.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

For the quarter ended September 30, 2018

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 every Interactive Data File required to be submitted 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 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, 2018, there were 296,253,136 shares of Common Stock outstanding.

 

 

 

 

---

 

HESS CORPORATION

Form 10-Q

TABLE OF CONTENTS

 

 

 

Unless the context indicates otherwise, references to “Hess”, the “Corporation”, “Registrant”, “we”, “us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.

---

PART I - FINANCIAL INFORMATION

 

 

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

2

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

 

3

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

 

4

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

5

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

 

See accompanying Notes to Consolidated Financial Statements.

 

 

6

 

---

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, 2018 and December 31, 2017, the consolidated results of operations for the three months and nine months ended September 30, 2018 and 2017, and consolidated cash flows for the nine months ended September 30, 2018 and 2017.  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, 2017.

In the first quarter of 2018, we adopted Accounting Standards Codification (ASC) Topic, ASC 606, Revenue from Contracts with Customers, using the modified retrospective method.  The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized.  Accounts receivables from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to conform to the current period presentation.  In addition, as the adoption of ASC 606 did not affect previous conclusions regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the Statement of Consolidated Income.

In the first quarter of 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.  This ASU prohibits the capitalization of the non-service cost components of net periodic benefit cost in connection with the production or construction of an asset.  This provision was applied prospectively effective January 1, 2018.  The provision requiring that non-service cost components of net periodic benefit cost to be presented separately from the service cost component in the Statement of Consolidated Income was applied retrospectively.  We elected the practical expedient allowing the use of the amounts previously disclosed in the notes to our consolidated financial statements as the basis for applying this provision retrospectively as the capitalization of the non-service cost components of net periodic benefit cost was not material during the comparative periods.  This resulted in a reclassification of $- million and $9 million of expense from Operating costs and expenses, and General and administrative expenses to Other, net for the three months ended and nine months ended September 30, 2017, respectively.

In the first quarter of 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities.  This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance.  The adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income (loss) of $1 million to remove the cumulative effect of hedging ineffectiveness previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018.  

In the first quarter of 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230):  Restricted Cash (a consensus of the FASB Emerging Issues Task Force).  This ASU requires that the total change in cash and cash equivalents and restricted cash be reflected on the statement of cash flows.  A reconciliation to the balance sheet is also required when cash and cash equivalents and restricted cash are not separately presented on the balance sheet or are presented in more than one financial statement line item on the balance sheet.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

In the first quarter of 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (a consensus of the FASB Emerging Issues Task Force).  This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The guidance addresses eight specific classification issues for which current guidance is either unclear or is non-specific.  The requirement that fees paid to third-parties and premiums incurred in connection with the repayment of debt be classified as financing cash outflows is among the classification issues addressed by this ASU.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

7

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

To conform with the Statement of Consolidated Income presentation in our December 31, 2017 Form 10-K, we have revised the presentation of Sales and other operating revenues and Marketing, including purchased oil and gas for the three months and nine months ended September 30, 2017 associated with the recovery of certain natural gas processing costs from third-parties, by reducing each by $22 million and $60 million, respectively.  This revision did not impact net income, our Consolidated Balance Sheet, Statement of Consolidated Comprehensive Income, Statement of Consolidated Cash Flows, nor Statement of Consolidated Equity.  Amounts reported as Sales and other operating revenues and Marketing, including purchased oil and gas (formerly Costs of products sold) in our September 30, 2017 Form 10-Q were $1,370 million and $360 million, respectively, for the third quarter of 2017 and $3,863 million and $851 million, respectively, for the nine months ended September 30, 2017.

New Accounting Pronouncements:  In February 2016, the FASB issued ASU 2016-02, Leases, as a new Accounting Standards Codification (ASC) Topic, ASC 842.  The new standard supersedes ASC 840 and will require the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year, including leases currently treated as operating leases under ASC 840.  ASC 842 is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We have elected to adopt ASC 842 on January 1, 2019 using the modified retrospective method which allows application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to Retained Earnings at the date of adoption.  Accordingly, comparative financial statements for periods prior to the adoption date of ASC 842 will not be affected.    In addition, we have elected to apply the ‘package’ of practical expedients allowing us to avoid reassessing whether existing contracts are (or contain) leases, whether the lease classification for existing leases would differ under ASC 842, and whether initial direct costs incurred for existing leases are capitalizable under ASC 842.  Finally, we have elected to apply the practical expedient allowing us to avoid reassessing land easements that were not previously accounted for as leases under ASC 840.  We have not elected the ‘hindsight’ practical expedient when determining lease term.  As part of our ASC 842 implementation project, we continue to evaluate contracts, monitor standard setting activity, and evaluate our internal controls to comply with the accounting and disclosure requirements of ASC 842.  Although we cannot reasonably estimate the quantitative impact ASC 842 will have on our consolidated financial statements at the effective date, we believe adoption will have a material effect on our Consolidated Balance Sheet due to the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year.  We enter into various leases in the normal course of business primarily for drilling rigs, a floating storage and offloading vessel, support vessels, and office space.

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 ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in 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 2017-04, 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 February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220):  Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.  This ASU allows the reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”).  Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual items (or of the underlying portfolio of items) within Accumulated other comprehensive income (loss).  This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

8

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2.  Revenue

Revenue from contracts with customers on a disaggregated basis was as follows:

 

 

Exploration and Production

The E&P segment recognizes revenue from the sale of crude oil, natural gas liquids (NGLs), and natural gas as performance obligations under contracts with customers are satisfied.  Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations.  These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer.  Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery.  Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.

Our responsibility to stand-ready to provide a minimum volume over each commitment period under long-term international gas contracts with take-or-pay provisions represent separate, distinct performance obligations.  Shortfall payments received from customers that occur when volumes purchased are below the minimum volume commitment under contracts with customer make-up rights are deferred upon receipt as a contract liability.  Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights.  Price discounts owed against future deliveries of international natural gas due to delivery of natural gas volumes below customer nominations are recognized as reductions to revenue in the commitment period when the shortfall occurs.

Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers.  Where control over the crude oil, NGLs, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively.  Where control of crude oil,

9

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.

Contract types

The following is a summary of contract types for our E&P segment:

Crude oil, NGLs, and natural gas – United States (U.S.):  Contracts with customers for the sale of U.S. crude oil, NGLs, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels.  We have certain long-term contracts with customers for the sale of U.S. natural gas and NGLs that have remaining durations of less than ten years.  Contracts may specify a fixed volume for delivery subject to tolerance thresholds or may specify a percentage of production to be delivered from a particular location.  Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.

Crude oil – International:  Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period.  These contracts specify a fixed volume for delivery subject to tolerance thresholds.  Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer.

Natural gas – International:  Contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments.  Pricing is determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors.  These contracts also specify a minimum volume we are obligated to make available during specified periods within the contract term and may specify minimum volumes the customer is obligated to purchase during specified periods within the contract term.  If we do not deliver the volume properly nominated by the customer, the customer is entitled to a price discount on future volumes equivalent to the shortfall delivery.  Under certain international natural gas sales agreements, if the customer purchases natural gas volumes below the minimum volume commitment, the customer is required to pay us for the shortfall volumes and may receive make-up volumes in subsequent periods at no additional cost.  

Revenue from sale of third-party purchased volumes:  Crude oil, NGLs, and natural gas are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers.  The types of contracts with customers for the sale of third-party purchased volumes are the same as those described above.

Contract Balances

Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights.  Shortfall payments received from customers under contracts with take-or-pay provisions with customer make-up rights are deferred upon receipt and reflected as a contract liability.  At September 30, 2018 and December 31, 2017, there were no contract assets or contract liabilities.

Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGLs, or natural gas.  In the three months and nine months ended September 30, 2018, we did not recognize any impairment losses on receivables arising from contracts with customers.

Transaction Price Allocated to Remaining Performance Obligations

The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable.  Further, many of our contracts with customers have durations of less than twelve months.  Accordingly, we have elected under the provisions of ASC 606 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.

Sales-based Taxes

We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers.  Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.

10

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Midstream

Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation services.

The Midstream segment has multiple long-term, fee-based commercial agreements with a marketing subsidiary of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of our Midstream segment.  These contracts have minimum volumes the customer is obligated to provide each calendar quarter.  The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken.  As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. 

The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations.  Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period.  The Midstream segment has elected the practical expedient under the provisions of ASC 606 to recognize revenue in the amount it is entitled to invoice.  If the commercial agreements have take-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations.  Shortfall payments received under take-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period.  All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial agreements are eliminated upon consolidation.

3.  Common Stock Repurchase Program

In the three and nine months ended September 30, 2018, we repurchased $250 million (3.8 million shares) and $1,130 million (20.4 million shares) of our common stock, respectively, bringing total repurchases under our $1.5 billion common stock repurchase program to $1.25 billion (23.0 million shares) as of September 30, 2018.  

4.  Debt

Debt extinguishment:  In the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 and to purchase other notes with a carrying value of $38 million.  Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million.  In the second quarter of 2018, we paid $138 million to purchase notes with a carrying value of $112 million.  As a result, we recorded total losses on debt extinguishment totaling $53 million ($53 million after income taxes).

Capital lease:  In the third quarter of 2018, we entered into a sale and lease-back arrangement for a floating, storage and offloading vessel (FSO) to handle produced condensate at the North Malay Basin, offshore Peninsular Malaysia (Hess operated - 50%).  Pursuant to the sale agreement, we received total proceeds of approximately $260 million, including our partner’s share of the proceeds which is reported in Accounts Payable on our Consolidated Balance Sheet.  No gain or loss was recognized from the sale transaction.  The lease agreement is for 16 years with four consecutive twelve-month renewal options that may be exercised at our discretion.  At September 30, 2018, the carrying value of the lease obligation is $273 million, which represents 100% of the present value of future minimum lease payments, of which $15 million is included in Current maturities of long-term debt and $258 million is included in Long-term debt on our Consolidated Balance Sheet.  As the payments under the lease agreement become due, we will bill our partner their proportionate share for reimbursement pursuant to the terms of our joint operating agreement.

5.  Inventories

Inventories consisted of the following:

 

 

11

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

6.  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, 2018 (in millions):

 

The table above does not include well costs incurred and expensed during 2018 of $119 million associated with the Aspy well, offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, the Sorubim-1 well on the Stabroek Block, offshore Guyana, and the Bunga Teruntum-1 well in the North Malay Basin.  Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $251 million at September 30, 2018 and primarily related to:  

Gulf of Mexico: Approximately 45% of the capitalized well costs in excess of one year relates to the appraisal of the northern portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015.  The operator is planning to acquire 3D seismic in 2019 for use in development planning of the northern portion of the Shenzi Field.

Guyana: Approximately 35% of the capitalized well costs in excess of one year primarily relates to the Liza-4, Payara-1, Payara-2 and Snoek-1 wells on the Stabroek Block, offshore Guyana (Hess 30% participating interest), where hydrocarbons were encountered.  The operator plans to integrate the Liza-4 discovery into the second phase of development, which is expected to commence production by mid-2022.  The operator plans to integrate the Payara-1 and Payara-2 discoveries into the third phase of development, which is expected to commence production as early as 2023.

JDA:  Approximately 15% 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.  The operator is currently conducting subsurface evaluations and pre-development planning to facilitate commercial negotiations with the regulator for an extension of the existing gas sales contract to include development of the western part of the Block.

Malaysia:  Approximately 5% of the capitalized well costs in excess of one year relates to the North Malay Basin, offshore Peninsular Malaysia (Hess 50%), where hydrocarbons were encountered in one successful exploration well drilled in the fourth quarter of 2015.  We are planning to conduct subsurface evaluations and evaluate whether to integrate this discovery into a future phase of field development.

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, 2018, HIP liabilities totaling $1,100 million (December 31, 2017: $1,065 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 $395 million (December 31, 2017: $356 million) and property, plant and equipment with a carrying value of $2,630 million (December 31, 2017: $2,520 million).

8.  Exit and Disposal Costs

In the first nine months of 2018, we recorded severance expense of $39 million and paid severance costs of $39 million as part of our previously announced cost reduction program.  At September 30, 2018, we have accrued severance cost of $6 million (December 31, 2017: $6 million), which we expect to pay in the fourth quarter of 2018.  In the third quarters of 2018 and 2017, we recorded charges of $57 million and $11 million, respectively, in General and Administrative Expenses in connection with vacated office space.

 

12

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

9.  Dispositions

In the third quarter of 2018, we completed the sale of our joint venture interests in the Utica shale play in eastern Ohio for proceeds of $396 million, after normal closing adjustments, and recognized a pre-tax gain of $14 million ($14 million after income taxes).  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.

10.  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 an anticipated sale of the asset using Level 3 inputs to determine fair value.  The sale was completed in the fourth quarter of 2017.

11. Retirement Plans

Components of net periodic pension cost consisted of the following:

In the first quarter of 2018, we recorded curtailment gains of $18 million to Accumulated other comprehensive income (loss) and $2 million to the Statement of Consolidated Income following workforce reductions.  In connection with this curtailment, as required under accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease of $125 million in the Corporation’s U.S. post retirement liabilities.  This reduction was primarily driven by a change in weighted average discount rates used to measure the liabilities.  There was no change to the weighted average expected long-term rate of return on plan assets.

For the full year 2018, we forecast pension service costs of approximately $45 million and net non-service pension costs of approximately $60 million of income, which is comprised of interest cost of approximately $95 million, amortization of unrecognized net actuarial losses of approximately $40 million and estimated expected return on plan assets of approximately $195 million.  

Net non-service pension costs included in Other, net in the Statement of Consolidated Income for the three and nine months ended September 30, 2018 was income of $17 million and $49 million, respectively, compared to expenses of $0 million and $9 million for the three and nine months ended September 30, 2017, respectively.

In 2018, we expect to contribute $47 million to our funded pension plans.  In the nine months ended September 30, 2018, we have contributed $35 million to these plans.

13

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

12.  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, 2018, we granted 1,255,799 shares of restricted stock (2017: 1,214,460), 278,003 performance share units (2017: 438,980) and 683,167 stock options (2017: 662,819).

13.  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 was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action

14

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

to ameliorate the alleged effects on the environment of releases of MTBE.  The majority of the cases asserted against us have been settled.  There are four remaining active cases, filed by Pennsylvania, Vermont, Rhode Island, and Maryland.  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 thereto gasoline with MTBE.  The suit filed in Rhode Island is proceeding in Federal court. In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE.  The suit filed in Maryland state court, was served on us in January 2018 and has been removed to Federal court by the defendants.

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 or the Newark Bay, 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 or the Newark Bay, 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 our former terminal did not store or use contaminants which are of concern in the river sediments and could not have contributed contamination along the river’s length.  Further, there are numerous other parties who we expect will bear the cost of remediation and damages.

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.  

On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection Agency relating to Superfund claims for the Ector Drum, Inc.  Superfund Site in Odessa, Texas.  The EPA and Texas Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and concluded in December 2015.  The site was determined to have improperly stored industrial waste, including drums with oily liquids.  The total clean-up cost incurred by the EPA was approximately $3.5 million.  We were invited to negotiate a voluntary settlement for our purported share of the clean-up costs.  Our share, if any, is undetermined.  

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 the aforementioned proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

15

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

14.  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:

 

16

 

---

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:

 

15.  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 produced 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, 2018, 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.

We present gross notional amounts of both long and short positions 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 outstanding financial risk management derivative contracts related to West Texas Intermediate (WTI) instruments as of the dates shown below were as follows:

At December 31, 2017, we had WTI crude oil price collars with a monthly floor price of $50 per barrel and a monthly ceiling price of $65 per barrel with a notional amount of 115,000 barrels of oil per day (bopd) for the full year 2018.  In the first quarter of 2018, we bought back the WTI $65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018.  As a result, during this period we are able to realize monthly WTI selling prices above $65 per barrel on the crude oil price collars covering the notional amount of 115,000 bopd.  The put options within our crude oil collar contracts remain outstanding with a WTI monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018.  During the nine months ended September 30, 2018, we purchased WTI put options with a notional amount of 90,000 bopd with a WTI monthly floor price of $60 per barrel for calendar year 2019.

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

 

 

17

 

---

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 derivatives:  Crude oil price hedging contracts for the three and nine months ended September 30, 2018 decreased Sales and other operating revenues by $45 million and $119 million, respectively.  In the third quarter and nine months ended September 30, 2017, 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, respectively.  At September 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) related to outstanding crude oil price hedging contracts were $92 million, of which $90 million will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.  

Interest rate swaps designated as fair value hedges:  At September 30, 2018 and December 31, 2017, we had interest rate swaps with gross notional amounts totaling $100 million and $450 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.  Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income.  For the three and nine months ended September 30, 2018, the change in fair value of interest rate swaps was an increase in the liability of less than $1 million and $4 million, respectively, compared with an increase in liability of less than $1 million and $3 million in the third quarter and first nine months of 2017, respectively, with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt.  In the first quarter of 2018, we paid $3 million, to terminate interest rate swaps with a gross notional amount of $350 million.  See Note 4, Debt.

Interest rate swaps designated as cash flow hedges:  There were no floating to fixed interest rate swap contracts in 2018.  During the nine months ended September 30, 2017, HIP had interest rate swaps with gross notional amounts totaling $459 million, which were designated as cash flow hedges and relates to debt in our Midstream operating segment where HIP converted 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.

18

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Derivative contracts not designated as hedging instruments:

Crude oil collars:  For the three and nine months ended September 30, 2018, noncash adjustments to crude oil price hedging contracts, which were de-designated as cash flow hedges in the fourth quarter of 2017, decreased Sales and other operating revenues by $4 million and $20 million, respectively.  At September 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) in connection with the de-designation, were $3 million, of which all will be reclassified into earnings during the remainder of 2018 as the originally hedged crude oil sales are recognized in earnings.

Foreign exchange:  Foreign exchange gains and losses which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income were losses of $4 million in the three months and nine months ended September 30, 2018, respectively, compared with gains of $17 million and $26 million in the three months and nine months ended September 30, 2017, respectively.  A component of foreign exchange gain or loss is the result of foreign exchange derivative contracts that are not designated as hedges, which amounted to losses of less than $1 million and $1 million in the three months and nine months ended September 30, 2018, respectively, compared to gains of less than $1 million and $2 million in the third quarter and first nine months of 2017, respectively.

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, 2018.  Total long-term debt, excluding capital leases, with a carrying value of $6,421 million at September 30, 2018, had a fair value of $6,925 million based on Level 2 inputs.

16.  Subsequent Events

In October, at Block 42, Offshore Suriname (Hess – 33%), the operator, Kosmos Energy Ltd, completed drilling operations on the Pontoenoe-1 exploration well.  High-quality reservoir was encountered, but commercial quantities of hydrocarbons were not discovered.  Third quarter results include $25 million in exploration expense for well costs incurred through September 30, 2018.  We estimate approximately $10 million of exploration expense will be recognized in the fourth quarter of 2018 for well costs incurred after September 30, 2018.

In early November, the operator, BP Canada, completed drilling of the Aspy exploration well, offshore Nova Scotia, Canada (Hess – 50%).  The well did not encounter commercial quantities of hydrocarbons and third quarter results include $94 million in exploration expense for well costs incurred through September 30, 2018.  We estimate approximately $30 million of exploration expense will be recognized in the fourth quarter of 2018 for well costs incurred after September 30, 2018.

  

 

 

19

 

---

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, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia.  We conduct exploration activities primarily offshore Guyana, Suriname, Canada and in the Gulf of Mexico, including at the Stabroek Block, offshore Guyana, where we have participated in nine significant crude oil discoveries and sanctioned the first phase of a multi-phase development project at the Liza Field.

In the third quarter of 2018, we completed the sale of our joint venture interests in the Utica shale play in eastern Ohio for net cash consideration of $396 million, after closing adjustments.  This sale is consistent with our strategy to high grade and focus our portfolio by divesting lower return noncore assets to invest in higher return assets, primarily in Guyana and the Bakken.

Our 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.

Third Quarter Highlights and Outlook

Net cash provided by operating activities was $1,058 million in the first nine months of 2018, compared to $602 million in the first nine months of 2017, which includes uses of working capital of $483 million and $631 million, respectively.  Capital expenditures were $1,544 million in the first nine months of 2018 and $1,426 million in the first nine months of 2017.  In the third quarter of 2018, we repurchased $250 million of common stock, bringing total share repurchases under the Corporation’s $1.5 billion share repurchase program to $1.25 billion (23.0 million shares).  Excluding our Midstream segment, we ended the third quarter of 2018 with approximately $2.6 billion in cash and cash equivalents.  

Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at September 30, 2018 will be sufficient to fund our capital investment program and dividends through the end of 2019, and the repurchase of $250 million of common stock remaining under our $1.5 billion stock repurchase program during the fourth quarter of 2018.

Third Quarter Results

In the third quarter of 2018, we recorded a net loss of $42 million, compared to a net loss of $624 million in the third quarter of 2017.  Excluding items affecting comparability of earnings between periods on pages 28 to 30, the adjusted net income for the third quarter of 2018 was $29 million, compared to an adjusted net loss of $324 million in the third quarter of 2017.  The improved adjusted third quarter 2018 results, compared to the prior year quarter, reflect higher realized crude oil selling prices combined with lower operating costs and depreciation, depletion and amortization expense, partially offset by lower production volumes due to asset sales and higher exploration expenses.

Exploration and Production Results

In the third quarter of 2018, E&P had net income of $50 million, compared with a net loss of $474 million in the third quarter of 2017.  Excluding items affecting comparability of earnings between periods, the adjusted net income for the third quarter of 2018 was $109 million, compared to an adjusted net loss of $238 million in 2017.  Total net production, excluding Libya, averaged 279,000 barrels of oil equivalent per day (boepd) in the third quarter of 2018, compared to 299,000 boepd in the third quarter of 2017.  Excluding assets sold in 2017 and Libya, third quarter 2017 net production was 249,000 boepd.  The average realized crude oil selling price, including hedging, was $66.08 per barrel, up from $46.97 in the third quarter of 2017.  The average realized natural gas liquids selling price in the third quarter of 2018 was $24.29 per barrel, up from $17.22 in the prior year quarter, while the average realized natural gas selling price was $4.11 per thousand cubic feet (mcf), up from $3.35 in the third quarter of 2017.  

We expect net production, excluding Libya, to average approximately 265,000 boepd in the fourth quarter of 2018, and to average approximately 255,000 boepd for full year 2018.  We project E&P capital and exploratory expenditures of $2.1 billion for full year 2018 and closer to $3.0 billion for 2019, with the incremental spend in 2019 directed to our Bakken and Guyana assets.

 

20

 

---

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:

The Liza Phase 1 development, which is expected to begin producing oil by early 2020, will use the Liza Destiny FPSO to produce up to 120,000 gross bopd.  Construction of the FPSO and subsea equipment is well advanced.  Phase 2 of the Liza development will use a second FPSO designed to produce up to 220,000 gross bopd and is expected to be producing by mid-2022.  A third phase of development at the Payara Field is targeted to use an FPSO designed to produce approximately 180,000 gross bopd, with first production expected as early as 2023.

A second exploration vessel, the Noble Tom Madden drillship, has arrived in Guyana to accelerate exploration of high potential opportunities and will commence drilling at the Pluma prospect, which is located approximately 17 miles south of the Turbot discovery, in November.  The Stena Caron drillship will leave the Block for recertification and is expected to return to the Block in late December when we expect it will spud the Aimara prospect, which is located 24 miles southeast of the Turbot discovery.

21

 

---

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 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 above are explained on pages 28 to 30.

Reconciliations of GAAP and non-GAAP measures

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

Adjusted net income (loss) attributable to Hess Corporation presented in this report 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 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. 

22

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Comparison of Results

Exploration and Production

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

Excluding the E&P Items affecting comparability of earnings between periods detailed on page 28, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.

23

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Selling Prices:  Higher realized selling prices in the third quarter and first nine months of 2018, improved after-tax results by approximately $290 million and $655 million, respectively, compared to the same periods in 2017.  Average selling prices were as follows:

The decrease in Sales and other operating revenues from crude oil price derivatives was $49 million and $139 million in the third quarter and first nine months of 2018, respectively.  Realized and unrealized results from crude oil price derivatives amounted to an increase of $6 million and a decrease of $5 million in Sales and other operating revenues in the third quarter and first nine months of 2017, respectively.

24

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

At December 31, 2017, we had West Texas Intermediate (WTI) crude oil price collars with a monthly floor price of $50 per barrel and a monthly ceiling price of $65 per barrel with a notional amount of 115,000 bopd for the full year 2018.  In the first quarter of 2018, we bought back the WTI $65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018.  As a result, during this period we are able to realize monthly WTI selling prices above $65 per barrel on the crude oil price collars covering the notional amount of 115,000 bopd.  The put options within our crude oil collar contracts remain outstanding with a WTI monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018.  During the nine months ended September 30, 2018, we purchased WTI put options with a notional amount of 90,000 bopd with a WTI monthly floor price of $60 per barrel for calendar year 2019.  In October we purchased additional WTI put options with a notional amount of 5,000 bopd and an average floor price of $60 per barrel for calendar year 2019.

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

 

25

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

 

We forecast net production for 2018 to average approximately 255,000 boepd excluding Libya.  

United States:  Bakken net production was higher in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, primarily due to ongoing drilling activity and improved well performance in the current year, and the impact of reduced field availability due to adverse weather in the third quarter of 2017.  Excluding Bakken, net U.S. onshore total production was lower in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, due to the sale of our interests in the Utica shale play in August 2018, and the sale of our Permian assets in August 2017.  Total U.S. offshore oil production was higher in the third quarter of 2018, compared to the corresponding period in 2017, primarily due to higher production from the Stampede and Penn State fields, partially offset by natural decline.  Total U.S. offshore oil production was lower in the first nine months of 2018, compared to the corresponding period in 2017, primarily due to the 2018 impact of the shutdown at the third-party operated Enchilada platform and downtime from a second quarter 2018 planned well workover at the Tubular Bells Field, partially offset by higher production from the Stampede and Penn State fields.

International:  Net production was lower in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, primarily due to the sale of our assets in Equatorial Guinea and Norway, partially offset by higher production from the North Malay Basin full-field development and Libya.

Sales Volumes:  Worldwide sales volumes from Hess net production, excluding sales volumes of crude oil, natural gas liquids and natural gas purchased from third-parties, were as follows:

Marketing, including purchased oil and gas:  Marketing expense is mainly comprised of costs to purchase crude oil, natural gas liquids and natural gas from our partners in Hess operated wells or other third-parties, primarily in the U.S., and transportation costs for U.S. marketing activities.  The increase in the third quarter and first nine months of 2018, compared to the same periods in 2017, 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 2018 on an absolute and per-unit basis, compared to the same periods in 2017, primarily due to the impact of increased low-cost production from North Malay Basin, cost reduction efforts, and sales of higher cost assets in the second half of 2017.

Depreciation, Depletion and Amortization:  Depreciation, depletion and amortization (DD&A) expenses were lower in the third quarter and first nine months of 2018 on an absolute and per-unit basis, compared to the same periods in 2017, primarily due to the sale of assets which had higher DD&A rates than the portfolio average, a lower DD&A rate at the Bakken due to year-end 2017 proved reserve additions, and the impact of prior year asset impairments.

26

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Unit Costs:  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 disclosed 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 2018 relate to the Aspy well, offshore Nova Scotia, Canada and the Pontoenoe-1 well at Block 42, offshore Suriname.  Exploratory dry hole costs in the first nine months of 2018 include the Aspy and Pontoenoe-1 wells, as well as the Sorubim-1 well on the Stabroek Block, offshore Guyana and the Bunga Teruntum-1 well in the North Malay Basin.

Exploration expenses, excluding dry hole expense, are estimated to be in the range of $55 million to $65 million in the fourth quarter of 2018 and $190 million to $200 million for the full year of 2018.

Income Taxes:  Excluding items affecting comparability of earnings between periods and Libyan operations, the effective income tax rate for E&P operations in the third quarter and first nine months of 2018 was a benefit of 11% and 22%, respectively, compared to a benefit of 18% and 12%, in the third quarter and first nine months of 2017, respectively.  Excluding items affecting comparability of earnings between periods and Libyan operations, the E&P effective income tax rate is expected to be a benefit in the range of 0% to 4% in the fourth quarter of 2018, and a benefit in the range of 7% to 11% for the full year of 2018.

The enactment of U.S. Federal tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”), provided for broad changes to the taxation of both domestic and foreign operations.  The financial statement impact of the Act was provisionally accounted for in the period ending December 31, 2017 and there have been no changes to such accounting to date.  The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop.  The Company has included reasonable estimates of the impact of the Act on its 2018 tax provision in accordance with SAB 118.  However, the Company’s evaluation is ongoing, and final application of the Act to our operations and financial results may differ from that for which we have provisionally provided.  Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Corporation has utilized in calculating the transition impacts.  

 

 

 

 

 

 

 

27

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Items Affecting Comparability of Earnings Between Periods:

The following table summarizes, on an after-tax basis, income (expense) items affecting comparability of E&P earnings between periods:

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

Gain on asset sales, net:  In the third quarter of 2018, we recorded a pre-tax gain of $14 million ($14 million after income taxes) associated with the sale of our interests in the Utica shale play in eastern Ohio.  In the second quarter of 2018, we recorded a pre-tax gain of $10 million ($10 million after income taxes) associated with the sale of our interests in Ghana.  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.

Vacated office space:  In the third quarter of 2018, we incurred noncash pre-tax charges of $73 million ($73 million after income taxes) in connection with vacated office space, of which $57 million is included in General and administrative expenses and $16 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.

Employee severance:  In the first quarter of 2018, we recorded a net after-tax severance charge of $37 million related to a previously disclosed cost reduction program.  The pre-tax amounts are reported in Operating costs and expenses ($19 million), Exploration expenses, including dry holes and lease impairment ($3 million) and General and administrative expenses ($15 million), in the Statement of Consolidated Income.  

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, which closed in the fourth quarter of 2017.  See Note 10, Impairment in the Notes to Consolidated Financial Statements.

28

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Midstream

Following is a summarized income statement of our Midstream operations:

Total revenues and non-operating income for the third quarter and first nine months of 2018 increased, compared to the corresponding periods in 2017, primarily due to higher throughput volumes, partially offset by prior year activity associated with our former Permian assets that were sold in August 2017.

Operating costs and expenses for the third quarter of 2018 increased, compared to the prior year quarter due to higher activity related to produced water disposal services.  The decrease in Operating costs and expenses for the first nine months of 2018, compared to the corresponding period in 2017, was primarily due to the sale of our former Permian assets, partially offset by higher activity related to produced water disposal services.  The increase in interest expense in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, reflects higher borrowings by Hess Infrastructure Partners L.P. (HIP) following HIP’s issuance of fixed-rate notes in the fourth quarter of 2017.

Net income attributable to Hess Corporation from the Midstream segment is estimated to be approximately $30 million in the fourth quarter of 2018 and approximately $115 million for the full year of 2018.

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.

29

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Consolidated Results of Operations (continued)

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

Corporate and other expenses, excluding items affecting comparability, were lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to lower employee related costs in the current year.  Interest expense was lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to lower average borrowings.  Capitalized interest was lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to the Stampede Field that commenced production in January 2018.

Fourth quarter 2018 corporate expenses are expected to be in the range of $25 million to $30 million, and interest expense is expected to be approximately $85 million.  We estimate corporate expenses for full year 2018 to be in the range of $100 million to $105 million, and interest expense to be approximately $340 million.  

Items Affecting Comparability of Earnings Between Periods:  In the third quarter of 2018, Corporate expenses include an allocation of noncash income tax expense of $12 million to offset the recognition of a noncash income tax benefit recorded in other comprehensive income resulting from changes in fair value of our 2019 crude oil hedging program, as required under accounting standards.  In the nine months ended September 30, 2018, we also recognized pre-tax charges totaling $53 million ($53 million after income taxes) related to the premium paid for debt repurchases, a pre-tax charge of $58 million ($58 million after income taxes) resulting from the settlement of legal claims related to former downstream interests, and, as required under accounting standards, we recognized an allocation of noncash income tax benefit of $30 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income, resulting from a reduction in our pension liabilities.  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.

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, 2017.

30

 

---

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 $1,058 million in the first nine months of 2018, compared to $602 million in the first nine months of 2017.  The increase in 2018 operating cash flows primarily reflects higher benchmark crude oil prices, and lower operating costs, partially offset by lower production volumes due to asset sales.  Changes in working capital was a use of cash of $483 million in the first nine months of 2018, and a use of cash of $631 million in the first nine months of 2017.  Changes in working capital during 2018 primarily relate to an increase in accounts receivable, which reflects higher realized sales prices, a reduction in accounts payable and accrued liabilities, and premiums paid on commodity contracts.

Investing activities:  Cash outflows from investing activities increased in the first nine months of 2018 compared to the prior year period.  Additions to property, plant and equipment were up $50 million, compared to the same period in 2017, primarily reflecting increased Midstream expenditures, increased drilling activity in the Bakken, increased activity at the Liza Phase 1 development, exploratory drilling offshore Nova Scotia, Canada, and lower activity in the Gulf of Mexico in 2018.  The Midstream segment invested $67 million in its 50/50 joint venture with Targa Resources, which was formed in 2018.  Proceeds received from assets sales were $607 million in the first nine months of 2018 down from $783 million in the first nine months of 2017.  Proceeds from asset sales in 2018 include the sale of our joint venture interests in the Utica shale play in eastern Ohio, and our share of proceeds from the sale and lease-back transaction of the floating, storage, and offloading vessel in the North Malay Basin.  

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

 

 

31

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Liquidity and Capital Resources (continued)

Financing activities: In the first nine months of 2018, net debt repayments totaled $610 million including the redemption of 8.125% notes due 2019, compared to $92 million in the first nine months of 2017.  In the first nine months of 2018, we also cash settled the repurchase of $1,120 million of common stock (2017: $- million).  In addition, we paid common and preferred stock dividends totaling $262 million in the first nine months of 2018, compared to $273 million in the first nine months of 2017.  In the first nine months of 2017, Hess Midstream Partners LP received $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.  

Future Capital Requirements and Resources

Excluding our Midstream segment, we ended the third quarter of 2018 with approximately $2.6 billion in cash and cash equivalents, total liquidity including available committed credit facilities of approximately $7.0 billion and no significant near-term debt maturities.

Net cash provided by operating activities was $1,058 million in the first nine months of 2018, compared to $602 million in the first nine months of 2017, which includes uses of working capital of $483 million and $631 million, respectively.  Capital expenditures were $1,544 million in the first nine months of 2018 and $1,426 million in the first nine months of 2017.  Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at September 30, 2018 will be sufficient to fund our capital investment program and dividends through the end of 2019, and the repurchase of $250 million of common stock remaining under our $1.5 billion stock repurchase program in the fourth quarter of 2018.

The table below summarizes the capacity, usage and available capacity of our borrowings and letter of credit facilities at September 30, 2018:

Hess Corporation’s $4.0 billion syndicated revolving credit facility expires in January 2021, with commitments of $3.7 billion available for the final year.  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 60% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity.  As of September 30, 2018, 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.

32

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

Liquidity and Capital Resources (continued)

HIP has $800 million of senior secured syndicated credit facilities, consisting of a $600 million 5-year revolving credit facility and a $200 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.  Borrowings under the 5-year Term Loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%.  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 an investment grade credit rating, as defined in the amended credit agreement, 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 cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters.  The credit agreement includes a secured leverage ratio test not to exceed 3.75 to 1.00 for so long as the facilities remain secured.  HIP was in compliance with these financial covenants at September 30, 2018.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At September 30, 2018, HIP’s revolving credit facility was undrawn and borrowings under the Term Loan A facility amounted to $200 million, excluding deferred issuance costs.  The credit facilities are secured by first priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject to customary exclusions.

Hess Midstream Partners LP (the “Partnership”) has a $300 million 4-year senior secured syndicated revolving credit facility through March 2021 that 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.  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, 2018, this facility was undrawn.

Market Risk Disclosures

We are 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 15, 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 $9 million at September 30, 2018 that are used to reduce our exposure to fluctuating foreign exchange rates for the British Pound.  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 $1 million at September 30, 2018.

At September 30, 2018, our outstanding long‑term debt of $6,421 million, excluding capital leases and including current maturities, had a fair value of $6,925 million.  A 15% increase or decrease in the rate of interest would decrease or increase the fair value of debt by approximately $490 million or $550 million, respectively.

At September 30, 2018, we have outstanding West Texas Intermediate (WTI) crude oil put contracts.  See Note 15, Financial Risk Management Activities in the Notes to Consolidated Financial Statements. As of September 30, 2018, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair value of our crude oil put contracts would reduce the fair value of these derivatives instruments by approximately $30 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value of these derivative instruments by approximately $50 million.

33

 

---

PART I - FINANCIAL INFORMATION (CONT’D.)

 

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.

 

34

 

---

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, 2018, 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, 2018.

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, 2018 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

 

 

35

 

---

PART II – OTHER INFORMATION

 

 

Item 1.          Legal Proceedings.

Information regarding legal proceedings is contained in Note 13, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

Item 2.          Share Repurchase Activities.

Our common stock share repurchase activities for the three months ended September 30, 2018, were as follows:

 

 

36

 

---

PART II – OTHER INFORMATION (CONT’D.)

 

Item 6.          Exhibits.

 

 

37

 

---

 

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 9, 2018

 

38