing Arrangements and Debt
In May 2013, the Company increased the capacity of its committed credit facility to $2.0 billion, and it extended the facility for one year such that it now expires in June 2017. Borrowings under the facility continue to bear interest at 1.25% above LIBOR based on the Company’s current credit rating as of September 30, 2013. In addition, facility fees of 0.25% are charged on the full $2.0 billion commitment. 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 2015.
During June 2013, the Company and its partners entered into 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. The original lease asset, which was recorded in Property, Plant and Equipment, and the associated debt obligation, which was recorded in Current Maturities of Long-Term Debt and Long-Term Debt, amounted to $354.8 million.
8
Note F – Cash Flow Disclosures
Additional disclosures regarding cash flow activities are provided below.
Net (increase) decrease in operating working capital other than cash and cash equivalents (from continuing operations):
(Increase) decrease in accounts receivable
Increase in inventories
Increase in prepaid expenses
Decrease in deferred income tax assets
Increase (decrease) in accounts payable and accrued liabilities
Increase in current income tax liabilities
Total
Supplementary disclosures (including discontinued operations):
Cash income taxes paid
Interest paid, net of amounts capitalized
Note G – 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.
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 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 spin-off date.
The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most active and retired U.S. employees. Additionally, most U.S. retired employees are covered by a life insurance benefit plan. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2013 and 2012.
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of transitional asset
Recognized actuarial loss
Special termination benefits
Curtailments
Net periodic benefit expense
9
Note G – Employee and Retiree Benefit Plans (Contd.)
During the nine-month period ended September 30, 2013, the Company made contributions of $41.2 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2013 for the Company’s defined benefit pension and postretirement plans is anticipated to be $7.3 million.
In March 2010, the United States Congress enacted a health care reform law. Along with other provisions, the law (a) eliminates 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 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 eligible U.S. retired employees. The law did not significantly affect the Company’s Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 and the Consolidated Statements of Income for the three-month and nine-month periods ended September 30, 2013 and 2012. The Company continues to evaluate the various components of the law as further guidance is issued and cannot predict with certainty all the ways it may impact the Company. However, based on the 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 or cash flow in future periods.
Note H – 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, 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.
During 2013, the Committee has granted stock options for 1,320,176 shares at exercise prices ranging between $60.015 and $70.725 per share. The Black-Scholes valuation for these awards was between $15.81 and $20.62 per option. The Committee also granted 496,076 performance-based restricted stock units during 2013. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $39.50 to $68.01 per unit. Additionally, on February 5, 2013, the Committee granted 851,000 stock appreciation rights (SAR) and 93,200 units of restricted stock-cash (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 values of these SAR were
10
Note H – Incentive Plans (Contd.)
equivalent to the stock options granted, while the initial value of RSU-C were equivalent to restricted stock units granted. During 2013, the Committee granted 38,184 shares of time-based restricted stock units to the Company’s Directors under the Non-employee Director Plan. These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which ranged between $60.30 and $69.67 per share. During 2013, the Committee also granted 25,000 shares of time-based restricted stock units that vest on January 2, 2014 to a former executive officer. The fair value of this award was estimated based on the fair market value of the Company’s stock on the date of grant, which was $69.67 per share.
Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2013 and 2012 was $2.8 million and $11.1 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $6.3 million and $3.3 million for the nine-month periods ended September 30, 2013 and 2012, respectively.
Amounts recognized in the financial statements with respect to share-based plans are as follows:
Compensation charged against income before tax benefit
Related income tax benefit recognized in income
Note I – Earnings per Share
Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2013 and 2012. The following table reconciles the weighted-average shares outstanding used for these computations.
Basic method
Dilutive stock options and restricted stock units
Diluted method
The following table reflects certain options to purchase shares of common stock that were outstanding during the 2013 and 2012 periods but were not included in the computation of diluted EPS above because the incremental shares from assumed conversion were antidilutive.
Antidilutive stock options excluded from diluted shares
Weighted average price of these options
11
Note J – Income Taxes
The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month and nine-month periods in 2013 and 2012, the Company’s effective income tax rates were as follows:
Three months ended September 30
Nine months ended September 30
The effective tax rates for the periods presented exceeded the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.
The Company recognized a $13.7 million tax benefit during the third quarter 2013 related to a previously recorded U.S. tax liability that was written back into net income due to the passage of time.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of September 30, 2013, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2010; Canada – 2007; United Kingdom – 2011; and Malaysia – 2006.
Note K – Financial Instruments and Risk Management
Murphy periodically utilizes 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. 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 Income. Certain interest rate derivative contracts are accounted for as hedges and the gain or loss associated with recording the fair value of these contracts has been deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.
Commodity Purchase Price Risks
The Company is subject to commodity price risk related to the sales price for crude oil and natural gas it produces worldwide. To manage a portion of this risk, the Company has entered into a series of West Texas Intermediate (WTI) crude oil price swap financial contracts to hedge a portion of its Eagle Ford Shale production from October 2013 through September 2014. Under these contracts, which mature monthly, the Company will pay the average monthly price in effect and will receive the fixed contract prices. WTI open contracts were as follows:
Dates
October – December 2013
January – March 2014
April – June 2014
July – September 2014
In addition, the Company has entered into crude oil swap contracts to hedge about 1,500 barrels per day of Seal heavy oil production during the fourth quarter 2013. The estimated netback price of these contracts is $55.05 per barrel.
12
Note K – Financial Instruments and Risk Management (Contd.)
The impact of marking to market these commodity derivative contracts increased income from continuing operations before taxes by $1.6 million during the nine months ended September 30, 2013.
The Company’s former U.S. retail marketing subsidiary had ethanol production operations that were subject to commodity price risk related to corn that it purchased for feedstock and also had price risk related to wet and dried distillers grain with solubles that it sold. In 2013 and 2012, the former subsidiary had physical delivery commitment contracts for purchases of corn at fixed prices and had physical delivery commitment contracts for sale of wet and dried distillers gain with solubles at fixed prices. To address the risks associated with these fixed price physical delivery contracts, certain of those contracts were hedged with derivative contracts. The effects of these physical delivery and associated derivative contracts increased income from discontinued operations before taxes by $1.6 million in the nine-month period ended September 30, 2013, and reduced income from discontinued operations before taxes by $38.0 million in the nine-month period ended September 30, 2012.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the United States. Short-term derivative instruments were outstanding at September 30, 2013 and 2012 to manage the risk of certain future income taxes that are payable in Malaysian ringgits. The equivalent U.S. dollar values of Malaysian ringgit derivative contracts open at September 30, 2013 and 2012 were approximately $76.0 million and $97.6 million, respectively. Short-term derivative instrument contracts totaling $28.0 million U.S. dollars were also outstanding at September 30, 2013 to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. The impact from marking to market these foreign currency derivative contracts reduced income from continuing operations before taxes by $4.1 million for the nine-month period ended September 30, 2013 and increased income from continuing operations before taxes by $3.1 million for the nine-month period ended September 30, 2012.
At September 30, 2013 and December 31, 2012, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
September 30, 2013
Asset (Liability) Derivatives
Type of Derivative Contract
Balance Sheet Location
Commodity
Foreign exchange
For the three-month and nine-month periods ended September 30, 2013 and 2012, the gains and losses recognized in the Consolidated Statements of Income for derivative instruments not designated as hedging instruments are presented in the following table.
Location
Interest Rate Risks
The Company had ten-year notes totaling $350 million that matured on May 1, 2012. The Company expected to replace these notes at maturity with new ten-year notes, and it therefore had risk associated with the interest rate related to the anticipated sale of these notes in 2012. To manage this risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that matured in May 2012. The Company utilized hedge accounting to defer any gain or loss on these contracts associated with the payment of interest on these anticipated notes in 2012 through 2022. During the nine-month periods ended September 30, 2013 and 2012, $2.3 million and $1.1 million, respectively, of the deferred loss on the interest rate swaps were charged to income. The remaining loss deferred on these matured contracts at September 30, 2013 was $25.6 million, which is recorded, net of income taxes of $9.0 million, in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet.
13
The Company expects to charge approximately $0.7 million of this deferred loss to income in the form of interest expense during the remaining three months of 2013.
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2013 and December 31, 2012 are presented in the following table.
Assets
Commodity derivative contracts
Liabilities
Nonqualified employee savings plans
Foreign currency exchange derivative contracts
The fair value of West Texas Intermediate (WTI) crude oil contracts was based on active market quotes for WTI crude oil. The fair value of Canadian crude oil contracts was based on active market quotes for Western Canadian Sour crude oil. The fair value of commodity derivative contracts for corn and wet and dried distillers grain was determined based on market quotes for No. 2 yellow corn. The fair value of foreign exchange derivative contracts 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 Income and the effect 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. No offsetting of assets and liabilities on derivative contracts occurred at September 30, 2013. Derivative assets and liabilities which have offsetting positions at December 31, 2012 are presented in the following tables.
At December 31, 2012
Commodity derivatives
14
All commodity derivatives above with offsetting positions were corn-based contracts associated with the Company’s former U.S. ethanol plants. Net derivative assets in the table above are included in Accounts Receivable presented in the table on page 13 and on the Consolidated Balance Sheet; likewise, net derivative liabilities in the above table are included in Accounts Payable in the table on page 13 and are included in Accounts Payable and Accrued Liabilities on the Consolidated Balance Sheet. Separate derivative agreements existed for each of the ethanol plants. These contracts permitted net settlement and the Company generally availed itself of this right to settle net.
Note L – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at September 30, 2013 and the changes during the three month periods ended September 30, 2013 are presented net of taxes in the following table.
Balance at January 1, 2013
Components of other comprehensive income (loss):
Before reclassifications to income
Reclassifications to income
Net other comprehensive income (loss)
Balance at September 30, 2013
All amounts are presented net of income taxes.
Reclassifications before taxes of $15,610 for the nine-month period ended September 30, 2013 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $6,823 for the nine-month period ended September 30, 2013 are included in Income tax expense.
Reclassifications before taxes of $2,223 for the nine-month period ended September 30, 2013 are included in Interest expense. Related income taxes of $770 for the nine-month period ended September 30, 2013 are included in Income tax expense.
Note M – 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
15
Note M – Environmental and Other Contingencie (Contd.)
governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released at properties owned or leased by the Company or at 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. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, the Company is investigating the extent of any such liability and the availability of applicable defenses. With the sale of the U.S. refineries in 2011, the Company retained certain liabilities related to environmental matters at these sites. The Company also has insurance covering certain levels of environmental expenses at the refinery sites. The Company believes costs related to these current or former operating sites will not have a material adverse effect on its net income, financial condition or liquidity in a future period. With the spin-off of Murphy’s U.S. retail marketing business in 2013, the newly formed public company, Murphy USA Inc., has retained any environmental exposure associated with U.S. marketing operations.
The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The potential total cost to all parties to perform necessary remedial work at the Superfund site may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at the Superfund site. The Company has not recorded a liability for remedial costs on the Superfund site. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at this site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up 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.
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.
In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At September 30, 2013, the Company had contingent liabilities of $22.8 million on outstanding letters of credit. The Company has not accrued a liability in its Consolidated Balance Sheets related to these letters of credit because it is believed that the likelihood of having these drawn is remote.
16
Note N – Accounting Matters
In December 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that requires enhanced disclosures about financial instruments and derivative instruments that are either offset in the balance sheet or are subject to an enforceable master netting arrangement or similar agreement. The guidance was effective for all interim and annual periods beginning on or after January 1, 2013. These disclosures are presented in Note K.
In February 2013, the FASB issued an accounting standards update that requires additional disclosures for reclassification adjustments from accumulated other comprehensive income (AOCI). These additional disclosures include changes in AOCI balances by component and significant items reclassified out of AOCI. These disclosures must be presented either on the face of the affected financial statement or in the notes to the financial statements. The disclosures are effective for Murphy Oil beginning in the first quarter of 2013 and are to be provided on a prospective basis. These disclosures are presented in Note L.
Note O – Commitments
The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2013 heavy oil and 2013 and 2014 natural gas sales volumes in Western Canada. The heavy oil sales contracts call for deliveries of approximately 2,900 barrels per day during the fourth quarter 2013 that achieve netback values averaging Cdn$50.89 per barrel The natural gas contracts call for deliveries from October through December 2013 that average approximately 77 million cubic feet per day at a price of Cdn$3.76. Additionally for 2014, open gas contracts call for deliveries of 50 million cubic feet per day at an average price of Cdn$4.01 per MCF. The 2013 and 2014 natural gas contracts call for delivery at the NOVA inventory transfer sales point. These oil and natural gas contracts have been accounted for as normal sales for accounting purposes.
17
Note P – Business Segments
(Millions of dollars)
Exploration and production2
United States
Canada
Malaysia
Republic of the Congo
Refining and marketing – U.K.
Total operating segments
Corporate
Assets/revenue/income from continuing operations
Discontinued operations, net of tax
Revenue/income from continuing operations
Additional details about results of oil and gas operations are presented in the tables on pages 24 and 25.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Murphy’s net income in the third quarter of 2013 was $284.8 million ($1.51 per diluted share) compared to net income of $226.7 million ($1.16 per diluted share) in the third quarter of 2012. The income improvement in 2013 was primarily driven by higher crude oil sales volumes from the Eagle Ford Shale area of South Texas. Additional favorable variances in the 2013 quarter included higher average realized oil and natural gas prices, income tax benefits in the U.S., foreign currency exchange profits in Malaysia and the U.K., and better retail marketing and ethanol margins in the now separated U.S. retail marketing business. These factors were partially offset by lower natural gas sales volumes, higher expenses for exploration and oil and gas extraction, unfavorable results for U.K. refining and marketing operations, and higher expenses for financing and administration. The Company completed the separation of its U.S. retail marketing business on August 30, 2013 and has reported the results of these operations as discontinued operations for all periods presented. The 2013 quarterly net income included income from discontinued operations of $32.7 million ($0.17 per diluted share) compared to income of $15.0 million ($0.08 per diluted share) in the 2012 quarter. Income from continuing operations was $252.1 million ($1.34 per diluted share) in 2013 and $211.7 million ($1.08 per diluted share) in the comparable 2012 quarter.
For the first nine months of 2013, net income totaled $1,048.0 million ($5.51 per diluted share) compared to net income of $812.2 million ($4.17 per diluted share) for the same period in 2012. The improvement in net income in 2013 compared to 2012 was attributable to several factors, including higher crude oil sales volumes, favorable results from transactions in foreign currencies, higher income from discontinued operations, which was attributable to both a gain on sale of all U.K. oil and gas assets and higher profits from U.S. downstream discontinued operations. These were somewhat offset by lower crude oil sales prices in 2013 and higher expenses associated with oil and gas extraction, exploration, financing and administration. Income from continuing operations in the 2013 and 2012 nine months was $684.9 million ($3.60 per diluted share) and $718.3 million ($3.69 per diluted share), respectively. Income from discontinued operations totaled $363.1 million ($1.91 per diluted share) in the nine-month period of 2013, compared to income of $93.9 million ($0.48 per diluted share) in 2012. Discontinued operations in 2013 included a $216.2 million after-tax gain on sale of U.K. oil and gas assets.
Murphy’s income from continuing operations by operating business is presented below.
Exploration and production
In the 2013 third quarter, the Company’s exploration and production continuing operations earned $264.2 million compared to $221.1 million in the 2012 quarter. Income in the 2013 quarter was favorably impacted compared to 2012 by higher crude oil sales volumes and higher oil and natural gas sales realizations. These factors were somewhat offset by a reduction in natural gas sales volumes, and higher exploration and oil and gas extraction expenses in 2013. Exploration expenses were $147.8 million in the third quarter of 2013 compared to $94.0 million in the same period of 2012. The Company’s U.K. refining and marketing results from continuing operations were a loss of $12.9 million in the 2013 third quarter compared to a profit of $25.5 million in the same quarter of 2012. U.K. refining margins were significantly weaker in the 2013 quarter compared to the prior year. The corporate function had an after-tax benefit of $0.8 million in the 2013 third quarter compared to after-tax costs of $34.9 million in the 2012 period with the favorable variance in 2013 mostly due to gains on transactions denominated in foreign currencies in 2013 compared to losses on such transactions in the 2012 quarter. The 2013 corporate results included costs related to the spin-off of the U.S. retail marketing operations that was completed on August 30, 2013 as well as higher costs for employee compensation and financing.
In the first nine months of 2013, the Company’s exploration and production continuing operations earned $786.3 million compared to $760.0 million in the same period of 2012. Upstream earnings in 2013 were ahead of 2012 primarily due to higher crude oil sales volumes. The benefit of higher crude oil sales volumes was partially offset by lower realized crude oil sales prices, higher oil extraction expense, and higher costs associated with the Company’s exploration program. Exploration expenses increased from $243.7 million in the first nine months of 2012 to $345.1 million in the 2013 period, as the current year included unsuccessful wildcat drilling costs for wells offshore
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Cameroon and Australia and in Western Canada. The Company’s U.K. refining and marketing continuing operations had losses of $22.7 million in the first nine months of 2013 compared to earnings of $35.7 million in the same 2012 period. The 2013 period experienced significantly weaker margins for U.K. refining operations compared to 2012. Corporate after-tax costs were $78.7 million in the 2013 period compared to after-tax costs of $77.4 million in the 2012 period. The current period included favorable impacts from transactions denominated in foreign currencies, while the prior year included losses from these transactions. These foreign exchange benefits in 2013 were essentially offset by higher administrative and borrowing costs.
Exploration and Production
Results of exploration and production continuing operations are presented by geographic segment below.
Exploration and production – continuing operations
Other International
Third quarter 2013 vs. 2012
United States exploration and production operations had earnings of $151.3 million in the third quarter of 2013 compared to earnings of $33.5 million in the 2012 quarter. Results were improved in the 2013 period due to a combination of higher oil and natural gas production, higher natural gas sales prices and lower exploration expenses. Higher expenses for hydrocarbon extraction and administration somewhat offset these favorable impacts. Crude oil sales volumes were higher in 2013 due to an active development drilling program at the Eagle Ford Shale operations in South Texas. At September 30, 2013, the Company had eight rigs actively drilling in this play. Production and depreciation expenses increased $7.4 million and $73.7 million, respectively, in 2013 compared to 2012 mostly due to higher production in the Eagle Ford Shale area. Exploration expenses in the 2013 quarter were $8.6 million less primarily due to lower leasehold amortization for acreage in the Eagle Ford Shale area in the current year.
Operations in Canada had earnings of $77.3 million in the third quarter 2013 compared to earnings of $29.3 million in the 2012 quarter. Canadian earnings were improved in 2013 mostly due to higher oil sales volumes and higher realized prices for oil and natural gas volumes sold. Oil sales volumes increased in the 2013 period compared to 2012 primarily due to higher production at the Terra Nova field, offshore Newfoundland. This field was shut-in for maintenance during a portion of the prior year’s quarter. Heavy oil production in the Seal area of Western Canada was also up in 2013 due to volumes produced at acreage acquired near year-end 2012. Canadian synthetic oil production was lower in the current year due to downtime for maintenance at Syncrude. Natural gas sales volumes decreased in 2013 primarily in the Tupper area of Western Canada due to normal well decline following a period of voluntary deferral of development drilling activities caused by generally weak sales prices for North American natural gas. Production expenses in 2013 for conventional operations was virtually flat with 2012 levels despite significantly higher production volumes because the prior period included maintenance costs for the Terra Nova field while it was down for turnaround. Depreciation expense for conventional operations in Canada was unfavorable by $15.3 million in 2013 due primarily to higher crude oil volumes sold in the current quarter.
Operations in Malaysia reported earnings of $183.8 million in the 2013 quarter compared to earnings of $215.7 million during the same period in 2012. Earnings in 2013 were below 2012 levels in Malaysia primarily due to lower oil sales volumes and lower sales prices for oil and natural gas. Lower oil sales volumes in 2013 were caused by the timing of large cargo sales in the current year. Natural gas sales volumes from offshore Sarawak fields increased due to more customer demand in the current year, but gas sales volumes at the Kikeh field were significantly lower due to more downtime at the third party onshore receiving facility. Natural gas realized prices for Sarawak production was unfavorably affected in 2013 by contractually required revenue sharing with the local government. Exploration expense in 2013 was less than in 2012 by $26.2 million primarily due to dry hole costs in the prior year that did not repeat.
20
Exploration and Production (Contd.)
Third quarter 2013 vs. 2012 (Contd.)
Operations in Republic of the Congo incurred a loss of $10.8 million in the third quarter of 2013 compared to a loss of $4.7 million in the 2012 quarter. The 2013 quarter had a larger loss due to higher expenses for production operations and late costs for an exploratory well drilled in a prior period.
Other international operations reported a loss of $137.4 million in the third quarter of 2013 compared to a loss of $52.7 million in the 2012 period. The larger loss in the current quarter was primarily attributable to higher exploration expenses compared to the prior year. The 2013 expenses included unsuccessful exploratory drilling costs in Cameroon, seismic acquisition costs covering prospective areas in Southeast Asia, and higher overall office costs in the various exploration areas in which the Company operates.
On a worldwide basis, the Company’s crude oil, condensate and gas liquids sales prices averaged $96.80 per barrel in the third quarter 2013 compared to $96.09 in the 2012 period. Total hydrocarbon production averaged 207,281 barrels of oil equivalent per day in the 2013 third quarter, up 14% from the 181,558 barrels equivalent per day produced in the 2012 quarter. Average crude oil and liquids production was 138,075 barrels per day in the third quarter of 2013 compared to 105,796 barrels per day in the third quarter of 2012, with the more than 30% increase primarily attributable to higher oil production in the Eagle Ford Shale area of South Texas driven by an increase in the number of producing wells. Canadian offshore crude oil production at Terra Nova was higher in 2013 due to wells being shut-in for equipment maintenance during the prior year. Canadian heavy oil volumes were higher in 2013 mostly attributable to volumes associated with property acquired in the Seal area near year-end 2012. Synthetic crude oil production was lower in 2013 due to more downtime for maintenance in the current quarter at Syncrude. Oil production increased in Malaysia during the 2013 quarter primarily due to start up of new Sarawak oil fields in 2013 and a higher Company entitlement percentage for production at the West Patricia field, offshore Sarawak. Oil production in the Republic of Congo was lower in 2013 primarily due to well decline at the Azurite field. The Company sold all its oil and gas properties in the United Kingdom in early 2013. North American natural gas sales prices averaged $3.00 per thousand cubic feet (MCF) in the 2013 quarter compared to $2.61 per MCF in the same quarter of 2012. Natural gas produced in 2013 at fields offshore Sarawak was sold at $6.69 per MCF, compared to a sale price of $7.59 per MCF in the 2012 quarter. This Sarawak price reduction in the current year was caused by contractually required revenue sharing with the local government. Natural gas sales volumes averaged 415 million cubic feet per day in the third quarter 2013, down 9% from 454 million cubic feet per day in the 2012 quarter. The reduction in natural gas sales volumes in 2013 was primarily at the Tupper area in British Columbia caused by normal well decline following a period of voluntary deferral of development drilling operations due to weak natural gas sales prices in North America. Natural gas production at fields offshore Sarawak, Malaysia, was higher in 2013 compared to the prior quarter mainly due to stronger demand in the current quarter. Natural gas sales volumes were lower in 2013 at the Kikeh field due to reduced customer demand caused by downtime for maintenance at a third party onshore receiving facility during the current quarter.
Nine months 2013 vs. 2012
U.S. exploration and production operations had income of $368.0 million for the nine months ended September 30, 2013 compared to income of $83.1 million in the 2012 period. The 2013 period benefited from higher crude oil sales volumes, higher natural gas sales prices and lower exploration expense compared to the prior year. Crude oil production volumes increased in 2013 primarily due to new wells added in the Eagle Ford Shale area. Production and depreciation expenses were higher by $77.4 million and $213.5 million, respectively, in 2013 compared to 2012 primarily due to additional oil volumes produced in the Eagle Ford Shale area. Exploration expense in the 2013 period was $57.8 million less than in 2012 primarily due to unsuccessful exploration drilling expense in the Gulf of Mexico in 2012 coupled with lower undeveloped lease amortization expense in the Eagle Ford Shale area in the later year. The Company expended more funds in 2013 to acquire geophysical data covering prospective areas in the Gulf of Mexico. Selling and general expenses rose by $20.0 million in 2013 compared to 2012 essentially due to higher costs for employee compensation and other professional services.
Canadian operations had income of $142.3 million in the first nine months of 2013 compared to income of $146.3 million a year ago. The benefits of higher crude oil sales volumes and higher natural gas sales prices in the current year were more than offset by higher dry hole expense and a property value impairment charge. Production and depreciation expenses for conventional operations increased $10.5 million and $28.6 million, respectively, in 2013 mostly related to higher production volumes at the Seal heavy oil area. Exploration expenses increased by
21
Nine months 2013 vs. 2012 (Contd.)
$23.6 million in 2013 primarily due to dry hole costs in the Rainbow area of Northern Alberta. Impairment expense of $21.6 million in the current year related to a writedown of wells performing below expectations in the Kainai area of Southern Alberta.
Malaysia operations earned $602.5 million in the first nine months of 2013 compared to earnings of $662.9 million in the 2012 period. Results were in 2013 below 2012 primarily due to lower sales prices for crude oil and natural gas sales volumes. Production expense declined $57.8 million in 2013 compared to 2012 due to lower well workover costs at the Kikeh field in the current period. Depreciation expense in 2013 was $46.0 million more than the 2012 period due to higher crude oil sales volumes in the current year. Exploration expense was $24.1 million lower in 2013 mostly due to dry hole costs in 2012.
Operations in Republic of the Congo had a loss of $37.3 million for the nine-month 2013 period, compared to a loss of $8.4 million in the 2012 period. The unfavorable variance in 2013 was primarily attributable to higher operating costs for the Azurite field. Depreciation expense was down $33.7 million in 2013 due to a write-off of property values at the Azurite field at year-end 2012.
Other international operations reported a loss of $289.2 million in the first nine months of 2013 compared to a loss of $123.9 million in the 2012 period. The larger 2013 loss primarily related to higher dry hole costs of $90.7 million, mostly associated with unsuccessful offshore wildcat drilling that occurred offshore in Cameroon and Australia. Dry hole costs in 2012 were principally associated with an unsuccessful well in the Kurdistan region of Iraq. Higher geophysical expense of $60.1 million in 2013 was primarily related to current-year costs for 3D seismic acquired on prospects in Southeast Asia. Other exploration expenses increased $14.5 million in 2013 due to higher costs for various exploration field offices. Lower undeveloped leasehold amortization of $10.8 million in 2013 compared to 2012 was attributable to higher costs for exploration licenses in the Kurdistan region of Iraq in the prior year. Selling and general expenses were $8.5 million higher in 2013 primarily due to additional office costs supporting international exploration activities.
For the first nine months of 2013, the Company’s sales price for crude oil, condensate and gas liquids averaged $94.69 per barrel, down from $97.13 per barrel in 2012. Total worldwide production averaged 205,539 barrels of oil equivalent per day during the nine months ended September 30, 2013, an increase of 9% from 188,385 barrels of oil equivalent produced in the same period in 2012. Crude oil, condensate and gas liquids production in the first nine months of 2013 averaged 133,534 barrels per day compared to 105,766 barrels per day a year ago. The 26% increase in oil production was mostly attributable to higher volumes in the Eagle Ford Shale area where active development drilling operations are ongoing. Oil production in Western Canada increased in 2013 primarily due to a property acquisition at Seal near year-end 2012. Crude oil production offshore eastern Canada was higher in 2013 due to shut-in of the Terra Nova field for several months in 2012 to conduct maintenance on the production facility. Synthetic oil production levels declined in 2013 due to downtime for maintenance at Syncrude. Crude oil production volume in Republic of the Congo decreased in 2013 primarily due to well decline. The Company sold all of its U.K. oil and gas properties in early 2013. The average sales price for North American natural gas in the first nine months of 2013 was $3.23 per MCF, up from $2.43 per MCF realized in 2012. Natural gas production at fields offshore Sarawak was sold at an average price of $6.90 per MCF in 2013 compared to $7.79 per MCF in 2012, with the reduction mostly caused by contractual revenue sharing with the local government during the current year. Natural gas sales volumes decreased from 496 million cubic feet per day in 2012 to 432 million cubic feet per day in 2013, with the 13% decline mostly due to lower gas production volumes at the Tupper area, where wells have experienced normal decline following a period of voluntary deferral of development drilling operations due to low North American natural gas sales prices. Lower natural gas sales volume in Malaysia during 2013 was principally caused by reduced gas demand from the customer attributable primarily to more downtime for maintenance at the onshore receiving facility.
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Selected operating statistics for the three-month and nine-month periods ended September 30, 2013 and 2012 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Continuing operations
Canada – light
– heavy
– offshore
– synthetic
Discontinued operations – United Kingdom
Net crude oil, condensate and gas liquids sold – barrels per day
Net natural gas sold – thousands of cubic feet per day
Malaysia – Sarawak
– Kikeh
Total net hydrocarbons produced – equivalent barrels per day (1)
Total net hydrocarbons sold – equivalent barrels per day (1)
Weighted average sales prices –
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
Canada (3) – light
Malaysia (4)
Republic of the Congo (4)
United Kingdom – discontinued operations
Natural gas – dollars per thousand cubic feet
United States (2)
Canada (3)
Malaysia – Sarawak (4)
United Kingdom (3) – discontinued operations
23
OIL AND GAS OPERATING RESULTS — THREE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012
Three Months Ended September 30, 2013
Oil and gas sales and other revenues
Production expenses
Exploration expenses
Dry holes
Geological and geophysical
Undeveloped lease amortization
Total exploration expenses
Results of operations before taxes
Income tax provisions (benefits)
Results of operations (excluding corporate overhead and interest)
Three Months Ended September 30, 2012
24
OIL AND GAS OPERATING RESULTS — NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012
Nine Months Ended September 30, 2013
Nine Months Ended September 30, 2012
Income tax provisions
Refining and Marketing
Third Quarter 2013 vs. 2012
On August 30, 2013, the Company completed the separation of the U.S. retail marketing business. The new independent company, Murphy USA Inc., trades on the New York Stock Exchange under the ticker symbol “MUSA”. The Company now reports the results of the U.S. retail marketing business as discontinued operations for all periods presented. The Company has also announced its intention to sell its U.K. refining and marketing operations. The sale process for the U.K. downstream operations continues. See Note D in the consolidated financial statements for further discussion. The United Kingdom refining and marketing segment includes the Milford Haven, Wales, refinery and U.K. retail and other refined products marketing operations.
25
Refining and Marketing (Contd.)
Refining and marketing operations in the United Kingdom reported a loss of $12.9 million in the third quarter of 2013 compared to a net profit of $25.5 million in the same quarter of 2012. The U.K. results in 2013 were unfavorably affected by significantly weaker refining margins at the Milford Haven refinery in the current period. Margins for U.K. marketing operations were stronger during 2013 compared to the prior year. The overall combined unit margin in the U.K. was a loss of $0.66 per barrel in the 2013 quarter, compared to a positive $3.44 per barrel in the 2012 quarter. Crude oil throughput volumes at Milford Haven were 126,761 barrels per day during the 2013 quarter, down from throughputs of 129,948 barrels per day in the 2012 quarter; this throughput decline was attributable to the poor unit margins in the current quarter that led the Company to marginally reduce crude inputs. Petroleum product sales in the U.K. were 137,526 barrels per day in the 2013 quarter, slightly above the 137,189 barrels per day a year ago.
Refining and marketing operations in the United Kingdom incurred a net loss of $22.7 million in the 2013 nine months compared to a profit of $35.7 million in the same 2012 period. The U.K. results in 2013 were principally hurt by much weaker refining margins, but this was somewhat offset by stronger marketing margins compared to a year ago. In 2013, the overall combined unit margin per barrel sold was negative $0.34, well below the positive $1.85 per barrel margin during the 2012 nine months. Crude oil throughput volumes at the Milford Haven refinery were 123,218 barrels per day in 2013, down from 129,006 barrels per day in 2012. The decline in crude oil throughput in 2013 was primarily caused by equipment reliability issues that somewhat restricted inputs early in the year. U.K. petroleum product sales were 131,177 barrels per day in the 2013 period, down from 135,638 barrels per day a year ago.
United Kingdom refining and marketing – unit margins per barrel
Petroleum and other products sold in U.K. – barrels per day
Gasoline
Kerosine
Diesel and home heating oils
Residuals
LPG and other
U.K. refinery inputs – barrels per day
Milford Haven, Wales – crude oil
– other feedstocks
U.K. refinery yields – barrels per day
Fuel and loss
26
Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had a net benefit of $0.8 million in the 2013 third quarter compared to net costs of $34.9 million in the 2012 third quarter. The 2013 results of corporate activities were improved compared to the prior year primarily due to net after-tax benefits of $45.8 million on transactions denominated in foreign currencies in the current quarter compared to net after-tax charges of $12.6 million in the comparable 2012 period. The current period foreign currency benefit was about evenly split between the U.K. and Malaysia. The British pound strengthened against the U.S. dollar during the 2013 quarter leading to a benefit on U.S. dollar denominated liabilities in the U.K. downstream business. A weakening of the Malaysian ringgit against the U.S. dollar led to lower costs in U.S. dollar terms for income tax liabilities that are to be paid in the local currency. A stronger Malaysian ringgit during the third quarter 2012 led to foreign exchange losses associated with higher income tax liabilities in U.S. dollar terms. The foreign currency benefits in 2013 were partially offset by higher costs for administration and debt financing. The higher administrative costs were driven by higher employee compensation costs and separation costs related to Murphy USA Inc. Higher net interest expense in 2013 was attributable to higher average borrowing levels during the current quarter.
For the first nine months of 2013, corporate activities reflected net costs of $78.7 million compared to net costs of $77.4 million a year ago. In 2013, favorable results from transactions denominated in foreign currencies were offset by higher costs for administration and debt financing. Total after-tax benefits associated with foreign currency transactions were $57.8 million in the 2013 nine months compared to after-tax costs of $3.5 million in the same 2012 period. Net interest expense in 2013 was $40.4 million more than 2012 primarily due to higher average outstanding debt levels in the current year. Administrative expense was higher in 2013, primarily associated with increased employee compensation costs and expenses related to separation of the U.S. retail marketing business in the current year.
Discontinued Operations
On August 30, 2013, the Company completed the separation of its former U.S. retail marketing business into a stand-alone, publicly traded company named Murphy USA Inc. Additionally, in early 2013, the Company sold all of its U.K. exploration and production assets. The Company has accounted for the results of the U.S. retail marketing business and the U.K. oil and gas business as discontinued operations in all periods presented. See Note D of the consolidated financial statements for further information.
Discontinued operations had a profit of $32.7 million in the third quarter of 2013 compared to a profit of $15.0 million in the third quarter of 2012. The results in the 2013 third quarter were above 2012 primarily due to stronger margins for both U.S. retail marketing and ethanol production operations during the current year.
For the first nine months of 2013 and 2012 income from discontinued operations was $363.1 million and $93.9 million, respectively. The 2013 period included a $216.2 million gain on sale of the U.K. oil and gas assets. Additionally, the current year included stronger U.S. ethanol production margins and higher sales prices for Renewable Identification Numbers (RIN). The U.K. enacted a tax rate change in the third quarter of 2012. Consequently, each of the three-month and nine-month periods in 2012 included a tax charge of $5.5 million associated with the tax rate change.
27
Financial Condition
Net cash provided by operating activities was $2,678.5 million for the first nine months of 2013 compared to $2,101.2 million during the same period in 2012. Cash provided by operating activities of discontinued operations amounted to $200.1 million and 214.7 million, respectively, in the 2013 and 2012 periods. Changes in operating working capital other than cash and cash equivalents provided cash of $224.0 million in the first nine months of 2013 compared to a use of cash of $252.1 million in the first nine months of 2012. Cash provided by working capital changes in 2013 was primarily generated by an increase in accounts payable during the current year. Cash used for working capital in 2012 was primarily invested in petroleum and other inventories as well as for prepaid insurance and prepaid taxes in the U.S. and Canada. Cash of $496.4 million in the 2013 period and $1,401.2 million in 2012 was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The sale of all U.K. oil and gas properties generated cash proceeds, reflected as discontinued operations, of $282.2 million during 2013. Prior to the spin-off of Murphy USA Inc. (MUSA), this former subsidiary borrowed $650.0 million primarily through the debt market. On the separation date of August 30, 2013, MUSA paid a $650.0 million cash dividend to Murphy Oil Corporation, which primarily used this dividend to repay a portion of its outstanding debt.
Significant uses of cash in both years were for dividends, which totaled $177.8 million in 2013 and $167.5 million in 2012, and for property additions and dry holes from continuing operations, which including amounts expensed, were $2,719.9 million and $2,156.6 million in the nine-month periods ended September 30, 2013 and 2012, respectively. Cash used for property additions related to discontinued operations totaled $128.9 million and $111.9 million, respectively, in 2013 and 2012. The Company paid quarterly per-share dividends on outstanding common shares of $0.3125 during each of the first three quarters of 2013. During the first two quarters of 2012, the Company’s cash dividend was $0.275 per common share; the quarterly cash dividend was increased to the current $0.3125 per share beginning in the third quarter 2012. At the spin-off date, MUSA retained a cash balance of $55.5 million, which has been reflected as a reduction of Murphy Oil’s cash in the Consolidated Statement of Cash Flows during 2013. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $670.6 million in the 2013 period and $1,360.7 million in the 2012 period.
Total accrual basis capital expenditures were as follows:
Capital Expenditures
Exploration and production, including discontinued operations
Refining and marketing, including discontinued operations
Corporate and other
Total capital expenditures, including discontinued operations
The increase in capital expenditures in the exploration and production business in 2013 was mostly attributable to more drilling and development activities in the Eagle Ford Shale area in South Texas. The increase in refining and marketing capital expenditures in 2013 was principally related to land acquired for future retail station development by the now independent Murphy USA Inc.
A reconciliation of property additions and dry hole costs in the consolidated statements of cash flows to total capital expenditures follows.
Property additions and dry hole costs per cash flow statements, including discontinued operations
Geophysical and other exploration expenses
Capital expenditure accrual changes, including discontinued operations
Working capital (total current assets less total current liabilities) at September 30, 2013 was $586.6 million, a decline of $112.9 million from December 31, 2012. This level of working capital does not fully reflect the Company’s liquidity position because the lower historical costs assigned to U.K. refining inventories under last-in first-out accounting were $285.9 million below fair value at September 30, 2013.
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Financial Condition (Contd.)
At September 30, 2013, long-term debt of $2,583.2 million had increased by $338.0 million compared to December 31, 2012. The increase during 2013 was essentially all related to a $338.8 million long-term capital lease obligation for production equipment placed in service at the Kakap field, offshore Malaysia. Excluding this capital lease, long-term debt would equal 20.1% of capital employed at September 30, 2013. A summary of capital employed at September 30, 2013 and December 31, 2012 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 10.5 to 1 for the nine-month period ended September 30, 2013.
Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2013, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $365 million in Canada, $577 million in Malaysia and $334 million in the United Kingdom. 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 exist 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.
Accounting and Other Matters
In December 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that requires enhanced disclosures about financial instruments and derivative instruments that are either offset in the balance sheet or are subject to an enforceable master netting arrangement or similar agreement. The guidance was effective for all interim and annual periods beginning on or after January 1, 2013. These disclosures are presented in Note K to the consolidated financial statements.
In February 2013, the FASB issued an accounting standards update that requires additional disclosures for reclassification adjustments from accumulated other comprehensive income (AOCI). These additional disclosures include changes in AOCI balances by component and significant items reclassified out of AOCI. These disclosures must be presented either on the face of the affected financial statement or in the notes to the financial statements. The disclosures are effective for Murphy Oil beginning in the first quarter of 2013 and are to be provided on a prospective basis. These disclosures are presented in Note L to the consolidated financial statements.
The United States Congress passed the Dodd-Frank Act (the Act) in 2010. As mandated by the Act, the U.S. Securities and Exchange Commission (SEC) issued rules regarding annual disclosures for purchases of “conflict minerals” and payments made to the U.S. Federal and all foreign governments by extractive industries, including oil and gas companies. “Conflict minerals”’ are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or adjoining countries. For companies to whom the rule applies, the first annual report for conflict minerals must be filed by May 31, 2014 for the calendar year of 2013. Based on the Company’s assessment to date, it believes that the rule does not currently apply to it and, therefore, it is not required to file an annual “conflict minerals” report.
On July 2, 2013, the United States District Court for the District of Columbia vacated the SEC’s rules regarding reporting of payments made to the U.S. Federal and foreign governments. The D.C. Court found that the SEC misread the Act to mandate public disclosure of reports and that the denial of exemptions in the case of countries that prohibit public disclosures was improper. The Court remanded the matter to the SEC, which has indicated that it will restart the rulemaking process. The Company cannot predict how the SEC will alter its rules based on the Court’s findings.
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Outlook
Average crude oil prices in October 2013 declined slightly from the average prices during the third quarter of 2013. The Company expects its oil and natural gas production to average 199,000 barrels of oil equivalent per day in the fourth quarter 2013. U.K. downstream margins remain weak early in the fourth quarter 2013. Foreign currency exchange rates remain quite volatile. In October 2013, the U.S. dollar softened against the Malaysian ringgit which, if this continues through year-end 2013, would be expected to lead to foreign exchange losses in the fourth quarter 2013.
The Company currently anticipates total capital expenditures for the full year 2013 to be approximately $4.2 billion. The Company will primarily fund its capital program using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s projections call for borrowings of long-term debt during the remainder of 2013 and in 2014 to fund a portion of the capital program. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required to maintain funding of the Company’s ongoing development projects. Additionally, the Company has $500 million of further share repurchases available under the previously announced share buyback program of up to $1.0 billion. Through September 30, 2013, the Company had repurchased 8,044,378 shares at a cost of $500 million under the repurchase program. The level of any additional share repurchases could also influence the amount of long-term debt outstanding under credit facilities during 2013 and 2014.
The Company has announced that it plans to sell the U.K. refining and marketing business. The sale process for this U.K. business continues to progress in 2013. Should the Company be unable to sell its U.K. refining and marketing assets on acceptable terms, this could require additional borrowings under credit facilities in future periods. Additionally, depending on the net proceeds received, a sale of these operations could lead to a loss in the Consolidated Statement of Income in a future period.
Following the separation of the U.S. retail marketing business from Murphy Oil Corporation in August 2013, and after the desired sale of the U.K. downstream business, the Company will have significantly lower sales revenue as the U.S. and U.K. businesses generated a significant portion of Murphy’s consolidated revenue. The Company also anticipates that without these operations, it will no longer qualify as a member of the Fortune 500 group of companies. Murphy Oil is anticipated to be an independent oil and gas company in the future and will not have a significant refining and marketing business as a diversification to its oil and gas business. This significant decrease in revenue and change in diversification could impact the Company’s credit rating, and could, although not expected to, impact its ability to repay long-term debt obligations when due. The future sale of the U.K. downstream business is expected to lead to reclassifications of the results of this business as discontinued operations in the Company’s consolidated financial statements in a future period.
As noted above, crude oil sales prices have declined in October 2013. Should future oil or natural gas prices weaken significantly below the average prices in the third quarter 2013, it is possible that certain investments in oil and gas properties could become impaired in a future period.
Production at the Company’s Azurite oil field in Republic of the Congo is expected to end in the near future. It is possible that the Company could incur further costs, some of which may be material, upon the winding down of this field’s operations.
Forward-Looking Statements
This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, customer demand for our products, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards. Factors that could cause the forecasted sale of its U.K. refining and marketing business, as discussed in this Form 10-Q, not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a failure to obtain assurances of anticipated tax treatment, a deterioration in the business or prospects of Murphy or its U.K. downstream business, adverse developments in Murphy or its U.K. downstream business’ markets, and adverse developments in the U.S. or global capital markets, credit markets or economies in general. Additionally, the Company may be unable to sell its U.K. downstream business as it desires to do because it may fail to execute a sale of these operations on acceptable terms. For further discussion of risk factors, see Murphy’s 2012 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note K to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity derivative contracts in place at September 30, 2013 to hedge the sales price of certain Eagle Ford Shale and Canadian heavy oil production between October 2013 and September 2014. A 10% increase in the respective benchmark price of these commodities would have increased the recorded net liability associated for these derivative contracts by approximately $49.4 million, while a 10% decrease would have reduced the recorded net liability by a similar amount.
There were short-term derivative foreign exchange contracts in place at September 30, 2013 to hedge the value of the U.S. dollar against the Malaysian ringgit and the Canadian dollar. A 10% strengthening of the U.S. dollar against these foreign currencies would have increased the recorded net liability associated with these contracts by approximately $9.4 million, while a 10% weakening of the U.S. dollar would have decreased the recorded net liability by approximately $12.2 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In March 2013, a subsidiary of the Company paid a $151,250 fine to the U.S. Department of Transportation for violations of the pipeline and hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) of 49 C.F.R.R. Part 195 from an on-site pipeline safety inspection of its former Superior, Wisconsin refinery. The subsidiary had recorded an expense related to this fine in a prior year.
Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in our 2012 Form 10-K filed on February 28, 2013. The Company has not identified any additional risk factors not previously disclosed in its 2012 Form 10-K report.
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ITEM 6. EXHIBITS
The Exhibit Index on page 34 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
November 6, 2013
(Date)
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EXHIBIT INDEX
Exhibit
No.
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
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