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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

For the quarter ended September 30, 2017

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  ☒    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  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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  ☒

At September 30, 2017, there were 317,754,024 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 our consolidated financial position at September 30, 2017 and December 31, 2016, the consolidated results of operations for the three months and nine months ended September 30, 2017 and 2016, and consolidated cash flows for the nine months ended September 30, 2017 and 2016.  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 generally accepted accounting principles (GAAP) in the United States 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, 2016.

On January 1, 2017, the Corporation’s interests in a Permian Basin gas plant in West Texas and related CO₂ assets, and water handling assets in North Dakota were transferred from the Exploration and Production (E&P) segment to the Midstream segment as a result of organizational changes to the management of these assets.  These assets were wholly-owned by the Corporation and are not included in our Hess Infrastructure Partners joint venture.  Prior period information has been recast to conform to the current period presentation.  See Note 12, Segment Information.  In the third quarter of 2017, we completed the sale of our enhanced oil recovery assets in the Permian basin, including the gas plant in West Texas and related CO₂ assets.  See Note 2, Disposition.

In the first quarter of 2017, we adopted Accounting Standards Update (ASU) 2016-16, Income Taxes – Intra-Entity Transfer of Assets Other than Inventory.  This ASU requires the recognition of income tax consequences from intra-entity transfer of assets other than inventory when the transfer occurs.  The adoption of this standard was applied on a modified retrospective basis through a cumulative effect adjustment as of January 1, 2017, that resulted in a decrease to Retained earnings and a decrease to Deferred income taxes, included in non-current assets, of $37 million.

In the first quarter of 2017, we adopted ASU 2016-09, Improvements to Employee Share-Based Payment Accounting.  This ASU makes changes to various provisions associated with share-based accounting, including provisions affecting the accounting for income taxes, the accounting for forfeitures, the presentation of the statements of cash flow, and the consideration of net settlement provisions on the balance sheet classification of the share-based award.  As part of the adoption of this ASU, we elected to account for forfeitures of share-based awards in the period when they occur.  The effect of this election was applied on a modified retrospective basis through a cumulative effect adjustment as of January 1, 2017, that resulted in a decrease to Retained earnings and an increase to Capital in excess of par value of $2 million.  The cumulative effect adjustment to deferred tax assets for excess tax benefits not previously recognized as of the beginning of the period was offset by a corresponding change in valuation allowance, resulting in no cumulative effect adjustment to Retained earnings.  Further, as part of the adoption of this ASU, we have applied its provisions affecting excess tax benefits on a prospective basis in the statement of income and the statement of cash flows, effective January 1, 2017.

New Accounting Pronouncements:  In May 2014, the Financial Accounting Standards Board (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 us beginning in the first quarter of 2018.  As of September 30, 2017, our analysis of contracts with customers against the requirements of the standard is largely complete.  Based on our assessment to date, we have not identified any changes to the timing of revenue recognition based on the requirements of ASC 606 that would have a material impact on our consolidated financial statements.  We plan to adopt ASC 606 using the modified retrospective method that requires application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to Retained earnings as of January 1, 2018.

In February 2016, the FASB issued ASU 2016-02, Leases, as a new ASC Topic, ASC 842.  The new standard will require assets and liabilities to be reported on the balance sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard.  This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We have developed a project plan for the implementation of ASC 842 in the first quarter of 2019 and begun assessing existing leases against the requirements of the standard.  We continue to assess the impact of the ASU on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses.  This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments.  The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model.  This

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted from the first quarter of 2019.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01, Business Combinations – Clarifying the Definition of a Business.  This ASU provides a screen that excludes an integrated set of activities and assets from the definition of a business if the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets.  This ASU also clarifies that an integrated set of activities and assets must include (at a minimum), an input and a substantive process that together significantly contribute to the ability to create output to be considered a business.  This ASU is effective for us beginning in the first quarter of 2018, with early application permitted.  Application of this ASU is on a prospective basis only when adopted.

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment.  This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value.  Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value.  The impairment charge would be limited by the amount of goodwill allocated to the reporting unit.  This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits.  This ASU requires that an employer disaggregate the service cost component from the other components of net periodic benefit cost.  The amendments also provide explicit guidance on how to present the service cost component and the other components of net periodic benefit cost in the statement of income and allow only the service cost component of net periodic benefit cost to be eligible for capitalization.  This ASU is effective for us beginning in the first quarter of 2018, with early application permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities.  This ASU aims to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements.  In addition, this ASU make certain targeted improvements to simplify the application of the existing hedge accounting guidance.  This ASU is effective for us beginning in the first quarter of 2019, with early application permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

2.  Disposition

In the third quarter of 2017, we completed the sale of our enhanced oil recovery assets in the Permian Basin for proceeds of $597 million, after normal closing adjustments, and recognized a pre-tax gain of $273 million ($280 million attributable to Hess Corporation after income taxes and noncontrolling interest).  This sale transaction included both upstream and midstream assets resulting in an after-tax gain of $314 million allocated to the E&P segment, and an after-tax loss of $34 million allocated to the Midstream segment.

3.  Impairment

In the third quarter of 2017, we recorded a pre-tax impairment charge of $2,503 million ($550 million after income taxes) to impair the carrying value of our interests in Norway based on the anticipated sale of this asset using Level 3 inputs.  Upon recognition of the impairment and corresponding tax benefit of $1,953 million, the deferred tax position recognized for Norway on the Consolidated Balance Sheet changed to a non-current deferred tax asset from a net non-current deferred tax liability.  See Note 14. Subsequent Events.

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

4.  Inventories

Inventories consisted of the following:

 

 

5.  Capitalized Exploratory Well Costs

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the nine months ended September 30, 2017 (in millions):

 

Reclassifications to wells, facilities and equipment based on the determination of proved reserves resulted primarily from sanction of the first phase of development for the Liza Field, offshore Guyana.  Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $404 million at September 30, 2017 and primarily related to:  

Ghana:  Approximately 65% of the capitalized well costs in excess of one year relates to our Deepwater Tano/Cape Three Points license (Hess 50%), offshore Ghana.  The government of Côte d’Ivoire had challenged the maritime border between it and the country of Ghana, which includes a portion of our Deepwater Tano/Cape Three Points license.  The International Tribunal for Law of the Sea rendered a final ruling on the maritime border dispute in September 2017 in favor of Ghana.  Under terms of our license, we now have ten months to submit a plan of development to the Ghanaian government.  We have declared commerciality for four discoveries, including the Pecan Field in March 2016, which would be the primary development hub for the block.  Front-end engineering studies and other development planning are progressing.

Gulf of Mexico: Approximately 25% of the capitalized well costs in excess of one year relates to an appraisal well in the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015.  The operator is evaluating plans for developing this area of the field.

JDA:  Approximately 10% of the capitalized well costs in excess of one year relates to the JDA in the Gulf of Thailand (Hess 50%) where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18.  We, along with our partner, are currently evaluating results and formulating future drilling plans in the area.

6.  Goodwill

The changes in the carrying amount of goodwill were as follows:

 

The change in the carrying amount of goodwill relates to the sale of our enhanced oil recovery assets in the Permian Basin. See Note 2, Disposition.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

7.  Hess Infrastructure Partners LP

We consolidate the activities of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), which qualifies as a variable interest entity (VIE) under U.S. GAAP.  We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly impact the economic performance of HIP.

HIP, which owns Bakken midstream assets, is a component of our Midstream segment.  At September 30, 2017, HIP liabilities totaling $756 million (December 31, 2016: $841 million) are on a nonrecourse basis to Hess Corporation, while HIP assets available to settle the obligations of HIP include cash and cash equivalents totaling $50 million (December 31, 2016: $2 million) and property, plant and equipment with a carrying value of $2,516 million (December 31, 2016: $2,528 million).

8.  Hess Midstream Partners LP – Initial Public Offering

In April 2017, Hess Midstream Partners LP (the “Partnership”), sold 16,997,000 common units representing limited partner interests at a price of $23 per unit in an initial public offering (IPO) for net proceeds of $365.5 million, of which $350 million was distributed 50/50 to Hess Corporation and GIP.  

The Partnership owns an approximate 20% controlling interest in the operating companies that comprise our midstream joint venture, while HIP, the 50/50 joint venture between Hess Corporation and GIP, owns the remaining 80%.  Hess Corporation and GIP each own a direct 33.75% limited partner interest in the Partnership and a 50% indirect ownership interest through HIP in the Partnership’s general partner, which has a 2% economic interest in the Partnership plus incentive distribution rights.  The public unit holders own a 30.5% limited partner interest in the Partnership.

The Partnership has a $300 million 4-year senior secured syndicated revolving credit facility, which became available for utilization at completion of the IPO.  The credit facility can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At September 30, 2017, this facility was undrawn.

9. Retirement Plans

Components of net periodic pension cost consisted of the following:

In 2017, we expect to contribute $52 million to our funded pension plans.  Through September 30, 2017, we have contributed $40 million to these plans.

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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 following table summarizes the number of antidilutive shares excluded from the computation of diluted shares:

During the nine months ended September 30, 2017, we granted 1,214,460 shares of restricted stock (2016: 1,656,598), 438,980 performance share units (2016: 447,536) and 662,819 stock options (2016: 824,225).

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

11.  Guarantees and Contingencies

We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings.  A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated.  If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies.  We cannot predict with certainty if, how or when existing claims, lawsuits and 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 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, claims and proceedings, including the matters described below, is not expected to have a material adverse effect on our financial condition.  However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.

We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline.  A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us.  The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE.  The majority of the cases asserted against us have been settled.  In June 2014, the Commonwealth of Pennsylvania and the State of Vermont each filed independent lawsuits alleging that we and all major oil companies with operations in each respective state, have damaged the groundwater in those states by introducing thereto gasoline with MTBE.  The Pennsylvania suit has been removed to Federal court and has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York.  The suit filed in Vermont is proceeding there in a state court.  In September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing gasoline with MTBE.  The suit filed in Rhode Island is proceeding in federal court.

In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River.  The NJDEP is also seeking natural resource damages.  The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned.  We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing.  We and other parties settled a cost recovery claim by the State of New Jersey and also agreed with EPA to fund remediation of a portion of the site.  On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion.  The ROD does not address the upper nine miles of the Lower Passaic River, which may require additional remedial action.  In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River.  Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River, total remedial costs cannot be reliably estimated at this time.  Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because there are numerous other parties who we expect will share in the cost of remediation and damages and our former terminal did not store or use contaminants which are of the greatest concern in the river sediments and could not have contributed contamination along most of the river’s length.

In March 2014, we received an Administrative Order from EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York.  The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap.  EPA has estimated that this remedy will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain.  Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected ship-building and repair facility adjacent to the Canal.  We indicated to EPA that we would comply with the Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs among the parties.  At the same time, we are participating in an allocation process whereby a neutral expert selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants.  The parties have not yet addressed the allocation of costs associated with implementing the remedy that is

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

currently being designed.

On January 18, 2017, we entered into a Consent Decree with the North Dakota Department of Health resolving alleged non-compliance with North Dakota’s air pollution laws and provisions of the federal Clean Air Act.  Pursuant to the Consent Decree, we were required to implement corrective actions, including implementation of a leak detection and repair program, at most of our existing facilities in North Dakota.  We were assessed a base penalty of $922,000 and made an initial penalty payment of $55,000 during the first quarter of 2017.  Based on corrective actions completed in accordance with the Consent Decree, the remainder of the penalty was reduced to $745,000 and paid in the third quarter of 2017.

From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters.  We 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 our financial condition, results of operations or cash flows.

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

12.  Segment Information

We currently have two operating segments, Exploration and Production and Midstream.  All unallocated costs are reflected under Corporate, Interest and Other.  The following table presents operating segment financial data:

 

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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 Activities

In the normal course of our business, we are exposed 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.  Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or by reducing our 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 our crude oil or natural gas production.  Forward contracts may also be used to purchase certain currencies in which we conduct the business with the intent of reducing exposure to foreign currency fluctuations.  At September 30, 2017, these forward contracts relate to the British Pound.  Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates and, in the case of certain long-term debt relating to our Midstream operating segment, from floating to fixed rates.

Gross notional amounts of both long and short positions are presented in the table 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.

The gross notional amounts of financial risk management derivative contracts outstanding were as follows:  

 

At September 30, 2017, we have outstanding Brent and West Texas Intermediate (WTI) crude oil collar positions by year of settlement as follows:

These crude oil price collars, which have been designated as cash flow hedges, reduce the price exposure to our crude oil production that is hedged.

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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 the risk management derivative instruments, all of which are based on Level 2 inputs:

Derivative contracts designated as hedging instruments:

Crude oil collars:  The impact from realized and unrealized movements in crude oil price collars on Sales and other operating revenues was an increase of $6 million and a reduction of $5 million in the three and nine months ended September 30, 2017, respectively.  Realized and unrealized movements were inclusive of a $2 million charge for hedge ineffectiveness in the third quarter of 2017.  Reclassifications to the Statement of Consolidated Income from Other comprehensive income in the three and nine months ended September 30, 2017 amounted to gains of $18 million and $38 million, respectively.  At September 30, 2017, after-tax deferred losses in Accumulated other comprehensive income (loss) related to crude oil collars were $39 million, of which $33 million will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.  There were no crude oil hedge contracts in 2016.  

Interest rate swaps designated as fair value hedges:  At September 30, 2017 and December 31, 2016, Hess Corporation had interest rate swaps with gross notional amounts totaling $450 million and $350 million, respectively, which were designated as fair value hedges and relate to debt where we have converted interest payments on certain long-term debt from fixed to floating rates.  For the three and nine months ended September 30, 2017, the change in fair value of interest rate swaps was an increase in the liability of less than $1 million and $3 million respectively.  There was an increase of $9 million and a decrease of $9 million in the liability in the third quarter and first nine months of 2016, respectively.  Changes in the fair value of the interest rate swaps and the hedged fixed‑rate debt are recorded in Interest expense in the Statement of Consolidated Income.

Interest rate swaps designated as cash flow hedges:  At September 30, 2017, HIP had interest rate swaps with gross notional amounts totaling $459 million, which convert interest payments on certain long-term debt from floating to fixed rates.  For the three and nine months ended September 30, 2017, the change in fair value of interest rate swaps was an increase to assets of $1 million and $2 million, respectively.  At September 30, 2017, the after-tax deferred gains in Accumulated other comprehensive income (loss) related to interest rate swaps was $2 million before noncontrolling interests, which will be reclassified into earnings as the hedged interest payments are recognized in the Statement of Income.  Of this amount, losses of less than $1 million will be reclassified into earnings during the next 12 months.  There were no floating to fixed interest rate swap contracts in 2016.  

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PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Derivative contracts not designated as hedging instruments:

Foreign exchange:  Foreign exchange gains, which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income were $17 million and $26 million in the three months and nine months ended September 30, 2017, respectively, compared with $11 million and $32 million in the third quarter and first nine months of 2016, respectively.  A component of foreign exchange gains is the result of foreign exchange derivative contracts that are not designated as hedges.  These contracts had gains of less than $1 million and $2 million in the third quarter and first nine months of 2017, respectively, compared to a loss of $2 million and a gain of $11 million in the third quarter and first nine months of 2016, respectively.  

The after‑tax foreign currency translation adjustments included in the Statement of Consolidated Comprehensive Income amounted to gains of $121 million and $208 million in the three months and nine months ended September 30, 2017, respectively, compared to gains of $117 million and $259 million in the third quarter and first nine months of 2016, respectively.  The cumulative currency translation adjustment at September 30, 2017, was a reduction to shareholders’ equity of $837 million compared with a reduction of $1,045 million at December 31, 2016.

Fair Value Measurement:  We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at September 30, 2017.  Total long-term debt with a carrying value of $6,714 million at September 30, 2017, had a fair value of $7,157 million based on Level 2 inputs.

14.  Subsequent Events

On October 23, 2017, we announced the sale of our interests in offshore Equatorial Guinea for total consideration of $650 million before normal closing adjustments, based on an effective date of January 1, 2017.  As a result of the sale, we forecast a pre-tax gain of approximately $475 million ($475 million after income taxes) in the fourth quarter of 2017. These assets produced an average of 28,000 barrels of oil equivalent per day (boepd) during the first nine months of 2017.

On October 24, 2017, we announced the sale of our interests in offshore Norway for total consideration of $2 billion before normal closing adjustments, based on an effective date of January 1, 2017.  In the fourth quarter of 2017, we will record a charge for the cumulative translation adjustment in Stockholders’ Equity in the Consolidated Balance Sheet for Norway, which was approximately $840 million at September 30, 2017.  Once the transaction has closed, the charge related to the cumulative translation adjustment will have no impact to Stockholders’ Equity, as the reduction to Retained Earnings will be offset by an increase in Accumulated Other Comprehensive Income (Loss).  These assets produced an average of 24,000 boepd during the first nine months of 2017.

On October 24, 2017, we also announced that we would commence a process to sell our interests in Denmark where we hold a 61.5% interest in the South Arne Field.  This sales process is expected to be completed in 2018.  The South Arne Field produced an average of 11,000 boepd during the first nine months of 2017.

 

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Overview

Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Norway.  The Corporation has exploration and development activities in the Stabroek Block, offshore Guyana, where we have participated in five significant crude oil discoveries and sanctioned the first phase of a multi-phase development project at the Liza Field.  

The Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas and fractionating natural gas liquids (NGLs); gathering, terminaling, loading and transporting crude oil and NGLs; and storing and terminaling propane, primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.  Beginning January 1, 2017, Hess’ Midstream segment includes our interests in a Permian Basin gas plant in West Texas and related CO₂ assets, which were sold on August 1, 2017, and water handling assets in North Dakota.  The water handling assets are wholly-owned by the Corporation and are not held in our Hess Infrastructure Partners joint venture.  Certain previously reported amounts have been recast to reflect the inclusion of these assets as part of the Midstream operating segment.  In the third quarter of 2017, we completed the sale of our E&P and Midstream enhanced oil recovery assets in the Permian Basin.  See Note 2, Disposition in the Notes to Consolidated Financial Statements.  

Outlook

We forecast net production, excluding assets sold and Libya, to average 300,000 barrels of oil equivalent per day (boepd) in 2017 and to average between 290,000 boepd and 300,000 boepd in the fourth quarter of 2017.  In October 2017, we announced the sale of our interests in Equatorial Guinea for $650 million and Norway for $2 billion before normal closing adjustments, based on an effective date of January 1, 2017.  The sale of our interests in Equatorial Guinea is expected to close later in the fourth quarter and the sale of our interests in Norway is expected to close following receipt of government approvals.  As proceeds are received, we intend to reduce debt by $500 million in 2018 and use the remainder primarily for funding our development projects.  We also plan to commence a process to sell our interests in Denmark that is expected to be completed in 2018.  See Note 14, Subsequent Events in the Notes to Consolidated Financial Statements.

Net cash provided by operating activities was $602 million in the first nine months of 2017, compared to $469 million in the first nine months of 2016, while capital expenditures for the first nine months of 2017 and 2016 were $1,426 million and $1,512 million, respectively.  Based on current forward strip crude oil prices for 2018, which are comparable to 2017 prices, we forecast a net operating cash flow deficit (including capital expenditures) in 2018.  We expect to fund our net operating cash flow deficit (including capital expenditures) through the end of 2018 with existing cash and cash equivalents at September 30, 2017.

Third Quarter Results

In the third quarter of 2017, we incurred a net loss of $624 million compared to a net loss of $339 million in the third quarter of 2016.  Excluding items affecting comparability of earnings between periods on pages 25 to 27, the adjusted net loss for the quarter was $324 million compared to an adjusted net loss of $340 million in the third quarter of 2016.  The improved third quarter 2017 results reflect higher realized crude oil selling prices and lower operating costs, depreciation, depletion and amortization, and exploration expenses.  Third quarter 2017 results were adversely impacted by lower tax benefits compared to the prior-year quarter following a required change in deferred tax accounting.  On an adjusted pre-tax basis, we reported a loss of $307 million in the third quarter of 2017, down from $553 million in the year-ago quarter.  

Exploration and Production Results

In the third quarter of 2017, E&P had net loss of $474 million compared with a net loss of $234 million in the third quarter of 2016.  Excluding items affecting comparability of earnings between periods, the adjusted net loss for the third quarter of 2017 was $238 million compared to an adjusted net loss of $285 million in 2016.  Total net production, excluding assets sold and Libya, averaged 296,000 boepd in the third quarter of 2017, compared to an equivalent of 307,000 boepd in the third quarter of 2016.  The average realized crude oil selling price, including hedging, was $46.97 per barrel, up from $41.50 in the third quarter of 2016.  The average realized natural gas liquids selling price in the third quarter of 2017 was $17.22 per barrel, up from $9.23 in the prior-year quarter, while the average realized natural gas selling price was $3.35 per thousand cubic feet (mcf), up from $3.20 in the third quarter of 2016.  The E&P effective tax rate, excluding items affecting comparability of earnings between periods and Libyan operations, was a benefit of 18% in the third quarter of 2017, down from a benefit of 41% in the third quarter of 2016.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Overview (continued)

The following is an update of our ongoing E&P activities:

Producing E&P assets:

Other E&P assets:

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated 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 a pre-tax basis, items of income (expense) that are included in income (loss) before income taxes and affect 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 tables above are explained on pages 25 to 27.

Reconciliations of GAAP and non-GAAP measures

The following table reconciles reported income (loss) before income taxes and adjusted income (loss) before income taxes:

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

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

“Adjusted income (loss) before income taxes” presented in this report is a non-GAAP financial measure, which we define as reported income (loss) before income taxes excluding items identified as affecting comparability of earnings between periods.  “Adjusted net income (loss) attributable to Hess Corporation” is also presented in this report and is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods.  Management uses both adjusted income (loss) before income taxes and adjusted net income (loss) to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing these measures, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations.  These measures are not, and should not be viewed as, substitutes for U.S. GAAP income (loss) before incomes taxes or 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. 

Comparison of Results

Exploration and Production

Following is a summarized income statement of our E&P operations:

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Excluding the E&P Items affecting comparability of earnings between periods in the table on page 25, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, cost of products sold, cash operating costs, depreciation, depletion and amortization, midstream tariffs, exploration expenses and income taxes, as discussed below.

Selling Prices:  Higher realized selling prices in the third quarter and first nine months of 2017, improved after-tax results by approximately $50 million and $265 million, respectively, compared to the same periods in 2016.  Average selling prices were as follows:

 

In the third quarter of 2017, the Corporation increased its West Texas Intermediate (WTI) crude oil hedging program by 50,000 barrels of oil per day (bopd) to a total of 110,000 bopd through December 31, 2017.  In addition, the Corporation added WTI crude oil collars covering 115,000 bopd for 2018.

Realized and unrealized movements in crude oil price collars increased Sales and other operating revenues by $6 million in the third quarter of 2017, compared to a decrease in Sales and other operating revenues of $5 million in the nine months ended September 30, 2017.  There were no crude oil hedge contracts in 2016.

Our open Brent and WTI crude oil collar positions at September 30, 2017 are summarized in Note 13, Financial Risk Management Activities in the Notes to Consolidated Financial Statements.  

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Production Volumes:  Our daily worldwide net production was as follows:

We expect net production, excluding assets sold and Libya, to be in the range of 290,000 boepd and 300,000 boepd for the fourth quarter of 2017, resulting in full-year 2017 guidance of approximately 300,000 boepd.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

United States:  Onshore net liquids production was lower in the third quarter and first nine months of 2017, compared to corresponding periods in 2016, primarily due to the sale of our Permian assets in August 2017 and fewer well completions in the Bakken.  Onshore natural gas production was lower in the third quarter and first nine months of 2017 due to natural decline in the Utica shale play.  Offshore net crude oil production was lower in the third quarter and first nine months of 2017, compared to the corresponding periods in 2016, primarily due to shutdowns at the Llano Field and Penn State fields as well as natural field decline, partially offset by higher production from the Tubular Bells Field.  In addition, there was lower production from the Conger Field in the first half of 2017 due to planned and unplanned downtime.  Offshore net gas production was higher in the third quarter and first nine months of 2017, compared to corresponding periods in 2016, primarily due to higher uptime from the Tubular Bells Field in 2017.

International:  Net oil production was lower in the third quarter and first nine months of 2017, compared to corresponding periods in 2016, primarily due to a planned shutdown at the Valhall Field in Norway and natural field decline.  Net gas production was higher in the third quarter and first nine months of 2017, compared to the corresponding periods in 2016, primarily due to first production at the North Malay Basin full-field development in July 2017, and a temporary adjustment to entitlement and higher uptime at the JDA.

Sales Volumes:  Our worldwide sales volumes from Hess net production were as follows:

Lower sales volumes in the third quarter and first nine months of 2017 decreased after-tax results by approximately $35 million and $175 million, respectively, compared to the same periods in 2016.

Cost of Products Sold:  Cost of products sold is mainly comprised of costs relating to the purchases of crude oil, natural gas liquids and natural gas from our partners in Hess operated wells or other third parties.  The increase in Cost of products sold, in the third quarter and first nine months of 2017, compared to the same periods in 2016, primarily reflects the impact of higher benchmark crude oil prices on the cost of purchased volumes

Cash Operating Costs:  Cash operating costs, consisting of operating costs and expenses, production and severance taxes and E&P general and administrative expenses, were lower in the third quarter and first nine months of 2017, compared to the same periods in 2016, due to lower workover expenses, lease operating and employee costs, partially offset by higher production taxes in the Bakken shale play during the first half of 2017.

Depreciation, Depletion and Amortization:  DD&A expenses were lower in the third quarter and first nine months of 2017, compared with the prior-year periods, resulting from lower production and an improved portfolio average DD&A rate due to the production mix.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated 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 excludes items affecting comparability of earnings as described below.  Actual and forecast unit costs per boe are as follows:

Exploration Expenses:  Exploration expenses were as follows:

Exploratory dry hole costs in the third quarter of 2016 relates to the non-operated Skipjack well, offshore Guyana.  Exploratory dry hole costs in the first nine months of 2016 primarily related to the write-off of two wells at the non-operated Sicily prospect and a non-operated exploration well in the Gulf of Mexico.  Exploration expenses, excluding dry hole expense, are estimated to be in the range of $75 million to $85 million in the fourth quarter of 2017 and $225 million to $235 million for the full year of 2017.

Income Taxes:  The effective income tax rate for E&P operations, excluding items affecting comparability of earnings between periods and Libyan operations, was a benefit of 18% and 12% in the third quarter and first nine months of 2017, respectively, compared to a benefit of 41% and 42% in the third quarter and first nine months of 2016, respectively.  Commencing in 2017, we are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S., Denmark (hydrocarbon tax only), and Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with the requirements of U.S. accounting standards.  Excluding items affecting comparability of earnings between periods and Libyan operations, the E&P effective income tax rate is expected to be an expense in the range of 16% to 20% in the fourth quarter of 2017, and a benefit in the range of 5% to 9% for the full year of 2017.

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:

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

The following table summarizes, on a pre-tax basis, income (expense) items that affect comparability of E&P earnings between periods:

Impairment:  In the third quarter of 2017, we recorded a noncash impairment charge totaling $2,503 million pre-tax ($550 million after income taxes) associated with the anticipated sale of our interests in Norway.  See Note 3, Impairment in the Notes to Consolidated Financial Statements.

Gains on asset sales, net:  In the third quarter of 2017, we recorded a pre-tax gain of $330 million ($314 million after income taxes) associated with the sale of our enhanced oil recovery assets in the Permian Basin related to our E&P operations.  In the second quarter of 2016, we recognized a pre-tax gain of $27 million ($17 million after income taxes) related to the sale of undeveloped Onshore acreage in the United States.

Tax benefits:  In the third quarter of 2016, we recorded a tax benefit of $51 million related to the resolution of certain international tax matters.

Exploration expense:  In the second quarter of 2016, we recorded a pre-tax charge of $83 million ($52 million after income taxes) to write-off the previously capitalized Sicily #1 exploration well completed in 2015.

Contract termination costs:  In the second quarter of 2016, we incurred a pre-tax charge of $36 million ($22 million after income taxes) associated with the termination of an Offshore drilling rig contract.  The rig termination charge is included in Operating costs and expenses in the Statement of Consolidated Income.

Midstream

Following is a summarized income statement of our Midstream operations:

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Sales and other operating revenues for the third quarter and first nine months of 2017 increased from the corresponding periods in the prior year primarily due to higher deferred minimum volume deficiency payments earned, partially offset by lower rail export revenue associated with third-party rail charges and the sale of our Permian assets in August 2017.  Operating costs and expenses decreased in the third quarter and first nine months of 2017, compared with the same periods in 2016, primarily due to lower third-party rail charges and the sale of our Permian assets in August 2017.  Depreciation, depletion, and amortization increased in the first nine months of 2017, compared to the same period in 2016, due to gathering pipelines and related facilities that have been placed in service.  Net income attributable to Hess Corporation from the Midstream segment is estimated to be in the range of $15 million to $20 million in the fourth quarter of 2017 and $70 million to $75 million for the full year of 2017.

Items Affecting Comparability of Earnings Between Periods:  In the third quarter of 2017, we recorded a pre-tax loss of $57 million ($34 million after income taxes and noncontrolling interest) associated with the sale of our Midstream assets in the Permian Basin.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

Corporate and other expenses were higher in the third quarter of 2017, compared to the same period in 2016, primarily due to increased pension settlement charges in the third quarter of 2017.   Corporate and other expenses were higher in the first nine months of 2017, compared to the same period in 2016, primarily due to increased pension settlement charges in 2017 and the recognition of a nonrecurring gain of $8 million in 2016.  Capitalized interest was higher in the third quarter and first nine months of 2017, compared to the same periods in 2016, due to increased activity at the Hess operated Stampede development project and sanction of the Liza Field Phase 1 development project during the second quarter of 2017.  The benefit for income taxes is lower in the third quarter and first nine months of 2017, compared to the same periods in 2016, due to us generally not recognizing deferred tax benefit or expense in the U.S. while we maintain valuation allowances against net deferred tax assets in accordance with the requirements of U.S. accounting standards.

Fourth quarter 2017 corporate expenses, are expected to be in the range of $30 million to $35 million, and interest expense is expected to be in the range of $70 million to $75 million.  We estimate corporate expenses for full year 2017 to be in the range of $130 million to $135 million, and interest expense to be in the range of $300 million to $305 million.  

Items Affecting Comparability of Earnings Between Periods:  

In the third quarter of 2017, we incurred pre-tax charges of $30 million ($30 million after income taxes) in connection with vacated office space, of which, $11 million is included in General and administrative expenses and $19 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.   In the third quarter of 2016, we purchased $650 million principal amount of tendered 8.125% notes due 2019.   This transaction resulted in a pre-tax debt extinguishment charge of $80 million ($50 million after income taxes).

Other Items Potentially Affecting Future Results

Our future results may be impacted by a variety of factors, including but not limited to, volatility in the selling prices of crude oil, natural gas liquids and natural gas, reserve and production changes, asset sales, impairment charges and exploration expenses, industry cost inflation and/or deflation, changes in foreign exchange rates and income tax rates, changes in deferred tax asset valuation allowances, the effects of weather, political risk, environmental risk and catastrophic risk.  For a more comprehensive description of the risks that may affect our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Liquidity and Capital Resources

The following table sets forth certain relevant measures of our liquidity and capital resources:

Cash Flows

The following table summarizes our cash flows:

Operating activities:  Net cash provided by operating activities was $602 million in the first nine months of 2017, compared to $469 million in the first nine months of 2016.  The increase in 2017 operating cash flows primarily reflects higher benchmark crude oil prices and lower operating costs, partially offset by lower production volumes.  Changes in working capital were a use of cash of $588 million in the first nine months of 2017, and a use of cash of $245 million in the first nine months of 2016.  Changes in working capital during 2017 primarily related to abandonment expenditures, premiums on crude oil hedging contracts, termination payments for an offshore drilling rig and crude oil delivered as line fill.

Investing activities:  The reduction in cash outflows from investing activities is due to higher proceeds from asset sales and lower Additions to property, plant and equipment.  Proceeds from asset sales totaled $783 million in the first nine months of 2017 and primarily relate to the sale of our enhanced oil recovery assets in the Permian Basin and non-core acreage, onshore United States.

The following table reconciles capital expenditures incurred on an accrual basis to Additions to property, plant and equipment:  

Financing activities: In 2017, Hess Midstream Partners LP received proceeds of $365.5 million from the issuance of common units in an initial public offering, of which $350 million was distributed 50/50 to Hess Corporation and GIP.  We paid common and preferred stock dividends totaling $273 million in the first nine months of 2017, compared to $260 million in the first nine months of 2016.  In the first nine months of 2016, we issued $1.5 billion of senior notes and we repaid total debt of $820 million.  In the first nine months of 2016, we also issued $1.64 billion of preferred and common stock.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Liquidity and Capital Resources (continued)

Future Capital Requirements and Resources

Excluding our Midstream segment, we ended the quarter with approximately $2.5 billion in cash and cash equivalents and total liquidity including available committed credit facilities of approximately $6.8 billion.  The Corporation has no significant near-term debt maturities.  Excluding Midstream debt that is non-recourse to Hess, the Corporation’s debt maturities through 2022 amount to $19 million for the remainder of 2017, $78 million in 2018, $389 million in 2019, and zero in 2020, 2021 and 2022.

Net cash provided by operating activities was $602 million in the first nine months of 2017, compared to $469 million in the first nine months of 2016, while capital expenditures for the first nine months of 2017 and 2016 were $1,426 million and $1,512 million, respectively.  Based on current forward strip crude oil prices for 2018, which are comparable to 2017 prices, we forecast a net operating cash flow deficit (including capital expenditures) in 2018.  We expect to fund our net operating cash flow deficit (including capital expenditures) through the end of 2018 with existing cash and cash equivalents at September 30, 2017.

The table below summarizes the capacity, usage and available capacity of our borrowings and letter of credit facilities at September 30, 2017:

Hess Corporation has a $4.0 billion syndicated revolving credit facility expiring in January 2020.  Borrowings on the facility will generally bear interest at 1.30% above the London Interbank Offered Rate (LIBOR).  The interest rate will be higher if our credit rating is lowered.  The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 65% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity.  As of September 30, 2017, Hess Corporation had no outstanding borrowings under this facility and was in compliance with this financial covenant.  

We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.

HIP has $1.0 billion of senior unsecured syndicated credit facilities, consisting of a $400 million 5-year revolving credit facility and a drawn $600 million 5-year Term Loan A facility.  The revolving credit facility can be used for borrowings and letters of credit to fund the joint venture’s operating activities and capital expenditures.  Term Loan A proceeds were used for a distribution to partners in July 2015.  Borrowings on both loan facilities generally bear interest at LIBOR plus an applicable margin ranging from 1.10% to 2.00%.  The interest rate is subject to adjustment based on HIP’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA).  If HIP obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time.  The credit facilities contain financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters.  HIP is in compliance with these financial covenants at the end of the third quarter.  At September 30, 2017, borrowings under HIP’s revolving credit facility amounted to $168 million and borrowings under the Term Loan A facility amounted to $534 million, excluding deferred issuance costs, which are non-recourse to Hess Corporation.

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Liquidity and Capital Resources (continued)

Hess Midstream Partners LP (the “Partnership”) has a $300 million 4-year senior secured syndicated revolving credit facility, that became available for utilization at completion of its initial public offering in April.  The credit facility can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership.  Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%.  The interest rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt to EBITDA.  Facility fees will accrue at 0.275% every quarter.  If the Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time.  The Partnership is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters.  The credit facility is secured by first priority perfected liens on substantially all directly owned assets of the Partnership and its wholly-owned subsidiaries, including equity interests in subsidiaries, subject to certain customary exclusions.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At September 30, 2017, this facility was undrawn.

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 Activities, in the Notes to Consolidated Financial Statements.

Financial Risk Management Activities

We have outstanding foreign exchange contracts with notional amounts totaling $35 million at September 30, 2017, to reduce our exposure to fluctuating foreign exchange rates for various currencies.  The change in fair value of foreign exchange contracts from a 10% strengthening of the U.S. Dollar exchange rate is estimated to be a loss of approximately $5 million at September 30, 2017.

At September 30, 2017, our outstanding long‑term debt of $6,714 million, including current maturities, had a fair value of $7,157 million.  A 15% increase or decrease in the rate of interest would decrease or increase the fair value of long-term debt, including the impact of interest rate swaps, by approximately $460 million or $530 million, respectively.

At September 30, 2017, we have outstanding Brent and WTI crude oil price collars.  See Note 13, Financial Risk Management Activities in the Notes to Consolidated Financial Statements.  

Forward-looking Information

Certain sections in this Quarterly Report on Form 10-Q, including information incorporated by reference herein, contain “forward-looking” statements, as defined under the Private Securities Litigation Reform Act of 1995.  Generally, the words “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which generally are not historical in nature.  Forward-looking statements related to our operations and financial conditions are based on our current understanding, assessments, estimates and projections.  Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or expectations.  As and when made, we believe that these forward-looking statements are reasonable.  However, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur.  We are not obligated to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  Risk factors that could materially impact future actual results are discussed in Item 1A. Risk Factors in our Annual Report on Form 10-K and in our other filings with the SEC.

 

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PART I - FINANCIAL INFORMATION (CONT’D.)

 

Item 3.Quantitative and Qualitative Disclosures about Market Risk.

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.”  

Item 4.Controls and Procedures.

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 September 30, 2017, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of September 30, 2017.

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 September 30, 2017 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

 

 

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PART II – OTHER INFORMATION

 

 

Item 1.          Legal Proceedings.

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.

Item 6.          Exhibits.

 

 

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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: November 6, 2017

 

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