HESS CORP - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended September 30, 2015

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-1204

HESS CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE

(State or Other Jurisdiction of Incorporation or Organization)

13-4921002

(I.R.S. Employer Identification Number)

1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y.

(Address of Principal Executive Offices)

10036

(Zip Code)

(Registrant’s Telephone Number, Including Area Code is (212) 997-8500)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its Corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Large Accelerated Filer	x	Accelerated Filer	¨	Non-Accelerated Filer	¨	Smaller Reporting Company	¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At September 30, 2015, there were 286,097,193 shares of Common Stock outstanding.

HESS CORPORATION

Form 10-Q

TABLE OF CONTENTS

Item No.		Page Number
	PART I FINANCIAL INFORMATION
1.	Financial Statements (Unaudited)
	Consolidated Balance Sheet at September 30, 2015, and December 31, 2014	2
	Statement of Consolidated Income for the Three and Nine Months Ended September 30, 2015, and 2014	3
	Statement of Consolidated Comprehensive Income for the Three and Nine Months Ended September 30, 2015, and 2014	4
	Statement of Consolidated Cash Flows for the Nine Months Ended September 30, 2015, and 2014	5
	Statement of Consolidated Equity for the Nine Months Ended September 30, 2015, and 2014	6
	Notes to Consolidated Financial Statements	7
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
3.	Quantitative and Qualitative Disclosures about Market Risk	33
4.	Controls and Procedures	33

	PART II OTHER INFORMATION
1.	Legal Proceedings	34
2.	Share Repurchase Activities	34
6.	Exhibits and Reports on Form 8-K	35
	Signatures	36
	Certifications

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30,			December 31,
	2015			2014
	(In millions,
	except share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,013		$	2,444
Accounts receivable
Trade		1,211			1,642
Other		311			431
Inventories		535			527
Other current assets		527			1,643
Total current assets		5,597			6,687
PROPERTY, PLANT AND EQUIPMENT
Total — at cost		48,138			46,522
Less: Reserves for depreciation, depletion, amortization and lease impairment		21,255			19,005
Property, plant and equipment — net		26,883			27,517
GOODWILL		1,473			1,858
DEFERRED INCOME TAXES		2,109			2,169
OTHER ASSETS		394			347
TOTAL ASSETS	$	36,456		$	38,578
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	537		$	708
Accrued liabilities		1,930			3,781
Taxes payable		79			294
Current maturities of long-term debt		78			68
Total current liabilities		2,624			4,851
LONG-TERM DEBT		6,474			5,919
DEFERRED INCOME TAXES		1,618			2,009
ASSET RETIREMENT OBLIGATIONS		2,161			2,281
OTHER LIABILITIES AND DEFERRED CREDITS		1,216			1,198
Total liabilities		14,093			16,258
EQUITY
Hess Corporation stockholders’ equity
Common stock, par value $1.00
Authorized — 600,000,000 shares
Issued — 286,097,193 shares at September 30, 2015; 285,834,964 shares at December 31, 2014		286			286
Capital in excess of par value		4,097			3,277
Retained earnings		18,530			20,052
Accumulated other comprehensive income (loss)		(1,582	)		(1,410	)
Total Hess Corporation stockholders’ equity		21,331			22,205
Noncontrolling interests		1,032			115
Total equity		22,363			22,320
TOTAL LIABILITIES AND EQUITY	$	36,456		$	38,578

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions, except per share amounts)
REVENUES AND NON-OPERATING INCOME
Sales and other operating revenues	$	1,671		$	2,678	$	5,162		$	8,180
Gains on asset sales, net		50			31		50			820
Other, net		(32	)		27		(38	)		(89	)
Total revenues and non-operating income		1,689			2,736		5,174			8,911

COSTS AND EXPENSES
Cost of products sold (excluding items shown separately below)		356			423		990			1,208
Operating costs and expenses		508			511		1,517			1,551
Production and severance taxes		29			69		110			209
Exploration expenses, including dry holes and lease impairment		144			90		503			669
General and administrative expenses		119			139		417			424
Interest expense		84			75		255			241
Depreciation, depletion and amortization		988			838		2,972			2,349
Impairment		—			—		385			—
Total costs and expenses		2,228			2,145		7,149			6,651
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(539	)		591		(1,975	)		2,260
Provision (benefit) for income taxes		(300	)		232		(807	)		563
INCOME (LOSS) FROM CONTINUING OPERATIONS		(239	)		359		(1,168	)		1,697
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES		(13	)		671		(40	)		684
NET INCOME (LOSS)		(252	)		1,030		(1,208	)		2,381
Less: Net income (loss) attributable to noncontrolling interests		27			22		27			56
NET INCOME (LOSS) ATTRIBUTABLE TO HESS CORPORATION	$	(279	)	$	1,008	$	(1,235	)	$	2,325

NET INCOME (LOSS) ATTRIBUTABLE TO HESS CORPORATION PER SHARE
BASIC:
Continuing operations	$	(0.94	)	$	1.19	$	(4.21	)	$	5.51
Discontinued operations		(0.04	)		2.16		(0.14	)		2.03
NET INCOME (LOSS) PER SHARE	$	(0.98	)	$	3.35	$	(4.35	)	$	7.54

DILUTED:
Continuing operations	$	(0.94	)	$	1.18	$	(4.21	)	$	5.43
Discontinued operations		(0.04	)		2.13		(0.14	)		2.01
NET INCOME (LOSS) PER SHARE	$	(0.98	)	$	3.31	$	(4.35	)	$	7.44

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)		283.5			305.0		283.8			312.7
COMMON STOCK DIVIDENDS PER SHARE	$	0.25		$	0.25	$	0.75		$	0.75

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions)

NET INCOME (LOSS)	$	(252	)	$	1,030		$	(1,208	)	$	2,381

OTHER COMPREHENSIVE INCOME (LOSS):

Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		(34	)		(8	)		(34	)		(18	)
Income taxes on effect of hedge (gains) losses reclassified to income		13			3			13			7
Net effect of hedge (gains) losses reclassified to income		(21	)		(5	)		(21	)		(11	)
Change in fair value of cash flow hedges		109			90			111			64
Income taxes on change in fair value of cash flow hedges		(41	)		(34	)		(42	)		(24	)
Net change in fair value of cash flow hedges		68			56			69			40
Change in derivatives designated as cash flow hedges, after taxes		47			51			48			29

Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		(5	)		—			(20	)		(4	)
Income taxes on actuarial changes in plan liabilities		1			—			7			2
(Increase) reduction in unrecognized actuarial losses, net		(4	)		—			(13	)		(2	)
Amortization of net actuarial losses		29			19			73			42
Income taxes on amortization of net actuarial losses		(10	)		(7	)		(24	)		(15	)
Net effect of amortization of net actuarial losses		19			12			49			27
Change in pension and other postretirement plans, after taxes		15			12			36			25

Foreign currency translation adjustment
Foreign currency translation adjustment		(208	)		(166	)		(256	)		(203	)
Change in foreign currency translation adjustment		(208	)		(166	)		(256	)		(203	)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(146	)		(103	)		(172	)		(149	)

COMPREHENSIVE INCOME (LOSS)		(398	)		927			(1,380	)		2,232
Less: Comprehensive income (loss) attributable to noncontrolling interests		27			22			27			56
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO HESS CORPORATION	$	(425	)	$	905		$	(1,407	)	$	2,176

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)

	Nine Months Ended
	September 30,
	2015			2014
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(1,208	)	$	2,381
Adjustments to reconcile net income (loss) to net cash provided by operating activities
(Gains) losses on asset sales, net		(50	)		(820	)
Depreciation, depletion and amortization		2,972			2,349
Impairment		385			—
Loss from equity affiliates		10			84
Exploratory dry hole costs		180			297
Exploration lease impairment		139			183
Stock compensation expense		71			65
Provision (benefit) for deferred income taxes		(819	)		220
(Income) loss from discontinued operations, net of income taxes		40			(684	)
Changes in operating assets and liabilities		(331	)		(657	)
Cash provided by (used in) operating activities - continuing operations		1,389			3,418
Cash provided by (used in) operating activities - discontinued operations		(31	)		(35	)
Net cash provided by (used in) operating activities		1,358			3,383

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant and equipment		(3,386	)		(3,686	)
Proceeds from asset sales		25			2,978
Other, net		(44	)		(136	)
Cash provided by (used in) investing activities - continuing operations		(3,405	)		(844	)
Cash provided by (used in) investing activities - discontinued operations		108			2,407
Net cash provided by (used in) investing activities		(3,297	)		1,563

CASH FLOWS FROM FINANCING ACTIVITIES
Debt with maturities of greater than 90 days
Borrowings		600			598
Repayments		(51	)		(553	)
Common stock acquired and retired		(142	)		(2,638	)
Cash dividends paid		(215	)		(232	)
Employee stock options exercised, including income tax benefits		11			191
Noncontrolling interests, net		2,329			(4	)
Other, net		(24	)		—
Cash provided by (used in) financing activities - continuing operations		2,508			(2,638	)
Cash provided by (used in) financing activities - discontinued operations		—			(2	)
Net cash provided by (used in) financing activities		2,508			(2,640	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		569			2,306
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		2,444			1,814
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,013		$	4,120

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

										Accumulated
				Capital in						Other			Total Hess
	Common			Excess of			Retained			Comprehensive			Stockholders’			Noncontrolling			Total
	Stock			Par			Earnings			Income (Loss)			Equity			Interests			Equity
	(In millions)
BALANCE AT JANUARY 1, 2015	$	286		$	3,277		$	20,052		$	(1,410	)	$	22,205		$	115		$	22,320
Net income (loss)								(1,235	)					(1,235	)		27			(1,208	)
Other comprehensive income (loss)											(172	)		(172	)		—			(172	)
Comprehensive income (loss)														(1,407	)		27			(1,380	)
Activity related to restricted common stock awards, net		1			46			—			—			47			—			47
Employee stock options, including income tax benefits		—			14			—			—			14			—			14
Performance share units		—			19			—			—			19			—			19
Cash dividends declared		—			—			(215	)		—			(215	)		—			(215	)
Common stock acquired and retired		(1	)		(18	)		(72	)		—			(91	)		—			(91	)
Formation of Bakken Midstream joint venture		—			759			—			—			759			1,305			2,064
Noncontrolling interests, net		—			—			—			—			—			(415	)		(415	)
BALANCE AT SEPTEMBER 30, 2015	$	286		$	4,097		$	18,530		$	(1,582	)	$	21,331		$	1,032		$	22,363

BALANCE AT JANUARY 1, 2014	$	325		$	3,498		$	21,235		$	(338	)	$	24,720		$	64		$	24,784
Net income (loss)								2,325						2,325			56			2,381
Other comprehensive income (loss)											(149	)		(149	)		—			(149	)
Comprehensive income (loss)														2,176			56			2,232
Activity related to restricted common stock awards, net		1			46			—			—			47			—			47
Employee stock options, including income tax benefits		3			190			—			—			193			—			193
Performance share units		—			14			—			—			14			—			14
Cash dividends declared		—			—			(232	)		—			(232	)		—			(232	)
Common stock acquired and retired		(30	)		(331	)		(2,308	)		—			(2,669	)		—			(2,669	)
Noncontrolling interests, net		—			—			—			—			—			(4	)		(4	)
BALANCE AT SEPTEMBER 30, 2014	$	299		$	3,417		$	21,020		$	(487	)	$	24,249		$	116		$	24,365

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Basis of Presentation

The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Corporation’s consolidated financial position at September 30, 2015 and December 31, 2014, the consolidated results of operations for the three months and nine months ended September 30, 2015 and 2014, and consolidated cash flows for the nine months ended September 30, 2015 and 2014. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

The financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (SEC) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by 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, 2014.

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

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

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

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

2. Bakken Midstream Joint Venture

On July 1, 2015 the Corporation sold a 50% interest in Hess Infrastructure Partners LP (HIP) to Global Infrastructure Partners (GIP) for net cash consideration of approximately $2.6 billion. HIP and its affiliates comprise the Corporation’s Bakken Midstream operating segment which provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids (NGLs), terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane, primarily located in the Bakken shale play of North Dakota. Such services are currently provided solely to the Corporation’s Bakken shale operations under tariff agreements with Bakken Midstream entities, with plans to market services to third parties in the future. The Corporation operates the Bakken Midstream assets and operations, including routine and emergency maintenance and repair services under various operational and administrative services agreements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The tariff agreements between the Corporation and the Bakken Midstream entities are 10-year, fee-based commercial agreements, with HIP having the sole option to renew the agreements for an additional 10-year term. These agreements include minimum volume commitments based on dedicated production, inflation escalators and fee recalculation mechanisms. The Bakken Midstream segment has minimal direct commodity price exposure, and the Corporation retains ownership of the crude oil, natural gas or natural gas liquids processed, terminaled, stored or transported by the Bakken Midstream segment.

The Corporation consolidates the activities of HIP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. The Corporation, through its 50% ownership, has concluded that it is the primary beneficiary of the VIE, as defined in the accounting standards, since it has the power to direct those activities that most significantly impact the economic performance of HIP. This conclusion was based on a qualitative analysis that considered HIP’s governance structure, the commercial agreements between HIP and the Corporation, and the voting rights established between the members which provide the Corporation the ability to control the operations of HIP.

As a result of the July 1, 2015 sale transaction, the Corporation recorded an after-tax gain of $759 million in additional paid-in-capital and an increase to total shareholder’s equity of $1,305 million in noncontrolling interest representing GIP’s proportional share of the Corporation’s basis in the net assets of HIP. The results attributable to GIP’s 50% ownership is reported within Net income (loss) attributable to noncontrolling interests in the Statement of Consolidated Income, while the carrying amount of GIP’s equity is included as Noncontrolling interests in the Consolidated Balance Sheet.

Upon formation, the joint venture incurred $600 million of debt through a 5-year Term Loan A facility with the proceeds distributed equally to the partners. See Note 7, Debt. HIP liabilities totaling $727 million at September 30, 2015 are on a nonrecourse basis to the Corporation, while HIP assets available to settle the obligations of HIP included Cash and cash equivalents totaling $9 million and Property, plant and equipment totaling $2,233 million at September 30, 2015.

3. Discontinued Operations

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

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions)
Sales and other operating revenues	$	—		$	3,096	$	14		$	9,346

Income (loss) from discontinued operations before income taxes	$	(16	)	$	1,057	$	(59	)	$	1,063
Current tax provision (benefit)		—			—		—			—
Deferred tax provision (benefit)		(3	)		386		(19	)		379
Provision (benefit) for income taxes		(3	)		386		(19	)		379
Income (loss) from discontinued operations, net of income taxes	$	(13	)	$	671	$	(40	)	$	684
Less: Net income (loss) attributable to noncontrolling interests		—			22		—			56
Income (loss) from discontinued operations attributable to Hess Corporation	$	(13	)	$	649	$	(40	)	$	628

In September 2014, the Corporation completed the sale of its retail business for cash proceeds of approximately $2.8 billion. This transaction resulted in a pre-tax gain of $954 million ($602 million after income taxes).

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

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

4. Inventories

Inventories consisted of the following:

	September 30,		December 31,
	2015		2014
	(In millions)
Crude oil and natural gas liquids	$	217	$	246
Materials and supplies		318		281
Total inventories	$	535	$	527

5. Capitalized Exploratory Well Costs

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves for the nine months ended September 30, 2015 (in millions):

Balance at January 1	$	1,416
Additions to capitalized exploratory well costs pending the determination of proved reserves		326
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(72	)
Capitalized exploratory well costs charged to expense		(120	)
Balance at September 30, 2015	$	1,550

Capitalized exploratory well costs charged to expense in the preceding table primarily relate to the Dinarta Block in the Kurdistan Region of Iraq following the decision of the Corporation and its partner in March 2015 to cease further drilling activity in the region. In addition, the Corporation expensed $60 million of exploratory well costs incurred during 2015 that are not reflected in the preceding table.

Capitalized exploratory well costs greater than one year old after completion of drilling were $1,293 million at September 30, 2015. Approximately 65% of the capitalized well costs in excess of one year relates to Block WA-390-P, offshore Western Australia, where development planning and commercial activities for the Corporation’s natural gas discoveries are ongoing. In December 2014, the Corporation executed a non-binding letter of intent with the North West Shelf (NWS), a third party joint venture with existing natural gas processing and liquefaction facilities. Successful execution of binding agreements with NWS is necessary before the Corporation can execute a gas sales agreement and sanction development of the project. Approximately 35% of the capitalized well costs in excess of one year relates to offshore Ghana, where the Corporation has drilled seven successful exploration wells. Appraisal plans for the seven discoveries on the block were submitted to the Ghanaian government in June 2013 for approval. Four of the plans were approved and discussions continue with the government on the three remaining appraisal plans. In 2014, the Corporation completed three appraisal wells in Ghana. Well results continue to be evaluated and development planning is progressing. The government of Côte d’Ivoire has challenged the maritime border between it and the country of Ghana, which includes a portion of our Deepwater Tano Cape Three Points license. We are unable to proceed with development of this license until there is a resolution of this matter, which may also impact our ability to develop the license.

6. Goodwill

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

In accordance with accounting standards for goodwill, the Corporation performed impairment tests at June 30, 2015 on the Offshore and Onshore reporting units prior to creation of the Bakken Midstream segment. No impairment resulted from

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this assessment. In addition, accounting standards require that following a reorganization, allocated goodwill should be tested for impairment. The Corporation also performed impairment tests on the allocated goodwill for the Bakken Midstream and the Onshore reporting unit at June 30, 2015. Goodwill allocated to the Bakken Midstream operating segment passed the impairment test but the goodwill allocated to the Onshore reporting unit did not pass the impairment test. As a result, the Corporation recorded a noncash pre-tax charge of $385 million ($385 million after income taxes) in the second quarter of 2015 to reflect the Onshore reporting unit’s goodwill at its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards.

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

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

	Exploration and Production			Bakken Midstream		Total
Beginning balance at January 1	$	1,858		$	—	$	1,858
Reclassification		(375	)		375		—
Impairment		(385	)		—		(385	)
Ending balance at September 30, 2015	$	1,098		$	375	$	1,473

7. Debt

In January 2015, the Corporation entered into a $4 billion syndicated revolving credit facility that expires in January 2020. The new facility, which replaced a $4 billion facility that was scheduled to expire in April 2016, can be used for borrowings and letters of credit. Based on the Corporation’s credit rating as of September 30, 2015, borrowings on the facility will generally bear interest at a rate of 1.075% above the London Interbank Offered Rate (LIBOR) with the facility fee amounting to 0.175% per annum. The interest rate and facility fee are subject to adjustment if the Corporation's credit rating changes. The restrictions on the amount of total borrowings and secured debt are substantially similar to the previous facility. At September 30, 2015, there were no borrowings outstanding or letters of credit issued against the syndicated revolving credit facility.

In July 2015, HIP, a 50/50 joint venture between the Corporation and GIP, incurred $600 million of debt through a 5-year Term Loan A facility. The proceeds from the debt were distributed equally to the partners. HIP also entered into a $400 million 5-year syndicated revolving credit facility, which can be used for borrowings and letters of credit and is expected to fund the joint venture’s operating activities and capital expenditures. Borrowings on both loan facilities generally bear interest at LIBOR plus an applicable margin ranging from 1.10% to 2.00%. Facility fees on the revolving credit facility accrue at an applicable rate every quarter, ranging from 0.15% to 0.35% per annum. Prior to obtaining credit ratings, applicable interest margins and facility fees are based on the joint venture’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If the joint venture obtains credit ratings, pricing levels will be based on its credit ratings in effect from time to time. The joint venture is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. At September 30, 2015, borrowings attributable to the joint venture amounted to $600 million on the Term Loan A loan facility. This debt is non-recourse to the Corporation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

8. Dispositions

In the third quarter of 2015, the Corporation completed the sale of approximately 13,000 acres of Utica dry gas acreage for a sales price of approximately $120 million. The transaction resulted in a pre-tax gain of $49 million ($31 million after income taxes).

9. Exit and Severance Costs

During the nine months ended September 30, 2015, the Corporation recorded exit related costs of $11 million associated with vacant office space. During the three and nine months ended September 30, 2014, the Corporation recorded exit related costs of $20 million and $44 million, respectively. In addition, the Corporation incurred severance expense of $11 million for the three and nine months ended September 30, 2015 and incurred severance expense totaling $16 million and $77 million during the three months and nine months ended September 30, 2014, respectively, primarily related to the Corporation’s divestiture program. During the three and nine months ended September 30, 2015, payments for accrued severance costs amounted to $6 million and $43 million, respectively. The Corporation has accrued liabilities of $20 million for exit related costs and $44 million for severance at September 30, 2015.

10. Retirement Plans

Components of net periodic pension cost consisted of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions)
Service cost	$	18		$	15		$	53		$	40
Interest cost		26			26			78			75
Expected return on plan assets		(42	)		(41	)		(127	)		(121	)
Amortization of unrecognized net actuarial losses		19			8			58			23
Settlement loss		10			11			15			19
Pension expense	$	31		$	19		$	77		$	36

In 2015, the Corporation expects to contribute approximately $45 million to its funded pension plans. Through September 30, 2015, the Corporation contributed $41 million of this amount.

11. Income Taxes

In the third quarter of 2015, the Corporation received approval for an international investment incentive. As a result, the Corporation recognized a tax benefit of $50 million in the current period.

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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:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions, except per share amounts)
Net income (loss) from continuing operations, net of income taxes	$	(239	)	$	359	$	(1,168	)	$	1,697
Less: Net income (loss) attributable to noncontrolling interests		27			—		27			—
Net income (loss) from continuing operations attributable to Hess Corporation	$	(266	)	$	359	$	(1,195	)	$	1,697
Income (loss) from discontinued operations, net of income taxes		(13	)		671		(40	)		684
Less: Net income (loss) attributable to noncontrolling interests		—			22		—			56
Net income (loss) from discontinued operations attributable to Hess Corporation		(13	)		649		(40	)		628
Net income (loss) attributable to Hess Corporation	$	(279	)	$	1,008	$	(1,235	)	$	2,325

Weighted average common shares outstanding:
Basic		283.5			300.7		283.8			308.6
Effect of dilutive securities
Restricted common stock		—			1.5		—			1.4
Stock options		—			2.0		—			2.0
Performance share units		—			0.8		—			0.7
Diluted		283.5			305.0		283.8			312.7

Net income (loss) attributable to Hess Corporation per share:
Basic:
Continuing operations	$	(0.94	)	$	1.19	$	(4.21	)	$	5.51
Discontinued operations		(0.04	)		2.16		(0.14	)		2.03
Net income (loss) per share	$	(0.98	)	$	3.35	$	(4.35	)	$	7.54
Diluted:
Continuing operations	$	(0.94	)	$	1.18	$	(4.21	)	$	5.43
Discontinued operations		(0.04	)		2.13		(0.14	)		2.01
Net income (loss) per share	$	(0.98	)	$	3.31	$	(4.35	)	$	7.44

The Corporation granted 1,127,242 shares of restricted stock, 362,873 performance share units (PSUs) and 521,773 stock options during the nine months ended September 30, 2015 and 1,073,179 shares of restricted stock, 298,222 PSUs and 162,911 stock options for the same period in 2014. The Corporation excluded 6,983,524 stock options, 2,955,200 restricted stock awards and 915,238 PSUs from the computation of diluted shares for the three months ended September 30, 2015 and excluded 6,928,958 stock options, 2,953,075 restricted stock awards and 988,963 PSUs from the computation of diluted shares for the nine months ended September 30, 2015 as they are anti-dilutive. The weighted average common shares used in the diluted earnings per share calculations for the three and nine months ended September 30, 2014 excluded stock options amounting to 124,357 and 1,214,422, respectively, as they were anti-dilutive.

The Corporation is permitted but not required to repurchase up to $6.5 billion of outstanding common shares under a Board authorized plan. During the third quarter and first nine months of 2015, the Corporation purchased $55 million and $91 million of common stock, respectively. As of September 30, 2015 total shares repurchased under the plan were 64.1 million shares at a cost of approximately $5.4 billion.

13. Guarantees and Contingencies

The Corporation is subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in the Corporation’s 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, the Corporation discloses the nature of those contingencies. The Corporation cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

In July 2004, HOVENSA LLC (HOVENSA), a 50/50 joint venture between the Corporation’s subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), and HOVIC each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the HOVENSA refinery, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. In 2014 HOVIC, HOVENSA and the government of the U.S. Virgin Islands entered into a settlement agreement pursuant to which HOVENSA paid $3.5 million and agreed to pay the government of the U.S. Virgin Islands an additional $40 million no later than December 31, 2014. HOVENSA was unable to make this additional payment because the U.S. Virgin Islands legislature did not approve a proposed operating agreement required to complete a proposed sale of HOVENSA, which would have provided funds to make the settlement payment. Under the terms of the settlement agreement, the U.S. Virgin Islands government was granted a first lien on HOVENSA’s assets to secure the settlement payment, and in January 2015 the government commenced a foreclosure action to enforce this lien. On September 15, 2015, HOVENSA filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States District Court of the Virgin Islands - Bankruptcy Division (the “Bankruptcy Court”). As part of its chapter 11 case, HOVENSA is pursuing a court-supervised sale process, seeking to sell all or substantially all of its assets pursuant to section 363 of the Bankruptcy Code. The Bankruptcy Court has approved certain procedures by which HOVENSA will receive bids for its assets and determine the eventual buyer of its assets in the section 363 sale process. The Bankruptcy Court also entered an order approving HOVENSA’s entry into a $40 million debtor-in-possession credit facility with HOVENSA’s owners for the purpose of funding HOVENSA through December 31, 2015. HOVIC has committed to fund up to $20 million, if needed, to HOVENSA, with PDVSA funding the remainder of the facility. The Corporation cannot predict with certainty if, how, or when HOVENSA’s chapter 11 case will be resolved. As part of HOVENSA’s chapter 11 case, parties, including the government of the Virgin Islands and other creditors, may pursue claims against HOVENSA, HOVIC, or the Registrant relating to the ownership and management of, and business dealings with HOVENSA.

On September 13, 2015, two days before HOVENSA filed for chapter 11 relief, the government of the U.S. Virgin Islands filed a complaint against the Corporation in the territorial Superior Court of the Virgin Islands, Division of St. Croix, alleging, among other things, that the Corporation violated the Territory’s Criminally Influenced and Corrupt Organizations Act and committed various torts in connection with the 50% ownership interest of its subsidiary, HOVIC, in HOVENSA. In the complaint, the government of the U.S. Virgin Islands claims aggregate damages of up to approximately $1.5 billion and is seeking a treble damage award with respect to certain claims. The Corporation has filed a notice removing the complaint to the federal District Court of the Virgin Islands and filed a motion to refer the complaint to the Bankruptcy Court presiding over HOVENSA’s chapter 11 case. The Corporation will vigorously defend itself and believes that it has strong defenses against these claims alleged by the government of the U.S. Virgin Islands.

In February 2015, the Pension Benefit Guaranty Corporation (PBGC) issued a notice of determination to terminate the HOVENSA pension plan. Resolution of this matter with the PBGC will likely occur in connection with HOVENSA's pending chapter 11 case.

The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. The Corporation cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of

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development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on the financial condition, results of operations or cash flows of the Corporation.

14. Segment Information

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

For the Three Months Ended September 30, 2015	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total

Operating Revenues - Third parties	$	1,671		$	—	$	—		$	—		$	1,671
Intersegment Revenues		—			148		—			(148	)		—
Operating Revenues	$	1,671		$	148	$	—		$	(148	)	$	1,671

Net income (loss) from continuing operations attributable to Hess Corporation	$	(188	)	$	16	$	(94	)	$	—		$	(266	)
Depreciation, depletion and amortization		963			22		3			—			988
Provision (benefit) for income taxes		(256	)		10		(54	)		—			(300	)
Capital Expenditures*		770			88		—			—			858

For the Three Months Ended September 30, 2014	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total

Operating Revenues - Third parties	$	2,678		$	—	$	—		$	—		$	2,678
Intersegment Revenues		—			89		—			(89	)		—
Operating Revenues	$	2,678		$	89	$	—		$	(89	)	$	2,678

Net income (loss) from continuing operations attributable to Hess Corporation	$	433		$	8	$	(82	)	$	—		$	359
Depreciation, depletion and amortization		815			19		4			—			838
Provision (benefit) for income taxes		278			5		(51	)		—			232
Capital Expenditures*		1,296			47		19			—			1,362

For the Nine Months Ended September 30, 2015	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total

Operating Revenues - Third parties	$	5,162		$	—	$	—		$	—		$	5,162
Intersegment Revenues		—			423		—			(423	)		—
Operating Revenues	$	5,162		$	423	$	—		$	(423	)	$	5,162

Net income (loss) from continuing operations attributable to Hess Corporation	$	(1,004	)	$	75	$	(266	)	$	—		$	(1,195	)
Depreciation, depletion and amortization		2,899			65		8			—			2,972
Provision (benefit) for income taxes		(687	)		45		(165	)		—			(807	)
Capital Expenditures*		2,915			193		—			—			3,108

For the Nine Months Ended September 30, 2014	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total

Operating Revenues - Third parties	$	8,180		$	—	$	—		$	—		$	8,180
Intersegment Revenues		—			218		—			(218	)		—
Operating Revenues	$	8,180		$	218	$	—		$	(218	)	$	8,180

Net income (loss) from continuing operations attributable to Hess Corporation	$	2,003		$	2	$	(308	)	$	—		$	1,697
Depreciation, depletion and amortization		2,289			48		12			—			2,349
Provision (benefit) for income taxes		754			2		(193	)		—			563
Capital Expenditures*		3,491			168		51			—			3,710

* Capital expenditures include accruals.

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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Identifiable assets by operating segment were as follows:

	September 30,		December 31,
	2015		2014
	(In millions)
Exploration and Production	$	30,898	$	32,742
Bakken Midstream		2,650		2,465
Corporate, Interest and Other		2,908		2,213
Continuing operations		36,456		37,420
Discontinued operations		—		1,158
Total	$	36,456	$	38,578

15. Financial Risk Management

In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas liquids, and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate risk management activities refer to the mitigation of these risks through hedging activities.

Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix or reduce volatility in the forward selling price of a portion of the Corporation’s crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does business with the intent of reducing exposure to foreign currency fluctuations. These forward contracts comprise various currencies, primarily the British Pound and Danish Krone. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

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

	September 30,		December 31,
	2015		2014
Commodity, primarily crude oil (millions of barrels)		9		—
Foreign exchange (millions of USD)	$	985	$	1,189
Interest rate swaps (millions of USD)	$	1,300	$	1,300

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

Realized and unrealized gains from Brent and WTI crude oil collars for the three and nine months ended September 30, 2015 increased Sales and other operating revenues by $42 million and $24 million, respectively, which was net of pre-tax losses of $23 million and $46 million, respectively, associated with changes in time value of the hedging contracts. Realized and unrealized gains in 2014 amounted to $37 million and $36 million for the three months and nine months ended September 30, 2014, respectively. There was no significant hedge ineffectiveness for the three months and nine months ended September 30, 2015. The Corporation recorded gains associated with hedge ineffectiveness of approximately $6 million and $2 million for the three months and nine months ended September 30, 2014, respectively. At September 30, 2015, the after-tax deferred gains in Accumulated other comprehensive income (loss) related to crude oil collars was approximately $47 million, which will be reclassified into earnings during 2015 as the hedged crude oil sales are recognized in earnings.

At September 30, 2015 and December 31, 2014, the Corporation had interest rate swaps with gross notional amounts of $1,300 million. During the first quarter of 2015, the Corporation settled existing interest rate swaps and received cash proceeds of $41 million. Simultaneously, the Corporation entered into new interest rate swap arrangements. All interest rate

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

swaps have been designated as fair value hedges. The Corporation recorded increases of $10 million and $14 million for the three months and nine months ended September 30, 2015, respectively, and decreases of $10 million and $5 million for the three months and nine months ended September 30, 2014, respectively, in the fair value of interest rate swaps (excluding accrued interest). These items, excluding accrued interest, offset changes in the carrying value of the hedged fixed-rate debt.

Total foreign exchange gains and losses are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income and amounted to a loss of $15 million and a loss of $7 million in the three months and nine months ended September 30, 2015, respectively, compared with a gain of $19 million and a loss of $6 million in the three months and nine months ended September 30, 2014, respectively. Gains on foreign exchange derivative contracts not designated as hedges, which are a component of total foreign exchange gains and losses, amounted to $13 million and $71 million in the three and nine months ended September 30, 2015, respectively, and $81 million and $68 million the three and nine months ended September 30, 2014, respectively.

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

				Gross Amounts Offset
				in the Consolidated
				Balance Sheet
				Physical					Net Amounts			Gross Amounts
				Derivative					Presented in			Not Offset in
				and					the			the
	Gross			Financial			Cash		Consolidated			Consolidated		Net
	Amounts			Instruments			Collateral		Balance Sheet			Balance Sheet		Amounts
	(i)			(ii)			(iii)		(iv)=(i)+(ii)+(iii)			(v)		(vi)=(iv)+(v)
	(In millions)
September 30, 2015
Assets
Derivative contracts
Commodity	$	97		$	(21	)	$	—	$	76		$	—	$	76
Interest rate and other		33			(4	)		—		29			—		29
Counterparty netting		—			—			—		—			—		—
Total derivative contracts	$	130		$	(25	)	$	—	$	105		$	—	$	105
Liabilities
Derivative contracts
Commodity	$	(24	)	$	21		$	—	$	(3	)	$	—	$	(3	)
Other		(4	)		4			—		—			—		—
Counterparty netting		—			—			—		—			—		—
Total derivative contracts	$	(28	)	$	25		$	—	$	(3	)	$	—	$	(3	)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

	Accounts			Accounts
	Receivable			Payable
	(In millions)
September 30, 2015
Derivative contracts designated as hedging instruments
Commodity	$	76		$	—
Interest rate and other		14			—
Total derivative contracts designated as hedging instruments		90			—
Derivative contracts not designated as hedging instruments
Commodity		21			(24	)
Foreign exchange		19			(4	)
Total derivative contracts not designated as hedging instruments		40			(28	)
Gross fair value of derivative contracts		130			(28	)
Master netting arrangements		(25	)		25
Net fair value of derivative contracts	$	105		$	(3	)

At September 30, 2015, Level 1 items comprised $3 million of Derivative liabilities. Level 2 items comprised Derivative assets of $105 million, which included commodity contracts of $76 million and interest rate and other items of $29 million. The Corporation did not have Level 3 instruments at September 30, 2015. For all other short-term financial instruments, primarily cash and cash equivalents, accounts receivable and accounts payable, the carrying value approximated the respective fair value at September 30, 2015. Total Long-term debt of $6,552 million at September 30, 2015, had a fair value of $6,935 million based on Level 2 inputs.

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

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

Third Quarter Results

The Corporation reported a net loss of $279 million in the third quarter of 2015, compared with net income of $1,008 million in the third quarter of 2014. Excluding items affecting comparability of earnings between periods on page 21, adjusted net losses were $291 million in the third quarter of 2015 down from adjusted net income of $377 million in the third quarter of 2014. Lower realized selling prices reduced adjusted third quarter 2015 results by approximately $745 million after-tax compared with the prior-year quarter. In addition, third quarter 2015 results benefitted from higher production and lower cash operating costs that were partially offset by higher depreciation, depletion, and amortization expense.

Response to Low Oil Prices

In response to the decline in oil prices that began in late 2014, the Corporation conducted an extensive company-wide review of its cost base and engaged with our suppliers to identify opportunities to reduce costs. As a result of these efforts to date, the Corporation has lowered its projected 2015 E&P capital and exploratory expenditures by $300 million to $4.1 billion and lowered forecasted cash operating costs by approximately $300 million, or approximately $2.50 per barrel. In addition, the Corporation significantly reduced share repurchases during the nine months ended September 30, 2015 to $91 million.

While the Corporation’s 2016 budgeting process will not be finalized until the end of the year, the Corporation presently expects full year 2016 E&P capital and exploratory expenditures to be in the range of $2.9 billion to $3.1 billion. Oil and gas production in 2016 is forecast to be in the range of 330,000 to 350,000 barrels of oil equivalent per day (boepd) compared with projected production of 370,000 to 375,000 boepd in 2015. Based on current strip crude oil prices, the Corporation forecasts a significant net loss and a net operating cash flow deficit (including capital expenditures) in 2015 and 2016. At September 30, 2015, the Corporation had $3.0 billion in cash and cash equivalents and total liquidity of nearly $8 billion. The Corporation expects to fund its net operating cash flow deficit (including capital expenditures) for the remainder of 2015 and the full year of 2016 with existing cash on hand, and, if necessary, borrowings under its credit facilities. The Corporation plans to maintain its financial flexibility and will continue to pursue further cost reductions and supply chain savings. Depending on where crude oil prices trend, the Corporation may take other steps to improve its financial position by further reducing its planned capital program, accessing other sources of liquidity by issuing debt and equity securities, and/or pursuing further asset sales.

Exploration and Production

E&P incurred a net loss of $188 million in the third quarter of 2015 compared with net income of $433 million in the third quarter of 2014. Excluding items affecting comparability of earnings between periods, the adjusted net loss was $221 million in the third quarter of 2015 compared to adjusted net income of $404 million in 2014. In the third quarter of 2015, the Corporation’s average worldwide crude oil selling price, including the effect of hedging, was $45.66 per barrel down from $96.78 per barrel in the third quarter of 2014. The average worldwide natural gas liquids selling price was $7.17 per barrel in the third quarter of 2015, down from $29.62 per barrel in the year-ago quarter while the average worldwide natural gas selling price was $4.02 per thousand cubic feet (mcf) in the third quarter of 2015 compared with $5.59 per mcf in the third quarter a year-ago. Worldwide crude oil and natural gas production was 380,000 barrels of oil equivalent per day (boepd) in the third quarter of 2015, compared with 318,000 boepd in the same period of 2014.

PART I - FINANCIAL INFORMATION (CONT’D.)

Overview (continued)

The following is an update of E&P activities:

In North Dakota, net production from the Bakken oil shale play increased to an average of 113,000 boepd for the third quarter of 2015 compared with 86,000 boepd in the prior-year quarter due to continued drilling activities. The Corporation brought 48 gross operated wells on production in the third quarter of 2015 bringing the year-to-date total to 185 wells, and expects a further 34 wells to be brought on production in the fourth quarter of 2015. Drilling and completion costs per operated well averaged $5.3 million for the third quarter of 2015, a reduction of 26% from the third quarter of 2014. The Corporation operated an average of seven rigs in the third quarter of 2015 compared with 17 rigs in the third quarter of 2014. The Corporation expects full year 2015 Bakken production to approximate 110,000 boepd. Based on preliminary forecasts, the Corporation intends to operate four Hess operated rigs in 2016 and expects full-year 2016 production to be in the range of 95,000 boepd to 105,000 boepd.

In the Utica shale, net production amounted to 28,000 boepd in the third quarter of 2015, compared to 11,000 boepd in the prior-year quarter. Five wells were drilled, five wells were completed and eleven wells were brought on production across the Corporation’s joint venture acreage in the third quarter of 2015. The Corporation is currently in discussions with its joint venture partner on activity levels for 2016. In the third quarter of 2015, the Corporation completed the sale of approximately 13,000 acres of Utica dry gas acreage for consideration of approximately $120 million.

In the Gulf of Mexico, third quarter net production was 83,000 boepd compared to 70,000 boepd in the prior-year quarter, with higher volumes from Tubular Bells, which totaled 19,000 boepd in the third quarter of 2015, being primarily offset by lower production from the Llano Field. During the third quarter, the Tubular Bells Field experienced a mechanical issue related to a subsurface safety valve that is stuck in the closed position, as well as a near wellbore skin effect at two producing wells and, consequently, these items will require subsurface well intervention work. As a result, full-year 2015 production from Tubular Bells is expected to approximate 20,000 boepd.

Net production from the Valhall Field, offshore Norway increased to 35,000 boepd for the third quarter of 2015 compared with 25,000 boepd in the prior-year quarter due to a higher number of active wells and increased facility uptime in the current period.

At the North Malay Basin in the Gulf of Thailand, the Corporation progressed fabrication of the Central Processing Platform, which is part of the full-field development project. The project is on schedule to be completed in 2017.

In Guyana at the Stabroek Block (Hess 30 percent), the operator, Esso Exploration and Production Guyana Limited, announced a significant oil discovery at the Liza-1 well in the second quarter of 2015. The operator plans to drill an appraisal well in the first quarter of 2016 and is currently completing preparatory technical work and developing drilling plans. A new 17,000 square kilometer 3D seismic shoot is in process and the operator, along with its partners, continues to evaluate the resource potential of the block.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions, except per share amounts)
Net income (loss) attributable to Hess Corporation:
Exploration and Production	$	(188	)	$	433		$	(1,004	)	$	2,003
Bakken Midstream		16			8			75			2
Corporate, Interest and Other		(94	)		(82	)		(266	)		(308	)
Income (loss) from continuing operations		(266	)		359			(1,195	)		1,697
Discontinued operations		(13	)		649			(40	)		628
Total	$	(279	)	$	1,008		$	(1,235	)	$	2,325

Net income (loss) attributable to Hess Corporation per share - Diluted:
Continuing operations	$	(0.94	)	$	1.18		$	(4.21	)	$	5.43
Discontinued operations		(0.04	)		2.13			(0.14	)		2.01
Net income (loss) attributable to Hess Corporation per share - Diluted	$	(0.98	)	$	3.31		$	(4.35	)	$	7.44

Items Affecting Comparability of Earnings Between Periods

The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods. The items in the table below are explained and the pre-tax amounts are shown on pages 26 to 29.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions)
Exploration and Production	$	33		$	29		$	(466	)	$	597
Bakken Midstream		—			—			—			—
Corporate, Interest and Other		(8	)		(2	)		(12	)		(71	)
Discontinued operations		(13	)		604			(40	)		544
Total items affecting comparability of earnings between periods	$	12		$	631		$	(518	)	$	1,070

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions)
Net income (loss) attributable to Hess Corporation	$	(279	)	$	1,008	$	(1,235	)	$	2,325
Less: Total items affecting comparability of earnings between periods		12			631		(518	)		1,070
Adjusted net income (loss) attributable to Hess Corporation	$	(291	)	$	377	$	(717	)	$	1,255

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

In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Comparison of Results

Exploration and Production

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions)
Revenues and non-operating Income
Sales and other operating revenues	$	1,671		$	2,678	$	5,162		$	8,180
Gains on asset sales, net		50			37		50			813
Other, net		(23	)		21		(29	)		(13	)
Total revenues and non-operating income		1,698			2,736		5,183			8,980
Costs and Expenses
Cost of products sold (excluding items shown separate below)(a)		386			447		1,078			1,284
Operating costs and expenses		443			457		1,321			1,393
Production and severance taxes		29			69		110			209
Bakken Midstream tariffs		117			65		335			142
Exploration expenses, including dry holes and lease impairment		144			90		503			669
General and administrative expenses		60			82		243			237
Depreciation, depletion and amortization		963			815		2,899			2,289
Impairment		—			—		385			—
Total costs and expenses		2,142			2,025		6,874			6,223
Results of operations before income taxes		(444	)		711		(1,691	)		2,757
Provision (benefit) for income taxes		(256	)		278		(687	)		754
Net income (loss) attributable to Hess Corporation	$	(188	)	$	433	$	(1,004	)	$	2,003

(a)	Includes amounts from the Bakken Midstream.

Excluding the E&P items affecting comparability of earnings between periods in the table on page 26, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, cash operating costs, depreciation, depletion and amortization, Bakken Midstream tariffs, exploration expenses and income taxes, as well as the impact of asset sales as described below.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Selling Prices: Average realized crude oil selling prices were 53% and 51% lower in the third quarter and first nine months of 2015, respectively, compared to same periods in 2014 primarily due to declines in Brent and West Texas Intermediate (WTI) crude oil prices. In addition, realized selling prices for natural gas liquids declined by 76% and 69% in the third quarter and first nine months of 2015, respectively, compared to same periods in 2014. Lower realized selling prices reduced third quarter 2015 results by approximately $745 million after-taxes, and $2.2 billion after-taxes, for the nine months ended September 30, 2015, compared with the respective prior-year periods.

The Corporation’s average selling prices were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Crude oil - per barrel (including hedging)
United States
Onshore	$	40.43	$	87.29	$	43.38	$	90.14
Offshore		42.70		97.50		48.75		99.11
Total United States		41.33		91.47		45.43		93.92

Europe		53.49		110.06		55.87		110.09
Africa		51.98		101.21		54.99		105.68
Asia		—		—		56.85		104.66
Worldwide		45.66		96.78		49.14		99.53

Crude oil - per barrel (excluding hedging)
United States
Onshore	$	37.91	$	87.29	$	42.61	$	90.14
Offshore		42.70		96.25		48.75		98.92
Total United States		39.81		90.95		44.95		93.84

Europe		50.12		106.40		55.01		109.01
Africa		48.60		99.21		54.26		104.86
Asia		—		—		56.85		104.66
Worldwide		43.43		95.41		48.55		99.11

Natural gas liquids - per barrel
United States
Onshore	$	5.45	$	28.20	$	9.47	$	33.62
Offshore		12.56		31.45		14.60		32.63
Total United States		6.69		28.84		10.32		33.31

Europe		21.44		49.37		25.50		56.98
Worldwide		7.17		29.62		10.84		34.76

Natural gas - per mcf
United States
Onshore	$	1.70	$	2.25	$	1.78	$	3.57
Offshore		2.37		3.64		2.26		4.01
Total United States		1.92		2.85		1.95		3.80

Europe		6.43		9.63		7.18		10.60
Asia and other		5.98		6.97		6.07		7.13
Worldwide		4.02		5.59		4.40		6.32

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Realized and unrealized gains from crude oil price collars increased Sales and other operating revenues by $42 million and $24 million for the three and nine months ended September 30, 2015, respectively ($26 million and $15 million after income taxes, respectively). Realized and unrealized gains in 2014 amounted to $37 million and $36 million for the three months and nine months ended September 30, 2014, respectively ($24 million and $23 million after income taxes, respectively).

Production Volumes: The Corporation’s crude oil and natural gas production increased to 380,000 boepd in the third quarter of 2015 and 377,000 boepd in the first nine months of 2015, from 318,000 boepd for the same periods in 2014.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands)
Operating Data
Net Production Per Day
Crude oil - barrels
United States
Bakken		82		63		82		61
Other Onshore		10		11		11		10
Total Onshore		92		74		93		71
Offshore		60		51		57		52
Total United States		152		125		150		123

Europe		40		31		38		35
Africa		50		53		50		51
Asia		2		2		2		3
Worldwide		244		211		240		212

Natural gas liquids - barrels
United States
Bakken		20		15		21		9
Other Onshore		12		8		11		5
Total Onshore		32		23		32		14
Offshore		7		6		6		6
Total United States		39		29		38		20

Europe		1		1		1		1
Worldwide		40		30		39		21

Natural gas - mcf
United States
Bakken		65		46		65		36
Other Onshore		125		52		100		43
Total Onshore		190		98		165		79
Offshore		93		76		85		79
Total United States		283		174		250		158

Europe		45		29		41		33
Asia and other		246		259		297		316
Worldwide		574		462		588		507

Barrels of oil equivalent*		380		318		377		318

Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices in the table on page 23.

United States: Onshore crude oil and natural gas liquids production was higher in the third quarter and first nine months of 2015, compared to the corresponding period in 2014, primarily due to continued drilling in the Bakken oil shale

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

play while the increase in natural gas production was primarily attributable to the Bakken and the Utica shale. Total Offshore production increased in the third quarter of 2015 as production from the Tubular Bells Field, which came online in November 2014, exceeded the decline in production from the Llano Field. Offshore production increased in the first nine months of 2015 relative to the prior-year nine-month period as higher production from the Tubular Bells Field, was offset primarily by lower production from the Llano and Conger Fields.

Europe: Crude oil production in the third quarter of 2015 was higher compared with the same period of 2014 primarily due to an increase from the Valhall Field, offshore Norway as a result of a higher number of active wells and lower maintenance activities in the current period. Natural gas production in the third quarter of 2015 was higher compared with the same period of 2014 due to maintenance at the Valhall Field in the prior-year and higher production from the South Arne Field in Denmark. The increase in crude oil and natural gas production for the first nine months of 2015 compared with 2014 can primarily be attributed to less facility downtime and new wells at the Valhall and South Arne Fields.

Africa: Crude oil production in Africa was slightly lower in the third quarter and first nine months of 2015 compared to the corresponding periods in 2014, primarily due to Libyan production being shut-in in 2015.

Asia and Other: Natural gas production in the third quarter of 2015 was down from the same period in 2014 primarily due to lower production entitlement at the Joint Development Area of Malaysia/Thailand (JDA). Lower natural gas production in the first nine months of 2015 relative to 2014, is primarily due to asset sales partially offset by higher production at the JDA as a result of higher facility uptime in the current year.

Sales Volumes: The impact of higher sales volumes increased after-tax results by approximately $220 million and $530 million in the third quarter and first nine months of 2015, compared with the corresponding periods in 2014.

The Corporation’s worldwide sales volumes were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands)
Crude oil - barrels		22,592		19,719		65,028		57,662
Natural gas liquids - barrels		3,701		2,772		10,668		5,836
Natural gas - mcf		52,784		42,511		160,604		138,530
Barrels of oil equivalent*		35,090		29,576		102,463		86,586

Crude oil - barrels per day		245		214		238		211
Natural gas liquids - barrels per day		40		30		39		21
Natural gas - mcf per day		574		462		588		507
Barrels of oil equivalent per day*		381		321		375		317

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

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

Depreciation, Depletion and Amortization: Depreciation, depletion and amortization (DD&A) expenses were higher in the third quarter and first nine months of 2015, compared with the prior-year periods, primarily reflecting higher production volumes from the Bakken, Tubular Bells and Utica Fields, which had higher DD&A rates per barrel than the portfolio average.

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

Unit Cost Information: Unit cost per barrel of oil equivalent (boe) information is calculated on total E&P production volumes and exclude items affecting comparability of earnings as described below.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Actual unit costs per boe were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	Per boe
Cash operating costs	$	14.98	$	20.62	$	15.77	$	21.09
Depreciation, depletion and amortization		27.53		27.82		28.14		26.31
Total production unit costs	$	42.51	$	48.44	$	43.91	$	47.40

Bakken Midstream tariff expense	$	3.36	$	2.22	$	3.26	$	1.63

For the fourth quarter of 2015, E&P cash operating costs are estimated to be in the range of $16.00 to $17.00 per boe and DD&A expenses are estimated to be in the range of $29.00 to $30.00 per boe resulting in total production unit costs ranging from $45.00 to $47.00 per boe. For the full year 2015, E&P cash operating costs are estimated to be in the range of $15.50 to $16.00 per boe and DD&A expenses are estimated to be in the range of $28.50 to $29.00 per boe resulting in total production unit costs ranging from $44.00 to $45.00 per boe. Bakken Midstream tariff expense is expected to be $3.80 to $3.90 per boe for the fourth quarter of 2015, and $3.35 to $3.45 per boe for the full year of 2015.

Exploration Expenses: Exploration expenses were higher in the third quarter of 2015 compared to the same period in 2014, primarily due to increased seismic and lease impairment expense in the Gulf of Mexico. Exploration expenses were lower in the first nine months of 2015 compared to the same period in 2014, primarily due to prior-year charges to write down projects in the United States, Kurdistan, France and Malaysia. Exploration expenses, excluding dry hole expense, are estimated to be in the range of $115 million to $125 million in the fourth quarter of 2015 and $340 million to $350 million for the full year.

Income Taxes: Excluding items affecting comparability between periods, the effective income tax rate for E&P operations was a benefit of 47% and 49% in the third quarter and first nine months of 2015, respectively, compared to a provision of 41% and 38% for the third quarter and the first nine months of 2014, respectively. For the full year 2015, the E&P effective income tax rate is expected to be a benefit in the range of 44% to 48% and the fourth quarter rate is expected to be a benefit in the range of 40% to 44%, assuming no contribution from Libya.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions)
Gains on asset sales, net	$	31		$	33		$	31		$	774
Tax benefit from international investment incentive		50			—			50			—
Dry hole, lease impairment and other exploration expenses		(43	)		—			(120	)		(173	)
Exit costs and other		(5	)		(4	)		(26	)		(4	)
Impairment		—			—			(385	)		—
Inventory write-off		—			—			(16	)		—
	$	33		$	29		$	(466	)	$	597

Gains on asset sales, net: In the third quarter of 2015, the Corporation completed the sale of approximately 13,000 acres of Utica dry gas acreage for consideration of approximately $120 million. This transaction resulted in a pre-tax gain of $49 million ($31 million after income taxes). In September 2014, the Corporation completed the sale of an exploration asset in the United Kingdom North Sea, for cash proceeds of $53 million, which resulted in a pre-tax gain of $33 million ($33 million after income taxes). In June 2014, the Corporation completed the sale of approximately 30,000 net acres, including related wells and facilities in the dry gas area of the Utica shale play, for cash proceeds of approximately $485 million, resulting in a pre-tax gain of $62 million ($35 million after income taxes). In April 2014, the Corporation completed the sale of its Thailand assets for cash proceeds of approximately $805 million. This transaction resulted in a pre-tax gain of $706 million ($706 million after income taxes).

Tax benefit from international investment incentive: In the third quarter of 2015, the Corporation received approval for an international investment incentive. As a result, the Corporation recognized a tax benefit of $50 million in the current period.

Dry hole, lease impairment and other exploration expenses: In the third quarter of 2015, the Corporation recorded a pre-tax charge of $41 million ($26 million after income taxes) to impair a relinquished lease in the Gulf of Mexico, and a pre-tax

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

charge of $27 million ($17 million after income taxes) associated with the cessation of exploratory drilling operations in Kurdistan. In the first quarter of 2015, the Corporation incurred a pre-tax charge of $159 million ($67 million after income taxes) to write-off a previously capitalized exploration well and associated leasehold expenses related to the Dinarta Block, in the Kurdistan Region of Iraq following the decision of the Corporation and its partner in March 2015 to abandon the well, relinquish the Dinarta Block, and to exit operations in the region. Exploration expenses in the first quarter of 2015 also included a pre-tax charge of $16 million ($10 million after income taxes) to write down a foreign exploration project to fair value. In the second quarter of 2014, the Corporation recorded a pre-tax charge of $169 million ($105 million after income taxes) to write-off a previously capitalized exploration well in the western half of Green Canyon Block 469 in the Gulf of Mexico. In addition, in the second quarter of 2014 the Corporation recorded charges totaling $135 million pre-tax ($68 million after income taxes) to write-off leasehold acreage in the Paris Basin of France, the Shakrok Block in Kurdistan and the Corporation’s interest in a natural gas exploration project, offshore Sabah, Malaysia.

Exit costs and other: In the second quarter of 2015, the Corporation recognized pre-tax charges totaling $21 million ($21 million after income taxes) associated with terminated international office space and in the third quarter of 2015 incurred charges of $6 million ($5 million after income taxes) related to employee severance.

Impairment: During the first nine months of 2015, the Corporation recorded a noncash pre-tax goodwill impairment charge of $385 million ($385 million after income taxes) associated with the Onshore reporting unit. As a result of establishing the Bakken Midstream business as a separate operating segment in the second quarter of 2015, U.S. GAAP required the reallocation of goodwill to the Bakken Midstream segment and a goodwill impairment test for each of the Corporation’s reporting units. See Note 6, Goodwill in Notes to Consolidated Financial Statements for further information.

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

The Corporation’s future E&P earnings may be impacted by external factors, such as volatility in the selling prices of crude oil, natural gas liquids, and natural gas, reserve and production changes, exploration expenses, industry cost inflation and/or deflation, changes in foreign exchange rates and income tax rates, the effects of weather, political risk, environmental risk and catastrophic risk. For a more comprehensive description of the risks that may affect the Corporation’s E&P business, see Item 1A. Risk Factors Related to Our Business and Operations in the Annual Report on Form 10-K for the year ended December 31, 2014.

Bakken Midstream

Following is a summarized income statement of the Corporation’s Bakken Midstream operations:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In millions)
Revenues and Non-operating Income
Total revenues and non-operating income	$	148	$	89	$	423	$	218

Costs and Expenses
Operating costs and expenses		65		54		196		158
General and administrative expenses		4		3		9		7
Depreciation, depletion and amortization		22		19		65		48
Interest expense		4		—		6		1
Total costs and expenses		95		76		276		214

Results of operations before income taxes		53		13		147		4
Provision (benefit) for income taxes		10		5		45		2
Net income (loss)		43		8		102		2
Less: Net income (loss) attributable to noncontrolling interests*		27		—		27		—
Net income (loss) attributable to Hess Corporation	$	16	$	8	$	75	$	2

* The partnership is not subject to tax and, therefore, the noncontrolling interest’s share of net income is a pre-tax amount.

Total revenues and non-operating income for the three and nine months ended September 30, 2015 increased from the

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

prior-year periods mainly due to higher throughput volumes at the Tioga Gas Plant. In the fourth quarter of 2013, the Tioga Gas Plant was shut down for a large‑scale expansion, refurbishment and optimization project, during which a new cryogenic processing train was installed and processing capacity was increased to 250 MMcf/d from 120 MMcf/d. The Tioga Gas Plant’s expanded operations commenced in late March 2014. Operating costs and expenses were higher in the three and nine months ended September 30, 2015 compared to the prior-year periods reflecting the increased activity levels. DD&A expenses were higher in the first nine months of 2015 compared with 2014, primarily due to the commencement of depreciation of the Tioga Gas Plant expansion expenditures upon restart of operations in late March 2014. The increase in interest expense is attributable to the 5-year Term Loan A facility described below. Net income attributable to Hess Corporation from the Bakken Midstream segment for the fourth quarter of 2015 is estimated to be in the range of $15 million to $20 million.

On July 1, 2015, the Corporation completed the sale of a 50% interest in its Bakken Midstream business to Global Infrastructure Partners (GIP) for net cash consideration of approximately $2.6 billion. Subsequent to closing, the joint venture incurred $600 million of debt through a 5-year Term Loan A facility with proceeds distributed equally to both partners. In addition, the joint venture has independent access to capital through a $400 million 5-year Senior Revolving Credit Facility, which is fully committed.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	57		$	55		$	165		$	147
Interest expense		92			97			282			301
Less: Capitalized interest		(12	)		(22	)		(33	)		(61	)
Interest expense, net		80			75			249			240
Corporate, Interest and Other expenses before income taxes		137			130			414			387
Provision (benefit) for income taxes		(51	)		(50	)		(160	)		(150	)
Net Corporate, Interest and Other expenses after income taxes		86			80			254			237
Items affecting comparability of earnings between periods, after-tax		8			2			12			71
Total Corporate, Interest and Other expenses after income taxes	$	94		$	82		$	266		$	308

Corporate and other expenses for the nine months ended September 30, 2014 include a pre-tax gain of $13 million ($8 million after income taxes) related to the disposition of the Corporation’s 50% interest in a joint venture involved in the construction of an electric generating facility in Newark, New Jersey. The remaining increase in the nine months ended September 30, 2015 compared to the year-ago period is primarily attributable to higher professional fees. Interest expense was lower in the three months ended September 30, 2015 compared to 2014 primarily due to lower borrowings. Interest expense for the nine months ended September 30, 2015 was lower compared to 2014, as lower interest rates offset higher average borrowings. Capitalized interest was down in the three and nine months ended September 30, 2015 relative to the same periods in 2014 due to the cessation of capitalized interest on the Tubular Bells Field upon first production in the fourth quarter of 2014.

Fourth quarter 2015 corporate expenses are expected to be in the range of $30 million to $35 million after taxes and interest expense is expected to be in the range of $50 million to $55 million after taxes. Excluding items affecting comparability of earnings, the estimate for corporate expenses for full year 2015 is expected to be in the range of $125 million to $130 million after taxes and interest expense is still estimated to be in the range of $205 million to $210 million after taxes.

Items Affecting Comparability of Earnings Between Periods:

In the third quarter of 2015, the Corporation recorded a pre-tax charge of $10 million ($8 million after income taxes) associated with financing provided to HOVENSA LLC which filed for bankruptcy as described in Note 13, Guarantees and Contingencies in the Notes to the Consolidated Financial Statements. In the first quarter of 2015, the Corporation incurred exit costs of $6 million ($4 million after income taxes).

During the first quarter of 2014, the corporation recorded a charge of $84 million ($52 million after income taxes) to reduce the carrying value of its investment in the Bayonne Energy Center to fair value. In the three and nine months ended September 30, 2014 the Corporation recorded severance and other exit costs of $3 million ($2 million after income taxes) and $30 million ($19 million after-tax), respectively.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Discontinued Operations

The net loss attributable to Hess Corporation from discontinued operations for the three and nine months ended September 30, 2015 was $13 million and $40 million, respectively, compared to income of $649 million and $628 million for the three and nine months ended September 30, 2014, respectively. The loss in the third quarter of 2015 resulted from a pension settlement charge, employee related costs and other miscellaneous expenses. Net income in the third quarter of 2014 included an after-tax gain of $602 million resulting from the sale of the retail business. The Corporation sold its interest in HETCO, its energy trading joint venture, in February 2015.

Liquidity and Capital Resources

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

	September 30,				December 31,
	2015				2014
	(In millions, except ratio)
Cash and cash equivalents	$	3,013			$	2,444
Current maturities of long-term debt		78				68
Total debt		6,552				5,987
Total equity		22,363				22,320
Debt to capitalization ratio		22.7	%	*		21.2	%

*	Total debt as a percentage of the sum of total debt plus equity, excluding amounts associated with the Corporation’s Bakken Midstream joint venture, which was established on July 1, 2015.

Cash Flows

The following table summarizes the Corporation’s cash flows:

	Nine Months Ended
	September 30,
	2015			2014
	(In millions)
Cash flows from operating activities:
Cash provided by (used in) operating activities - continuing operations	$	1,389		$	3,418
Cash provided by (used in) operating activities - discontinued operations		(31	)		(35	)
Net cash provided by (used in) operating activities		1,358			3,383

Cash flows from investing activities:
Additions to property, plant and equipment		(3,386	)		(3,686	)
Proceeds from asset sales		25			2,978
Other, net		(44	)		(136	)
Cash provided by (used in) investing activities - continuing operations		(3,405	)		(844	)
Cash provided by (used in) investing activities - discontinued operations		108			2,407
Net cash provided by (used in) investing activities		(3,297	)		1,563

Cash flows from financing activities:
Cash provided by (used in) financing activities - continuing operations		2,508			(2,638	)
Cash provided by (used in) financing activities - discontinued operations		—			(2	)
Net cash provided by (used in) financing activities		2,508			(2,640	)

Net increase (decrease) in cash and cash equivalents from continuing operations		492			(64	)
Net increase (decrease) in cash and cash equivalents from discontinued operations		77			2,370
Net increase (decrease) in cash and cash equivalents	$	569		$	2,306

Operating activities: Net cash provided by operating activities was $1,358 million in the first nine months of 2015, compared with $3,383 million in the same period of 2014, primarily reflecting the decline in benchmark crude oil prices.

Investing activities: Additions to property, plant and equipment were lower in the nine months of 2015 compared to the same period in 2014 primarily due to reduced drilling activity (the Bakken, the Utica, Norway and Equatorial Guinea), reduced development expenditures at Tubular Bells and lower exploratory drilling activity in Ghana and Kurdistan. These reductions were offset by 2015 activity related to development activities at Stampede in the Gulf of Mexico and exploration drilling activity in the Gulf of Mexico and Guyana, and full field development at North Malay Basin.

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

During the first nine months of 2014, the Corporation received proceeds of approximately $805 million from the sale of its assets in Thailand, approximately $650 million from the sale of its interest in the Pangkah Field, offshore Indonesia, approximately $1,075 million from the sale of dry gas acreage in the Utica, including related wells and facilities, and $399 million from the sale of its interest in two power plant joint ventures.

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

Financing activities: In the first nine months of 2015, the Corporation received net cash consideration of approximately $2.6 billion from the sale of a 50% interest in its Bakken Midstream business and, as a result of the establishment of the Bakken Midstream joint venture, proceeds of $600 million under a term loan, of which $300 million was distributed to our partner. In addition, the Corporation repaid $51 million of borrowings and paid a total of $142 million for the purchase and settlement of common shares under its Board authorized $6.5 billion repurchase plan. Common stock purchases amounted to $2,638 million in the first nine months of 2014. Dividends of $215 million were paid in the first nine months of 2015 compared to $232 million in the first nine months of 2014 representing a dividend per common share of $0.75 in both periods.

Future Capital Requirements and Resources

While the Corporation’s 2016 budgeting process will not be finalized until the end of the year, the Corporation presently expects full year 2016 E&P capital and exploratory expenditures to be in the range of $2.9 billion to $3.1 billion, down from projected 2015 E&P capital and exploratory expenditures of $4.1 billion. Oil and gas production in 2016 is forecast to be in the range of 330,000 to 350,000 barrels of oil equivalent per day (boepd) compared with projected production of 370,000 to 375,000 boepd in 2015. Based on current strip crude oil prices, the Corporation forecasts a significant net loss and a net operating cash flow deficit (including capital expenditures) in 2015 and 2016. At September 30, 2015, the Corporation had $3.0 billion in cash and cash equivalents and total liquidity of nearly $8 billion. The Corporation expects to fund its net operating cash flow deficit (including capital expenditures) for the remainder of 2015 and the full year of 2016 with existing cash on hand, and, if necessary, borrowings under its credit facilities. The Corporation plans to maintain its financial flexibility and will continue to pursue further cost reductions and supply chain savings. Depending on where crude oil prices trend, the Corporation may take other steps to improve its financial position by further reducing its planned capital program, accessing other sources of liquidity by issuing debt and equity securities, and/or pursuing further asset sales.

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

						Letters of
	Expiration					Credit				Available
	Date	Capacity		Borrowings		Issued		Total Used		Capacity
		(In millions)
Revolving credit facility - Hess Corporation	January 2020	$	4,000	$	—	$	—	$	—	$	4,000
Revolving credit facility - Bakken Midstream (a)	July 2020		400		—		—		—		400
Committed lines	Various (b)		800		—		10		10		790
Uncommitted lines	Various (b)		104		—		104		104		—
Total		$	5,304	$	—	$	114	$	114	$	5,190

(a)

The Revolving credit facility – Bakken Midstream may only be utilized by the Corporation’s Bakken Midstream operating segment.

(b)

Committed and uncommitted lines have expiration dates through 2016.

The Corporation’s $114 million in letters of credit outstanding at September 30, 2015 are primarily issued to satisfy performance obligations related to the Corporation’s exploration and production activities.

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

interest at the LIBOR plus an applicable margin ranging from 1.10% to 2.00%. Facility fees on the revolving credit facility accrue at an applicable rate every quarter, ranging from 0.15% to 0.35% per annum. The interest rate and facility fee are subject to adjustment based on the joint venture’s leverage ratio. If the joint venture obtains credit ratings, pricing levels will be based on its credit ratings in effect from time to time. At September 30, 2015, borrowings attributable to the joint venture amounted to $600 million on the Term Loan A loan facility. This debt is non-recourse to the Corporation and proceeds therefore may only be used for the operations of the Bakken Midstream operating segment.

The Corporation’s long-term debt agreements, including the revolving credit facilities, contain financial covenants that restrict the amount of total borrowings and secured debt. The joint venture’s 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 of no less than 2.25 to 1.0 for the prior four fiscal quarters. These financial covenants do not currently materially impact the Corporation’s ability to issue indebtedness to fund its future capital requirements.

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Market Risk Disclosures

The Corporation is exposed in the normal course of business to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values. See Note 15, Financial Risk Management, in the Notes to Consolidated Financial Statements. In the disclosures that follow, risk management activities refer to the mitigation of these risks through hedging activities.

Financial Risk Management Activities

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

The Corporation estimates that the value at risk associated with crude oil collars was $13 million at September 30, 2015. The results may vary from time to time primarily as crude oil prices or hedge levels change.

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

The Corporation’s outstanding long-term debt of $6,552 million, including current maturities, had a fair value of $6,935 million at September 30, 2015. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $480 million at September 30, 2015. A 15% increase in the rate of interest would decrease the fair value of debt by approximately $420 million at September 30, 2015.

Discontinued Operations – Trading Activities

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

Forward-looking Information

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, asset sales, oil and gas production, costs and expenses, tax rates, debt repayment, hedging, derivative and market risk disclosures include forward-looking information. These sections typically include statements with words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “would” or similar words, indicating that future outcomes are uncertain. Forward-looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors.

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, 2015, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of September 30, 2015.

There was no change in internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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.

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

2015	Total Number of Shares Purchased (a)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (b) (In millions)
July		407,000	$	61.85		407,000	$	1,180
August		429,312		56.40		429,312		1,156
September		98,167		57.19		98,167		1,150
Total		934,479	$	58.86		934,479

(a)

Repurchased in open-market transactions. The average price paid per share was inclusive of transaction fees.

(b)

In March 2013, the Corporation announced a board authorized plan to repurchase up to $4 billion of outstanding common shares. In May 2014, the Corporation increased the repurchase program to $6.5 billion.

PART II - OTHER INFORMATION (CONT’D.)

Item 6.

Exhibits and Reports on Form 8‑K.

a.	Exhibits
	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

b.	Reports on Form 8-K

	During the quarter ended September 30, 2015, Registrant filed the following reports on Form 8-K:
	(i)	Filing dated July 29, 2015 reporting under Items 2.02 and 9.01 a news release dated July 29, 2015 reporting results for the second quarter of 2015.

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.

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

Date: November 5, 2015