hes-10q_20180331.htm

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 ☒

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.

	March 31,			December 31,
	2018			2017
	(In millions,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	3,726		$	4,847
Accounts receivable:
From contracts with customers		729			677
Joint venture and other		268			347
Inventories		239			232
Other current assets		52			54
Total current assets		5,014			6,157
Property, plant and equipment:
Total — at cost		32,906			32,504
Less: Reserves for depreciation, depletion, amortization and lease impairment		16,725			16,312
Property, plant and equipment — net		16,181			16,192
Goodwill		360			360
Deferred income taxes		22			21
Other assets		495			382
Total Assets	$	22,072		$	23,112
Liabilities
Current Liabilities:
Accounts payable	$	375		$	435
Accrued liabilities		1,251			1,337
Taxes payable		82			83
Current maturities of long-term debt		196			580
Total current liabilities		1,904			2,435
Long-term debt		6,372			6,397
Deferred income taxes		425			429
Asset retirement obligations		774			753
Other liabilities and deferred credits		660			744
Total Liabilities		10,135			10,758
Equity
Hess Corporation stockholders’ equity:
Preferred stock, par value $1.00; Authorized — 20,000,000 shares
Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference; Issued — 575,000 shares (2017: 575,000)		1			1
Common stock, par value $1.00; Authorized — 600,000,000 shares
Issued — 308,055,101 shares (2017: 315,053,615)		308			315
Capital in excess of par value		5,701			5,824
Retained earnings		5,166			5,597
Accumulated other comprehensive income (loss)		(571	)		(686	)
Total Hess Corporation stockholders’ equity		10,605			11,051
Noncontrolling interests		1,332			1,303
Total equity		11,937			12,354
Total Liabilities and Equity	$	22,072		$	23,112

	Three Months Ended
	March 31,
	2018			2017
	(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,346		$	1,258
Gains on asset sales, net		7			—
Other, net		37			(4	)
Total revenues and non-operating income		1,390			1,254

Costs and Expenses
Marketing, including purchased oil and gas		358			200
Operating costs and expenses		288			358
Production and severance taxes		39			31
Exploration expenses, including dry holes and lease impairment		40			58
General and administrative expenses		110			95
Interest expense		103			84
Loss on debt extinguishment		27			—
Depreciation, depletion and amortization		417			737
Total costs and expenses		1,382			1,563
Income (Loss) Before Income Taxes		8			(309	)
Provision (benefit) for income taxes		73			(13	)
Net Income (Loss)		(65	)		(296	)
Less: Net income (loss) attributable to noncontrolling interests		41			28
Net Income (Loss) Attributable to Hess Corporation		(106	)		(324	)
Less: Preferred stock dividends		11			12
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$	(117	)	$	(336	)

Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$	(0.38	)	$	(1.07	)
Diluted	$	(0.38	)	$	(1.07	)
Weighted Average Number of Common Shares Outstanding (Diluted)		309.5			313.9
Common Stock Dividends Per Share	$	0.25		$	0.25

	Three Months Ended
	March 31,
	2018			2017
	(In millions)

Net Income (Loss)	$	(65	)	$	(296	)

Other Comprehensive Income:

Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		31			—
Income taxes on effect of hedge (gains) losses reclassified to income		—			—
Net effect of hedge (gains) losses reclassified to income		31			—
Change in fair value of cash flow hedges		(22	)		4
Income taxes on change in fair value of cash flow hedges		—			(2	)
Net change in fair value of cash flow hedges		(22	)		2
Change in derivatives designated as cash flow hedges, after taxes		9			2

Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		125			7
Income taxes on actuarial changes in plan liabilities		(30	)		(3	)
(Increase) reduction in unrecognized actuarial losses, net		95			4
Amortization of net actuarial losses		12			17
Income taxes on amortization of net actuarial losses		—			—
Net effect of amortization of net actuarial losses		12			17
Change in pension and other postretirement plans, after taxes		107			21

Foreign currency translation adjustment
Foreign currency translation adjustment		—			14
Change in foreign currency translation adjustment		—			14

Other Comprehensive Income		116			37

Comprehensive Income (Loss)		51			(259	)
Less: Comprehensive income attributable to noncontrolling interests		41			28
Comprehensive Income (Loss) Attributable to Hess Corporation	$	10		$	(287	)

	Three Months Ended March 31,
	2018			2017
	(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	(65	)	$	(296	)
Adjustments to reconcile to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net		(7	)		—
Depreciation, depletion and amortization		417			737
Exploration lease and other impairment		10			7
Stock compensation expense		13			22
Non-cash (gains) losses on commodity derivatives, net		38			—
Provision (benefit) for deferred income taxes and other tax accruals		(36	)		(27	)
Loss on debt extinguishment		27			—
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable		(11	)		115
(Increase) decrease in inventories		(7	)		(55	)
Increase (decrease) in accounts payable and accrued liabilities		(135	)		(115	)
Increase (decrease) in taxes payable		(1	)		6
Changes in other operating assets and liabilities		(33	)		(45	)
Net cash provided by (used in) operating activities		210			349

Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P		(363	)		(340	)
Additions to property, plant and equipment - Midstream		(37	)		(50	)
Payments for Midstream equity investments		(24	)		—
Proceeds from asset sales		6			100
Other, net		(4	)		—
Net cash provided by (used in) investing activities		(422	)		(290	)

Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less		—			5
Debt with maturities of greater than 90 days
Borrowings		—			—
Repayments		(434	)		(26	)
Common stock acquired and retired		(371	)		—
Cash dividends paid		(89	)		(92	)
Noncontrolling interests, net		(12	)		—
Other, net		(3	)		8
Net cash provided by (used in) financing activities		(909	)		(105	)

Net Increase (Decrease) in Cash and Cash Equivalents		(1,121	)		(46	)
Cash and Cash Equivalents at Beginning of Year		4,847			2,732
Cash and Cash Equivalents at End of Period	$	3,726		$	2,686

	Mandatory Convertible Preferred Stock		Common Stock			Capital in Excess of Par			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Hess Stockholders' Equity			Noncontrolling Interests			Total Equity
	(In millions)
Balance at January 1, 2018	$	1	$	315		$	5,824		$	5,597		$	(686	)	$	11,051		$	1,303		$	12,354
Cumulative effect of adoption of new accounting standards		—		—			—			1			(1	)		—			—			—
Net income (loss)		—		—			—			(106	)		—			(106	)		41			(65	)
Other comprehensive income		—		—			—			—			116			116			—			116
Share-based compensation, including income taxes		—		1			12			—			—			13			—			13
Dividends on preferred stock		—		—			—			(11	)		—			(11	)		—			(11	)
Dividends on common stock		—		—			—			(78	)		—			(78	)		—			(78	)
Common stock acquired and retired		—		(8	)		(135	)		(237	)		—			(380	)		—			(380	)
Noncontrolling interests, net		—		—			—			—			—			—			(12	)		(12	)
Balance at March 31, 2018	$	1	$	308		$	5,701		$	5,166		$	(571	)	$	10,605		$	1,332		$	11,937

Balance at January 1, 2017	$	1	$	317		$	5,773		$	10,147		$	(1,704	)	$	14,534		$	1,057		$	15,591
Cumulative effect of adoption of new accounting standards		—		—			2			(39	)		—			(37	)		—			(37	)
Net income (loss)		—		—			—			(324	)		—			(324	)		28			(296	)
Other comprehensive income		—		—			—			—			37			37			—			37
Share-based compensation, including income taxes		—		1			29			—			—			30			—			30
Dividends on preferred stock		—		—			—			(12	)		—			(12	)		—			(12	)
Dividends on common stock		—		—			—			(80	)		—			(80	)		—			(80	)
Balance at March 31, 2017	$	1	$	318		$	5,804		$	9,692		$	(1,667	)	$	14,148		$	1,085		$	15,233

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 March 31, 2018 and December 31, 2017, the consolidated results of operations for the three months ended March 31, 2018 and 2017, and consolidated cash flows for the three months ended March 31, 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 will be 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 Statements 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 $2 million of expense for the first quarter of 2017 from Operating costs and expenses, and General and administrative expenses to Other, net.

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 line item on the balance sheet. The adoption of this ASU did not have a material impact on our Consolidated Statements of 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 Consolidated Statements of Cash Flows.

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 ended March 31, 2017 associated with the recovery of certain natural gas processing costs from third parties, by reducing each by $19 million. 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 revenue and Marketing, including purchased oil and gas (formerly Costs of products sold) in our March 31, 2017 Form 10-Q were $1,277 million and $219 million, respectively.

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 will require assets and liabilities to be reported on the Consolidated 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 and are executing a project plan for the implementation of ASC 842 in the first quarter of 2019. We are progressing our assessment of existing leases and evaluating our disclosure processes with reference to 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 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 the first quarter of 2018, revenue from contracts with customers on a disaggregated basis was as follows:

	Exploration and Production												Midstream		Eliminations			Total
	United States			Europe		Africa		Asia		E&P Total
Revenues from sales of our net production volumes:
Crude oil revenue	$	593		$	33	$	99	$	43	$	768		$	—	$	—		$	768
Natural gas liquids revenue		71			—		—		—		71			—		—			71
Natural gas revenue		39			3		8		128		178			—		—			178
Revenue from sale of third-party purchased volumes		325			—		24		14		363			—		—			363
Intercompany revenue		—			—		—		—		—			167		(167	)		—
Total revenues from contracts with customers		1,028			36		131		185		1,380			167		(167	)		1,380
Other operating revenue (a)		(34	)		—		—		—		(34	)		—		—			(34	)
Total sales and other operating revenues	$	994		$	36	$	131	$	185	$	1,346		$	167	$	(167	)	$	1,346

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. Pricing is determined subsequent to contract inception, but prior to the transfer of control or shortly thereafter if required per contractual terms, with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials. As a result, the entire transaction price at contract inception is variable. We do not apply a constraint to the transaction price at contract inception.

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 minimum volume commitments 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. Where control of crude oil, NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes.

Crude oil, natural gas liquids, and natural gas – 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, prior to transfer of control.

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, prior to the recognition of revenue, 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.

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 March 31, 2018 and December 31, 2017, there were no contract assets or contract liabilities. In the three months ended March 31, 2018, there were no credit losses on receivables with customers.

At March 31, 2018, the transaction price allocated to our unsatisfied performance obligations on uncompleted contracts was entirely variable. 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.

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.

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 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. 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.

In the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 with a carrying value of $349 million at December 31, 2017, and to purchase other notes with a carrying value of $38 million at December 31, 2017. Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million. First quarter 2018 results included a pre-tax charge of $27 million ($27 million after income taxes) for the loss on extinguishment of the redeemed and purchased notes.

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the three months ended March 31, 2018 (in millions):

Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $211 million at March 31, 2018 and primarily related to:

Gulf of Mexico: Approximately 55% 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 conducting appraisal activities on adjacent acreage and is evaluating plans for development of the northern portion of the Shenzi Field.

Guyana: Approximately 20% of the capitalized well costs in excess of one year primarily relates to the Payara-1 well on the Stabroek Block, offshore Guyana (Hess 30% participating interest), where hydrocarbons were encountered. The operator plans to integrate this discovery into the third phase of development, with first production from this phase planned for late 2023 or early 2024.

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.

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 March 31, 2018, HIP liabilities totaling $1,060 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 $375 million (December 31, 2017: $356 million) and property, plant and equipment with a carrying value of $2,527 million (December 31, 2017: $2,520 million).

In the first quarter of 2018, we recorded severance expense of $46 million, and a reduction to expense of $9 million for stock-based compensation forfeitures, as part of the previously announced cost reduction program. During the first quarter of 2018, we paid severance costs of $21 million. At March 31, 2018, we have accrued severance cost of $31 million (December 31, 2017: $6 million), which we expect to pay in 2018.

In 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 the first quarter. 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. pension 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 now forecast pension service costs of approximately $45 million, 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 months ended March 31, 2018 and 2017, was income of $16 million and expense of $2 million, respectively.

In 2018, we expect to contribute $44 million to our funded pension plans. Through March 31, 2018, we have contributed $14 million to these plans.

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 three months ended March 31, 2018, we granted 1,081,923 shares of restricted stock (2017: 1,206,732), 278,003 performance share units (2017: 438,980) and 683,167 stock options (2017: 662,819).

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. 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 was filed in state court, but has not been served to date.

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 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.

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, TX. 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 are not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

The Corporation has 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:

	Exploration and Production			Midstream		Corporate, Interest and Other			Eliminations			Total
	(In Millions)
For the Three Months Ended March 31, 2018
Sales and Other Operating Revenues - Third-parties	$	1,346		$	—	$	—		$	—		$	1,346
Intersegment Revenues		—			167		—			(167	)		—
Sales and Other Operating Revenues	$	1,346		$	167	$	—		$	(167	)	$	1,346

Net Income (Loss) attributable to Hess Corporation	$	(25	)	$	28	$	(109	)	$	—		$	(106	)
Depreciation, Depletion and Amortization		385			31		1			—			417
Provision (Benefit) for Income Taxes		95			9		(31	)		—			73
Capital Expenditures		354			37		—			—			391

For the Three Months Ended March 31, 2017
Sales and Other Operating Revenues - Third-parties	$	1,256		$	2	$	—		$	—		$	1,258
Intersegment Revenues		—			147		—			(147	)		—
Sales and Other Operating Revenues	$	1,256		$	149	$	—		$	(147	)	$	1,258

Net Income (Loss) attributable to Hess Corporation	$	(233	)	$	18	$	(109	)	$	—		$	(324	)
Depreciation, Depletion and Amortization		703			32		2			—			737
Provision (Benefit) for Income Taxes		(20	)		11		(4	)		—			(13	)
Capital Expenditures		342			28		—			—			370

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 March 31, 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 were as follows:

At December 31, 2017, we had WTI crude oil price collars with an average monthly floor price of $50 per barrel and an average 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 average 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 average monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018.

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

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:

	Assets		Liabilities
	(In millions)
March 31, 2018
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts receivable	$	10	$	—
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(4	)
Total derivative contracts designated as hedging instruments		10		(4	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts receivable		3		—
Total derivative contracts not designated as hedging instruments		3		—
Gross fair value of derivative contracts		13		(4	)
Net Fair Value of Derivative Contracts	$	13	$	(4	)

December 31, 2017
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts payable	$	—	$	(7	)
Interest rate - Other assets (noncurrent) and Accounts payable		—		(4	)
Total derivative contracts designated as hedging instruments		—		(11	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts payable		—		(2	)
Foreign exchange		1		—
Total derivative contracts not designated as hedging instruments		1		(2	)
Gross fair value of derivative contracts		1		(13	)
Net Fair Value of Derivative Contracts	$	1	$	(13	)

Crude oil collars: Crude oil price hedging contracts decreased Sales and other operating revenues by $30 million in the first quarter of 2018 and decreased Sales and other operating revenues by $1 million in the first quarter of 2017. At March 31, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) related to outstanding hedged crude oil collars were $120 million, of which all will be reclassified into earnings during the remainder of 2018 as the hedged crude oil sales are recognized in earnings.

Interest rate swaps designated as fair value hedges: At March 31, 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. In the first quarter of 2018, the change in fair value of interest rate swaps was an increase in the liability of $3 million (2017 Q1: an increase in the liability of $1 million) 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 3, Debt.

Crude oil collars: In the first quarter of 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 $8 million. At March 31, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) in connection with the de-designation, were $11 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 which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income were $4 million in the first quarter of 2018 (2017 Q1: loss of $1 million). A component of foreign exchange gain (loss) is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to a gain of $2 million in the first quarter of 2018 (2017 Q1: loss of less than $1 million).

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 March 31, 2018. Total long-term debt with a carrying value of $6,568 million at March 31, 2018, had a fair value of $7,058 million based on Level 2 inputs.

In April 2018, we entered into an accelerated share repurchase program (ASR) with a financial institution to repurchase $500 million of our common stock as part of our $1.5 billion share repurchase program. Under the terms of the ASR, we paid $500 million in cash to the financial institution and received an initial delivery of approximately 8 million shares of our common stock with final settlement expected to be completed during the second quarter.

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 seven significant crude oil discoveries and sanctioned the first phase of a multi-phase development project at the Liza Field.

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.

In the first quarter of 2018, the Corporation increased its share repurchase program by $1.0 billion to a total of $1.5 billion, which is expected to be completed by year-end. During the first quarter, we repurchased approximately 8 million common shares for $380 million completing the initial $500 million program. In April, we commenced a $500 million accelerated share repurchase, which is expected to be completed in the second quarter, as part of our $1.5 billion share repurchase program. During the first quarter, we also retired $390 million principal amount of debt, including our 8.125% notes due 2019, in connection with our previously announced $500 million debt reduction initiative.

We forecast net production, excluding Libya, to average between 245,000 barrels of oil equivalent per day (boepd) and 255,000 boepd in 2018, and to average between 235,000 boepd and 245,000 boepd in the second quarter of 2018. We expect net production to ramp up over the remainder of the year, driven by the restart of production from our Gulf of Mexico assets associated with the third-party operated Enchilada platform, increased drilling activity in the Bakken, and a ramp up in production at the Stampede Field.

Net cash provided by operating activities was $210 million in the first quarter of 2018, compared to $349 million in the first quarter of 2017, which includes uses of working capital of $187 million and $94 million, respectively. Capital expenditures were $391 million in the first quarter of 2018 and $370 million in the prior-year quarter. Based on current forward strip crude oil prices for 2018, we forecast a reduced net operating cash flow deficit (including capital expenditures) in 2018 compared with 2017. We expect to fund our remaining 2018 net operating cash flow deficit (including capital expenditures), retire the remaining $110 million in debt principal under our $500 million debt reduction initiative, and repurchase the remaining $1.0 billion of common stock under our $1.5 billion stock repurchase program with cash and cash equivalents existing at March 31, 2018, which was $3.4 billion, excluding Midstream.

In the first quarter of 2018, we incurred a net loss of $106 million, compared to a net loss of $324 million in the first quarter of 2017. Excluding items affecting comparability of earnings between periods on pages 26 to 28, the adjusted net loss for the first quarter of 2018 was $72 million. The improved adjusted first quarter 2018 results reflect higher realized crude oil selling prices, lower operating costs and depreciation, depletion and amortization expense, partially offset by lower production volumes, primarily due to asset sales.

In the first quarter of 2018, E&P had a net loss of $25 million, compared with a net loss of $233 million in the first quarter of 2017. Excluding items affecting comparability of earnings between periods, the adjusted net income for the first quarter of 2018 was $12 million. Total net production, excluding assets sold and Libya, averaged 233,000 boepd in the first quarter of 2018, compared to 241,000 boepd in the first quarter of 2017. The average realized crude oil selling price, including hedging, was $59.32 per barrel, up from $48.58 in the first quarter of 2017. The average realized natural gas liquids selling price in the first quarter of 2018 was $21.11 per barrel, up from $18.71 in the prior-year quarter, while the average realized natural gas selling price was $3.86 per thousand cubic feet (mcf), up from $3.20 in the first quarter of 2017.

At the Stampede development (Hess operated - 25%), first production commenced in the first quarter of 2018 and is expected to ramp up gradually throughout 2018. We expect to achieve peak production rates during 2019 as we complete additional wells.

Net production in the Gulf of Mexico is expected to average between 45,000 boepd and 50,000 boepd in the second quarter. By the fourth quarter, with all Enchilada impacted fields back online and the continued ramp up at Stampede, we forecast net production in the Gulf of Mexico to average approximately 65,000 boepd.

The operator also completed drilling at the Liza-5 well with the Stena Carron drillship, and is conducting a series of production tests before drilling commences at the Longtail-1 prospect, located approximately four miles northwest of the Turbot-1 discovery. In the second quarter, the operator completed drilling of the Sorubim-1 well, which failed to encounter commercial quantities of hydrocarbons. The cost of this well to Hess is expected to be less than $10 million. The operator will use the Noble Bob Douglas to begin drilling the first of 17 planned development wells associated with Liza Phase 1.

Development activities for Liza Phase 1, which include a Floating production, storage and offloading vessel (FPSO) with a gross capacity of 120,000 bopd, are on schedule and first production is expected by 2020. Planning continues for a second phase of development, that is expected to include a larger FPSO with a gross capacity of approximately 220,000 bopd, with first production planned by mid-2022.

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 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.

	Three Months Ended
	March 31,
	2018			2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,346		$	1,256
Gains on asset sales, net		2			—
Other, net		15			(5	)
Total revenues and non-operating income		1,363			1,251
Costs and Expenses
Marketing, including purchased oil and gas		374			223
Operating costs and expenses		247			308
Production and severance taxes		39			31
Midstream tariffs		151			124
Exploration expenses, including dry holes and lease impairment		40			58
General and administrative expenses		57			57
Depreciation, depletion and amortization		385			703
Total costs and expenses		1,293			1,504
Results of Operations Before Income Taxes		70			(253	)
Provision (benefit) for income taxes		95			(20	)
Net Income (Loss) Attributable to Hess Corporation	$	(25	)	$	(233	)

Excluding the E&P Items affecting comparability of earnings between periods detailed on page 26, 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.

Selling Prices: Higher realized selling prices improved after-tax results by approximately $120 million in the first quarter of 2018, compared to the first quarter of 2017. Average selling prices were as follows:

	Three Months Ended
	March 31,
	2018		2017
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
Onshore	$	56.40	$	46.47
Offshore		59.14		47.18
Total United States		57.23		46.74
Europe		67.37		54.04
Africa		66.27		51.25
Asia		67.69		54.70
Worldwide		59.32		48.58

Crude Oil - Per Barrel (Excluding Hedging)
United States
Onshore	$	59.61	$	46.47
Offshore		62.31		47.18
Total United States		60.43		46.74
Europe		67.37		54.18
Africa		66.27		51.37
Asia		67.69		54.70
Worldwide		61.82		48.61

Natural Gas Liquids - Per Barrel
United States
Onshore	$	20.78	$	18.07
Offshore		24.28		20.55
Total United States		21.11		18.43
Europe		—		28.06
Worldwide		21.11		18.71

Natural Gas - Per Mcf
United States
Onshore	$	2.47	$	2.32
Offshore		2.08		2.40
Total United States		2.38		2.35
Europe		3.44		3.99
Asia and other		4.63		4.01
Worldwide		3.86		3.20

In the first quarter of 2018, the decrease in Sales and other operating revenues from crude oil price collars was $38 million ($38 million after income taxes).

At December 31, 2017, we had West Texas Intermediate (WTI) crude oil price collars with an average monthly floor price of $50 per barrel and an average 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 average 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 average monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018.

	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
Crude Oil - Barrels
United States
Bakken		72			67
Other Onshore (b)		1			8
Total Onshore		73			75
Offshore		31			47
Total United States		104			122
Europe (c)		6			31
Africa (d) (e)		20			35
Asia		4			2
Worldwide		134			190

Natural Gas Liquids - Barrels
United States
Bakken		28			23
Other Onshore (b)		5			10
Total Onshore		33			33
Offshore		4			6
Total United States		37			39
Europe (c)		—			1
Worldwide		37			40

Natural Gas - Mcf
United States
Bakken		66			53
Other Onshore		65			106
Total Onshore		131			159
Offshore		37			75
Total United States		168			234
Europe (c)		10			38
Asia and other (e)		326			212
Worldwide		504			484

Barrels of Oil Equivalent (a)		255			311

Crude oil and natural gas liquids as a share of total production		67	%		74	%

We forecast production for the year to be in the range of 245,000 boepd to 255,000 boepd excluding Libya.

United States: Bakken net production was higher in the first quarter of 2018, compared to the first quarter of 2017, primarily due to increased drilling activity and improved well performance. Excluding Bakken, net U.S. onshore total production was lower in the first quarter of 2018, compared to the first quarter of 2017, due to natural decline in the Utica shale play and the sale of our Permian assets in August 2017. U.S. offshore oil production was lower in the first quarter of 2018, compared to the first quarter of 2017, primarily due to the ongoing shutdown at the third-party operated Enchilada platform from the fourth quarter of 2017.

International: Net production was lower in the first quarter of 2018, compared to the first quarter of 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 that commenced production in July 2017.

Sales Volumes: The impact of lower sales volumes, primarily due to asset sales, decreased after-tax results by approximately $145 million in the first quarter of 2018, compared to the first quarter of 2017. 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: This expense category 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 associated transportation costs for U.S. marketing activities. The increase in the first quarter of 2018, compared to the first quarter of 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 first quarter of 2018 on an absolute and per-unit basis, compared to the first quarter of 2017, primarily due to increased low-cost production from North Malay Basin and sales of higher cost assets in 2017.

Depreciation, Depletion and Amortization: Depreciation, depletion and amortization (DD&A) expenses were lower in the first quarter of 2018 on an absolute and per-unit basis, compared to the first quarter of 2017, primarily due to asset sales, a lower DD&A rate at the Bakken due to year-end 2017 proved reserve additions, and the impact of prior-year asset impairments.

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, excluding dry hole expense, are estimated to be in the range of $60 million to $70 million in the second quarter of 2018 and $190 million to $210 million for the full year of 2018.

Income Taxes: E&P income tax expense increased in the first quarter of 2018, compared to the prior-year quarter, primarily due to higher Libya production. Excluding items affecting comparability of earnings between periods and Libyan operations, the effective income tax rate for E&P operations in the first quarter of 2018 was not meaningful as results on a pre-tax basis were essentially break-even, while the E&P effective rate on the same basis was a benefit of 13% in the first quarter of 2017. 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 second quarter of 2018, and a benefit in the range of 0% to 4% 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. 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.

In the first quarter of 2018, we recorded a net after-tax severance charge of $37 million related to the 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.

	Three Months Ended
	March 31,
	2018		2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	167	$	149
Other, net		1		—
Total revenues and non-operating income	$	168	$	149

Costs and Expenses
Operating costs and expenses		41		50
General and administrative expenses		3		5
Depreciation, depletion and amortization		31		32
Interest expense		15		5
Total costs and expenses		90		92

Results of Operations Before Income Taxes		78		57
Provision (benefit) for income taxes (a)		9		11
Net income (loss)		69		46
Less: Net income (loss) attributable to noncontrolling interests (b)		41		28
Net Income (Loss) Attributable to Hess Corporation	$	28	$	18

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

Operating costs and expenses for the first quarter of 2018 decreased, compared to the first quarter of 2017, primarily due to the prior year reflecting activity in the Permian. The increase in interest expense in the first quarter of 2018, compared with the first quarter of 2017, reflects higher borrowings by Hess Infrastructure Partners L.P. (HIP) relative to the prior year 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 second quarter of 2018 and $105 million to $115 million for the full year of 2018.

Corporate and other expenses were lower in the first quarter of 2018, compared with the first quarter of 2017, primarily due to higher interest income and lower employee compensation costs in the first quarter of 2018. Capitalized interest was lower in the first quarter of 2018, compared with the first quarter of 2017, primarily due to the Stampede Field that commenced first production in January 2018.

Second quarter 2018 corporate expenses, are expected to be in the range of $25 million to $30 million, and interest expense is expected to be in the range of $85 million to $90 million. We estimate corporate expenses for full year 2018 to be in the range of $105 million to $115 million, and interest expense to be in the range of $345 million to $355 million.

In the first quarter of 2018, we incurred pre-tax charges of $27 million ($27 million after income taxes) relating to the premium paid for the retirement of debt. In addition, as required under accounting standards’ intraperiod allocation rules, we recognized a noncash income tax benefit of $30 million to offset a noncash income tax expense recognized in other comprehensive income, resulting from a reduction in our pension liabilities.

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.

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

Operating activities: Net cash provided by operating activities was $210 million in the first quarter of 2018, compared to $349 million in the first quarter of 2017. The decrease in 2018 operating cash flows primarily reflects lower production volumes, primarily due to asset sales, partially offset by higher benchmark crude oil prices, and lower operating costs. Changes in working capital were a use of cash of $187 million in the first quarter of 2018, and a use of cash of $94 million in the first quarter of 2017. Changes in working capital during 2018 primarily related to a reduction in accounts payable and accrued liabilities, premiums paid on commodity contracts, and the timing of interest payments.

Investing activities: Cash outflows from investing activities increased in the first quarter of 2018 due to higher Additions to property, plant and equipment, compared to the same period in 2017. The increase primarily reflects increased drilling activity in the Bakken and ongoing Liza Phase 1 development, partially offset by the impact of prior year expenditures associated with the Gulf of Mexico, Malaysia and exploration activities. Proceeds from asset sales totaled $100 million in the first quarter of 2017 and primarily related to the sale of our 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 the first quarter of 2018, net debt repayments totaled $434 million (2017 Q1: $21 million), including the redemption of 8.125% notes due 2019, and we cash settled the repurchase of $371 million of common stock (2017 Q1: $- million). In addition, we paid common and preferred stock dividends totaling $89 million in the first quarter of 2018, compared to $92 million in the first quarter of 2017.

Excluding our Midstream segment, we ended the quarter with approximately $3.4 billion in cash and cash equivalents, total liquidity including available committed credit facilities of approximately $7.7 billion and no significant near-term debt maturities.

The table below summarizes the capacity, usage and available capacity of our borrowings and letter of credit facilities at March 31, 2018:

						Letters of
	Expiration					Credit		Total		Available
	Date	Capacity		Borrowings		Issued		Used		Capacity
		(In millions)
Revolving credit facility - Hess Corporation (a)	January 2021	$	4,000	$	—	$	—	$	—	$	4,000
Revolving credit facility - HIP (b)	November 2022		600		—		—		—		600
Revolving credit facility - Hess Midstream Partners LP (HESM) (c)	March 2021		300		—		—		—		300
Committed lines	Various (d)		370		—		29		29		341
Uncommitted lines	Various (d)		272		—		272		272		—
Total		$	5,542	$	—	$	301	$	301	$	5,241

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 March 31, 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.

HIP has $800 million of senior secured syndicated credit facilities, consisting of a $600 million 5-year revolving credit facility and a drawn $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 March 31, 2018. Outstanding borrowings under this credit facility are non-recourse to Hess Corporation. At March 31, 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 March 31, 2018, this facility was undrawn.

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 12, Financial Risk Management Activities, in the Notes to Consolidated Financial Statements.

We have outstanding foreign exchange contracts with notional amounts totaling $31 million at March 31, 2018 that are used 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 March 31, 2018.

At March 31, 2018, our outstanding long‑term debt of $6,568 million, including current maturities, had a fair value of $7,058 million. A 15% increase or decrease in the rate of interest would decrease or increase the fair value of debt by approximately $500 million or $560 million, respectively.

At March 31, 2018, we have outstanding West Texas Intermediate (WTI) crude oil collar contracts. See Note 12, Financial Risk Management Activities in the Notes to Consolidated Financial Statements. As of March 31, 2018, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair value of our crude oil collars would reduce the fair value of these derivatives instruments by approximately $15 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value of these derivative instruments by approximately $35 million.

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.

The information required by this item is presented under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Disclosures.”

Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 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 March 31, 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 March 31, 2018 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Information regarding legal proceedings is contained in Note 10, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

Our common share repurchases activities for the three months ended March 31, 2018, were as follows:

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.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐ (Do not check if a smaller reporting company)	Smaller reporting company	☐
Emerging growth company	☐

Item No.		Page Number
	PART I - FINANCIAL INFORMATION
1.	Financial Statements (Unaudited)
	Consolidated Balance Sheet at March 31, 2018, and December 31, 2017	2
	Statement of Consolidated Income for the Three Months Ended March 31, 2018, and 2017	3
	Statement of Consolidated Comprehensive Income for the Three Months Ended March 31, 2018, and 2017	4
	Statement of Consolidated Cash Flows for the Three Months Ended March 31, 2018, and 2017	5
	Statement of Consolidated Equity for the Three Months Ended March 31, 2018, and 2017	6
	Notes to Consolidated Financial Statements (Unaudited)	7
	Note 1 - Basis of Presentation	7
	Note 2 - Revenue	8
	Note 3 - Debt	10
	Note 4 - Inventories	10
	Note 5 - Capitalized Exploratory Well Costs	11
	Note 6 - Hess Infrastructure Partners LP	11
	Note 7 - Severance Costs	11
	Note 8 - Retirement Plans	12
	Note 9 - Weighted Average Common Shares	12
	Note 10 - Guarantees and Contingencies	13
	Note 11 - Segment Information	15
	Note 12 - Financial Risk Management Activities	15
	Note 13 - Subsequent Event	18

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
3.	Quantitative and Qualitative Disclosures about Market Risk	32
4.	Controls and Procedures	32

	PART II - OTHER INFORMATION
1.	Legal Proceedings	33
2.	Share Repurchase Activities	33
6.	Exhibits	34
	Signatures	35
	Certifications

	Three Months Ended
	March 31,
	2018		2017
Restricted common stock		2,922,316		3,126,222
Stock options		5,807,579		6,298,896
Performance share units		623,088		313,004
Common shares upon conversion of Preferred stocks		12,584,974		12,547,650

	March 31, 2018		December 31, 2017
Instrument type	Puts		Collars
Effective date	Apr. 1, 2018		Jan. 1, 2018
End date	Dec. 31, 2018		Dec. 31, 2018
Crude oil volumes (millions of barrels)		31.6		42.0
Ceiling price	N/A		$	65
Floor price	$	50	$	50

	Three Months Ended
	March 31,
	2018		2017
	(In thousands)
Crude oil - barrels		11,811		15,744
Natural gas liquids - barrels		3,308		3,623
Natural gas - mcf		45,392		43,544
Barrels of Oil Equivalent (a)		22,684		26,624

Crude oil - barrels per day		131		175
Natural gas liquids - barrels per day		37		40
Natural gas - mcf per day		504		484
Barrels of Oil Equivalent Per Day (a)		252		296

Balance at January 1, 2018	$	304
Additions to capitalized exploratory well costs pending the determination of proved reserves		42
Balance at March 31, 2018	$	346

Weighted average common shares outstanding:
Basic	309.5	313.9
Effect of dilutive securities
Restricted common stock	—	—
Stock options	—	—
Performance share units	—	—
Mandatory convertible preferred stock	—	—
Diluted	309.5	313.9

	Actual				Forecast range (a)
	Three Months Ended				Three Months Ended	Twelve Months Ended
	March 31,				June 30,	December 31,
	2018		2017		2018	2018
Cash operating costs	$	13.46	$	14.16	$14.50 — $15.50	$13.00 — $14.00
DD&A		16.77		25.10	17.50 — 18.50	18.00 — 19.00
Total Production Unit Costs	$	30.23	$	39.26	$32.00 — $34.00	$31.00 — $33.00

	Three Months Ended, March 31,
	2018			2017
	(In millions)
Net cash provided by (used in):
Operating activities	$	210		$	349
Investing activities		(422	)		(290	)
Financing activities		(909	)		(105	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(1,121	)	$	(46	)

	Three Months Ended, March 31
	2018			2017
	(In millions)
Capital expenditures incurred - E&P	$	(354	)	$	(342	)
Increase (decrease) in related liabilities		(9	)		2
Additions to property, plant and equipment - E&P	$	(363	)	$	(340	)

Capital expenditures incurred - Midstream	$	(37	)	$	(28	)
Increase (decrease) in related liabilities		—			(22	)
Additions to property, plant and equipment - Midstream	$	(37	)	$	(50	)

Period	Total Number of Shares Purchased (a) (b)		Average Price Paid per Share (a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (c)		Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (d) (In millions)
January		607,771	$	52.30		607,771	$	998
February		3,670,578		45.76		3,670,578		830
March		3,748,598		48.57		3,708,888		1,650
Total		8,026,947	$	47.57		7,987,237

a.	Exhibits
	10(1)	Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Plan.
	10(2)	Form of Stock Option Award Agreement under the 2017 Long-Term Incentive Plan.
	10(3)	Form of Performance Award Agreement for three-year period ending December 31, 2020 under the 2017 Long-Term Incentive Plan.
	31(1)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
	31(2)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
	32(1)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
	32(2)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
	101(INS)	XBRL Instance Document.
	101(SCH)	XBRL Schema Document.
	101(CAL)	XBRL Calculation Linkbase Document.
	101(LAB)	XBRL Labels Linkbase Document.
	101(PRE)	XBRL Presentation Linkbase Document.
	101(DEF)	XBRL Definition Linkbase Document.

HESS CORPORATION
(REGISTRANT)


By		/s/ John B. Hess
		JOHN B. HESS
		CHIEF EXECUTIVE OFFICER


By		/s/ John P. Rielly
		JOHN P. RIELLY
		SENIOR VICE PRESIDENT AND
		CHIEF FINANCIAL OFFICER