UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended June 30, 2012
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-1204
HESS CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE
(State or Other Jurisdiction of Incorporation or Organization)
13-4921002
(I.R.S. Employer Identification Number)
1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y.
(Address of Principal Executive Offices)
10036
(Zip Code)
(Registrant’s Telephone Number, Including Area Code is (212) 997-8500)
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. Yes þ 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). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
At June 30, 2012, there were 341,512,444 shares of Common Stock outstanding.
PART I — FINANCIAL INFORMATION
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (UNAUDITED)
(In millions,
except share amounts)
CURRENT ASSETS
Cash and cash equivalents
Accounts receivable
Trade
Other
Inventories
Other current assets
Total current assets
INVESTMENTS IN AFFILIATES
PROPERTY, PLANT AND EQUIPMENT
Total — at cost
Less reserves for depreciation, depletion, amortization and lease impairment
Property, plant and equipment — net
GOODWILL
DEFERRED INCOME TAXES
OTHER ASSETS
TOTAL ASSETS
CURRENT LIABILITIES
Accounts payable
Accrued liabilities
Taxes payable
Short-term debt and current maturities of long-term debt
Total current liabilities
LONG-TERM DEBT
ASSET RETIREMENT OBLIGATIONS
OTHER LIABILITIES AND DEFERRED CREDITS
Total liabilities
EQUITY
Hess Corporation Stockholders’ Equity
Common stock, par value $1.00Authorized — 600,000,000 sharesIssued — 341,512,444 shares at June 30, 2012; 339,975,610 shares at December 31, 2011
342
340
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income (loss)
Total Hess Corporation stockholders’ equity
Noncontrolling interests
Total equity
TOTAL LIABILITIES AND EQUITY
See accompanying notes to consolidated financial statements.
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PART I — FINANCIAL INFORMATION (CONT’D.)
STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)
REVENUES AND NON-OPERATING INCOME
Sales (excluding excise taxes) and other operating revenues
Income (loss) from equity investment in HOVENSA L.L.C.
Gains on asset sales
Other, net
Total revenues and non-operating income
COSTS AND EXPENSES
Cost of products sold (excluding items shown separately below)
Production expenses
Marketing expenses
Exploration expenses, including dry holes and lease impairment
Other operating expenses
General and administrative expenses
Interest expense
Depreciation, depletion and amortization
Asset impairments
Total costs and expenses
INCOME BEFORE INCOME TAXES
Provision (benefit) for income taxes
NET INCOME
Less: Net income (loss) attributable to noncontrolling interests
NET INCOME ATTRIBUTABLE TO HESS CORPORATION
BASIC NET INCOME PER SHARE
DILUTED NET INCOME PER SHARE
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)
COMMON STOCK DIVIDENDS PER SHARE
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STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)
OTHER COMPREHENSIVE INCOME (LOSS):
Derivatives designated as cash flow hedges
Effect of hedge losses reclassified to income
Income taxes on effect of hedge losses reclassified to income
Net effect of hedge losses reclassified to income
Change in fair value of cash flow hedges
Income taxes on change in fair value of cash flow hedges
Net change in fair value of cash flow hedges
Change in deferred gains (losses) on cash flow hedges, after-tax
Pension and other postretirement plans
Change in plan liabilities
Income taxes on change in plan liabilities
Change in plan liabilities, after-tax
Foreign currency translation adjustment and other
TOTAL OTHER COMPREHENSIVE INCOME
COMPREHENSIVE INCOME
Less: Comprehensive income (loss) attributable to noncontrolling interests
COMPREHENSIVE INCOME ATTRIBUTABLE TOHESS CORPORATION
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STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash provided by operating activities
Exploratory dry hole costs and lease impairment
Provision (benefit) for deferred income taxes
(Income) loss from equity investment in HOVENSA L.L.C.
Stock compensation expense
Changes in operating assets and liabilities and other
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
Proceeds from asset sales
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings of debt with maturities of 90 days or less
Debt with maturities of greater than 90 days
Borrowings
Repayments
Cash dividends paid
Net cash provided by (used in) financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
CASH AND CASH EQUIVALENTS AT END OF PERIOD
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STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)
BALANCE ATJANUARY 1, 2012
Other comprehensive income (loss)
Comprehensive income (loss)
Activity related to restricted common stock awards, net
Employee stock options, including income tax benefits
Performance share units
Cash dividends declared
Noncontrolling interests, net
BALANCE AT JUNE 30, 2012
BALANCE ATJANUARY 1, 2011
BALANCE AT JUNE 30, 2011
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Basis of Presentation
The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of Hess Corporation’s (the Corporation) consolidated financial position at June 30, 2012 and December 31, 2011 and the consolidated results of operations for the three and six month periods ended June 30, 2012 and 2011 and the consolidated cash flows for the six month periods ended June 30, 2012 and 2011. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.
The financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (SEC) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (GAAP) have been condensed or omitted from these interim financial statements. These statements, therefore, should be read in conjunction with the consolidated financial statements and related notes included in the Corporation’s Form 10-K for the year ended December 31, 2011. Certain information in the financial statements and notes has been reclassified to conform to the current period presentation.
Effective January 1, 2012, the Corporation adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, which requires comprehensive income to be presented either at the end of the income statement or as a separate statement immediately following the income statement. The Corporation elected to adopt the separate statement method.
Effective January 1, 2012, the Corporation adopted FASB ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. For the Corporation, this standard requires additional disclosures related to fair value measurements, which are included in Note 13, Risk Management and Trading Activities.
2. Dispositions
In January 2012, the Corporation completed the sale of its interest in the Snohvit Field (Snohvit) (Hess 3%), offshore Norway, for cash proceeds of $132 million. The transaction resulted in a gain of $36 million, after deducting the net book value of assets including allocated goodwill of $14 million. Snohvit was producing at a net rate of approximately 3,000 barrels of oil equivalent per day (boepd) at the time of sale.
In February 2011, the Corporation completed the sale of its interests in certain natural gas producing assets in the United Kingdom North Sea for cash proceeds of $359 million, after post-closing adjustments. These disposals resulted in pre-tax gains totaling $343 million ($310 million after income taxes). These assets had a productive capacity of approximately 15,000 boepd.
3. Inventories
Inventories were as follows:
Crude oil and other charge stocks
Refined petroleum products and natural gas
Less: LIFO adjustment
Merchandise, materials and supplies
Total inventories
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4. Property, Plant and Equipment
Assets Held for Sale: In February 2012, the Corporation reached an agreement to sell its interests in the Bittern Field (Hess 28%) in the United Kingdom North Sea. In May 2012, the Corporation also reached an agreement to sell its interests in the Schiehallion Field (Hess 16%) in the United Kingdom North Sea, the associated floating production, storage and offloading vessel, and the West of Shetland pipeline system. Both of these transactions are subject to various regulatory and other approvals.
The Corporation has classified the Bittern and Schiehallion assets and another property as assets held for sale. At June 30, 2012, the carrying amount of these assets totaling $944 million, including allocated goodwill of $87 million, was reported in Other current assets. In addition, related asset retirement obligations and deferred income taxes totaling $672 million were reported in Accrued liabilities. In accordance with GAAP, properties classified as held for sale are not depreciated but are subject to impairment testing.
Capitalized Exploratory Well Costs: The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves for the six months ended June 30, 2012 (in millions):
Balance at January 1
Additions to capitalized exploratory well costs pending the determination of proved reserves
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
Capitalized exploratory well costs charged to expense
Balance at end of period
Capitalized exploratory well costs charged to expense in the preceding table exclude $69 million of exploratory well costs which were incurred and subsequently expensed in 2012. Capitalized exploratory well costs greater than one year old after completion of drilling were $1,763 million at June 30, 2012. Approximately 37% of the capitalized well costs in excess of one year relates to the Pony discovery in the deepwater Gulf of Mexico. The Corporation is in discussions with the owners of the adjacent Knotty Head discovery on Green Canyon Block 512 on a proposal to jointly develop the field. Negotiation of a joint operating agreement, including working interest percentages for the partners, and planning for the field development are progressing. Approximately 34% relates to Block WA-390-P, offshore Western Australia, where development planning and commercial activities, including negotiations with liquefaction partners, are ongoing. Approximately 15% relates to Area 54, offshore Libya, where force majeure was lifted in March 2012 and the Corporation is pursuing commercial options. Approximately 7% relates to offshore Ghana where further drilling is ongoing. The remainder of the capitalized well costs in excess of one year relates to projects where further drilling is planned or development planning and other assessment activities are ongoing to determine the economic and operating viability of the projects.
5. Asset Impairments
In the second quarter of 2012, the Corporation recorded a charge of $59 million ($36 million after-tax) in the Exploration and Production (E&P) segment to reduce the carrying value of certain properties in the Eagle Ford shale in Texas to their fair value. These properties are part of an asset exchange with a joint venture partner that was completed in the third quarter of 2012.
6. Libyan Operations
In response to civil unrest in Libya and the resulting imposition of sanctions, production at the Waha Field was suspended in the first quarter of 2011. During the fourth quarter of 2011, the sanctions were lifted and production was restored. The Corporation’s Libyan production averaged 22,000 barrels of oil per day in the second quarter of 2012. The force majeure covering the Corporation’s offshore exploration interests was withdrawn in March 2012.
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7. HOVENSA L.L.C. Joint Venture
In January 2012, HOVENSA L.L.C. (HOVENSA) announced a decision to shut down its refinery in St. Croix, U.S. Virgin Islands. As a result, the Corporation recorded an accrued liability of $487 million at December 31, 2011 for its share of future funding commitments for costs to shut down HOVENSA’s refinery. The Corporation and its partner fully funded their estimated commitments in the first quarter of 2012.
8. Long-term Debt
In the first six months of 2012, the Corporation borrowed a net of $1,730 million from available credit facilities, which consisted of $1,222 million from its syndicated revolving credit facility, $475 million from the Corporation’s short-term credit facilities and $33 million from its asset-backed credit facility. The Corporation also had net repayments of $38 million relating to other debt during the first six months of 2012. At June 30, 2012, the Corporation classified $708 million of outstanding borrowings under short-term and asset-backed credit facilities as long-term, based on availability under its $4 billion syndicated revolving credit facility.
9. Foreign Currency
Pre-tax foreign currency gains (losses) amounted to the following:
Pre-tax foreign currency gains (losses)
10. Retirement Plans
Components of net periodic pension cost consisted of the following:
Service cost
Interest cost
Expected return on plan assets
Amortization of net loss
Pension expense
For the full year of 2012, the Corporation expects to contribute approximately $150 million to its funded pension plans. Through June 30, 2012, the Corporation contributed $83 million of this amount.
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11. Weighted Average Common Shares
The weighted average number of common shares used in the basic and diluted earnings per share computations are as follows:
Common shares — basic
Effect of dilutive securities
Stock options
Restricted common stock
Common shares — diluted
In March 2012, the Corporation changed the long-term incentive award program for its officers such that 50% of the shares awarded annually are performance share units (PSU’s) and the remaining 50% are in the form of restricted stock, with stock option awards being eliminated. The number of shares of common stock to be issued under the PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of fifteen peer companies over a three-year performance period ending December 31, 2014. Payouts of the 2012 performance share awards will range from 0% to 200% of the target award based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares and will only be paid out on earned shares after the performance period.
The Corporation granted 1,525,646 shares of restricted stock and 415,773 PSU’s during the six months ended June 30, 2012, and 713,280 shares of restricted stock and 2,142,270 stock options for the same period in 2011. The weighted average common shares used in the diluted earnings per share calculations exclude the effect of 8,144,000 and 7,509,000 out-of-the-money stock options, respectively, and 408,122 of PSU’s for the three and six months ended June 30, 2012, as well as 1,618,000 and 2,153,000 out-of-the-money stock options for the same periods in 2011.
12. Segment Information
The Corporation’s results by operating segment were as follows:
Operating revenues
Exploration and Production
Marketing and Refining
Less: Transfers between affiliates
Total (*)
Net income (loss) attributable to Hess Corporation
Corporate, including interest
Total
Operating revenues exclude excise and similar taxes of approximately $650 million and $590 million for the three months ended June 30, 2012 and 2011, respectively, and $1,290 million and $1,150 million for the six months ended June 30, 2012 and 2011, respectively.
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Identifiable assets by operating segment were as follows:
Corporate
13. Risk Management and Trading Activities
In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as energy marketing and corporate risk management activities. The Corporation also has trading operations, principally through a 50% voting interest in a consolidated partnership, that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity price risks primarily related to the prices of crude oil, natural gas, refined petroleum products and electricity.
The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value at risk limits. The chief risk officer must approve the trading of new instruments or commodities. Risk limits are monitored and reported on a daily basis to business units and senior management. The Corporation’s risk management department also performs independent price verifications (IPV’s) of sources of fair values, validations of valuation models and analyzes changes in fair value measurements on a daily, monthly and/or quarterly basis. These controls apply to all of the Corporation’s risk management and trading activities, including the consolidated trading partnership. The Corporation’s treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable.
The Corporation’s risk management department, in performing the IPV procedures, utilizes independent sources and valuation models that are specific to the individual contracts and pricing locations to identify positions that require adjustments to better reflect the market. This review is performed quarterly and the results are presented to the chief risk officer and senior management. The IPV process considers the reliability of the pricing services through assessing the number of available quotes, the frequency at which data is available and, where appropriate, the comparability between pricing sources.
Following is a description of the Corporation’s activities that use derivatives as part of their operations and strategies. Derivatives include both financial instruments and forward purchase and sale contracts. Gross notional amounts of both long and short positions are presented in the volume tables below. These amounts include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts.
Energy Marketing Activities: In its energy marketing activities the Corporation sells refined petroleum products, natural gas and electricity principally to commercial and industrial businesses at fixed and floating prices for varying periods of time. Commodity contracts such as futures, forwards, swaps and options, together with physical assets such as storage and pipeline capacity, are used to obtain supply and reduce margin volatility or lower costs related to sales contracts with customers.
The table below shows the gross volume of the Corporation’s energy marketing commodity contracts outstanding:
Crude oil and refined petroleum products (millions of barrels)
Natural gas (millions of mcf)
Electricity (millions of megawatt hours)
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The changes in fair value of certain energy marketing commodity contracts that are not designated as hedges are recognized currently in earnings. Revenues from the sales contracts are recognized in Sales and other operating revenues in the Statement of Consolidated Income, while supply contract purchases and net settlements from financial derivatives related to these energy marketing activities are recognized in Cost of products sold in the Statement of Consolidated Income. Net realized and unrealized pre-tax gains on derivative contracts not designated as hedges amounted to $24 million and $31 million for the three months ended June 30, 2012 and 2011, respectively, and $79 million and $28 million for the six months ended June 30, 2012 and 2011, respectively.
At June 30, 2012, a portion of energy marketing commodity contracts were designated as cash flow hedges to hedge the variability of expected future cash flows of forecasted supply transactions. The length of time over which the Corporation hedges exposure to variability in future cash flows is predominantly one year or less. For contracts outstanding at June 30, 2012, the maximum duration was approximately two years.
The Corporation records the effective portion of changes in the fair value of cash flow hedges as a component of Accumulated other comprehensive income (loss) in the Consolidated Balance Sheet and then reclassifies amounts to Cost of products sold in the Statement of Consolidated Income as the hedged transactions are recognized in earnings. At June 30, 2012, the after-tax deferred losses relating to energy marketing activities recorded in Accumulated other comprehensive income (loss) were $40 million ($64 million at December 31, 2011). The Corporation estimates that after-tax losses of approximately $26 million will be reclassified into earnings over the next twelve months. During the three months ended June 30, 2012 and 2011, the Corporation reclassified after-tax losses from Accumulated other comprehensive income (loss) of $25 million and $33 million, respectively, and $51 million and $53 million for the six months ended June 30, 2012 and 2011, respectively.
The amounts of ineffectiveness recognized immediately in Cost of products sold were gains of approximately $1 million and less than $1 million for the three months ended June 30, 2012 and 2011, respectively, and a gain of less than $1 million and a loss of $2 million for the six months ended June 30, 2012 and 2011, respectively. The pre-tax amount of deferred hedge losses is reflected in Accounts payable and the related income tax benefits are recorded as deferred income tax assets, which are included in Other current assets in the Consolidated Balance Sheet.
As a result of changes in the fair value of energy marketing cash flow hedge positions, after-tax deferred losses increased by $3 million and decreased by $1 million for the three months ended June 30, 2012 and 2011, respectively, and increased by $27 million and decreased by $3 million for the six months ended June 30, 2012 and 2011, respectively.
Corporate Risk Management Activities: Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil, refined petroleum products or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of the Corporation’s crude oil, refined petroleum products or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does business with the intent of reducing exposure to foreign currency fluctuations. These forward contracts comprise various currencies including the British Pound, Thai Baht and Australian Dollar. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
The table below shows the gross volume of the Corporate risk management derivative contracts outstanding:
Commodity, primarily crude oil (millions of barrels)
Foreign exchange (millions of U.S. Dollars)
Interest rate swaps (millions of U.S. Dollars)
During 2008, the Corporation closed Brent crude oil cash flow hedges covering 24,000 barrels per day through 2012, by entering into offsetting contracts with the same counterparty. As a result, the valuation of those contracts is no longer subject to change due to price fluctuations. The deferred hedge losses as of the date that the hedges were closed are being recorded in earnings as the hedged transactions occur. For 2012, the Corporation has entered into Brent crude oil hedges using fixed-
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price swap contracts to hedge the variability of forecasted future cash flows from 120,000 barrels per day of crude oil sales volumes for the full year. The average price for these hedges is $107.70 per barrel.
Realized losses from E&P hedging activities reduced Sales and other operating revenues by $141 million and $128 million for the three months ended June 30, 2012 and 2011, respectively ($89 million and $81 million after-tax, respectively), and $385 million and $256 million for the six months ended June 30, 2012 and 2011, respectively ($240 million and $162 million after-tax, respectively).
At June 30, 2012, the after-tax deferred losses in Accumulated other comprehensive income (loss) related to Brent crude oil hedges were $42 million ($286 million at December 31, 2011), which will be reclassified into earnings during the remainder of 2012 as the hedged crude oil sales are recognized. The amount of ineffectiveness from Brent crude oil hedges that was recognized immediately in Sales and other operating revenues was a gain of $3 million for the three months ended June 30, 2012 and a loss of $8 million for the six months ended June 30, 2012.
At June 30, 2012, the Corporation had interest rate swaps with a gross notional amount of $880 million, which were designated as fair value hedges. Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income. The Corporation recorded an increase of $13 million and $5 million (excluding accrued interest) for the three months ended June 30, 2012 and 2011, respectively, and an increase of $10 million and $3 million (excluding accrued interest) for the six months ended June 30, 2012 and 2011, respectively, in the fair value of interest rate swaps and a corresponding adjustment in the carrying value of the hedged fixed-rate debt.
Gains or losses on foreign exchange contracts that are not designated as hedges are recognized immediately in Other, net in Revenues and non-operating income in the Statement of Consolidated Income.
Net realized and unrealized pre-tax gains (losses) on derivative contracts used for Corporate risk management activities and not designated as hedges amounted to the following:
Commodity
Foreign exchange
Trading Activities: Trading activities are conducted principally through a trading partnership in which the Corporation has a 50% voting interest. This consolidated entity intends to generate earnings through various strategies primarily using energy-related commodities, securities and derivatives. The Corporation also takes trading positions for its own account. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.
The table below shows the gross volume of derivative contracts outstanding relating to trading activities:
Interest rate (millions of U.S. Dollars)
Equity securities (millions of shares)
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Pre-tax unrealized and realized gains (losses) recorded in Sales and other operating revenues in the Statement of Consolidated Income from trading activities amounted to the following:
Fair Value Measurements: The table below reflects the gross and net fair values of the Corporation’s risk management and trading derivative instruments:
June 30, 2012
Derivative contracts designated as hedging instruments
Interest rate and other
Total derivative contracts designated as hedging instruments
Derivative contracts not designated as hedging instruments (*)
Total derivative contracts not designated as hedging instruments
Gross fair value of derivative contracts
Master netting arrangements
Cash collateral (received) posted
Net fair value of derivative contracts
December 31, 2011
Includes trading derivatives and derivatives used for risk management.
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The Corporation generally enters into master netting arrangements to mitigate counterparty credit risk. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Corporation to terminate all contracts upon occurrence of certain events, such as a counterparty’s default or bankruptcy. Where these arrangements provide the right of offset and the Corporation’s intent and practice is to offset amounts in the case of contract terminations, the Corporation’s policy is to record the fair value of derivative assets and liabilities on a net basis.
The Corporation determines fair value in accordance with the fair value measurements accounting standard (Accounting Standards Codification (Topic 820): Fair Value Measurements and Disclosures), which established a hierarchy that categorizes the sources of inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2.
When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. To value derivatives that are characterized as Level 2 and 3, the Corporation uses observable inputs for similar instruments that are available from exchanges, pricing services or broker quotes. These observable inputs may be supplemented with other methods, including internal extrapolation or interpolation, that result in the most representative prices for instruments with similar characteristics. Multiple inputs may be used to measure fair value, however, the level of fair value for each physical derivative and financial asset or liability presented below is based on the lowest significant input level within this fair value hierarchy.
The following table provides the fair values for the Corporation’s net physical derivative and financial assets and (liabilities) that are based on this hierarchy:
Assets
Derivative contracts
Collateral and counterparty netting
Total derivative contracts
Other assets measured at fair value on a recurring basis
Total assets measured at fair value on a recurring basis
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Liabilities
Other liabilities measured at fair value on a recurring basis
Total liabilities measured at fair value on a recurring basis
Other fair value measurement disclosures
Long-term debt
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In the second quarter of 2012, the Corporation recorded a charge of $59 million ($36 million after-tax) to reduce the carrying value of certain properties in the Eagle Ford shale in Texas to their fair value. The valuation of these properties is considered a non-recurring Level 3 fair value measurement and is based on an income approach using a probability weighted discounted cash flow model. The most significant unobservable inputs used in this valuation include resource potential, future commodity prices, expected capital requirements and operating expenses.
The following table provides changes in physical derivatives and financial assets and (liabilities) that are measured at fair value based on Level 3 inputs:
Balance at beginning of period
Unrealized pre-tax gains (losses)
Included in earnings (a)
Included in other comprehensive income (b)
Purchases (c)
Sales (c)
Settlements (d)
Transfers into Level 3
Transfers out of Level 3
The unrealized pre-tax gains (losses) included in earnings that are reflected in Sales and other operating revenues in the Statement of Consolidated Income amounted to $105 million and $(48) million for the three and six months ended June 30, 2012, respectively. The unrealized pre-tax gains (losses) included in earnings that are reflected in Cost of products sold in the Statement of Consolidated Income amounted to $(28) million and $2 million for the three and six months ended June 30, 2012, respectively.
The unrealized pre-tax gains (losses) included in Other comprehensive income are reflected in the Change in fair value of cash flow hedges in the Statement of Consolidated Comprehensive Income.
Purchases and sales primarily represent option premiums paid or received, respectively, during the reporting period.
Settlements represent realized gains and (losses) on derivatives settled during the reporting period.
The following table provides net transfers into and out of each level of the fair value hierarchy:
Transfers into Level 1
Transfers out of Level 1
Transfers into Level 2
Transfers out of Level 2
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The Corporation’s policy is to recognize transfers in and transfers out as of the end of the reporting period. Transfers between levels result from the passage of time as contracts move closer to their maturities, fluctuations in the market liquidity for certain contracts and/or changes in the level of significance of fair value measurement inputs.
The significant unobservable inputs used in Level 3 fair value measurements for the Corporation’s physical commodity contracts and derivative instruments primarily include less liquid delivered locations for physical commodity contracts or volatility assumptions for out-of-the-money options. The following table provides information about the Corporation’s significant recurring unobservable inputs used in the Level 3 fair value measurements. Natural gas contracts are usually quoted and transacted using basis pricing relative to an active pricing location (e.g., Henry Hub), for which price inputs represent the approximate value of differences in geography and local market conditions. All other price inputs below represent full contract prices. Significant changes in any of the inputs below, independently or correlated, may result in a different fair value.
Commodity contracts with a fair value of $258 millionContract prices
Crude oil and refined petroleum products
Electricity
Basis prices
Natural gas
Contract volatilities
Commodity contracts with a fair value of $177 millionContract prices
Fair value measurement for all recurring inputs was performed using an income approach technique.
Credit Risk: The Corporation is exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. The Corporation’s net receivables at June 30, 2012 are concentrated with the following counterparty and customer industry segments: Integrated Oil Companies — 28%, Refiners — 9%, Government Entities — 9%, Services — 9%, Trading Companies — 8% and Real Estate — 7%. The Corporation reduces its risk related to certain counterparties by using master netting arrangements and requiring collateral, generally cash or letters of credit. The Corporation records the cash collateral received or posted as an offset to the fair value of derivatives executed with the same counterparty. At June 30, 2012 and December 31, 2011, the Corporation held cash from counterparties of $171 million and $121 million, respectively. The Corporation posted cash to counterparties at June 30, 2012 and December 31, 2011 of $65 million and $117 million, respectively.
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At June 30, 2012, the Corporation had outstanding letters of credit totaling $1 billion, primarily issued to satisfy margin requirements. Certain of the Corporation’s agreements also contain contingent collateral provisions that could require the Corporation to post additional collateral if the Corporation’s credit rating declines. As of June 30, 2012, the net liability related to derivatives with contingent collateral provisions was approximately $453 million before cash collateral posted of $9 million. At June 30, 2012, all three major credit rating agencies that rate the Corporation’s debt had assigned an investment grade rating. If two of the three agencies were to downgrade the Corporation’s rating to below investment grade, as of June 30, 2012, the Corporation would be required to post additional collateral of approximately $170 million.
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Overview
Hess Corporation (the Corporation) is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The M&R segment manufactures refined petroleum products and purchases, markets and trades refined petroleum products, natural gas and electricity.
The Corporation reported net income of $549 million in the second quarter of 2012 compared to $607 million in the second quarter of 2011. Net income for the second quarter of 2012 included an after-tax charge of $36 million which affected the comparability of earnings between periods. For further discussion of all items affecting comparability, see pages 20 and 24.
E&P reported net income of $644 million in the second quarter of 2012 compared to $747 million in the second quarter of 2011. Excluding the item affecting comparability referenced above, E&P net income was $680 million in the second quarter of 2012. In the second quarter of 2012, the Corporation’s average worldwide crude oil selling price, including the effect of hedging, was $86.86 per barrel compared with $97.20 per barrel in the second quarter of 2011. Worldwide crude oil and natural gas production was 429,000 barrels of oil equivalent per day (boepd) in the second quarter of 2012 up from 372,000 boepd in the same period of 2011, principally reflecting an increase in production from the Bakken oil shale play and the resumption of operations in Libya. The Corporation now expects its full year production to average between 395,000 and 405,000 boepd, including Libyan operations, up from the previous forecast of 370,000 to 390,000 boepd, which excluded Libya.
The following is an update of E&P activities during the second quarter of 2012:
In North Dakota, net production from the Bakken oil shale play was 55,000 boepd for the second quarter of 2012, up from 25,000 boepd in the second quarter of 2011. For the full year of 2012, the Corporation now expects net Bakken production to average between 54,000 and 58,000 boepd.
At the Llano Field (Hess 50%) in the deepwater Gulf of Mexico, a successful workover was performed on the Llano #3 well, which had been shut-in for mechanical reasons in the first quarter of 2011. In June 2012, net production averaged 13,000 boepd.
The Corporation signed agreements with its partner to develop nine discovered natural gas fields in the North Malay Basin (NMB), located offshore Peninsular Malaysia. The Corporation will have a 50% working interest and will become operator of the project. First production is forecast to commence in 2013.
The Corporation reached an agreement to sell its interests in the Schiehallion Field (Hess 16%) in the United Kingdom North Sea, the associated floating production, storage and offloading vessel, and the West of Shetland pipeline system for $503 million subject to normal closing adjustments. This asset sale is expected to close in the fourth quarter of 2012.
The Corporation agreed with its joint venture partner to exchange its working interests in certain properties in the Eagle Ford shale in Texas and $85 million in cash for additional working interests in other properties in the Eagle Ford shale and properties in the Paris Basin in France. The Eagle Ford portion of the exchange was completed in the third quarter and the Paris Basin portion is expected to complete in the third quarter, subject to various approvals. In the second quarter of 2012, the Corporation recorded a charge of $59 million ($36 million after-tax) to reduce to fair value the carrying value of the divested Eagle Ford properties.
The Corporation completed drilling the Hickory North-1 well, offshore Ghana and commenced its technical evaluation of the discovery. The well encountered approximately 100 net feet of gas condensate pay.
Offshore Brunei, the Jagus East well on Block CA-1 (Hess 14%), encountered hydrocarbons. This well, along with the Julong East discovery, is being evaluated and additional exploration and appraisal drilling is planned in 2013.
In June, the operator spud the Ness Deep well, located on Green Canyon 507 (Hess 50%) in the deepwater Gulf of Mexico. The well is anticipated to take approximately 160 days to drill.
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Overview (continued)
Status of Libyan Operations
M&R generated income of $8 million in the second quarter of 2012, compared to a loss of $39 million in the second quarter of 2011. The increase in earnings is primarily due to improved refining results, partially offset by lower marketing earnings. In the first quarter of 2012, HOVENSA L.L.C. (HOVENSA) shut down its refinery in St. Croix, U.S. Virgin Islands, and started the transition to operating the complex as an oil storage terminal.
Results of Operations
The after-tax results by major operating activity are summarized below:
Net income attributable to Hess Corporation
Net income per share (diluted)
Items Affecting Comparability Between Periods
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability between periods. The items in the table below are explained and the pre-tax amounts are shown on page 24.
In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are preferable for explaining variances in earnings, since these after-tax amounts show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts.
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Results of Operations (continued)
Comparison of Results
Following is a summarized income statement of the Corporation’s E&P operations:
Sales and other operating revenues (*)
Costs and expenses
Production expenses, including related taxes
General, administrative and other expenses
Results of operations before income taxes
Provision for income taxes
Results of operations attributable to Hess Corporation
Amounts differ from E&P operating revenues in Note 12, Segment Information, primarily due to the exclusion of sales of hydrocarbons purchased from third parties.
The changes in E&P earnings are primarily attributable to changes in selling prices, sales volumes, costs and expenses and items affecting comparability between periods as described below:
Selling prices: Lower average realized selling prices, primarily of crude oil including the effects of hedging, decreased E&P revenues by approximately $290 million and $210 million in the second quarter and first six months of 2012, respectively, compared with the corresponding periods in 2011.
The Corporation’s average selling prices were as follows:
Crude oil — per barrel (including hedging)
United States
Europe
Africa
Asia
Worldwide
Crude oil — per barrel (excluding hedging)
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Natural gas liquids — per barrel
Natural gas — per mcf
Asia and other
During 2008, the Corporation closed Brent crude oil cash flow hedges covering 24,000 barrels per day through 2012, by entering into offsetting contracts with the same counterparty. As a result, the valuation of those contracts is no longer subject to change due to price fluctuations. The deferred hedge losses as of the date that the hedges were closed are being recorded in earnings as the hedged transactions occur. For 2012, the Corporation has entered into Brent crude oil hedges using fixed-price swap contracts to hedge the variability of forecasted future cash flows from 120,000 barrels per day of crude oil sales volumes for the full year. The average price for these hedges is $107.70 per barrel.
Realized losses from E&P hedging activities reduced Sales and other operating revenues by $141 million in the second quarter and $385 million for the six months ended June 30, 2012 ($89 million and $240 million after-taxes, respectively) and $128 million and $256 million in the second quarter and first half of 2011, respectively ($81 million and $162 million after-taxes, respectively). At June 30, 2012, the after-tax deferred losses in Accumulated other comprehensive income (loss) related to Brent crude oil hedges were $42 million, which will be reclassified into earnings during the remainder of 2012 as the hedged crude oil sales are recognized in earnings.
Production and sales volumes: The Corporation’s crude oil and natural gas production was 429,000 boepd and 413,000 boepd in the second quarter and first six months of 2012 up from 372,000 boepd and 385,000 boepd for the same periods in 2011. The increase in production in the second quarter and first six months of 2012 was mainly due to higher production from the Bakken oil shale play and the resumption of operations in Libya. The Corporation now expects its full year 2012 production to average between 395,000 and 405,000 boepd, including Libyan operations, up from the previous forecast of 370,000 to 390,000 boepd, which excluded Libyan production.
The Corporation’s net daily worldwide production by region was as follows:
Crude oil — barrels per day
Natural gas liquids — barrels per day
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Natural gas — mcf per day
Barrels of oil equivalent per day (*)
Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table that begins on page 21.
United States: Crude oil and natural gas production in the United States was higher in the second quarter and first six months of 2012 compared to the corresponding periods in 2011, primarily due to increased production from the Bakken oil shale play.
Europe: Crude oil production in the second quarter of 2012 was higher compared to the same period in 2011, largely due to new wells in Russia and improved performance at the Schiehallion Field in the United Kingdom North Sea, which more than offset lower production from the Valhall Field, offshore Norway, resulting from unplanned downtime.
Natural gas production in the second quarter and first six months of 2012 was lower than the corresponding periods in 2011, principally due to the sale in February 2011 of certain natural gas producing assets in the United Kingdom North Sea, the sale in January 2012 of the Snohvit Field located offshore Norway and unplanned downtime at the Valhall Field.
Africa: Crude oil production in Africa was higher in the second quarter of 2012 compared to the corresponding period in 2011, mainly due to the resumption of operations in Libya, which more than offset natural field declines in Equatorial Guinea. There was no Libyan production in the second quarter of 2011.
Asia and other: Crude oil production in the second quarter and first six months of 2012 was higher than the corresponding periods in 2011 due to new wells at the Pangkah Field in Indonesia.
Sales volumes: Higher sales volumes, primarily relating to crude oil, increased revenue by approximately $585 million and $510 million in the second quarter and first six months of 2012, respectively, compared with the corresponding periods of 2011.
Operating costs and depreciation, depletion and amortization: Cash operating costs, consisting of production expenses and general and administrative expenses, increased by approximately $80 million and $205 million in the second quarter and first six months of 2012 compared with the same periods in 2011. The increase principally reflects higher operating and maintenance expenses, higher general and administrative expenses, together with increased production taxes.
Depreciation, depletion and amortization expenses were higher in the second quarter and first six months of 2012 compared to the same periods in 2011, principally reflecting increased production volumes and a higher average per barrel rate.
For the second quarter of 2012, E&P total production unit costs were $38.41 per barrel, which included cash operating costs of $19.38 per barrel and depreciation, depletion and amortization expenses of $19.03 per barrel. For the first six months of 2012, E&P total production unit costs were $38.50 per barrel, which included cash operating costs of $19.87 per barrel and depreciation, depletion and amortization expenses of $18.63 per barrel.
E&P total production unit costs are now expected to be in the range of $39.00 to $41.00 per barrel, down from the previous guidance of $40.50 to $42.50 per barrel for the full year of 2012. E&P cash operating costs are expected to be in the
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range of $20.00 to $21.00 per barrel and depreciation, depletion and amortization expenses are expected to be in the range of $19.00 to $20.00 per barrel.
Asset impairments: In the second quarter of 2012, the Corporation recorded a charge of $59 million ($36 million after-tax) to reduce the carrying value of certain properties in the Eagle Ford shale in Texas to their fair value. These properties are part of an asset exchange with a joint venture partner that was completed in the third quarter of 2012. This charge is included in the table of items affecting comparability between periods on page 20.
Exploration expenses: Exploration expenses in the second quarter and first six months of 2012 were down from the corresponding periods in 2011, due to lower dry hole and lease impairment expenses.
Income taxes: Excluding items affecting comparability between periods, the effective income tax rate for E&P operations was 44% in the first six months of 2012 compared to 40% for the same period in 2011. This increase reflects the resumption of operations in Libya in 2012, following the civil unrest in 2011.
In July 2012, the government of the United Kingdom changed the supplementary income tax rate applicable to deductions for dismantlement expenditures to 20% from 32%, with an effective date of March 12, 2012. As a result, the Corporation expects to record a one-time charge in the third quarter of 2012 of approximately $100 million for deferred taxes related to asset retirement obligations in the United Kingdom. For the full year of 2012, the Corporation now expects the E&P effective tax rate, excluding items affecting comparability, to be in the range of 44% to 48%, up from the previous guidance of 36% to 40%. This forecast reflects the resumption of operations in Libya.
Foreign exchange: The following currency gains (losses) related to E&P activities amounted to the following:
Pre-tax
After-tax
Gains on asset sales: First quarter of 2012 results included a gain of $36 million related to the completion of the sale of the Corporation’s interest in the Snohvit Field (Hess 3%). First quarter of 2011 results included pre-tax gains of $343 million ($310 million after income taxes) related to the completion of the sale of the Corporation’s interests in certain natural gas producing assets located in the United Kingdom North Sea. Both of these gains on asset sales are reflected in the table of items affecting comparability between periods on page 20.
The Corporation’s future E&P earnings may be impacted by external factors, such as volatility in the selling prices of crude oil and natural gas, reserve and production changes, exploration expenses, industry cost inflation, changes in foreign exchange rates and income tax rates, the effects of weather, political risk, environmental risk and catastrophic risk. For a more comprehensive description of the risks that may affect the Corporation’s E&P business see Item 1A. Risk Factors Related to Our Business and Operations in the December 31, 2011 Annual Report on Form 10-K.
M&R activities generated income of $8 million in the second quarter and $19 million in the first half of 2012, compared with a loss of $39 million in the second quarter and break even in the first half of 2011. The Corporation’s downstream operations include marketing, refining and trading operations. In June 2012, operations commenced at the Bayonne Energy Center, LLC (Hess 50%), a joint venture established to build and operate a 512-megawatt natural gas fueled electric generating station in Bayonne, New Jersey.
Marketing: Marketing operations, which consist principally of energy marketing, retail gasoline stations (most of which have convenience stores), terminals and supply operations, generated earnings of $18 million and $40 million in the second quarter and first six months of 2012, respectively, compared with $28 million and $96 million in the corresponding periods of 2011. The reduction in year-to-date earnings for 2012 compared with 2011, was principally due to lower energy marketing
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earnings as a result of lower margins, refined product sales and natural gas volumes together with an after-tax charge of $11 million for environmental liabilities in the second quarter of 2012.
The table below summarizes marketing sales volumes:
Refined petroleum product sales (thousands of barrels per day)
Gasoline
Distillates
Residuals
Total refined petroleum product sales
Natural gas (thousands of mcf per day)
Electricity (megawatts round the clock)
Refining: Following the shutdown of the HOVENSA refinery in St. Croix, U.S. Virgin Islands in the first quarter of 2012, the Corporation’s refining operations now consist of the Port Reading refining facility, which has a refining capacity of 70,000 barrels per day. Port Reading generated earnings of $8 million in the second quarter of 2012 and $5 million in the second quarter of 2011 reflecting improved margins. Earnings were $2 million in the first six months of 2012 and $7 million in the first six months of 2011. During the first quarter of 2012, the Port Reading refining facility was shut down for 15 days due to unplanned maintenance. As a result of fully accruing the Corporation’s estimated funding commitments for HOVENSA’s refinery shutdown at December 31, 2011, no incremental equity loss was recorded in the first six months of 2012. The Corporation’s equity share of HOVENSA’s losses was $49 million for the second quarter of 2011 and $97 million for the first six months of 2011.
The Corporation has a 50% voting interest in a consolidated partnership that trades energy-related commodities, securities and derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the results from the trading partnership, amounted to losses of $18 million and $23 million in the second quarter and first six months of 2012, respectively, compared with losses of $23 million and $4 million in the corresponding periods of 2011.
The Corporation’s future M&R earnings may be impacted by supply and demand factors, volatility in margins, credit risks, the effects of weather, competitive industry conditions, political risk, environmental risk and catastrophic risk. For a more comprehensive description of the risks that may affect the Corporation’s M&R business, see Item 1A. Risk Factors Related to Our Business and Operations in the December 31, 2011 Annual Report on Form 10-K.
The following table summarizes corporate expenses:
Corporate expenses
Income tax (benefits)
Total corporate expenses, after-tax
Corporate expenses were higher in the first six months of 2012, compared with the same period a year ago, primarily due to higher employee benefit costs and insurance expenses.
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Interest Expense
Interest expense was as follows:
Total interest incurred
Less: capitalized interest
Interest expense before income taxes
Total interest expense, after-tax
The increase in interest incurred in the three and six months ended June 30, 2012 compared to the corresponding periods of 2011, principally reflects higher average debt and bank facility fees.
Consolidated Sales and Cost of Products Sold
Sales and other operating revenues decreased by 6% and 5% in the second quarter and first six months of 2012, compared with the corresponding periods of 2011, primarily due to lower crude oil selling prices and lower sales volumes for refined petroleum products, partially offset by higher crude oil sales volumes. The decrease in Cost of products sold principally reflects lower prices for purchased refined petroleum products.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources:
Total debt
Debt to capitalization ratio (*)
Total debt as a percentage of the sum of total debt plus total equity.
Cash Flows
The following table summarizes the Corporation’s cash flows:
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Net increase (decrease) in cash and cash equivalents
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Liquidity and Capital Resources (continued)
Operating Activities: Net cash provided by operating activities, including changes in operating assets and liabilities, amounted to $2,228 million in the first six months of 2012 compared with $2,824 million in the first six months of 2011, reflecting lower operating earnings and a period over period increase in the use of cash from changes in operating assets and liabilities of $562 million. In the first quarter of 2012, the Corporation fully funded its accrued liability to HOVENSA of $487 million, which represents its estimated funding commitment for costs to shut down HOVENSA’s refinery.
Investing Activities: The following table summarizes the Corporation’s capital expenditures:
Marketing, Refining and Corporate
Capital expenditures for the first six months of 2012 compared to the same period a year ago reflect additional spend of approximately $800 million related to the Bakken for the drilling of new wells and higher working interest wells, together with increased spending on field infrastructure projects.
During the first quarter of 2012, the Corporation received proceeds of $132 million from the sale of its interest in the Snohvit Field. During the first quarter of 2011, the Corporation received proceeds of $359 million from the sale of natural gas producing assets in the United Kingdom North Sea.
Financing Activities: In the first six months of 2012, the Corporation borrowed a net of $1,730 million from available credit facilities, which consisted of $1,222 million from its syndicated revolving credit facility, $475 million from the Corporation’s short-term credit facilities and $33 million from its asset-backed credit facility. The Corporation also had net repayments of $38 million relating to other debt during the first six months of 2012. Dividends paid were $102 million in the first six months of 2012 and 2011.
Future Capital Requirements and Resources
The Corporation now anticipates investing a total of approximately $8.5 billion in capital and exploratory expenditures during 2012, substantially all of which is targeted for E&P operations. This revision reflects an increase of $1.7 billion above the previous guidance of $6.8 billion. This increase is substantially attributable to the following factors: (1) $1.1 billion of additional spending in the Bakken primarily driven by drilling in higher working interest areas, additional wells and increased well costs, (2) $250 million related to the recently sanctioned project in the North Malay Basin, (3) cost increases of $200 million for the Valhall redevelopment project and (4) accelerated spend of $100 million at the Tubular Bells deepwater development due to the early arrival of the rig.
Through the first half of 2012, the Corporation has largely funded its capital spending through cash flows from operations and net incremental borrowings. The gap between full year 2012 cash flows from operations and capital expenditures is expected to reach approximately $3 billion based on current commodity prices. The Corporation has announced asset sales totaling more than $850 million, of which approximately $130 million have closed in the first half of 2012. The Corporation is pursuing additional asset sales that should generate proceeds of $1 billion to $2 billion and is exploring possible further asset sales. These asset sales are expected to be largely completed by the end of 2013. In the interim, the Corporation expects to fund capital expenditures and ongoing operations, including dividends, pension contributions and required debt repayments with existing cash on-hand, cash flows from operations, proceeds from asset sales and available credit facilities. In 2013, the Corporation expects that capital and exploratory expenditures will be significantly lower than the 2012 expenditures and more aligned with expected cash flows.
Crude oil and natural gas prices are volatile and difficult to predict. In addition, unplanned increases in the Corporation’s capital expenditure program could occur. If conditions were to change, such as a significant decrease in commodity prices, an unexpected increase in capital expenditures or we are unable to complete the planned asset sales, the Corporation would take further steps to protect its financial flexibility and may pursue other sources of liquidity, including the issuance of debt securities, the issuance of equity securities and/or additional asset sales.
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The table below summarizes the capacity, usage, and available capacity of the Corporation’s borrowing and letter of credit facilities at June 30, 2012:
Revolving credit facility
Asset-backed credit facility
Committed lines
Uncommitted lines
Total capacity of $1 billion subject to the amount of eligible receivables posted as collateral.
Committed and uncommitted lines have expiration dates through 2014.
The Corporation maintains a $4 billion syndicated revolving credit facility, which can be used for borrowings and letters of credit. At June 30, 2012, available capacity under the facility was $2,672 million.
The Corporation has a 364-day asset-backed credit facility securitized by certain accounts receivable from its Marketing and Refining operations. Under the terms of this financing arrangement, the Corporation has the ability to borrow or issue letters of credit of up to $1 billion subject to the availability of sufficient levels of eligible receivables. At June 30, 2012, outstanding borrowings under this facility of $383 million were collateralized by a total of $859 million of accounts receivable, which are held by a wholly owned subsidiary. These receivables are only available to pay the general obligations of the Corporation after satisfaction of the outstanding obligations under the asset-backed facility.
The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.
The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and secured debt. At June 30, 2012, the Corporation is permitted to borrow up to an additional $25.4 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $4.9 billion of secured debt at June 30, 2012.
The Corporation’s $1 billion of letters of credit outstanding at June 30, 2012 were primarily issued to satisfy margin requirements. See also Note 13, Risk Management and Trading Activities.
Off-balance Sheet Arrangements
The Corporation has leveraged leases not included in its Consolidated Balance Sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $383 million at June 30, 2012 compared with $388 million at December 31, 2011. If these leases were included as debt, the Corporation’s debt to capitalization ratio at June 30, 2012 would increase to 29.2% from 28.2%.
Market Risk Disclosures
As discussed in Note 13, Risk Management and Trading Activities, in the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as energy marketing and corporate risk management activities. The Corporation also has trading operations, principally through a 50% voting interest in a consolidated partnership that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas, electricity and refined petroleum products.
Value at Risk: The Corporation uses value at risk to monitor and control commodity risk within its risk management and trading activities. The value at risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. Results
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Market Risk Disclosures (continued)
may vary from time to time as strategies change in trading activities or hedging levels change in risk management activities. The potential change in fair value based on commodity price risk is presented in the energy marketing and corporate risk management activities and trading activities sections below.
Energy Marketing and Corporate Risk Management Activities
The Corporation uses energy commodity derivatives in its energy marketing and corporate risk management activities. The Corporation estimates that the value at risk for these activities, which is primarily related to the Brent crude oil hedges, was $63 million at June 30, 2012 and $94 million at December 31, 2011. The results may vary from time to time as hedge levels change.
Long-term debt had a carrying value of $7,582 million, compared with a fair value of $8,725 million at June 30, 2012. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $258 million at June 30, 2012.
The Corporation’s risk exposure to foreign currency movements did not differ significantly from the levels shown in Item 7A of the Corporation’s 2011 Form 10-K.
Trading Activities
The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts. Derivative trading transactions are marked-to-market and unrealized gains or losses are recognized currently in earnings. Gains or losses from sales of physical products are recorded at the time of sale. Net realized gains and losses for the three and six months ending June 30, 2012 amounted to gains of $338 million and $169 million, respectively, compared to a loss of $111 million and a gain of $59 million for the corresponding periods in 2011.
The following table provides an assessment of the factors affecting the changes in the fair value of net assets (liabilities) relating to financial instruments and derivative commodity contracts used in trading activities:
Fair value of contracts outstanding at January 1
Change in fair value of contracts outstanding at thebeginning of the year and still outstanding at June 30
Reversal of fair value for contracts closed during the period
Fair value of contracts entered into during the period and still outstanding
Fair value of contracts outstanding at June 30
The following table summarizes the sources of fair values of net assets (liabilities) relating to financial instruments and derivative commodity contracts by year of maturity used in the Corporation’s trading activities at June 30, 2012:
Source of fair value
Level 1
Level 2
Level 3
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The Corporation estimates that the value at risk for trading activities, including commodities, was $7 million at June 30, 2012 and $4 million at December 31, 2011. The value at risk for trading activities may vary from time to time as strategies change to capture potential market rate movements.
The following table summarizes the fair values of receivables net of cash margin and letters of credit relating to the Corporation’s trading activities and the credit ratings of counterparties at June 30, 2012 (in millions):
Investment grade determined by outside sources
Investment grade determined internally (*)
Less than investment grade
Fair value of net receivables outstanding at end of period
Based on information provided by counterparties and other available sources.
Forward-looking Information
Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, asset sales, oil and gas production, tax rates, debt repayment, hedging, derivative and market risk disclosures and off-balance sheet arrangements, include forward-looking information. These sections typically include statements with words such as “anticipate”, “estimate”, “expect”, “forecast”, “guidance”, “could”, “may”, “should”, “would” or similar words, indicating that future outcomes are uncertain. Forward-looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors.
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The information required by this item is presented under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2012, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of June 30, 2012.
There was no change in internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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PART II — OTHER INFORMATION
Exhibits
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
XBRL Instance Document
XBRL Schema Document
XBRL Calculation Linkbase Document
XBRL Labels Linkbase Document
XBRL Presentation Linkbase Document
XBRL Definition Linkbase Document
Reports on Form 8-K
During the quarter ended June 30, 2012, Registrant filed the following reports on Form 8-K:
Filing dated May 7, 2012 reporting under Item 5.02 reporting compensatory arrangements of certain officers and submission of matters to a vote of security holders under Item 5.07.
Filing dated April 25, 2012 reporting under Items 2.02 and 9.01 a news release dated April 25, 2012 reporting results for the first quarter of 2012 and furnishing under Items 7.01 and 9.01 the prepared remarks of John B. Hess, Chairman of the Board of Directors and Chief Executive Officer of Hess Corporation, at a public conference call held April 25, 2012.
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SIGNATURES
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)
CHAIRMAN OF THE BOARD AND
CHIEF EXECUTIVE OFFICER
SENIOR VICE PRESIDENT AND
CHIEF FINANCIAL OFFICER
Date: August 3, 2012
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