UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended June 30, 2012
OR
For the transition period from to
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
(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. þ 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). þ 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 þ No
Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2012 was 194,256,715.
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
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 $7,855 in 2012 and $7,892 in 2011
Inventories, at lower of cost or market
Crude oil
Finished products
Materials and supplies
Prepaid expenses
Deferred income taxes
Total current assets
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $7,590,711 in 2012 and $6,861,494 in 2011
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
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 194,380,426 shares in 2012 and 193,909,200 shares in 2011
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Treasury stock, 123,711 shares of Common Stock in 2012 and 185,992 shares of Common Stock in 2011, 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
Gain on sale of assets
Interest and other income
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
Accretion of asset retirement obligations
Redetermination of Terra Nova working interest
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
PER COMMON SHARE – BASIC
Income from discontinued operations
Net 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
Amortization of deferred major repair costs
Expenditures for asset retirements
Dry hole costs
Amortization of undeveloped leases
Deferred and noncurrent income tax charges
Pretax gain from disposition of assets
Net increase 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 costs
Proceeds from sales of assets
Purchase of investment securities2
Proceeds from maturity of investment securities2
Expenditures for major repairs
Investing activities of discontinued operations
Other – net
Net cash required by investing activities
FINANCING ACTIVITIES
Borrowings of notes payable
Maturities of notes payable
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
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 June 30
Reclassified to conform to current presentation.
Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.
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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 194,380,426 shares at June 30, 2012 and 193,714,102 shares at June 30, 2011
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
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
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, 2011. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2012, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and six-month periods ended June 30, 2012 and 2011, 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 2011 Form 10-K and Form 10-K/A reports, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 2012 are not necessarily indicative of future results.
Note B – Property, Plant and Equipment
Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
At June 30, 2012, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $567.6 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2012 and 2011.
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 June 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 $463.8 million of exploratory well costs capitalized more than one year at June 30, 2012, $274.5 million is in Malaysia, $129.3 million is in the U.S., $29.3 million is in Republic of the Congo, and $30.7 million is in Canada. 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 Republic of the Congo further appraisal drilling is planned. In Canada a drilling and development program continues.
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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 June 30, 2012 and December 31, 2011, the carrying value of inventories under the LIFO method was $499.8 million and $580.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.
Note D – Discontinued Operations
In 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses. On September 30, 2011, the Company sold the Superior, Wisconsin refinery and related assets for $214 million, plus certain capital expenditures between July 25 and the date of closing and the fair value of all associated hydrocarbon inventories at these locations. On October 1, 2011, the Company sold the Meraux, Louisiana refinery and related assets for $325 million, plus the fair value of associated hydrocarbon inventories. The Company has accounted for operating results of the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations, and all prior periods presented have been reclassified to conform to this presentation. The cash proceeds from these refinery sales were primarily used to pay down outstanding loans under existing revolving credit facilities in 2011.
The results of operations associated with these discontinued operations for the three-month and six-month periods ended June 30, 2011 were as follows:
Revenues
Income before income taxes
The Company continues to offer for sale its U.K. refinery at Milford Haven, Wales and all U.K. product terminals and motor fuel stations. Based on current market conditions, it is possible that the Company could incur a loss on future sales of the U.K. downstream assets. Through June 30, 2012, the Company has accounted for U.K. downstream results as a component of continuing operations. If the sale of the U.K. assets continues to progress, the Company expects that the results of these operations to be sold will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.
Note E – Financing Arrangements
The Company has a $1.5 billion committed credit facility that expires June 14, 2016. Borrowings under the facility bear interest at 1.5% above LIBOR based on the Company’s current credit rating as of June 30, 2012. Facility fees are due at varying rates on the 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 September 2012.
Ten year notes totaling $350 million, which matured on May 1, 2012, were repaid using $350 million of borrowings from other existing credit facilities. In May 2012, the Company sold $500 million of new notes that carry a coupon rate of 4.00% and mature on June 1, 2022. The new notes pay interest semi-annually on June 1 and December 1. The initial interest payment is to be made on December 1, 2012. The proceeds of the $500 million notes were used to repay the borrowings incurred on May 1 under other credit facilities and for general corporate purposes.
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Note F – Cash Flow Disclosures
Additional disclosures regarding cash flow activities are provided below.
Net increase in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable
(Increase) decrease in inventories
(Increase) decrease in prepaid expenses
(Increase) decrease in deferred income tax assets
Increase (decrease) in accounts payable and accrued liabilities
Increase (decrease) in current income tax liabilities
Total
Supplementary disclosures:
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. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2012 and 2011.
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of transitional asset
Recognized actuarial loss
Special termination benefits
Net periodic benefit expense
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Note G – Employee and Retiree Benefit Plans (Contd.)
During the six-month period ended June 30, 2012, the Company made contributions of $29.0 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2012 for the Company’s defined benefit pension and postretirement plans is anticipated to be $16.4 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) eliminates 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. In June 2012, the U.S. Supreme Court upheld the constitutionality of the health care reform law. The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The law did not significantly affect the Company’s consolidated financial statements as of June 30, 2012 and 2011 and for the three-month and six-month periods then ended. 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 evaluation performed 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 financial statements using a fair value-based measurement method over the periods that the awards vest.
At the Company’s annual stockholders’ meeting held on May 9, 2012, shareholders approved replacement of the 2007 Annual Incentive Plan (2007 Annual Plan) and the 2007 Long-Term Incentive Plan (2007 Long-Term Plan) with the 2012 Annual Incentive Plan (2012 Annual Plan) and 2012 Long-Term Incentive Plan (2012 Long-Term Plan), respectively. The new plans can be found in the Company’s Definitive proxy statement (Definitive 14A) dated March 29, 2012. All awards on or after May 9, 2012 will be made under the respective 2012 plans.
The 2012 Annual Plan and the 2007 Annual Plan authorize 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 and 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2012 Long-Term Plan and the 2007 Long-Term Plan authorize the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2012 Long-Term Plan expires in 2022. A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. 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.
On January 31, 2012, the Committee granted stock options for 1,643,000 shares at an exercise price of $59.655 per share under the 2007 Long-Term Plan. The Black-Scholes valuation for these awards was $17.74 per option. The Committee also granted 653,356 performance-based restricted stock units on that date under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $54.90 to $63.64 per unit. On February 1, 2012, the Committee granted 40,260 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 was $59.33 per share.
On June 20, 2012, stock options for 227,500 shares were granted to two senior company officers under the 2012 Long-Term Plan. The exercise price of these stock options was $45.70 per share. These stock options vest and become exercisable in periods ranging between six months and three years. The fair value of these stock options using a Black-Scholes valuation model ranged from $12.37 to $13.10 per share.
10
Note H – Incentive Plans (Contd.)
Cash received from options exercised under all share-based payment arrangements for the six-month periods ended June 30, 2012 and 2011 was $8.8 million and $7.9 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.4 million and $7.4 million for the six-month periods ended June 30, 2012 and 2011, 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 six-month periods ended June 30, 2012 and 2011. The following table reconciles the weighted-average shares outstanding used for these computations.
(Weighted-average shares)
Basic method
Dilutive stock options and restricted stock units
Diluted method
Certain options to purchase shares of common stock were outstanding during the 2012 and 2011 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 3,169,055 shares at a weighted average share price of $65.57 in each 2012 period and 994,730 shares at a weighted average share price of $67.34 in each 2011 period.
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 six-month periods in 2012 and 2011, the Company’s effective income tax rates were as follows:
Three months ended June 30
Six months ended June 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; 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.
In July 2012, the United Kingdom enacted tax changes that reduced the corporation tax rate from 25% to 24% effective from April 1, 2012. The corporation tax rate will be further reduced effective April 1, 2013 to 23%. This tax change also limits tax relief on oil and gas decommissioning costs to 50%, a reduction from the 62% tax relief previously allowed for these costs. The Company currently estimates that these tax changes will lead to a net increase to tax expense of approximately $7 million when recorded in the third quarter 2012.
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Note J – Income Taxes (Contd.)
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of June 30, 2012, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2007; United Kingdom – 2010; 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 corn that it will purchase in the future for feedstock and to wet and dried distillers grain that it will sell in the future at its ethanol production facilities in the United States. At June 30, 2012 and 2011, the Company had open physical delivery fixed-price commitment contracts for purchase of approximately 23.6 million and 10.8 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-price quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. Also, at June 30, 2012, the Company had open physical delivery fixed-price commitment contracts for sale of approximately 1.3 million equivalent bushels of wet and dried distillers grain with outstanding derivative contracts to purchase a similar volume of these fixed-price quantities and sell them back at future prices in effect on the expected date of delivery under the sale commitment contracts. The impact of marking to market these commodity derivative contracts reduced income before taxes by $0.3 million in the six-month period ended June 30, 2012 and increased income before taxes by $1.9 million in the six-month period ended June 30, 2011. Cash collateral deposits of $23.0 million at June 30, 2012 associated with these commodity derivative contracts were excluded from the fair value of assets and liabilities included below.
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 June 30, 2012 and 2011 to manage the risk of certain income taxes that are payable in Malaysian ringgits. The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at June 30, 2012 and 2011 were approximately $235.6 million and $279.0 million, respectively. Short-term derivative instrument contracts totaling $13.0 million and $17.0 million U.S. dollars were also outstanding at June 30, 2012 and 2011, respectively, 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 increased income before taxes by $9.2 million and $12.0 million for the six-month periods ended June 30, 2012 and 2011, respectively.
At June 30, 2012 and December 31, 2011, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
Type of Derivative Contract
Commodity
Foreign exchange
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Note K – Financial Instruments and Risk Management (Contd.)
For the three-month and six-month periods ended June 30, 2012 and 2011, 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.
Interest Rate Risks
The Company had ten-year notes totaling $350 million that matured on May 1, 2012. In May 2012, the Company sold new ten-year notes, and it therefore had risk related to the interest rate associated with the anticipated sale of these notes. To manage this interest rate risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that matured on May 1, 2012. The Company utilized hedge accounting to defer any gain or loss on these contracts until the payment of interest on these new notes occurs. During the three-month and six-month periods ended June 30, 2012, $0.4 million of the deferred loss on the interest rate swaps was charged to income. The remaining loss deferred on these contracts at June 30, 2012 was $29.3 million.
At December 31, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.
Interest rate
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 June 30, 2012 and December 31, 2011 are presented in the following table.
Assets
Commodity derivative contracts
Liabilities
Nonqualified employee savings plans
Foreign currency exchange derivative contracts
Interest rate derivative contracts
13
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 and interest rate derivative contracts was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of commodity derivative contracts is recorded in Crude Oil and Product Purchases in the Consolidated Statements of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. The deferred loss on interest rate derivative contracts is being reclassified to Interest Expense in the Consolidated Statement of Income over the 10-year life of the $500 million notes payable that mature June 1, 2022. 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.
Note L – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at June 30, 2012 and December 31, 2011 are presented in the following table.
Foreign currency translation gains, net of tax
Retirement and postretirement benefit plan losses, net of tax
Loss deferred for fair value of interest rate derivative contracts, net of tax
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 governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by 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
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Note M – Environmental and Other Contingencies (Contd.)
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 sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period.
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.
In 2011, Murphy was notified by the U.K. Environment Agency (EA) that it failed to surrender sufficient greenhouse gas emission allowances, which Murphy self-reported to the EA in 2010. The EA has issued a civil penalty notice of approximately $1.7 million. The Company is pursuing all available options regarding this matter.
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 June 30, 2012, the Company had contingent liabilities of $164.7 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.
Note N – Commitments
The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2012 natural gas sales volumes in the Tupper area in Western Canada. The contracts call for natural gas deliveries of approximately 50 million cubic feet per day in 2012 at an average price of Cdn$4.43 per MCF, with the contracts calling for delivery at the AECO “C” sales point. These contracts have been accounted for as a normal sale for accounting purposes.
Note O – Terra Nova Working Interest Redetermination
The joint agreement between the owners of the Terra Nova field, offshore Eastern Canada, required a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests existed. Due to the redetermination process, the Company’s working interest at Terra Nova was reduced from its original 12.0% to 10.475% effective January 1, 2011. The Company made a cash settlement payment in the first quarter 2011 to certain Terra Nova partners for the value of oil sold since February 2005, net of adjustments for operating expenses and capital expenditures, related to the working interest reduction. The Company had recorded cumulative expense of $102.1 million through 2010 based on the working interest reduction. Based on the final settlement paid in 2011, the Company recorded a $5.4 million benefit in the six months of 2011 due to the ultimate cost of the redetermination settlement being less than originally estimated. The benefit has been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statement of Income for the six-month period ended June 30, 2011.
15
Note P – Accounting Matters
In September 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change was effective for the Company for annual and interim goodwill impairment tests performed in 2012. The Company adopted the standard effective January 1, 2012 and the standard did not have a significant effect on its 2012 consolidated financial statements.
In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of comprehensive income. Comprehensive income can be presented in (a) a single continuous Statement of Comprehensive Income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance was effective for the Company beginning in the first quarter of 2012. The Company adopted this guidance in 2012 and it continues to present comprehensive income in a separate statement following the statement of income. The adoption of this standard did not have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statement of Income.
In December 2011, the FASB issued an accounting standards update that will enhance 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 will be effective for all interim and annual periods beginning on or after January 1, 2013. The Company does not expect this new guidance to have a significant effect on its consolidated financial statements.
The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and has sought feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The Company cannot predict the final disclosure requirements that will be required by the Dodd-Frank Act.
Note Q – Business Segments
In 2010, the Company announced its intention to sell its two U.S. refineries and its U.K. downstream operations during 2011. On September 30, 2011, the Company completed the sale of the Superior, Wisconsin refinery and associated marketing assets. On October 1, 2011, the Company completed the sale of the Meraux, Louisiana refinery and associated marketing assets. The results of operations for the Superior and Meraux refineries and associated marketing assets have been reported as discontinued operations, net of income taxes, for all periods presented in the Consolidated Statement of Income and in the segment table that follows. Due to the sale of the two U.S. refineries, Company management has reevaluated the reportable segments for the downstream business. Based on this reevaluation, U.S. downstream operations are now being presented as one reportable segment while the two refineries that formerly comprised the majority of the former U.S. manufacturing segment are presented in the segment table as discontinued operations. The Company continues to actively market for sale the U.K. downstream assets. If the criteria for held for sale under U.S. generally accepted accounting principles is met in future periods, the results of these operations would be presented as discontinued operations.
16
Note Q – Business Segments (Contd.)
(Millions of dollars)
Exploration and production*
United States
Canada
Malaysia
United Kingdom
Republic of the Congo
Other
Refining and marketing
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 23 and 24.
17
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Murphy’s net income in the second quarter of 2012 was $295.4 million ($1.52 per diluted share) compared to net income of $311.6 million ($1.60 per diluted share) in the second quarter of 2011. The 2011 second quarter included income from discontinued operations of $31.6 million ($0.16 per diluted share) related to two former U.S. refineries sold near the end of the third quarter 2011. Income from continuing operations increased from $280.0 million ($1.44 per diluted share) in the 2011 quarter to $295.4 million ($1.52 per diluted share) in 2012. The income improvement from continuing operations in 2012 primarily related to more favorable refining and marketing results in the United Kingdom in the current period.
For the first six months of 2012, net income totaled $585.5 million ($3.01 per diluted share) compared to net income of $580.5 million ($2.98 per diluted share) for the same period in 2011. Earnings in the first six months of 2011 included income from discontinued operations of $62.0 million ($0.32 per diluted share). Continuing operations earned $585.5 million ($3.01 per diluted share) in the first six months of 2012, up from $518.5 million ($2.66 per diluted share) in the 2011 period. The increase in income from continuing operations in 2012 compared to 2011 was primarily attributable to higher average realized crude oil sales prices, higher crude oil sales volumes, lower exploration expenses and improved U.K. downstream results. Operating results were unfavorably affected in 2012 by lower North American natural gas sales prices.
Murphy’s income by operating business is presented below.
Exploration and production
Discontinued operations
In the 2012 second quarter, the Company’s exploration and production operations earned $230.1 million compared to $243.3 million in the 2011 quarter. Income in the 2012 quarter was unfavorably impacted compared to 2011 by lower sales price for worldwide crude oil and North American natural gas production. The 2011 quarter included a $13.1 million after-tax gain on sale of natural gas storage assets in Spain. Exploration expenses were $96.6 million in the second quarter of 2012 compared to $122.5 million in the same period of 2011. The Company’s refining and marketing operations generated income from continuing operations of $80.5 million in the 2012 second quarter compared to income of $60.1 million in the same quarter of 2011. U.K. downstream margins improved in the 2012 quarter compared to the 2011 quarter. The corporate function had after-tax costs of $15.2 million in the 2012 second quarter compared to after-tax costs of $23.4 million in the 2011 period with the favorable variance in 2012 mostly due to lower net interest expense and more favorable gains on transactions denominated in foreign currencies.
In the first six months of 2012, the Company’s exploration and production operations earned $551.7 million compared to $503.7 million in the same period of 2011. Earnings in 2012 compared favorably to the 2011 period primarily due to higher realized crude oil sales prices, higher crude oil and natural gas sales volumes and lower exploration expenses. The Company’s refining and marketing operations had earnings from continuing operations of $76.3 million in the first six months of 2012 compared to earnings of $60.4 million in the same 2011 period. The 2012 period included stronger financial results in the U.K. compared to a year ago based on better operating margins. However, results for U.S. downstream operations were unfavorable in 2012 compared to 2011 primarily due to weaker retail gasoline margins compared to the prior year. Corporate after-tax costs were $42.5 million in the 2012 period compared to after-tax costs of $45.6 million in the 2011 period. The current period had lower net interest expense and a more favorable impact from gains on transactions denominated in foreign currencies compared to the prior year.
18
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production
Results of exploration and production operations are presented by geographic segment below.
Other International
Second quarter 2012 vs. 2011
United States exploration and production operations reported a loss of $1.2 million in the second quarter of 2012 compared to earnings of $52.1 million in the 2011 quarter. Earnings were lower in the 2012 period due to higher exploration expenses, primarily associated with write-off of unsuccessful drilling at the Deep Blue prospect in the Gulf of Mexico, lower natural gas prices and higher oil and gas extraction costs. The 2012 quarter benefited from higher crude oil production at the Eagle Ford Shale area in South Texas compared to 2011. At June 30, 2012, the Company was employing ten drilling rigs in the Eagle Ford Shale area. Production and depreciation expenses increased $18.6 million and $22.5 million, respectively, in 2012 compared to 2011 mostly due to higher production in the Eagle Ford Shale area. Higher lease amortization expense in the current year was associated with expiring leases in the dry gas area in the Eagle Ford Shale. Selling and general expenses in the 2012 period increased $2.1 million from the prior year primarily due to higher staffing costs.
Operations in Canada had earnings of $43.7 million in the second quarter 2012 compared to earnings of $95.8 million in the 2011 quarter. Canadian earnings were lower in the 2012 quarter mostly due to weaker crude oil and natural gas sales prices. Oil production decreased in Canada in the 2012 period compared to 2011 primarily due to start of a 150-day turnaround at the Terra Nova field production facility in early June, and lower volumes at Syncrude caused by downtime for maintenance in the current quarter. Natural gas sales volumes increased in 2012 due to higher production at the Tupper West area. Production and depreciation expenses for conventional oil operations in Canada were unfavorable in 2012 by $3.1 million and $5.5 million, respectively, due primarily to higher gas volumes produced at Tupper West.
Operations in Malaysia reported earnings of $223.2 million in the 2012 quarter compared to earnings of $166.0 million during the same period in 2011. Earnings rose in 2012 in Malaysia primarily from a combination of higher natural gas sales prices and sales volumes from fields offshore Sarawak, and higher crude oil sales volumes at the Kikeh field. Additional Kikeh wells are now on production at this field in association with the ongoing development operations. Production expenses were higher in the 2012 period by $39.4 million primarily due to higher oil sales volumes and additional maintenance costs at the Kikeh field. Depreciation expense was $46.5 million more in the 2012 quarter due to higher crude oil and natural gas sales volumes and higher capital amortization rates in the current quarter. Exploration expense was $5.4 million lower in 2012 due to spending in the prior year quarter for 3-D seismic in Block H.
United Kingdom operations earned $4.1 million in the 2012 quarter compared to $9.3 million in the 2011 quarter. The income reduction was primarily due to higher current period depreciation expense of $9.2 million in 2012 compared to 2011, which was primarily caused by the Schiehallion field production facility now expected to be shuttered and replaced earlier than previously estimated. The Schiehallion field is currently expected to be offline for redevelopment from 2013 to 2015. A 12% tax rate increase was enacted in the third quarter 2011, which raised the U.K. effective tax rate on oil and gas company profits from 50% to 62%.
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Exploration and Production (Contd.)
Second quarter 2012 vs. 2011 (Contd.)
Operations in Republic of the Congo incurred a loss of $5.3 million in the second quarter of 2012 compared to a loss of $3.3 million in the 2011 quarter. The loss was higher in 2012 primarily due to no crude oil sales volumes from the Azurite field in the quarter. The Company currently anticipates the next Azurite crude oil sale to occur in the fourth quarter 2012.
Other international operations reported a loss of $34.4 million in the second quarter of 2012 compared to a loss of $76.6 million in the 2011 quarter. The favorable variance in the current quarter was primarily related to higher unsuccessful exploratory drilling costs in the prior year in Indonesia, offset in part by the 2011 after-tax gain of $13.1 million associated with the sale of gas storage assets in Spain.
On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $94.33 per barrel in the second quarter 2012 compared to $99.37 in the 2011 period. Total hydrocarbon production averaged 188,575 barrels of oil equivalent per day in the 2012 second quarter, up from the 170,457 barrels equivalent per day produced in the 2011 quarter. Average crude oil, condensate and gas liquids production was 104,012 barrels per day in the second quarter of 2012 compared to 94,242 barrels per day in the second quarter of 2011, with the increase primarily attributable to higher crude oil production at the Kikeh field, where wells have been put on production as part of the ongoing field development operations. Crude oil production in the U.S. was higher in the 2012 second quarter due to an ongoing drilling and development program in the Eagle Ford Shale area of South Texas. Higher production in the Eagle Ford more than offset production declines at fields in the Gulf of Mexico. Heavy oil production in Western Canada was higher in 2012 as a result of ongoing development activities in the Seal area and a forest fire that curtailed production in the prior year. Oil production at Syncrude was lower in 2012 primarily due to equipment maintenance in the current year. Oil production at the Azurite field, offshore Republic of the Congo, was lower in the 2012 quarter due to general field decline coupled with one well being offline during the quarter awaiting a mechanical workover. North American natural gas sales prices averaged $2.15 per thousand cubic feet (MCF) in the 2012 quarter compared to $4.26 per MCF in the same quarter of 2011. Natural gas produced in 2012 at fields offshore Sarawak was sold at $7.88 per MCF, compared to a sale price of $6.40 per MCF in the 2011 quarter. Natural gas sales volumes averaged 507 million cubic feet per day in the second quarter 2012, up from 457 million cubic feet per day in the 2011 quarter. The increase in natural gas sales volumes in 2012 was due to higher gas volumes produced at the Tupper West area in Western Canada.
Six months 2012 vs. 2011
U.S. E&P operations had income of $49.6 million for the six months ended June 30, 2012 compared to income of $68.6 million in the 2011 period. The 2012 period benefited from higher crude oil sales prices, but natural gas sales prices were significantly lower in the 2012 period compared to the prior year. Crude oil production volumes were higher in 2012 mostly due to additional crude oil volumes at the Eagle Ford Shale area, but these gains were partially offset by declines at fields in the Gulf of Mexico. Production and depreciation expenses were $26.0 million and $37.0 million, respectively, more in 2012 than 2011 mostly due to higher production in the Eagle Ford Shale. Exploration expense in the 2012 period was $14.1 million above 2011 levels primarily due to an unsuccessful exploration well at the Deep Blue prospect in the Gulf of Mexico. This dry hole in 2012 was partially offset by lower geophysical expense in the Eagle Ford Shale area compared to 2011. Selling and general expenses rose by $4.8 million in 2012 compared to 2011, primarily driven by increased staffing levels.
Canadian operations had income of $117.0 million in the first half of 2012 compared to income of $182.2 million a year ago. Significantly lower sales prices for natural gas and lower volumes of synthetic oil produced at Syncrude led to the reduction in 2012 earnings. Although natural gas production was meaningfully higher in 2012, primarily associated with growth in Tupper West area production, the lower gas sales prices led to unprofitable operating results for gas production operations. Production and depreciation expenses for conventional operations increased $16.6 million and $29.9 million, respectively, in 2012 mostly related to higher volumes of natural gas produced at Tupper West in the current year.
20
Six months 2012 vs. 2011 (Contd.)
Malaysia operations earned $447.2 million in the first half of 2012 compared to earnings of $361.8 million in the 2011 period. Earnings were stronger in 2012 primarily due to higher sales prices for all crude oil production and Sarawak natural gas production. Additionally, the 2012 period benefited from higher sales volumes for Kikeh crude oil production and Sarawak natural gas production. Production expense in 2012 exceeded the 2011 cost by $25.5 million primarily due to higher oil and gas sales volumes and higher Kikeh field maintenance. Depreciation expense was up $63.4 million in the 2012 period primarily due to higher oil and gas sales volumes coupled with higher per-unit depreciation rates for Malaysian production volumes. Exploration expense was $5.6 million lower in 2012 mostly due to less seismic costs associated with offshore Block H during the current year.
Income in the U.K. for the six-month period in 2012 was $12.8 million compared to $18.3 million a year ago with the earnings reduction primarily due to a higher income tax rate in the current year. The U.K. government enacted a 12% tax rate increase in the third quarter 2011 on oil and gas production company profits. This raised the effective tax rate on such profits from 50% to 62%. Natural gas sales volumes were lower in 2012 than 2011 primarily due to decline and more downtime at the Amethyst field. Depreciation expense for 2012 was $12.4 million more than in 2011 due to a higher capital amortization unit rate at the Schiehallion field, where the production facility is now expected to be shuttered and replaced earlier than previously estimated.
Operations in Republic of the Congo had a net loss of $3.7 million for the six-month 2012 period compared to earnings of $0.3 million in the 2011 period. The unfavorable result in 2012 was primarily due to lower sales volumes for oil produced at the offshore Azurite field. The field has experienced rapid production decline and one well has been offline awaiting a mechanical workover since March 2012. Exploration expense was $4.2 million lower in 2012 than 2011 due to the prior year including more costs for unsuccessful exploration drilling and geophysical data.
Other international operations reported a loss of $71.2 million in the first six months of 2012 compared to a loss of $127.5 million in the 2011 period. The 2011 period included significantly higher costs associated with unsuccessful offshore wildcat drilling in Indonesia and Suriname. Higher undeveloped leasehold amortization of $13.0 million in 2012 compared to 2011 was mostly attributable to exploration licenses in the Kurdistan region of Iraq. The current period included higher geological and geophysical expense associated with various studies and data acquired in several prospective areas, including Australia, Brunei and others. The 2011 period included an after-tax gain of $13.1 million attributable to sale of the Company’s gas storage assets in Spain.
Total worldwide production averaged 191,836 barrels of oil equivalent per day during the six months ended June 30, 2012, an increase from 176,272 barrels of oil equivalent produced in the same period in 2011. Crude oil, condensate and gas liquids production in the first half of 2012 averaged 105,751 barrels per day compared to 103,725 barrels per day a year ago. The increase was mostly attributable to higher oil production at the Kikeh field, offshore Sabah Malaysia, where additional wells have been brought on production as part of the ongoing development operations. Crude oil production in the U.S. rose in the 2012 period as higher production in the Eagle Ford Shale area more than offset lower oil production from Gulf of Mexico fields. Oil production at Syncrude was lower in 2012 due to the effects of equipment downtime for maintenance. Crude oil produced in Republic of the Congo was lower in 2012 than in 2011 due to both field decline and a well being offline since March 2012 awaiting a mechanical workover. For the first six months of 2012, the Company’s sales price for crude oil, condensate and gas liquids averaged $97.21 per barrel, up from $93.04 per barrel in 2011. Natural gas sales volumes increased from 435 million cubic feet per day in 2011 to 516 million cubic feet per day in 2012, with the increase mostly due to higher gas production volumes at the Tupper West area in British Columbia, which came onstream in February 2011. The average sales price for North American natural gas in the first six months of 2012 was $2.36 per MCF, down from $4.30 per MCF realized in 2011. Natural gas production at fields offshore Sarawak was sold at an average price of $7.80 per MCF in 2012 compared to $6.15 per MCF in 2011.
Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.
21
Selected operating statistics for the three-month and six-month periods ended June 30, 2012 and 2011 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Canada – light
– heavy
– offshore
– synthetic
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 gas liquids – dollars per barrel (2)
Canada (3) – light
Malaysia (4)
Natural gas – dollars per thousand cubic feet
United States (2)
Canada (3)
United Kingdom (3)
22
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2012 AND 2011
Three Months Ended June 30, 2012
Oil and gas sales and other operating revenues
Production expenses
Exploration expenses
Dry holes
Geological and geophysical
Undeveloped lease amortization
Total exploration expenses
Results of operations before taxes
Income tax provisions
Results of operations (excluding corporate overhead and interest)
Three Months Ended June 30, 2011
23
OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2012 AND 2011
Six Months Ended June 30, 2012
Six Months Ended June 30, 2011
Terra Nova working interest redetermination
24
Refining and Marketing
Results of Murphy’s refining and marketing continuing operations are presented below by segment.
Second Quarter 2012 vs. 2011
In 2010, the Company announced its intention to sell its three refineries and U.K. marketing operations during 2011. The Company sold the Superior, Wisconsin refinery and associated marketing assets on September 30, 2011, and also sold the Meraux, Louisiana refinery and associated marketing assets on October 1, 2011. The revenues and expenses for both refineries for all periods presented have been reported as discontinued operations, net of income taxes, in the Consolidated Statements of Income. The sale process for the U.K. downstream operations continues to progress. See Note D in the consolidated financial statements for further discussion.
The United States refining and marketing segment includes retail and wholesale fuel marketing operations and two ethanol production facilities. The United Kingdom refining and marketing segment includes the Milford Haven, Wales refinery and U.K. retail and other refined products marketing operations.
United States continuing operations generated a profit of $73.3 million in the 2012 second quarter compared to a profit of $75.9 million during the second quarter of 2011. The unfavorable result in the 2012 quarter was primarily due to weaker results for the Company’s two ethanol production facilities during the current period. Also, U.S. retail marketing margins were slightly weaker in 2012 compared to the 2011 quarter. U.S. retail margins averaged $0.197 per gallon in 2012 and $0.199 per gallon in 2011. In addition, overall per-store retail fuel sales volumes in the current period were below 2011 levels by about 2.6%. These U.S. retail operations generated higher profits from merchandise sales in the 2012 quarter. Ethanol production operations were less profitable in 2012 than 2011 as margins at both plants were below prior year levels. Compared to the 2011 second quarter, ethanol sales prices in 2012 declined more than corn costs. Results were near break-even at the Hankinson, North Dakota plant and were below break-even at the Hereford, Texas plant in the second quarter 2012.
Refining and marketing operations in the United Kingdom generated a profit of $7.2 million in the second quarter of 2012 compared to a loss of $15.8 million in the same quarter of 2011. The U.K. results in 2012 were favorably affected by stronger refining and marketing margins during the just completed quarter. Unit margins averaged $1.26 per barrel in the U.K. in the 2012 quarter, up from $(1.76) per barrel in 2011. Crude oil throughput volumes at the Milford Haven refinery were 130,059 barrels per day during the 2012 quarter, compared to record runs of 136,428 barrels per day in the 2011 second quarter.
Worldwide petroleum product sales were 483,561 barrels per day in the 2012 quarter, down from 601,498 barrels per day a year ago. This decrease was mostly due to the aforementioned sales of the two U.S. refineries near the end of the third quarter of 2011.
25
Refining and Marketing (Contd.)
United States continuing operations generated a profit of $66.1 million in the first six months of 2012 compared to a profit of $84.9 million during the 2011 period. Results in 2012 were below 2011 levels primarily due to weaker U.S. retail marketing margins which averaged $0.137 per gallon in 2012 following a margin of $0.146 per gallon in 2011. These U.S. retail operations generated higher profits, however, from merchandise sales in 2012. Per-store fuel sales volumes for the retail operations in the 2012 period were below 2011 levels by 4.5%. Ethanol production operations generated losses in the first six months of 2012, compared to about break-even results in the 2011 period. Operating margins for the ethanol facilities were more depressed in the 2012 period as prices for ethanol fell more than the price of corn.
Refining and marketing operations in the United Kingdom generated income of $10.2 million in the 2012 six months compared to a loss of $24.5 million in the same 2011 period. The U.K. results in 2012 benefited from much improved margins, which averaged $1.03 per barrel in 2012 and $(1.22) per barrel in 2011. Crude oil throughput volumes at Milford Haven were 128,530 barrels per day in 2012, down slightly from 128,919 barrels per day in 2011.
Total petroleum product sales were 467,049 barrels per day in the 2012 period, down from 583,019 barrels per day a year ago, with the volume decrease due to the aforementioned refinery sales in the U.S. near the end of the third quarter of 2011.
26
United States retail marketing:
Fuel margin per gallon1
Gallons sold per store month
Merchandise sales revenue per store month
Merchandise margin as a percentage of merchandise sales
Store count at end of period (Company operated)
United Kingdom refining and marketing – unit margins per barrel
Petroleum products sold – barrels per day
Gasoline
Kerosine
Diesel and home heating oils
Residuals
Asphalt, LPG and other
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
1Represents net sales prices for fuel less purchased cost of fuel.
2Includes 166,249 bbls. per day in the three-month period in 2011 and 160,032 bbls. per day in the six-month period in 2011 related to discontinued operations in the United States. Subsequent to the sale of the U.S. refineries in late 2011, a portion of the reduction in refined products produced and sold by these discontinued operations were offset by higher finished products purchased and sold by the Company’s ongoing marketing operations.
27
Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $15.2 million in the 2012 second quarter compared to net costs of $23.4 million in the second quarter of 2011. These costs were favorable to 2011 primarily due to lower net interest expense mostly associated with a higher level of financing costs capitalized to ongoing oil field development projects offshore Malaysia. Additionally, the 2012 quarter included net after-tax gains of $10.7 million on transactions denominated in foreign currencies compared to net after-tax gains of $4.9 million in the comparable 2011 period.
For the first six months of 2012, corporate activities reflected net costs of $42.5 million compared to net costs of $45.6 million a year ago. Six-month corporate costs in 2012 were favorable to 2011 mostly related to the effects of transactions denominated in foreign currencies. Total after-tax gains for foreign currency transactions were $9.1 million in the 2012 period compared to net gains of $3.9 million after taxes in the first six months of 2011. Net interest expense was also less in 2012 compared to 2011 primarily due to higher interest capitalized to ongoing oil development projects. Administrative expense was higher in 2012 associated with increased employee compensation costs.
Discontinued Operations
The Company sold the Superior, Wisconsin and Meraux, Louisiana refineries and related marketing assets near the end of the third quarter 2011. See Note D of the consolidated financial statement for further information. The Company has accounted for these assets as discontinued operations in all periods presented. Income from discontinued operations was $31.6 million in the second quarter of 2011 and $62.0 million in the first six months of 2011. The same 2012 periods included no discontinued operating results. Discontinued operations in the second quarter and first six months of 2011 benefited from positive U.S. refining margins that averaged $2.54 per barrel and $2.73 per barrel, respectively, of throughput by the refineries.
Financial Condition
Net cash provided by operating activities was $1,347.1 million for the first six months of 2012 compared to $917.9 million during the same period in 2011. Changes in operating working capital other than cash and cash equivalents from continuing operations used cash of $103.3 million in the first six months of 2012, compared to a cash use of $455.7 million in the first six months of 2011. Cash of $897.8 million in the 2012 period and $754.1 million in 2011 was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The sale of gas storage assets in Spain in the second quarter 2011 generated cash proceeds of $27.4 million in the prior year.
Significant uses of cash in both years were for dividends, which totaled $106.8 million in 2012 and $106.3 million in 2011, and for property additions and dry holes for continuing operations, which including amounts expensed, were $1,337.0 million and $1,227.4 million in the six-month periods ended June 30, 2012 and 2011, respectively. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $836.5 million in the 2012 period and $675.6 million in the 2011 period. Total accrual basis capital expenditures for continuing operations were as follows:
Capital Expenditures
Total capital expenditures
The increase in capital expenditures in the exploration and production business in 2012 was attributable to more drilling and development activities in the Eagle Ford Shale area, plus higher spending in Malaysia for both oil field development offshore Sarawak and development drilling in the Kikeh field. The increase in capital expenditures in 2012 was somewhat tempered by higher spend in the 2011 period for lease acquisitions in the Eagle Ford Shale, development activities at Tupper West and Tupper in Western Canada and Azurite in the Republic of the Congo, and exploratory drilling in Indonesia and Suriname.
28
Financial Condition (Contd.)
A reconciliation of property additions and dry hole costs in the consolidated statements of cash flows to total capital expenditures for continuing operations follows.
Property additions and dry hole costs per cash flow statements
Geophysical and other exploration expenses
Capital expenditure accrual changes
Working capital (total current assets less total current liabilities) at June 30, 2012 was $893.2 million, an increase of $270.4 million from December 31, 2011. This level of working capital does not fully reflect the Company’s liquidity position because the lower historical costs assigned to inventories under last-in first-out accounting were $499.8 million below fair value at June 30, 2012. During the second quarter 2012, the Company’s $350 million notes maturing in May 2012, which were classified as a current liability in the December 31, 2011 balance sheet, were repaid. New ten-year notes payable of $500 million were sold in May 2012 and are classified as long-term debt at June 30, 2012.
At June 30, 2012, long-term notes payable of $791.5 million had increased by $541.9 million compared to December 31, 2011. A summary of capital employed at June 30, 2012 and December 31, 2011 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 22.4 to 1 for the six-month period ended June 30, 2012.
Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 2012, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $550 million in Canada, $434 million in Malaysia and $56 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 June 2011, the FASB issued an accounting standards update that only permits two options for presentation of comprehensive income. Comprehensive income can be presented in (a) a single continuous Statement of comprehensive income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance was effective for the Company beginning in the first quarter of 2012. The Company adopted this guidance in 2012 and it continues to present comprehensive income in a separate statement following the statement of income. The adoption of this standard did not have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statement of Income.
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Accounting and Other Matters (Contd.)
Outlook
Average crude oil prices in July 2012 were somewhat lower than the average price during the second quarter of 2012. The Company expects its oil and natural gas production to average about 183,000 barrels of oil equivalent per day in the third quarter 2012. U.S. retail marketing margins have fallen significantly in July versus the average margins achieved in the second quarter 2012. Ethanol manufacturing margins remain weak early in the third quarter 2012. The Company currently anticipates total capital expenditures for the full year 2012 to be approximately $4.1 billion.
Murphy is evaluating the potential to separate its U.S. downstream business into a separate publicly traded company. At June 30, 2012, the Company’s U.S. downstream business had $1.77 billion in assets. For the six months ended June 30, 2012, the Company’s U.S. downstream business generated $8.78 billion in revenues and generated income from continuing operations of $66.1 million, and for the year ended December 31, 2011, it generated $17.47 billion in revenues and earned $222.6 million in income from continuing operations. Should a decision be made to separate the U.S. downstream business, the anticipated timing of the separation will be announced at that time. Some factors that could potentially affect the decision to separate include the future financial condition and operating results and economic, business, competitive and/or regulatory factors affecting the business and the industry. The Company cannot predict when, or if, the separation of its U.S. downstream business would take place, or on what terms such separation would be made.
The Company continues to offer for sale its U.K. refinery at Milford Haven, Wales and all U.K. product terminals and motor fuel stations. The Company cannot predict when, or if, the sale of these assets will take place or on what terms such a sale would be made.
North American natural gas prices continue to be extremely weak in July 2012. Should these prices remain weak for an extended period of time, or weaken further than the current level, it is possible that certain investments in natural gas properties could become impaired in a future period.
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 the Company’s 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, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2011 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 interest rates, 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 short-term commodity derivative contracts in place at June 30, 2012 to hedge the purchase price of about 23.6 million bushels of corn and the sale price of about 1.3 million equivalent bushels of wet and dried distillers grain at the Company’s ethanol production facilities. A 10% increase in the respective benchmark price of these commodities would have reduced the recorded net liability associated with these derivative contracts by approximately $2.4 million, while a 10% decrease would have increased the recorded net liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in the value for an equivalent volume of these feedstocks.
There were short-term derivative foreign exchange contracts in place at June 30, 2012 to hedge the value of the U.S. dollar against two foreign currencies. 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 $4.2 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $6.5 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.
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 June 30, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in our 2011 Form 10-K filed on February 28, 2012. The Company has not identified any additional risk factors not previously disclosed in its 2011 Form 10-K report.
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)
/s/ JOHN W. ECKART
John W. Eckart, Senior Vice President
and Controller (Chief Accounting Officer
and Duly Authorized Officer)
August 6, 2012
(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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