UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

For the quarter ended June 30, 2015

or

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  x    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  x    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  ¨    No  x

At June 30, 2015, there were 287,057,761 shares of Common Stock outstanding.

 

 

 

 

 

 

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HESS CORPORATION

Form 10-Q

TABLE OF CONTENTS

 

 

 

 

 

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PART I - FINANCIAL INFORMATION

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

 

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)

 

.

 

See accompanying Notes to Consolidated Financial Statements.

 

 

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)

 

 

See accompanying Notes to Consolidated Financial Statements.

 

 

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

 

 

See accompanying Notes to Consolidated Financial Statements.

 

 

 

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PART I - FINANCIAL INFORMATION (CONT’D)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

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 the Corporation’s consolidated financial position at June 30, 2015 and December 31, 2014, the consolidated results of operations for the three months and six months ended June 30, 2015 and 2014, and consolidated cash flows for the six months ended June 30, 2015 and 2014. 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 Annual Report on Form 10-K for the year ended December 31, 2014.

The statements of consolidated income for the three months and six months ended June 30, 2014 and consolidated cash flows for the six months ended June 30, 2014, have been recast to reflect the Corporation’s energy trading joint venture, HETCO, which was sold in February 2015, as discontinued operations.  In Note 12, Segment Information, the Corporation has reported a new operating segment to reflect the establishment of the Bakken Midstream operating segment in the second quarter of 2015 and have presented prior period numbers on a comparable basis.  See Note 14, Subsequent Event; in Notes to Consolidated Financial Statements for further information.  Certain information in the financial statements and notes has been reclassified to conform to the current period presentation.

New Accounting Pronouncements:  In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU amends the criteria for reporting discontinued operations to include only disposals representing a strategic shift in operations. The ASU also requires expanded disclosures regarding the assets, liabilities, income, and expenses of discontinued operations. This ASU became effective for the Corporation in the first quarter of 2015 and did not have a significant impact on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, as a new Accounting Standards Codification (ASC) Topic ASC 606. This ASU is effective for the Corporation beginning in the first quarter of 2018, with early adoption permitted from the first quarter of 2017. The Corporation is currently assessing the impact of the ASU on its consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities. This ASU is effective for the Corporation beginning in the first quarter of 2016, with early adoption permitted. The Corporation is currently assessing the impact of the ASU on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability.  This ASU is effective for the Corporation beginning in the first quarter of 2016, with early adoption permitted. The Corporation does not expect that the ASU will have a material impact to its consolidated financial statements.

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

 

2. Discontinued Operations

The results of operations for the Corporation’s divested energy trading joint venture, HETCO, which was sold in February 2015, and other previously divested downstream businesses have been reported as discontinued operations in the Statement of Consolidated Income for all periods presented.

Sales and other operating revenues and Income (loss) from discontinued operations were as follows:

At December 31, 2014, HETCO assets totaling $1,035 million, which consisted of accounts receivable and other long‑lived assets, were reported in Other current assets, and liabilities totaling $797 million, which consisted primarily of accounts payable, were reported in Accrued liabilities in the Consolidated Balance Sheet.

3. Inventories

Inventories consisted of the following:

 

4. 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, 2015 (in millions):

 

Capitalized exploratory well costs charged to expense in the preceding table primarily relate to the Dinarta Block in the Kurdistan Region of Iraq following the decision of the Corporation and its partner in March 2015 to cease further drilling activity in the region.  In addition, the Corporation expensed $56 million of exploratory well costs incurred during 2015 that are not reflected in the preceding table.

Capitalized exploratory well costs greater than one year old after completion of drilling were $1,247 million at June 30, 2015. Approximately 70% of the capitalized well costs in excess of one year relates to Block WA-390-P, offshore Western Australia, where development planning and commercial activities for the Corporation’s natural gas discoveries are ongoing.

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

In December 2014, the Corporation executed a non-binding letter of intent with the North West Shelf (NWS), a third party joint venture with existing natural gas processing and liquefaction facilities. Successful execution of binding agreements with NWS is necessary before the Corporation can execute a gas sales agreement and sanction development of the project. Approximately 30% of the capitalized well costs in excess of one year relates to offshore Ghana, where the Corporation has drilled seven successful exploration wells. Appraisal plans for the seven wells on the block were submitted to the Ghanaian government in June 2013 for approval. Four of the plans were approved and discussions continue with the government on the three remaining appraisal plans. In 2014, the Corporation completed a three well appraisal program in Ghana. Well results continue to be evaluated and development planning is progressing.

5. Goodwill

In the second quarter of 2015, the Corporation established a new operating segment, the Bakken Midstream segment which had previously been reported as part of the Onshore reporting unit within the E&P operating segment.  As a result, the Corporation has two operating segments, E&P and Bakken Midstream, as of June 30, 2015.  The E&P operating segment previously had two reporting units, Offshore which had allocated goodwill of $1,098 million and Onshore which had allocated goodwill of $760 million prior to forming the Bakken Midstream operating segment.  Upon formation of the Bakken Midstream operating segment, the Corporation allocated $375 million of goodwill from the Onshore reporting unit to the Bakken Midstream operating segment based on the relative fair values of the Bakken Midstream business and the remainder of the Onshore reporting unit.  There has been no change to the composition of the Offshore reporting unit.

In accordance with accounting standards for goodwill, the Corporation performed impairment tests at June 30, 2015 on the Offshore and Onshore reporting units prior to creation of the Bakken Midstream segment.   No impairment resulted from this assessment.  In addition, accounting standards require that following a reorganization, allocated goodwill should be tested for impairment.  The Corporation also performed impairment tests on the allocated goodwill for the Bakken Midstream and the Onshore reporting unit at June 30, 2015.  Goodwill allocated to the Bakken Midstream operating segment passed the impairment test but the goodwill allocated to the Onshore reporting unit did not pass the impairment test.  As a result, the Corporation recorded a noncash pre-tax charge of $385 million ($385 million after income taxes) in the second quarter of 2015 to reflect the Onshore reporting unit’s goodwill at its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards.

Fair value of the Corporation’s Onshore reporting unit was determined using multiple valuation techniques, including projected discounted cash flows of producing assets and known development projects. The determination of projected discounted cash flows depends on estimates about oil and gas reserves, future prices, operating costs, capital expenditures, discount rate and timing of future net cash flows. The Corporation also considered the relative market valuation of similar peer companies using market multiples, and other observable market data, in determining fair value of the Onshore reporting unit.  The valuation methodologies used represent Level 3 measurements as defined by accounting standards.  Fair value of the Bakken Midstream operating segment was based on the value implied in the Corporation’s announced sale in June 2015 of a 50% interest in the Bakken Midstream business.

The changes in the carrying amount of goodwill are as follows (in millions):

 

 

6. Debt

In January 2015, the Corporation entered into a $4 billion syndicated revolving credit facility that expires in January 2020. The new facility, which replaced a $4 billion facility that was scheduled to expire in April 2016, can be used for borrowings and letters of credit. Based on the Corporation’s credit rating as of June 30, 2015, borrowings on the facility will generally bear interest at 1.075% above the London Interbank Offered Rate with the facility fee amounting to 0.175% per annum. The

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

interest rate and facility fee are subject to adjustment if the Corporation's credit rating changes. The restrictions on the amount of total borrowings and secured debt are substantially similar to the previous facility.  At June 30, 2015, there were no borrowings outstanding or letters of credit issued against the syndicated revolving credit facility.

7. Dispositions

In April 2014, the Corporation completed the sale of its E&P interests in Thailand for cash proceeds of approximately $805 million. This transaction resulted in a pre-tax gain of $706 million ($706 million gain after income taxes).  In June 2014, the Corporation completed the sale of its 50% interest in a joint venture constructing an electric generating facility in Newark, New Jersey for cash proceeds of $320 million, resulting in a pre-tax gain of approximately $13 million ($8 million gain after income taxes). Also in June 2014, the Corporation completed the sale of approximately 30,000 net acres of Utica dry gas acreage, including related wells and facilities, for cash proceeds of approximately $485 million and recorded a pre-tax gain of $62 million ($35 million gain after income taxes).  The Corporation also sold approximately 47,000 acres of Utica dry gas acreage in March 2014 for proceeds of approximately $590 million. There was no gain or loss realized on the transaction as the carrying value of undeveloped leasehold costs was reduced by the sales proceeds. In the first quarter of 2014, the Corporation completed the sale of its interest in the Pangkah asset, offshore Indonesia for cash proceeds of approximately $650 million.  This transaction resulted in a pre-tax gain of $31 million ($10 million loss after income taxes). In addition, the Corporation sold an exploration block in Indonesia for a pre-tax loss of $20 million ($11 million gain after income taxes).

8. Exit and Severance Costs

During the three months and six months ended June 30, 2015, the Corporation recorded exit related costs of $21 million and $27 million, respectively, and recorded exit related costs of $4 million and $24 million for the three and six months ended June 30, 2014, respectively. In addition, the Corporation incurred severance expense totaling $28 million and $61 million during the three months and six months ended June 30, 2014, respectively, primarily related to the Corporation’s divestiture program.  During the three and six months ended June 30, 2015, payments for accrued severance costs amounted to $9 million and $37 million, respectively.

9.  Retirement Plans

Components of net periodic pension cost consisted of the following:

In 2015, the Corporation expects to contribute approximately $55 million to its funded pension plans.  Through June 30, 2015, the Corporation contributed approximately $27 million of this amount.

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

 

10. Weighted Average Common Shares

The net income (loss) and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows:

The Corporation granted 1,122,724 shares of restricted stock, 362,873 performance share units (PSUs) and 521,773 stock options during the six months ended June 30, 2015 and 1,028,883 shares of restricted stock, 298,222 PSUs and 162,911 stock options for the same period in 2014.  The Corporation excluded 7,012,818 stock options, 3,027,138 restricted stock awards and 912,383 performance stock units from the computation of diluted shares for the three months ended June 30, 2015, and excluded 6,901,674 stock options, 2,952,012 restricted stock awards and 1,025,826 performance share units from the computation of diluted shares for the six months period ended June 30, 2015 as they are anti-dilutive.  The weighted average common shares used in the diluted earnings per share calculations for the three and six months ended June 30, 2014 excluded stock options amounting to 1,978,777 and 2,577,984, respectively, as they were anti-dilutive.

The Corporation is permitted but not required to repurchase up to $6.5 billion of outstanding common shares under a Board authorized plan.  During the second quarter of 2015, the Corporation purchased $20 million of common stock.  As of June 30, 2015, total shares repurchased under the plan were 63.2 million shares at a cost of approximately $5.3 billion.

11. Guarantees and Contingencies

The Corporation is subject to loss contingencies with respect to various claims, lawsuits and other proceedings. The Corporation cannot predict with certainty if, how or when such claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be. Numerous issues may need to be resolved, including through lengthy discovery, conciliation and/or arbitration proceedings, or litigation before a loss or range of loss can be reasonably estimated.  Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such lawsuits,

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

claims and proceedings is not expected to have a material adverse effect on the financial condition of the Corporation.  However, the Corporation could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid.

In July 2004, HOVENSA LLC (HOVENSA), a 50/50 joint venture between the Corporation’s subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), and HOVIC each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the HOVENSA refinery, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. In 2014 HOVIC, HOVENSA and the government of the U.S. Virgin Islands entered into a settlement agreement pursuant to which HOVENSA paid $3.5 million and agreed to pay the government of the U.S. Virgin Islands an additional $40 million no later than December 31, 2014. HOVENSA was unable to make this additional payment because the U.S. Virgin Islands legislature did not approve a proposed operating agreement required to complete a proposed sale of HOVENSA, which would have provided funds to make the settlement payment. Under the terms of the settlement agreement, the U.S. Virgin Islands government was granted a first lien on HOVENSA’s assets to secure the settlement payment, and in January 2015 the government commenced a foreclosure action to enforce this lien. HOVENSA intends to defend this action and is also actively pursuing a sale of its terminal assets to satisfy its obligations, including its obligations to the government; however, it is possible that any such sale may not be completed before HOVENSA exhausts its available funds and it may be required to commence bankruptcy proceedings. The Registrant does not believe the resolution of the foreclosure proceeding or a HOVENSA bankruptcy will have a material adverse effect on its financial condition.

In February 2015, the Pension Benefit Guaranty Corporation (PBGC) issued a notice of determination to terminate the HOVENSA pension plan. HOVENSA had been in negotiations with the PBGC to make additional contributions to the plan with proceeds from a proposed sale of HOVENSA, which was not completed for the reasons described above. The Registrant does not believe that the resolution of this matter will have a material adverse effect on its financial condition.

The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. The Corporation cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on the financial condition, results of operations or cash flows of the Corporation.

12.  Segment Information

The Corporation has two operating segments, Exploration and Production and Bakken Midstream.  The Exploration and Production operating segment explores for, develops, produces, purchases and sells crude oil, natural gas liquids and natural gas with production operations primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Joint Development Area of Malaysia/Thailand (JDA), Malaysia, and Norway.  The Bakken Midstream operating segment provides services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane, primarily located in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other.

 

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

The following table presents operating segment financial data for continuing operations (in millions):

*   Capital expenditures include accruals.

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

Identifiable assets by operating segment were as follows:

 

13. Financial Risk Management

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 liquids, and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate risk management activities refer to the mitigation of these risks through hedging activities.

Corporate Financial Risk Management Activities:  Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil 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 or reduce volatility in the forward selling price of a portion of the Corporation’s crude oil 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, primarily the British Pound and Danish Krone. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

The gross notional volumes of Corporate risk management derivative contracts outstanding were as follows:

 

 

In the first quarter of 2015, the Corporation entered into Brent crude oil collars to hedge 50,000 barrels of oil per day (bopd) from March 2015 to December 2015 at a cost of $38 million. This program was supplemented in the second quarter of 2015 by entering into West Texas Intermediate (WTI) crude oil collars to hedge 20,000 bopd from May 6, 2015 to December 2015 at a cost of $10 million.  Under the terms of both programs, the floor price to be received by the Corporation is $60 per barrel and the ceiling price it may receive is $80 per barrel.  All crude oil collars have been designated as cash flow hedges.

Realized and unrealized losses from Brent and WTI crude oil collars for the three and six months ended June 30, 2015 decreased Sales and other operating revenues by $35 million and $18 million, respectively, which included pre-tax losses of $35 million and $23 million, respectively, associated with changes in time value of the hedging contracts.  Realized and unrealized losses in 2014 amounted to $10 million and $1 million for the three months and six months ended June 30, 2014, respectively. There was no significant hedge ineffectiveness for the three months and six months ended June 30, 2015 and an ineffectiveness loss of approximately $3 million and $4 million for the three months and six months ended June 30, 2014, respectively, under the 2014 hedge program.  At June 30, 2015, the after-tax deferred gains in Accumulated other comprehensive income (loss) related to crude oil collars was approximately $1 million, which will be reclassified into earnings during 2015 as the hedged crude oil sales are recognized in earnings.

At June 30, 2015 and December 31, 2014, the Corporation had interest rate swaps with gross notional amounts of $1,300 million.  During the first quarter of 2015, the Corporation settled existing interest rate swaps and received cash proceeds of $41 million.  Simultaneously, the Corporation entered into new interest rate swap arrangements.  All interest rate swaps have been designated as fair value hedges.  The Corporation recorded a decrease of approximately $6 million and an increase of approximately $4 million for the three months and six months ended June 30, 2015, respectively, and increases of approximately $4 million and $5 million for the three months and six months ended June 30, 2014, respectively, in the fair

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

value of interest rate swaps (excluding accrued interest).  These items, excluding accrued interest, offset changes in the carrying value of the hedged fixed-rate debt.

Total foreign exchange gains and losses are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income and amounted to a loss of $7 million and a gain of $8 million in the three months and six months ended June 30, 2015, respectively, compared with a loss of $19 million and $25 million in the three months and six months ended June 30, 2014, respectively.  Gains or losses on foreign exchange derivative contracts not designated as hedges, which are a component of total foreign exchange gains and losses, amounted to a loss of $41 million and a gain of $57 million in the three and six months ended June 30, 2015, respectively, and a loss of $13 million in both the three and six months ended June 30, 2014.

Fair Value Measurements:  The following table provides information about the effect of netting arrangements on the presentation of the Corporation’s physical and financial derivative assets and (liabilities) that are measured at fair value, with the effect of single counterparty multilateral netting being included in column (v):

 

 

The net assets and liabilities reflected in column (iv) of the table above were included in Accounts receivable – Trade and Accounts payable, respectively.    

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PART I - FINANCIAL INFORMATION (CONT’D)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

The table below reflects the gross and net fair values of risk management derivative instruments:

 

 

At June 30, 2015, Level 1 items comprised $3 million of Derivative liabilities.  Level 2 items comprised Derivative liabilities of $6 million and Derivative assets of $28 million, which included commodity contracts of $25 million and interest rate and other items of $3 million.  The Corporation did not have Level 3 instruments at June 30, 2015.  For all other short-term financial instruments, primarily cash equivalents and accounts receivable and payable, the carrying value approximated the respective fair value at June 30, 2015.  Total Long-term debt of $5,957 million at June 30, 2015, had a fair value of $6,642 million based on Level 2 inputs.

Discontinued Operations - Trading Activities:  In the first quarter of 2015, the Corporation sold its interest in the energy trading joint venture, HETCO.  Pursuant to the terms of the sale, the successor entity is permitted to continue to utilize the Corporation’s guarantees issued in favor of counterparties existing as of the sales date until November 12, 2015, provided that new trades are for a period of one year or less, comply with certain credit requirements, and net exposures remain within value at risk limits previously applied by the Corporation. The Corporation has the right to seek reimbursement from the successor entity upon any counterparty draw on the applicable guarantee from the Corporation.  The fair value of the guarantee recorded by the Corporation amounted to $11 million.

14. Subsequent Event

On July 1, 2015, the Corporation completed the sale of a 50% interest in its Bakken Midstream business to Global Infrastructure Partners (GIP) for cash consideration of approximately $2.7 billion and formed a joint venture with GIP.  Subsequent to closing, the joint venture incurred $600 million of debt through a 5-year Term Loan A facility with proceeds distributed equally to both partners, resulting in total after-tax cash proceeds, net to the Corporation, of approximately $3.0 billion. In addition, the joint venture has independent access to capital via a $400 million 5-year Senior Revolving Credit Facility, which is fully committed.

 

 

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

Overview

Hess Corporation is a global Exploration and Production (E&P) company that explores for, develops, produces, purchases, and sells crude oil, natural gas liquids, and natural gas with production operations primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Joint Development Area of Malaysia/Thailand (JDA), Malaysia, and Norway.  The Corporation’s Bakken Midstream operating segment, which was established in the second quarter of 2015, provides services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, transportation of crude oil by rail car, terminaling and loading crude oil and natural gas and the storage and terminaling of propane, primarily in the Bakken shale play of North Dakota.  Certain previously reported amounts have been recast to reflect the separation of Bakken Midstream business from the Exploration and Production operating segment.

Second Quarter Results

The Corporation reported a net loss of $567 million in the second quarter of 2015, compared with net income of $931 million in the second quarter of 2014. Excluding items affecting comparability of earnings between periods on page 19, adjusted net losses were $147 million in the second quarter of 2015 down from adjusted net income of $432 million in the second quarter of 2014.   Lower realized selling prices reduced adjusted net income by approximately $740 million after-tax compared with the prior-year quarter.  In addition, second quarter 2015 results benefitted from higher production, lower cash operating costs and reduced exploration expenses that were partially offset by higher depreciation, depletion, and amortization expense.

Response to Low Oil Prices

In response to the decline in oil prices that began in late 2014, the Corporation conducted an extensive company-wide review of its cost base and engaged with our suppliers during the first half of 2015 to identify opportunities to reduce costs.  As a result of our efforts to date, the Corporation has lowered its full year 2015 guidance for capital and exploratory expenditures by $300 million to $4.4 billion (E&P - $4.1 billion and Bakken Midstream - $0.3 billion), which is an approximate 20 percent reduction from 2014 capital and exploratory expenditures of $5.6 billion.  The Corporation also reduced its full year 2015 cash operating costs guidance by approximately $300 million, or $2.50 per barrel of oil equivalent associated with projected savings.  In addition, the Corporation significantly reduced share repurchases in the first half of 2015 to $27 million.

Based on current strip crude oil prices, the Corporation forecasts a significant net loss and a net cash flow deficit in 2015, excluding proceeds from asset sales.  The Corporation expects to fund its 2015 net cash flow deficit with existing cash on hand, proceeds from the sale of a 50% interest in its Bakken Midstream business in July 2015, which resulted in approximately $3 billion of total after-tax cash proceeds to the Corporation, and, if necessary, borrowings under its long-term syndicated revolving credit facility.  The Corporation plans to maintain its financial flexibility and to reduce its cash flow deficit by pursuing further cost reductions and supply chain savings, significantly moderating stock repurchases compared with 2014, and depending on where crude oil prices trend, potentially further reducing its planned capital program. In addition, should needs dictate, the Corporation may also access other sources of liquidity by utilizing existing uncommitted credit facilities, issuing debt and equity securities, and/or pursuing further asset sales.

Exploration and Production

E&P incurred a net loss of $502 million in the second quarter of 2015 compared with net income of $1,049 million in the second quarter of 2014.  Excluding items affecting comparability of earning between periods, the adjusted net loss was $96 million in the second quarter of 2015 compared to adjusted net income of $475 million in 2014. In the second quarter of 2015, the Corporation’s average worldwide crude oil selling price, including the effect of hedging, was $55.83 per barrel down from $102.16 per barrel in the second quarter of 2014.  The average worldwide natural gas liquids selling price was $11.06 per barrel in the second quarter of 2015, down from $36.59 per barrel in the year-ago quarter while the average worldwide natural gas selling price was $4.49 per thousand cubic feet (mcf) in the second quarter of 2015 compared with $6.35 per mcf in the second quarter a year-ago.  Worldwide crude oil and natural gas production was 391,000 barrels of oil equivalent per day (boepd) in the second quarter of 2015, compared with 319,000 boepd in the same period of 2014. Pro forma production, which excludes production from assets sold as well as any contribution from Libya, was 391,000 boepd and 310,000 boepd in the second quarter of 2015 and 2014, respectively.

The Corporation expects production, excluding Libya, to average between 355,000 boepd and 365,000 boepd for the third quarter and to average between 360,000 boepd and 370,000 boepd for the full year of 2015.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

Overview (continued)

 

The following is an update of E&P activities:

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations

 

The after-tax income (loss) by major operating activity is summarized below:

Items Affecting Comparability of Earnings Between Periods

The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods. The items in the table below are explained and the pre-tax amounts are shown on pages 24 to 26.

The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss):

 

“Adjusted net income (loss)” presented in this report is defined as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods. Management uses adjusted net income (loss) to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations. This measure is not, and should not be viewed as, a substitute for U.S. GAAP net income (loss).

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 a preferable method of explaining variances in earnings, since they 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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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Comparison of Results

Exploration and Production

Following is a summarized income statement of the Corporation’s E&P operations:

Excluding the E&P items affecting comparability of earnings between periods in the table on page 24, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, cash operating costs, depreciation, depletion and amortization, Bakken Midstream tariffs, exploration expenses and income taxes, as well as the impact of asset sales as described below.

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Selling Prices: Average realized crude oil selling prices were 45% and 49% lower in the second quarter and first six months of 2015, respectively, compared to same periods in 2014 primarily due to declines in the benchmark prices for Brent and West Texas Intermediary (WTI) crude oil.  In addition, realized selling prices for natural gas liquids declined by approximately 70% and 68% in the second quarter and first six months of 2015, respectively, compared to same periods in 2014.

The Corporation’s average selling prices were as follows:

In the first quarter of 2015, the Corporation entered into Brent crude oil collars to hedge 50,000 barrels of oil per day (bopd) from March 2015 to December 2015.  This program was supplemented in the second quarter of 2015 by entering into West Texas Intermediate (WTI) crude oil collars to hedge 20,000 bopd from May 6, 2015 to December 2015.  Under the terms of both programs, the floor price to be received by the Corporation is $60 per barrel and the ceiling price it may receive is $80 per barrel.

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Realized and unrealized losses from crude oil price collars decreased Sales and other operating revenues by $35 million and $18 million for the three and six months ended June 30, 2015, respectively ($22 million and $11 million after income taxes, respectively).  Realized and unrealized losses in 2014 amounted to $10 million and $1 million for the three months and six months ended June 30, 2014, respectively ($6 million and $1 million after income taxes, respectively).

Production Volumes:  The Corporation’s crude oil and natural gas production increased to 391,000 boepd and 376,000 boepd in the second quarter and first six months of 2015, from 319,000 boepd for the same periods in 2014.

The Corporation’s net daily worldwide production by region was as follows:

United States: Onshore crude oil and natural gas liquids production was higher in the second quarter and first six months of 2015, compared to the corresponding period in 2014, primarily due to continued drilling in the Bakken oil shale play while the increase in natural gas production was primarily attributable to the Bakken and the Utica shale.  Total Offshore

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

production increased in the second quarter of 2015 as production from the Tubular Bells Field, which came online in November 2014, exceeded the decline in production from the Conger and Llano Fields due to maintenance activities.  Total Offshore production in the first six months of 2015 was comparable to the year-ago quarter as production from the Tubular Bells Field was offset by lower production from the Conger and Llano Fields.

Europe: Crude oil and natural gas production in the second quarter of 2015 was slightly higher compared with the same period of 2014 due to scheduled maintenance at the Valhall Field, Offshore Norway in the prior year.  Crude oil and natural gas production was also slightly higher in the first six months of 2015 compared with 2014 as higher production from the South Arne Field was partially offset by lower production in Norway.

Africa: Crude oil production in Africa was lower in the second quarter of 2015 compared to the corresponding period in 2014, primarily due to lower production in Equatorial Guinea and Algeria.  Crude oil production in the six months ended June 30, 2015 was flat compared to the same period in 2014 as higher production from Equatorial Guinea was partly offset by reduced production in Algeria and Libya.

Asia and Other:  Natural gas production in the second quarter of 2015 was up from 2014 as higher production at the Joint Development Area of Malaysia/Thailand (JDA), caused by planned downtime in 2014, more than offset the impact of asset sales.  Lower natural gas production in the first six months of 2015 relative to 2014, largely results from asset sales in Indonesia and Thailand in 2014 which is partially offset by higher production from the JDA.

Sales Volumes:  The impact of higher sales volumes increased after-tax income by approximately $230 million and $310 million in the second quarter and first six months of 2015, compared with the corresponding period in 2014.

The Corporation’s worldwide sales volumes were as follows:

Cost of Products Sold: Cost of products sold is mainly comprised of costs relating to purchases of third party crude oil, natural gas liquids and natural gas.  The decrease in cost of products sold in the second quarter and first six months of 2015 compared with the same periods in 2014 principally reflect the decline in crude oil prices.

Cash Operating Costs:  Cash operating costs, consisting of Operating costs and expenses, Production and severance taxes and E&P General and administrative expenses, were down in the three and six months ended June 30, 2015 compared to the prior year periods due to lower operating costs across the portfolio and lower production taxes in the Bakken, which were partially offset by operating costs at Tubular Bells where production commenced in the fourth quarter of 2014.

Depreciation, Depletion and Amortization:  Depreciation, depletion and amortization (DD&A) expenses were higher in the second quarter and first six months of 2015, compared with the prior year periods, primarily reflecting higher production volumes from the Bakken, Tubular Bells and Utica Fields.  The Tubular Bells, Utica and Bakken fields each had a higher DD&A rate per barrel than the portfolio average.

Bakken Midstream Tariffs Expense:  Tariffs increased during the three and six months ended June 30, 2015 compared with the respective prior year periods primarily due to higher volumes processed through the Tioga Gas Plant.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Unit Cost Information:

Unit cost per barrel of oil equivalent (boe) information is based on total E&P production volumes and exclude items affecting comparability of earnings as disclosed below. Cash operating costs per boe were $15.65 in the second quarter of 2015 compared with $22.58 in the second quarter of 2014 and DD&A costs per boe were $28.22 in the second quarter of 2015 compared with $26.19 in the second quarter of 2014, resulting in total production unit costs of $43.87 and $48.77 per boe in the second quarter of 2015 and 2014, respectively.  Bakken Midstream Tariff expense was $3.26 and $2.00 per boe in the second quarter of 2015 and 2014, respectively.  Cash operating costs per boe were $16.17 in the first six months of 2015 compared with $21.33 in the first six months of 2014 and DD&A costs per boe were $28.45 in the first six months of 2015 compared with $25.54 in the first six months of 2014 resulting in total production unit costs of $44.62 and $46.87 per boe in the first six months of 2015 and 2014, respectively.  Bakken Midstream Tariff expense was $3.20 and $1.33 per boe in the first six months of 2015 and 2014, respectively.

For the third quarter of 2015, E&P cash operating costs are estimated to be in the range of $16.50 to $17.50 per boe and DD&A expenses are estimated to be in the range of $28.50 to $29.50 per boe resulting in total production unit costs ranging from $45.00 to $47.00 per boe.  For the full year 2015, E&P cash operating costs are estimated to be in the range of $16.00 to $17.00 per boe and DD&A expenses are estimated to be in the range of $28.50 to $29.50 per boe resulting in total production unit costs ranging from $44.50 to $46.50 per boe.  Bakken Midstream tariff expense is expected to be $3.55 to $3.65 per boe for the third quarter of 2015, and $3.40 to $3.50 per boe for the full year of 2015.

Exploration Expenses: Exploration expenses were lower in the second quarter and first six months of 2015 compared to the same period in 2014, primarily due to lower dry hole and lease impairment charges.  Exploration expenses, excluding dry hole expense, are estimated to be in the range of $110 million to $120 million for the third quarter of 2015 and $380 million to $400 million for the full year.

Income Taxes:  Excluding items affecting comparability between periods, the effective income tax rate for E&P operations was a benefit of 56% and 51% in the second quarter and first six months of 2015, respectively, compared to a provision of 34% and 37% for the second quarter and the first six months of 2014, respectively.  For the full year 2015, the E&P effective income tax rate is expected to be a benefit in the range of 44% to 48% and the third quarter rate is expected to be a benefit in the range of 41% to 45%, assuming no contribution from Libya.

Items Affecting Comparability of Earnings Between Periods: The following table summarizes, on an after-tax basis, income (expense) items that affect comparability of E&P earnings between periods:

Impairment:  Second quarter 2015 results include a noncash pre-tax goodwill impairment charge of $385 million ($385 million after income taxes) associated with the Corporation’s onshore reporting unit.  As a result of establishing the Bakken Midstream business as a separate operating segment in the second quarter of 2015, U.S. GAAP required the reallocation of goodwill to the Bakken Midstream segment and a goodwill impairment test for each of the Corporation’s reporting units. See Note 5, Goodwill in Notes to Consolidated Financial Statements for further information.

Terminated international office space:  The Corporation recognized pre-tax charges totaling $21 million ($21 million after income taxes) associated with terminated international office space in the second quarter.    

Gains on asset sales, net:  In June 2014, the Corporation completed the sale of approximately 30,000 net acres, including related wells and facilities in the dry gas area of the Utica shale play, for cash proceeds of approximately $485 million, resulting in a pre-tax gain of $62 million ($35 million after income taxes). In April 2014, the Corporation completed the sale of its Thailand assets for cash proceeds of approximately $805 million. This transaction resulted in a pre-tax gain of $706 million ($706 million after income taxes).

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Dry hole and other expenses:  The Corporation incurred a pre-tax charge of $159 million ($67 million after income taxes) to write-off a previously capitalized exploration well and associated leasehold expenses related to the Dinarta Block, in the Kurdistan Region of Iraq following the decision of the Corporation and its partner in March 2015 to abandon the well, relinquish the Dinarta Block, and to exit operations in the region.  Exploration expenses in the first quarter of 2015 also included a pre-tax charge of $16 million ($10 million after income taxes) to write down a foreign exploration project to fair value.  In the second quarter of 2014, the Corporation recorded a pre-tax charge of $169 million ($105 million after income taxes) to write-off a previously capitalized exploration well in the western half of Block 469 in the Gulf of Mexico.  In addition, in the second quarter of 2014 the Corporation recorded charges totaling $135 million pre-tax ($68 million after income taxes) to write-off leasehold acreage in the Paris Basin of France, the Shakrok Block in Kurdistan and the Corporation’s interest in a natural gas exploration project, offshore Sabah, Malaysia.    

Inventory write-off:  During the first quarter of 2015, the Corporation incurred a pre-tax charge of $21 million ($16 million after income taxes) to write off surplus drilling materials in Equatorial Guinea following the decision to suspend the infill drilling program at the Okume Field.  

The Corporation’s future E&P earnings may be impacted by external factors, such as volatility in the selling prices of crude oil, natural gas liquids, and natural gas, reserve and production changes, exploration expenses, industry cost inflation and/or deflation, 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 Annual Report on Form 10-K for the year ended December 31, 2014.  

Bakken Midstream

Net income (loss) of the Corporation’s Bakken Midstream operating segment, which is primarily located in North Dakota, is summarized as follows:

Total revenues and non-operating income for the three and six months ended June 30, 2015 improved from the prior year periods mainly due to higher throughput volumes at the Tioga Gas Plant.  In the fourth quarter of 2013, the Tioga Gas Plant was shut down for a large‑scale expansion, refurbishment and optimization project, during which a new cryogenic processing train was installed and processing capacity was increased to 250 MMcf/d from 120 MMcf/d.  The Tioga Gas Plant’s expanded operations commenced in late March 2014.  Operating costs and expenses were higher in the three and six months ended June 30, 2015 compared to the prior year periods mainly due to an increase in third‑party operating and maintenance expense.  Depreciation, depletion and amortization (DD&A) expenses were higher in the first six months of 2015 compared with 2014, primarily due to the commencement of depreciation of the Tioga Gas Plant expansion expenditures upon restart of operations in late March 2014.  Net income attributable to Hess Corporation from the Bakken Midstream segment for each of the third and fourth quarters of 2015 is estimated to be in the range of $15 million to $20 million, after giving effect to the sale of 50% of the Bakken Midstream business.

On July 1, 2015, the Corporation completed the sale of a 50% interest in its Bakken Midstream business to Global Infrastructure Partners (GIP) for cash consideration of approximately $2.7 billion and formed a joint venture with GIP.  

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PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

 

Subsequent to closing, the joint venture incurred $600 million of debt through a 5-year Term Loan A facility with proceeds distributed equally to both partners, resulting in total after-tax cash proceeds, net to the Corporation, of approximately $3.0 billion. In addition, the joint venture has independent access to capital via a $400 million 5-year Senior Revolving Credit Facility, which is fully committed.

Corporate, Interest and Other

The following table summarizes corporate, interest and other expenses:

Corporate and other expenses for the three and six months ended June 30, 2014 include a pre-tax gain of $13 million ($8 million after income taxes) related to the disposition of the Corporation’s 50% interest in a joint venture involved in the construction of an electric generating facility in Newark, New Jersey.  The remaining increase in 2015 compared to the year-ago periods is primarily attributable to higher pension expense.  Interest expense was lower in the three and six months of 2015 compared to the same periods in 2014 primarily due to lower interest rates in 2015.  The reduction in capitalized interest in the three and six months ended June 30, 2015 relative to the same periods in 2014 is associated with the cessation of capitalized interest on the Tubular Bells Field upon first production in the fourth quarter of 2014.  Third quarter 2015 Corporate expenses are expected to be in the range of $30 million to $35 million after taxes and interest expense is expected to be in the range of $50 million to $55 million after taxes.  Excluding items affecting comparability of earnings, the estimate for corporate expenses for full year 2015 is still expected to be in the range of $120 million to $130 million after taxes and interest expense is still estimated to be in the range of $205 million to $215 million after taxes.

Items Affecting Comparability of Earnings Between Periods:

In the first quarter of 2015, the Corporation incurred exit costs of $6 million ($4 million after income taxes). During the first quarter of 2014, the corporation recorded a charge of $84 million ($52 million after income taxes) to reduce the carrying value of its investment in the Bayonne Energy Center to fair value.  In the three and six months ended June 30, 2014 the Corporation recorded severance and other exit costs of $15 million ($9 million after income taxes) and $27 million ($17 million after-tax).

Discontinued Operations

The net loss attributable to Hess Corporation from discontinued operations was $14 million and $43 million for the three months ended June 30, 2015 and 2014, respectively, and $27 million and $21 million during the six months ended June 30, 2015, and 2014, respectively.  The loss in the second quarter resulted from a pension settlement charge, employee related costs and other miscellaneous expenses.  The Corporation sold its interest in HETCO, its energy trading joint venture, in February 2015 and the retail marketing business in September 2014.  

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources

 

The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources:

In July 2015, the Corporation received after-tax cash proceeds of approximately $3 billion from the Bakken Midstream joint venture transaction.  See Note 14, Subsequent Event, in Notes to Consolidated Financial Statements for further information.

 

Cash Flows

The following table summarizes the Corporation’s cash flows:

Operating activities:  Net cash provided by operating activities was $1,076 million in the first six months of 2015, compared with $2,061 million in the same period of 2014, primarily reflecting the decline in benchmark crude oil prices.  

Investing activities:  Additions to property, plant and equipment were higher in the six months of 2015 compared to the same period in 2014 primarily due to a net decrease in the Corporation’s capital expenditure accruals of approximately $170 million.  During the first half of 2014, the Corporation received proceeds of approximately $805 million from the sale of its assets in Thailand, approximately $650 million from the sale of its interest in the Pangkah Field, offshore Indonesia, approximately $1,075 million from the sale of dry gas acreage in the Utica, including related wells and facilities, and $320 million from the sale of the Corporation 50% interest in the Newark, New Jersey power plant.  

In January 2014, the Corporation acquired its partners’ 56% interest in WilcoHess, a retail gasoline joint venture, for approximately $290 million which is reported in discontinued operations.  In June 2014, the Corporation incurred capital expenditures of $105 million related to the acquisition of previously leased gasoline stations. Both of these transactions were undertaken in connection with the Corporation’s divesture of its retail marketing business.

Financing activities: In the first six months of 2015, the Corporation repaid $34 million of debt.  The Corporation also purchased $27 million of common shares under its Board authorized $6.5 billion repurchase plan and settled $51 million of

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PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

 

common stock purchases from 2014.  Common stock purchases were approximately $1,735 million in the first six months of 2014.  Dividends paid were $144 million in the first six months of 2015 compared to $156 million in the first six months of 2014 representing a dividend rate of $0.50 per common share in both periods.

Future Capital Requirements and Resources

The Corporation anticipates investing approximately $4.4 billion in capital and exploratory expenditures during 2015 of which $4.1 billion relates to E&P.  Based on current strip crude oil prices, the Corporation forecasts in 2015 a significant net loss and a net cash flow deficit, excluding proceeds from asset sales, after funding planned capital expenditures, dismantlement obligations, pension contributions, dividends and share repurchases under its Board authorized plan. The Corporation expects to fund its 2015 net cash flow deficit with existing cash on hand, proceeds from the July 2015 sale of a 50% interest in its Bakken Midstream business, which resulted in approximately $3.0 billion of total after-tax cash proceeds to the Corporation and, if necessary, borrowings under its long-term syndicated revolving credit facility.

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. The Corporation plans to maintain its financial flexibility and to reduce its cash flow deficit by pursuing further cost reductions and supply chain savings, significantly moderating stock repurchases compared with 2014, and depending on where crude oil prices trend, potentially further reducing its planned capital program. In addition, should needs dictate, the Corporation may also access other sources of liquidity by utilizing existing uncommitted credit facilities, issuing debt and equity securities, and/or pursuing further asset sales.

The table below summarizes the capacity, usage and available capacity of the Corporation’s borrowing and letter of credit facilities at June 30, 2015:

The Corporation’s $128 million in letters of credit outstanding at June 30, 2015 are primarily issued to satisfy performance obligations related to the Corporation’s exploration and production activities.

In January 2015, the Corporation entered into a $4 billion syndicated revolving credit facility that expires in January 2020.  The new facility, which replaced a $4 billion facility that was scheduled to expire in April 2016, can be used for borrowings and letters of credit.  Based on the Corporation’s credit rating as of June 30, 2015, borrowings on the facility will generally bear interest at 1.075% above the London Interbank Offered Rate.  A fee of 0.175% per annum is also payable on the amount of the facility.  The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes.  

The Corporation’s long-term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt.  These financial covenants do not currently materially impact the Company’s ability to issue indebtedness to fund its future capital requirements.

The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Market Risk Disclosures

The Corporation is exposed in the normal course of business to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values.  See Note 13, Financial Risk Management, in the Notes to Consolidated Financial Statements. In the disclosures that follow, risk management activities refer to the mitigation of these risks through hedging activities.

Value at Risk: The Corporation uses value at risk to monitor and control commodity risk within its risk management 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 may vary from time to time as hedging levels change in risk management activities.  The potential change in fair value based on commodity price risk is presented in the financial risk management activities section below.

Financial Risk Management Activities

In the first quarter of 2015, the Corporation entered into Brent crude oil collars to hedge 50,000 bopd from March 2015 to December 2015.  This program was supplemented in the second quarter of 2015 by entering into West Texas Intermediate crude oil collars to hedge 20,000 bopd from May 6, 2015 to December 2015.  Under the terms of both programs, the floor price to be received by the Corporation is $60 per barrel and the ceiling price it may receive is $80 per barrel.

The Corporation estimates that the value at risk associated with crude oil collars was $11 million at June 30, 2015.  The results may vary from time to time primarily as crude oil prices or hedge levels change.

The Corporation has outstanding foreign exchange contracts used to reduce its exposure to fluctuating foreign exchange rates for various currencies.  The change in fair value of foreign exchange contracts from a 10% weakening of the U.S. Dollar exchange rate is estimated to be a loss of approximately $95 million at June 30, 2015.

The Corporation’s outstanding long-term debt of $5,957 million, including current maturities, had a fair value of $6,642 million at June 30, 2015.  A 15% decrease in the rate of interest would increase the fair value of debt by approximately $480 million at June 30, 2015.  A 15% increase in the rate of interest would decrease the fair value of debt by approximately $420 million at June 30, 2015.

Discontinued Operations – Trading Activities

In the first quarter of 2015, the Corporation sold its interest in its energy trading joint venture, HETCO.  Pursuant to the terms of the sale, the successor entity is permitted to continue to utilize the Corporation’s guarantees issued in favor of counterparties existing as of the sales date until November 12, 2015, provided that new trades are for a period of one year or less, comply with certain credit requirements, and net exposures remain within value at risk limits previously applied by the Corporation. The Corporation has the right to seek reimbursement from the successor entity upon any counterparty drawing on the applicable guarantee from the Corporation.  The fair value of the guarantee recorded by the Corporation amounted to $11 million.

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, costs and expenses, tax rates, debt repayment, hedging, derivative and market risk disclosures 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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PART I - FINANCIAL INFORMATION (CONT’D.)

 

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, 2015, 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, 2015.

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, 2015 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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PART II - OTHER INFORMATION

 

 

Information regarding legal proceedings is contained in Note 11, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

The Corporation’s share repurchase activities for the three months ended June 30, 2015, were as follows:

 

On August 3, 2015, the Corporation entered into Change in Control Termination Benefits Agreements (the “CIC Agreements”) with Michael R. Turner, the Corporation’s Senior Vice President of Onshore, and four other senior officers of the Corporation (each, an “Executive”) to align the termination benefits for the Executives with the termination benefits currently in place for the Corporation’s other senior officers. The CIC Agreements are “double trigger” and provide for lump sum cash payments equal to two times the Executive’s annual compensation if within 24 months following a change in control, the employment of the Executive is terminated by the Executive for good reason or by the Corporation without cause, in each case as defined in the CIC Agreements. For these purposes, annual compensation consists of: (1) the Executive’s base pay at the date of his or her termination or immediately before the change in control, whichever is higher, plus (2) the greater of his or her target bonus for the year in which the change in control occurs or the highest bonus earned in the three fiscal years preceding the change in control. In addition, the Executive is entitled to receive a prorated portion of his or her target bonus for the fiscal year in which termination occurs.

The CIC Agreements provide for the continuation of medical, dental and other welfare benefits for 24 months following termination and up to $30,000 of reasonable outplacement assistance through the end of the second year following termination. The Executive’s stock options will vest and become fully exercisable, and all other stock-based awards will vest (with any performance criteria deemed to be met at target), on the date of termination. The CIC Agreements also provide for immediate vesting of retirement benefits upon termination, deemed age and service credit of an additional two years for purposes of determining retirement benefits, and deemed compensation in determining retirement benefits for those two years equal to the annual compensation used to calculate the lump sum severance payment, as described above.

The Executives are not entitled to a “gross-up” payment from the Corporation for any excise tax imposed by the Internal Revenue Code on “excess parachute payments” resulting from a change in control, but payments and benefits under the CIC Agreements may be reduced in order to avoid the application of such excise tax if the reduction would increase the net after-tax amount received by the Executive.

The CIC Agreements have an initial term of two years and are automatically extended so that there will at all times be two years remaining in the term, unless the Corporation elects to end automatic extensions, in which case the term will end two years after the Corporation provides such notice to the Executives. The CIC Agreements will otherwise terminate on the earlier of: (1) two years following a change of control, or (2) if prior to a change of control, the date the Executive’s employment with the Corporation is terminated.

The foregoing summary is qualified in its entirety by reference to the full text of the CIC Agreements, a form of which is filed as Exhibit 10.3 hereto and incorporated herein by reference.

 

 

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PART II - OTHER INFORMATION (CONT’D.)

 

 

 

 

 

 

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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.

 

Date: August 7, 2015

 

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