HESS CORP - Quarter Report: 2016 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarter ended September 30, 2016

☐	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 ☒ No ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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	☒	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 ☒

At September 30, 2016, there were 316,621,058 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, 2016, and December 31, 2015	2
	Statement of Consolidated Income for the Three and Nine Months Ended September 30, 2016, and 2015	3
	Statement of Consolidated Comprehensive Income for the Three and Nine Months Ended September 30, 2016, and 2015	4
	Statement of Consolidated Cash Flows for the Nine Months Ended September 30, 2016, and 2015	5
	Statement of Consolidated Equity for the Nine Months Ended September 30, 2016, and 2015	6
	Notes to Consolidated Financial Statements	7
	Basis of Presentation	7
	Common and Preferred Stock Issuance	7
	Debt Issuance and Notes Tender Offer	8
	Inventories	8
	Capitalized Exploratory Well Costs	8
	Bakken Midstream Joint Venture	9
	Impairment	9
	Dispositions	9
	Retirement Plans	10
	Income Taxes	10
	Weighted Average Common Shares	11
	Guarantees and Contingencies	12
	Segment Information	13
	Financial Risk Management Activities	14
	Subsequent Events	16

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
3.	Quantitative and Qualitative Disclosures about Market Risk	31
4.	Controls and Procedures	31

	PART II OTHER INFORMATION
1.	Legal Proceedings	32
2.	Share Repurchase Activities	32
6.	Exhibits and Reports on Form 8-K	33
	Signatures	34
	Certifications

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30,			December 31,
	2016			2015
	(In millions,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	3,529		$	2,716
Accounts receivable
Trade		771			847
Other		82			312
Inventories		403			399
Other current assets		108			130
Total current assets		4,893			4,404
Property, plant and equipment:
Total — at cost		48,416			46,826
Less: Reserves for depreciation, depletion, amortization and lease impairment		22,879			20,474
Property, plant and equipment — net		25,537			26,352
Goodwill		375			375
Deferred income taxes		3,257			2,653
Other assets		397			373
Total Assets	$	34,459		$	34,157
Liabilities
Current Liabilities:
Accounts payable	$	458		$	457
Accrued liabilities		1,433			1,997
Taxes payable		60			88
Current maturities of long-term debt		666			86
Total current liabilities		2,617			2,628
Long-term debt		6,671			6,506
Deferred income taxes		1,214			1,334
Asset retirement obligations		2,098			2,158
Other liabilities and deferred credits		944			1,130
Total Liabilities		13,544			13,756
Equity
Hess Corporation stockholders’ equity:
Preferred stock, par value $1.00; Authorized — 20,000,000 shares
Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference; Issued — 575,000 shares (2015: 0)		1			—
Common stock, par value $1.00; Authorized — 600,000,000 shares
Issued — 316,621,058 shares (2015: 286,045,586)		317			286
Capital in excess of par value		5,763			4,127
Retained earnings		15,129			16,637
Accumulated other comprehensive income (loss)		(1,372	)		(1,664	)
Total Hess Corporation stockholders’ equity		19,838			19,386
Noncontrolling interests		1,077			1,015
Total equity		20,915			20,401
Total Liabilities and Equity	$	34,459		$	34,157

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,
	2016			2015			2016			2015
	(In millions, except per share amounts)

Revenues and Non-Operating Income
Sales and other operating revenues	$	1,177		$	1,671		$	3,374		$	5,162
Other, net		19			18			84			12
Total revenues and non-operating income		1,196			1,689			3,458			5,174

Costs and Expenses
Cost of products sold (excluding items shown separately below)		222			356			688			990
Operating costs and expenses		421			508			1,312			1,517
Production and severance taxes		27			29			74			110
Exploration expenses, including dry holes and lease impairment		78			144			409			503
General and administrative expenses		106			119			310			417
Interest expense		84			84			254			255
Loss on debt extinguishment		80			—			80			—
Depreciation, depletion and amortization		811			988			2,476			2,972
Impairment		—			—			—			385
Total costs and expenses		1,829			2,228			5,603			7,149
Income (Loss) from Continuing Operations Before Income Taxes		(633	)		(539	)		(2,145	)		(1,975	)
Provision (benefit) for income taxes		(316	)		(300	)		(967	)		(807	)
Income (Loss) from Continuing Operations		(317	)		(239	)		(1,178	)		(1,168	)
Income (Loss) from Discontinued Operations, Net of Income Taxes		—			(13	)		—			(40	)
Net Income (Loss)		(317	)		(252	)		(1,178	)		(1,208	)
Less: Net income (loss) attributable to noncontrolling interests		22			27			62			27
Net Income (Loss) Attributable to Hess Corporation		(339	)		(279	)		(1,240	)		(1,235	)
Less: Preferred stock dividends		12			—			30			—
Net Income (Loss) Applicable to Hess Corporation Common Stockholders	$	(351	)	$	(279	)	$	(1,270	)	$	(1,235	)

Net Income (Loss) Attributable to Hess Corporation Per Common Share
Basic:
Continuing operations	$	(1.12	)	$	(0.94	)	$	(4.11	)	$	(4.21	)
Discontinued operations		—			(0.04	)		—			(0.14	)
Net Income (Loss) Per Common Share	$	(1.12	)	$	(0.98	)	$	(4.11	)	$	(4.35	)

Diluted:
Continuing operations	$	(1.12	)	$	(0.94	)	$	(4.11	)	$	(4.21	)
Discontinued operations		—			(0.04	)		—			(0.14	)
Net Income (Loss) Per Common Share	$	(1.12	)	$	(0.98	)	$	(4.11	)	$	(4.35	)

Weighted Average Number of Common Shares Outstanding (Diluted)		313.2			283.5			308.7			283.8
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,
	2016			2015			2016			2015
	(In millions)

Net Income (Loss)	$	(317	)	$	(252	)	$	(1,178	)	$	(1,208	)

Other Comprehensive Income (Loss):

Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		—			(34	)		—			(34	)
Income taxes on effect of hedge (gains) losses reclassified to income		—			13			—			13
Net effect of hedge (gains) losses reclassified to income		—			(21	)		—			(21	)
Change in fair value of cash flow hedges		—			109			—			111
Income taxes on change in fair value of cash flow hedges		—			(41	)		—			(42	)
Net change in fair value of cash flow hedges		—			68			—			69
Change in derivatives designated as cash flow hedges, after taxes		—			47			—			48

Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		—			(5	)		4			(20	)
Income taxes on actuarial changes in plan liabilities		—			1			(2	)		7
(Increase) reduction in unrecognized actuarial losses, net		—			(4	)		2			(13	)
Amortization of net actuarial losses		15			29			47			73
Income taxes on amortization of net actuarial losses		(5	)		(10	)		(16	)		(24	)
Net effect of amortization of net actuarial losses		10			19			31			49
Change in pension and other postretirement plans, after taxes		10			15			33			36

Foreign currency translation adjustment
Foreign currency translation adjustment		117			(208	)		259			(256	)
Change in foreign currency translation adjustment		117			(208	)		259			(256	)

Other Comprehensive Income (Loss)		127			(146	)		292			(172	)

Comprehensive Income (Loss)		(190	)		(398	)		(886	)		(1,380	)
Less: Comprehensive income (loss) attributable to noncontrolling interests		22			27			62			27
Comprehensive Income (Loss) Attributable to Hess Corporation	$	(212	)	$	(425	)	$	(948	)	$	(1,407	)

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,
	2016			2015
	(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	(1,178	)	$	(1,208	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net		(27	)		(50	)
Depreciation, depletion and amortization		2,476			2,972
Exploratory dry hole costs		234			180
Exploration lease impairment		33			139
Impairment		—			385
Loss from equity affiliates		—			10
Stock compensation expense		69			71
Provision (benefit) for deferred income taxes and other tax accruals		(973	)		(819	)
Loss on debt extinguishment		80			—
(Income) loss from discontinued operations, net of income taxes		—			40
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable		278			489
(Increase) decrease in inventories		1			(17	)
Increase (decrease) in accounts payable and accrued liabilities		(266	)		(449	)
Increase (decrease) in taxes payable		(28	)		(230	)
Changes in other operating assets and liabilities		(230	)		(124	)
Cash provided by (used in) operating activities - continuing operations		469			1,389
Cash provided by (used in) operating activities - discontinued operations		—			(31	)
Net cash provided by (used in) operating activities		469			1,358

Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P		(1,578	)		(3,232	)
Additions to property, plant and equipment - Bakken Midstream		(186	)		(154	)
Proceeds from asset sales		80			25
Other, net		18			(44	)
Cash provided by (used in) investing activities - continuing operations		(1,666	)		(3,405	)
Cash provided by (used in) investing activities - discontinued operations		—			108
Net cash provided by (used in) investing activities		(1,666	)		(3,297	)

Cash Flows From Financing Activities
Debt with maturities of greater than 90 days
Borrowings		1,501			600
Repayments		(825	)		(51	)
Proceeds from issuance of preferred stock		557			—
Proceeds from issuance of common stock		1,087			—
Common stock acquired and retired		—			(142	)
Cash dividends paid		(260	)		(215	)
Noncontrolling interests, net		—			2,329
Other, net		(50	)		(13	)
Cash provided by (used in) financing activities - continuing operations		2,010			2,508
Cash provided by (used in) financing activities - discontinued operations		—			—
Net cash provided by (used in) financing activities		2,010			2,508

Net Increase (Decrease) in Cash and Cash Equivalents		813			569
Cash and Cash Equivalents at Beginning of Year		2,716			2,444
Cash and Cash Equivalents at End of Period	$	3,529		$	3,013

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

	Mandatory											Accumulated
	Convertible					Capital in						Other			Total Hess
	Preferred		Common			Excess of			Retained			Comprehensive			Stockholders’			Noncontrolling			Total
	Stock		Stock			Par			Earnings			Income (Loss)			Equity			Interests			Equity
	(In millions)
Balance at January 1, 2016	$	—	$	286		$	4,127		$	16,637		$	(1,664	)	$	19,386		$	1,015		$	20,401
Net income (loss)		—		—			—			(1,240	)		—			(1,240	)		62			(1,178	)
Other comprehensive income (loss)		—		—			—			—			292			292			—			292
Stock issuance		1		29			1,577			—			—			1,607			—			1,607
Activity related to restricted common stock awards, net		—		2			40			—			—			42			—			42
Employee stock options, including income tax benefits		—		—			6			—			—			6			—			6
Performance share units		—		—			13			—			—			13			—			13
Dividends on preferred stock		—		—			—			(30	)		—			(30	)		—			(30	)
Dividends on common stock		—		—			—			(238	)		—			(238	)		—			(238	)
Balance at September 30, 2016	$	1	$	317		$	5,763		$	15,129		$	(1,372	)	$	19,838		$	1,077		$	20,915

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	)
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
Dividends on common stock		—		—			—			(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

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 our consolidated financial position at September 30, 2016 and December 31, 2015, the consolidated results of operations for the three months and nine months ended September 30, 2016 and 2015, and consolidated cash flows for the nine months ended September 30, 2016 and 2015. 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, 2015.

In the first quarter of 2016, we adopted Accounting Standard Update (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 reduction to the associated debt liability. The Consolidated Balance Sheet at December 31, 2015 has been recast to reduce Other assets and Long-term debt by $38 million.

In the first quarter of 2016, we adopted ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting interest model, which is applicable to all reporting entities involved with limited partnerships or similar entities. The adoption of this standard did not have an impact on our consolidated financial statements.

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

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

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU makes changes to various provisions associated with share-based accounting, including provisions affecting the accounting for income taxes, the accounting for forfeitures, and the consideration of net settlement provisions on the balance sheet classification of the share-based award. This ASU is effective for us beginning in the first quarter of 2017, with early adoption permitted. The adoption of ASU 2016 – 09 is not expected to have a material impact on our financial condition.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted from the first quarter of 2019. We are currently assessing the impact of the ASU on our consolidated financial statements.

In October 2016, the FASB issued ASU 2016-16, Income Taxes – Intra-Entity Transfer of Assets Other than Inventory. This ASU will require the recognition of income tax consequences from intra-entity transfer of assets other than inventory when the transfer occurs. This ASU is effective for us beginning in the first quarter of 2018, with early adoption permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.

2. Common and Preferred Stock Issuance

In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share, for total net proceeds of approximately $1.6 billion after deducting underwriting discounts, commissions, and offering expenses. The dividends on the Convertible Preferred Stock will be payable on a cumulative basis. Unless converted earlier, each share of Convertible Preferred Stock will automatically convert into between 21.822 shares and 25.642 shares of our common stock based on the average share price over a period of twenty consecutive trading days ending prior to February 1, 2019 (the “Final Average Price”), subject to anti-dilution adjustments.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

We also entered into capped call transactions that are expected generally to reduce the potential dilution to our common stock upon conversion of the Convertible Preferred Stock if the Final Average Price exceeds $45.83 per share, subject to anti-dilution adjustments. The number of common shares to be delivered by the counterparties to us will be the value of the capped call transactions at conversion divided by the Final Average Price. The value of the capped call transactions will be zero if the Final Average Price is $45.83 or less and can be up to the capped value of approximately $98 million if the Final Average Price is $53.625 or higher. For any Final Average Price between $45.83 and $53.625, the value of the capped call transactions will be 12.55 million covered shares multiplied by the difference between the Final Average Price and $45.83. The premium paid for the capped call transactions was $37 million, which was recorded against Capital in excess of par in the Statement of Consolidated Equity.

3. Debt Issuance and Notes Tender Offer

In September 2016, we issued $1 billion of 4.30% senior notes, due in April 2027, and $500 million of 5.80% senior notes, due in April 2047, for net proceeds of $1.48 billion to primarily fund the repurchase of higher-coupon debt and redemption of near-term maturities. During the third quarter of 2016, we used $750 million to purchase $650 million principal amount of tendered 8.125% notes, due 2019 with a carrying value of $670 million. Third quarter 2016 results include a charge of $80 million before income taxes for the loss on extinguishment of the tendered 2019 notes. See Note 15, Subsequent Events for discussion of notes purchased in October 2016.

4. Inventories

Inventories consisted of the following:

	September 30,		December 31,
	2016		2015
	(In millions)
Crude oil and natural gas liquids	$	104	$	144
Materials and supplies		299		255
Total inventories	$	403	$	399

5. Capitalized Exploratory Well Costs

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the nine months ended September 30, 2016 (in millions):

Balance at January 1, 2016	$	1,415
Additions to capitalized exploratory well costs pending the determination of proved reserves		107
Capitalized exploratory well costs charged to expense		(114	)
Balance at September 30, 2016	$	1,408

Exploratory wells costs charged to expense in the nine months ended September 30, 2016 totaled $234 million, which includes $120 million of exploratory well costs incurred in 2016 that are not reflected in the table above. In the third quarter, the operator of the Stabroek Block, offshore Guyana, completed drilling of the Skipjack exploration well, which was unsuccessful and expensed. At the non-operated Sicily exploration project in the Gulf of Mexico where hydrocarbons were encountered in two wells, we decided in the second quarter not to pursue the project due to the current price environment and the limited time remaining on the leases. The cost of both wells drilled at Sicily were expensed in the second quarter. In the first quarter, we expensed the non-operated Melmar exploration well in the Gulf of Mexico, where noncommercial hydrocarbons were encountered.

Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $1,167 million at September 30, 2016 and primarily related to:

Australia: Approximately 70% of the capitalized well costs in excess of one year relates to our Equus project on license WA-390-P, offshore Western Australia (Hess 100%), where development planning and commercial activities for our natural gas discoveries are ongoing. In December 2014, we 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. We continue with a joint front-end engineering study with NWS, the results of which will enable negotiations for a tariff agreement. In addition, we have commenced discussions with potential long-term purchasers of liquefied natural gas. In March 2016, we were awarded a retention lease through 2021 covering certain areas within the WA-390-P License which include our Equus discoveries. At our adjacent WA-474-P license which could become part of the Equus project, we completed drilling of an exploration

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

commitment well in the second quarter of 2016 and encountered hydrocarbons. The associated well costs have been capitalized pending determination of proved reserves. Successful negotiation of binding agreements with NWS and reaching agreement on terms for a gas sales agreement with one or more third parties is necessary before we can sanction development of the project.

Ghana: Approximately 20% of the capitalized well costs in excess of one year relates to our Deepwater Tano/Cape Three Points license (Hess 50% license interest), offshore Ghana. Since 2014, we have completed three appraisal wells and continue to progress subsurface evaluation and development planning. 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. The International Tribunal for Law of the Sea is expected to render a final ruling on the maritime border dispute in 2017. Under terms of our license and subject to resolution of the border dispute, we have declared commerciality for four discoveries, including the Pecan Field in March 2016 which would be the primary development hub for the block. We are continuing to work with the government on how best to progress work on the block given the maritime border dispute.

Guyana: Approximately 10% of the capitalized well costs in excess of one year relates to the Stabroek Block, offshore Guyana (Hess 30% participating interest), where the operator, Esso Exploration and Production Guyana Limited, announced a significant oil discovery at the Liza-1 well in the second quarter of 2015. During 2016, the operator completed a 17,000 square kilometer 3D seismic acquisition on the Stabroek Block and drilled the Liza-2 and Liza-3 wells, both of which encountered hydrocarbons. Pre-development planning is underway and we expect to be in a position to sanction the first phase of the Liza development in 2017.

6. Bakken Midstream Joint Venture

On July 1, 2015, we sold a 50% interest in Hess Infrastructure Partners LP (HIP) to Global Infrastructure Partners for net cash consideration of approximately $2.6 billion. HIP and its affiliates primarily comprise our 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, 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.

We consolidate the activities of HIP, which qualifies as a variable interest entity under U.S. GAAP. At September 30, 2016, HIP liabilities totaling $810 million (December 31, 2015: $824 million) are on a nonrecourse basis to Hess Corporation, which includes total long-term debt of $683 million (December 31, 2015: $704 million). At September 30, 2016, HIP assets available to settle its obligations include Cash and cash equivalents totaling $2 million (December 31, 2015: $3 million) and Property, plant and equipment with a carrying value of $2,505 million (December 31, 2015: $2,358 million).

7. Impairment

As a result of establishing the Bakken Midstream operating segment in the second quarter of 2015, we performed impairment tests on the Offshore and Onshore reporting units prior to creation of the Bakken Midstream segment in accordance with accounting standards for goodwill. No impairment resulted from this assessment. In addition, we performed separate impairment tests at June 30, 2015, on the allocated goodwill to the Bakken Midstream segment and Onshore reporting unit of the E&P segment following the creation of the Bakken Midstream segment. No impairment existed for the Bakken Midstream segment, but goodwill allocated to the Onshore reporting unit of $385 million did not pass the impairment test. As a result, we recorded a noncash charge of $385 million in the second quarter of 2015 to reduce the Onshore reporting unit goodwill to its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards.

8. Dispositions

In the third quarter of 2015, we 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).

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

9. Retirement Plans

Components of net periodic pension cost consisted of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In millions)
Service cost	$	15		$	18		$	47		$	53
Interest cost		27			26			83			78
Expected return on plan assets		(41	)		(42	)		(125	)		(127	)
Amortization of unrecognized net actuarial losses		15			19			47			58
Settlement loss		—			10			—			15
Pension expense	$	16		$	31		$	52		$	77

In 2016, we expect to contribute $27 million to our funded pension plans. Through September 30, 2016, we have contributed $19 million to these plans.

10. Income Taxes

In the third quarter of 2016, we recorded a tax benefit of $51 million for the resolution of certain international tax matters. In the third quarter of 2015, we received approval for an international investment incentive and, as a result, recognized a tax benefit of $50 million.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

11. 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,
	2016			2015			2016			2015
	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Income (loss) from continuing operations, net of income taxes	$	(317	)	$	(239	)	$	(1,178	)	$	(1,168	)
Less: Net income (loss) attributable to noncontrolling interests		22			27			62			27
Net income (loss) from continuing operations attributable to Hess Corporation		(339	)		(266	)		(1,240	)		(1,195	)
Less: Preferred stock dividends		12			—			30			—
Net income (loss) from continuing operations attributable to Hess Corporation Common Stockholders		(351	)		(266	)		(1,270	)		(1,195	)
Income from discontinued operations, net of income taxes		—			(13	)		—			(40	)
Net income (loss) attributable to Hess Corporation Common Stockholders	$	(351	)	$	(279	)	$	(1,270	)	$	(1,235	)

Weighted Average Number of Common Shares Outstanding:
Basic		313.2			283.5			308.7			283.8
Effect of dilutive securities
Restricted common stock		—			—			—			—
Stock options		—			—			—			—
Performance share units		—			—			—			—
Mandatory Convertible Preferred stock		—			—			—			—
Diluted		313.2			283.5			308.7			283.8

Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic:
Continuing operations	$	(1.12	)	$	(0.94	)	$	(4.11	)	$	(4.21	)
Discontinued operations		—			(0.04	)		—			(0.14	)
Net income (loss) per common share	$	(1.12	)	$	(0.98	)	$	(4.11	)	$	(4.35	)
Diluted:
Continuing operations	$	(1.12	)	$	(0.94	)	$	(4.11	)	$	(4.21	)
Discontinued operations		—			(0.04	)		—			(0.14	)
Net income (loss) per common share	$	(1.12	)	$	(0.98	)	$	(4.11	)	$	(4.35	)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
Restricted common stock		3,476,171		2,955,200		3,345,052		2,953,075
Stock options		6,945,925		6,983,524		6,886,816		6,928,958
Performance share units		965,634		915,238		960,998		988,963
Common shares upon conversion of Preferred stock		12,547,650		—		10,769,864		—

During the nine months ended September 30, 2016, we granted 1,656,598 shares of restricted stock (2015: 1,127,242), 447,536 performance share units (2015: 362,873) and 824,225 stock options (2015: 521,773).

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

12. Guarantees and Contingencies

We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings, including administrative proceedings and proceedings relating to environmental matters. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.

Numerous issues may need to be resolved, including through lengthy discovery, conciliation and/or arbitration proceedings, or litigation before a loss or range of loss can be reasonably estimated. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such lawsuits, claims and proceedings, including the matters described below, is not expected to have a material adverse effect on our financial condition. However, we could incur judgments, enter into settlements or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.

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

In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and also agreed with EPA to fund remediation of a portion of the site. In April 2014, the EPA issued a Focused Feasibility Study (“FFS”) proposing to conduct bank-to-bank dredging of the lower eight miles of the Lower Passaic River at an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued a Record of Decision (“ROD”) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because there are numerous other parties who we expect will share in the cost of remediation and damages and our former terminal did not store or use contaminants which are of the greatest concern in the river sediments and could not have contributed contamination along most of the river’s length.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

13. Segment Information

We currently have two operating segments, Exploration and Production and Bakken Midstream. All unallocated costs are reflected under Corporate, Interest and Other.

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

For the Three Months Ended September 30, 2016	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total
Operating Revenues - Third parties	$	1,177		$	—	$	—		$	—		$	1,177
Intersegment Revenues		—			120		—			(120	)		—
Operating Revenues	$	1,177		$	120	$	—		$	(120	)	$	1,177

Net Income (Loss) from Continuing Operations Attributable to Hess Corporation	$	(234	)	$	13	$	(118	)	$	—		$	(339	)
Depreciation, Depletion and Amortization		784			25		2			—			811
Provision (Benefit) for Income Taxes		(252	)		9		(73	)		—			(316	)
Capital Expenditures		383			88		—			—			471

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 Nine Months Ended September 30, 2016	Exploration and Production			Bakken Midstream		Corporate, Interest and Other			Eliminations			Total
Operating Revenues - Third parties	$	3,374		$	—	$	—		$	—		$	3,374
Intersegment Revenues		—			358		—			(358	)		—
Operating Revenues	$	3,374		$	358	$	—		$	(358	)	$	3,374

Net Income (Loss) from Continuing Operations Attributable to Hess Corporation	$	(1,013	)	$	38	$	(265	)	$	—		$	(1,240	)
Depreciation, Depletion and Amortization		2,396			73		7			—			2,476
Provision (Benefit) for Income Taxes		(839	)		24		(152	)		—			(967	)
Capital Expenditures		1,322			190		—			—			1,512

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

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Identifiable assets by operating segment were as follows:

	September 30,		December 31,
	2016		2015
	(In millions)
Exploration and Production	$	28,622	$	28,863
Bakken Midstream		2,903		2,754
Corporate, Interest and Other		2,934		2,540
Total	$	34,459	$	34,157

14. Financial Risk Management Activities

In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas as well as changes in interest rates and foreign currency values. Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or by reducing our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of our crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which we conduct the business with the intent of reducing exposure to foreign currency fluctuations. 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.

Gross notional amounts of both long and short positions are presented in the volume table below. These amounts include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts.

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

	September 30, 2016		December 31, 2015
	(In millions of USD)
Foreign exchange	$	705	$	967
Interest rate swaps		650		1,300

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The table below reflects the gross and net fair values of the risk management derivative instruments, all of which are based on Level 2 inputs:

	Accounts Receivable			Accounts Payable
	(In millions)
September 30, 2016
Derivative Contracts Designated as Hedging Instruments
Interest rate	$	3		$	—
Total derivative contracts designated as hedging instruments		3			—
Derivative Contracts Not Designated as Hedging Instruments
Foreign exchange		4			(6	)
Total derivative contracts not designated as hedging instruments		4			(6	)
Gross fair value of derivative contracts		7			(6	)
Master netting arrangements		—			—
Net Fair Value of Derivative Contracts	$	7		$	(6	)

December 31, 2015
Derivative Contracts Designated as Hedging Instruments
Interest rate	$	3		$	—
Total derivative contracts designated as hedging instruments		3			—
Derivative Contracts Not Designated as Hedging Instruments
Foreign exchange		19			(3	)
Total derivative contracts not designated as hedging instruments		19			(3	)
Gross fair value of derivative contracts		22			(3	)
Master netting arrangements		(3	)		3
Net Fair Value of Derivative Contracts	$	19		$	—

Derivative contracts designated as hedging instruments:

Interest rate swaps: We had interest rate swaps which were designated as fair value hedges with gross notional amounts totaling $650 million at September 30, 2016, down from $1,300 million at December 31, 2015. During the third quarter of 2016, we received cash proceeds of $5 million following settlement of certain existing interest rate swaps in connection with the repurchase of certain debt. See Note 3, Debt Issuance and Notes Tender Offer. The change in fair value of interest rate swaps was a decrease of $9 million and an increase of $9 million in the third quarter and first nine months of 2016, respectively, compared with increases of $10 million and $14 million in the third quarter and first nine months of 2015, respectively. Changes in fair value of interest rate swaps result in a corresponding adjustment to the carrying value of the hedged fixed‑rate debt.

Crude oil collars: Total gains from Brent and West Texas Intermediate crude oil collars in the third quarter and first nine months of 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. There were no crude oil hedges outstanding in 2016.

Derivative contracts not designated as hedging instruments:

Foreign exchange: Total foreign exchange gains and losses, which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income amounted to gains of $11 million and $32 million in the third quarter and first nine months of 2016, respectively, compared with losses of $15 million and $7 million in the third quarter and first nine months of 2015, respectively. Changes in fair value of foreign exchange contracts that are not designated as hedges, which are a component of total foreign exchange gains and losses above, amounted to a loss of $2 million and a gain of $11 million in the third quarter and first nine months of 2016, respectively, compared with gains of $13 million and $71 million in the third quarter and first nine months of 2015, respectively.

The after‑tax foreign currency translation adjustments included in the Statement of Consolidated Comprehensive Income in the third quarter and first nine months of 2016 amounted to gains of $117 million and $259 million, respectively, compared with losses of $208 million and $256 million in the third quarter and first nine months of 2015, respectively. The cumulative currency translation adjustment at September 30, 2016, was a reduction to shareholders’ equity of $842 million compared with a reduction of $1,101 million at December 31, 2015.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Fair Value Measurement: We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at September 30, 2016. Total Long-term debt with a carrying value of $7,337 million at September 30, 2016, had a fair value of $7,881 million based on Level 2 inputs.

15. Subsequent Events

In October 2016, we purchased $196 million principal amount of 7.875% notes due 2029 and $66 million principal amount of 7.30% notes due 2031 for $324 million. In addition, we redeemed $300 million principal amount of 1.30% notes due 2017 for $301 million. The carrying value of these notes, which are included in Current maturities of long-term debt in the Consolidated Balance Sheet, was $559 million at September 30, 2016. Fourth quarter 2016 results will include a charge of approximately $68 million before income taxes ($42 million after income taxes) for the loss on extinguishment of the tendered and redeemed notes.

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 engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Norway. The 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 in the Bakken shale play of North Dakota.

Response to Low Oil Prices

Through the first nine months of 2016, our industry continued to face a challenging commodity price environment leading to further reductions in capital investment compared with 2015. West Texas Intermediate crude oil prices averaged $41.33 per barrel and Brent crude oil prices averaged $43.01 per barrel for the first nine months of 2016, compared to $51.00 and $56.61, respectively, in the first nine months of 2015. In response, we reduced our E&P capital and exploratory expenditures during the first nine months of 2016 to $1.5 billion, a decrease of 53% compared to the same period in 2015, which partially contributed to our lower 2016 oil and gas production levels. We now project our full year 2016 E&P capital and exploratory expenditures to be approximately $2 billion, $100 million lower than our previous guidance.

In addition to reducing our capital and exploratory expenditures, we have proactively taken other steps in 2016 to preserve the strength of our balance sheet and improve liquidity, including issuing equity securities and executing a debt refinancing transaction. In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock, for total net proceeds of approximately $1.6 billion. In September 2016, we initiated a debt refinancing transaction by issuing $1 billion of 4.30% notes due in 2027 and $500 million of 5.80% notes due in 2047 with proceeds used primarily to purchase higher-coupon bonds and redeem near-term maturities. We ended the quarter with $3.5 billion in cash and cash equivalents and total liquidity including available committed credit facilities of approximately $8.2 billion. In October 2016, we used $625 million to complete the purchase and redemption of notes under our debt refinancing transaction. See Note 3, Debt Issuance and Notes Tender Offer and Note 15, Subsequent Events, in the Notes to Consolidated Financial Statements.

We forecast a significant net loss and net operating cash flow deficit (including capital expenditures) in 2016. Based on current forward strip crude oil prices for 2017 which are higher than 2016 prices, we forecast a smaller net loss and net operating cash flow deficit (including capital expenditures) in 2017. We expect to fund our projected net operating cash flow deficit (including capital expenditures) through 2017 with cash on hand. Due to the low commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: further reduce our planned capital program and other cash outlays, borrow from our committed credit facilities, issue debt or equity securities, and pursue asset sales.

Third Quarter Results

In the third quarter of 2016, we incurred a net loss of $339 million compared to a net loss of $279 million in the third quarter of 2015. Excluding items affecting the comparability of earnings between periods on pages 25 to 27, the adjusted net loss for the third quarter of 2016 was $340 million compared to an adjusted net loss of $291 million in the third quarter of 2015. Third quarter 2016 after-tax results reflect lower production and lower realized selling prices for crude oil and natural gas compared with the third quarter of 2015, partially offset by lower operating costs and depreciation, depletion and amortization expenses.

Exploration and Production

In the third quarter of 2016, E&P incurred a net loss of $234 million compared with a net loss of $188 million in the third quarter of 2015. Excluding items affecting the comparability of earnings between periods, the adjusted net loss for the third quarter of 2016 was $285 million compared to an adjusted net loss of $221 million in 2015. Worldwide net production averaged 314,000 barrels of oil equivalent per day (boepd) in the third quarter of 2016, compared to pro forma net production, which excludes assets sold, of 372,000 boepd in the third quarter of 2015. The average realized crude oil selling price was $41.50 per barrel, down from $45.66 in the third quarter of 2015, which included hedging. The average realized natural gas liquids selling price in the third quarter of 2016 was $9.23 per barrel compared to $7.17 in the prior-year quarter while the average realized natural gas selling price was $3.20 per thousand cubic feet (mcf), down from $4.02 in the third quarter of 2015.

PART I - FINANCIAL INFORMATION (CONT’D.)

Overview (continued)

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

Producing E&P assets:

•

In North Dakota, net production from the Bakken oil shale play decreased to an average of 107,000 boepd for the third quarter of 2016 (2015: 113,000 boepd) primarily due to reduced drilling activity in response to low oil prices. In the third quarter of 2016, we operated an average of three rigs, drilled 21 wells and brought 22 new wells on production. Drilling and completion costs averaged $4.7 million per operated well in the third quarter of 2016, a reduction of 11% from the prior-year quarter. We expect full year 2016 Bakken production to approximate 105,000 boepd.

•

In the Gulf of Mexico, net production for the third quarter of 2016 averaged 61,000 boepd (2015: 83,000 boepd). The decrease in production was primarily a result of unplanned well downtime at the Tubular Bells Field (Hess 57%) and the Conger Field (Hess 38%), due to subsurface valve failures, and natural field decline. At the Tubular Bells Field, subsurface valves in two wells were replaced in the first half of 2016. Further workover operations to replace a subsurface valve in a third well at the Tubular Bells Field and a well in the Conger Field are planned for the fourth quarter of this year. We expect production from these wells to recommence in the first quarter of 2017.

•

Net production from the Valhall Field (Hess 64%), offshore Norway, decreased to an average of 31,000 boepd for the third quarter of 2016 (2015: 35,000 boepd) primarily due to a reduced drilling program.

•

At the North Malay Basin (Hess 50%), in the Gulf of Thailand, net production from the Early Production System averaged 25 million cubic feet per day (mmcfd) for the third quarter of 2016 (2015: 42 mmcfd). In the third quarter of 2016, we completed installation of the topsides at three remote well-head platforms, which are part of the full-field development project, and completed drilling of three development wells. The project is on schedule for completion in the third quarter of 2017, after which net production is expected to increase to 165 mmcfd.

•

In the Joint Development Area of Malaysia/Thailand (Hess 50%), net production averaged 146 mmcfd for the third quarter of 2016 (2015: 218 mmcfd), as a result of lower entitlement and commissioning of the new booster compressor project. In the fourth quarter of 2016, we expect net production to exceed 180 mmcfd.

•

At the South Arne Field (Hess 62%) in Denmark, net production decreased to an average of 11,000 boepd in the third quarter of 2016 (2015: 14,000 boepd), as a result of a planned maintenance shutdown during the quarter. In October 2016, the Danish government awarded a 20 year extension to the South Arne Field license, extending expiry to 2047.

Other E&P assets:

•

In Guyana, at the offshore Stabroek Block (Hess 30%), the operator, Esso Exploration and Production Guyana Limited, successfully completed the Liza-3 appraisal well. The Liza-3 well was drilled to a total depth of approximately 18,100 feet and encountered approximately 200 feet of the same oil-bearing reservoirs encountered in other Liza wells. Pre-development planning is underway and we expect to be in a position to sanction the first phase of the Liza development in 2017.

In the fourth quarter of 2016, the operator plans to drill an exploration well at the Payara prospect, located approximately 10 miles northeast of the Liza discovery. At the Skipjack prospect 25 miles northwest of the Liza discovery, the operator completed the drilling of an exploration well, which was unsuccessful and expensed in the third quarter.

•

At the Hess operated Stampede development project (Hess 25%) in the Green Canyon area of the Gulf of Mexico, the topsides deck was installed on the hull and drilling operations in the field continued. First production is targeted for 2018.

Bakken Midstream

The following is an update of our Bakken Midstream activities:

•

We continue to progress the construction of facilities and reconfiguration of pipelines in McKenzie and Williams counties that are expected to increase the volumes of crude oil and natural gas to be sent to our natural gas processing and crude oil and natural gas liquids logistics assets in Tioga and Ramberg. We expect these projects to be in service in 2017.

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,
	2016			2015			2016			2015
	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	(234	)	$	(188	)	$	(1,013	)	$	(1,004	)
Bakken Midstream		13			16			38			75
Corporate, Interest and Other		(118	)		(94	)		(265	)		(266	)
Income (loss) from continuing operations		(339	)		(266	)		(1,240	)		(1,195	)
Discontinued operations		—			(13	)		—			(40	)
Total	$	(339	)	$	(279	)	$	(1,240	)	$	(1,235	)

Net Income (Loss) per Common Share - Diluted:
Continuing operations	$	(1.12	)	$	(0.94	)	$	(4.11	)	$	(4.21	)
Discontinued operations		—			(0.04	)		—			(0.14	)
Net income (loss) per common share - Diluted	$	(1.12	)	$	(0.98	)	$	(4.11	)	$	(4.35	)

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 25 to 27.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In millions)
Exploration and Production	$	51		$	33		$	(6	)	$	(466	)
Bakken Midstream		—			—			—			—
Corporate, Interest and Other		(50	)		(8	)		(50	)		(12	)
Discontinued operations		—			(13	)		—			(40	)
Total Items Affecting Comparability of Earnings Between Periods	$	1		$	12		$	(56	)	$	(518	)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In millions)
Net income (loss) attributable to Hess Corporation	$	(339	)	$	(279	)	$	(1,240	)	$	(1,235	)
Less: Total items affecting comparability of earnings between periods		1			12			(56	)		(518	)
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	(340	)	$	(291	)	$	(1,184	)	$	(717	)

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

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Comparison of Results

Exploration and Production

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,177		$	1,671		$	3,374		$	5,162
Other, net		7			27			54			21
Total revenues and non-operating income		1,184			1,698			3,428			5,183
Costs and Expenses
Cost of products sold (excluding items shown separately below)		229			386			712			1,078
Operating costs and expenses		378			443			1,178			1,321
Production and severance taxes		27			29			74			110
Bakken Midstream tariffs		113			117			334			335
Exploration expenses, including dry holes and lease impairment		78			144			409			503
General and administrative expenses		61			60			177			243
Depreciation, depletion and amortization		784			963			2,396			2,899
Impairment		—			—			—			385
Total costs and expenses		1,670			2,142			5,280			6,874
Results of Operations Before Income Taxes		(486	)		(444	)		(1,852	)		(1,691	)
Provision (benefit) for income taxes		(252	)		(256	)		(839	)		(687	)
Net Income (Loss) Attributable to Hess Corporation	$	(234	)	$	(188	)	$	(1,013	)	$	(1,004	)

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

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Selling Prices: Average realized crude oil selling prices were 9% and 25% lower in the third quarter and first nine months of 2016, respectively, compared to the same periods in 2015 primarily due to declines in Brent and West Texas Intermediate crude oil prices. In addition, realized selling prices for natural gas liquids were up 29% and down 21%, respectively, and realized selling prices for natural gas were down 20% and 23%, respectively, in the third quarter and first nine months of 2016, compared to the same periods in 2015. Lower realized selling prices reduced after-tax results by approximately $40 million and $430 million in the third quarter and first nine months of 2016, respectively, compared to the same periods in 2015.

Average selling prices were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
Crude Oil - Per Barrel (Including Hedging)
United States
Onshore	$	39.19	$	40.43	$	35.16	$	43.38
Offshore		39.55		42.70		35.08		48.75
Total United States		39.33		41.33		35.13		45.43
Europe		46.01		53.49		40.66		55.87
Africa		44.22		51.98		39.66		54.99
Asia		47.36		—		43.11		56.85
Worldwide		41.50		45.66		37.05		49.14

Crude Oil - Per Barrel (Excluding Hedging)
United States
Onshore	$	39.19	$	37.91	$	35.16	$	42.61
Offshore		39.55		42.70		35.08		48.75
Total United States		39.33		39.81		35.13		44.95
Europe		46.01		50.12		40.66		55.01
Africa		44.22		48.60		39.66		54.26
Asia		47.36		—		43.11		56.85
Worldwide		41.50		43.43		37.05		48.55

Natural Gas Liquids - Per Barrel
United States
Onshore	$	8.48	$	5.45	$	7.89	$	9.47
Offshore		13.94		12.56		12.14		14.60
Total United States		9.00		6.69		8.33		10.32
Europe		17.68		21.44		17.50		25.50
Worldwide		9.23		7.17		8.55		10.84

Natural Gas - Per Mcf
United States
Onshore	$	1.49	$	1.70	$	1.33	$	1.78
Offshore		2.24		2.37		1.74		2.26
Total United States		1.67		1.92		1.43		1.95
Europe		3.74		6.43		4.04		7.18
Asia		5.66		5.98		5.65		6.07
Worldwide		3.20		4.02		3.41		4.40

Realized and unrealized gains from crude oil price collars increased Sales and other operating revenues in the third quarter and first nine months of 2015 by $42 million ($26 million after income taxes) and $24 million ($15 million after income taxes), respectively. There were no crude oil hedge contracts in 2016.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Production Volumes: Our crude oil, natural gas liquids and natural gas production decreased to 314,000 boepd and 326,000 boepd in the third quarter and first nine months of 2016, respectively, from 380,000 boepd and 377,000 boepd in the third quarter and first nine months of 2015, respectively. We continue to expect net production to average between 315,000 boepd and 325,000 boepd for the full year of 2016. Net production for the fourth quarter of 2016 is expected to average approximately 305,000 boepd.

Our net daily worldwide production was as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Crude Oil - Barrels
United States
Bakken		67			82			70			82
Other Onshore		9			10			9			11
Total Onshore		76			92			79			93
Offshore		46			60			46			57
Total United States		122			152			125			150

Europe		34			40			32			38
Africa		33			50			34			50
Asia		1			2			2			2
Worldwide		190			244			193			240

Natural Gas Liquids - Barrels
United States
Bakken		29			20			27			21
Other Onshore		11			12			12			11
Total Onshore		40			32			39			32
Offshore		4			7			5			6
Total United States		44			39			44			38

Europe		1			1			1			1
Worldwide		45			40			45			39

Natural Gas - Mcf
United States
Bakken		66			65			64			65
Other Onshore		139			125			136			100
Total Onshore		205			190			200			165
Offshore		65			93			64			85
Total United States		270			283			264			250

Europe		41			45			42			41
Asia		161			246			221			297
Worldwide		472			574			527			588

Barrels of Oil Equivalent (a)		314			380			326			377

Crude oil and natural gas liquids as a share of total production		75	%		75	%		73	%		74	%

(a)

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 21.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

United States: Onshore crude oil production was lower in the third quarter and first nine months of 2016, compared to the corresponding periods in 2015, primarily due to reduced drilling activity in the Bakken shale play in response to low oil prices. Onshore natural gas liquids production was higher in the third quarter and first nine months of 2016, compared to the corresponding periods in 2015, primarily due to greater processed volumes at the Tioga gas plant. Onshore natural gas production was higher in the third quarter and in the first nine months of 2016, compared to the corresponding periods in 2015, primarily due to more wells being brought on production in the Utica shale play in the first half of 2016. Total offshore production was lower in the third quarter of 2016, compared to the corresponding period in 2015, primarily due to subsurface valve failures at the Tubular Bells Field and the Conger Field, and natural field decline. Total offshore production was lower in the first nine months of 2016, compared to the corresponding period in 2015, due to extended planned shutdowns on third-party hosted production facilities at the Tubular Bells and Conger Fields in the second quarter of 2016. In addition, at the Tubular Bells Field, two wells were shut-in for an extended period in the first half of 2016 due to subsurface valve failures, which have since been replaced. A third well at the Tubular Bells Field has also been shut-in for an extended period in 2016 due to a subsurface valve failure, which is scheduled to be replaced beginning in the fourth quarter of 2016. We are pursuing our options to recover damages for these valve failures.

Europe: Crude oil production was lower in the third quarter and first nine months of 2016, compared to the corresponding periods in 2015. Current quarter production reflected planned maintenance downtime at the South Arne Field, offshore Denmark, and a reduced drilling program at the Valhall Field, offshore Norway. In addition, current year production reflected planned maintenance downtime at the Valhall Field, offshore Norway, in the second quarter.

Africa: Crude oil production was lower in the third quarter and first nine months of 2016, compared to the corresponding periods in 2015, primarily due to reduced drilling activity in Equatorial Guinea and the sale of our Algeria asset in the fourth quarter of 2015. Net production from the Algeria asset was 8,000 boepd in the third quarter and 6,000 boepd in the first nine months of 2015.

Asia: Natural gas production was lower in the third quarter and first nine months of 2016, compared to the corresponding periods in 2015, primarily due to the planned shutdown of production facilities at the JDA in the third quarter of 2016 to commission the booster compressor project and from lower production entitlement in 2016.

Sales Volumes: The impact of lower sales volumes decreased after-tax results by approximately $170 million and $395 million in the third quarter and first nine months of 2016, respectively, compared with the corresponding periods in 2015.

Our worldwide sales volumes were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands)
Barrels of Oil Equivalent (a)
Crude oil - barrels		17,528		22,592		55,030		65,028
Natural gas liquids - barrels		4,167		3,701		12,389		10,668
Natural gas - mcf		43,413		52,784		144,381		160,604
		28,931		35,090		91,483		102,463

Barrels of Oil Equivalent Per Day (a)
Crude oil - barrels per day		190		245		201		238
Natural gas liquids - barrels per day		45		40		45		39
Natural gas - mcf per day		472		574		527		588
		314		381		334		375

(a)

Cost of Products Sold: Cost of products sold is mainly comprised of costs relating to the purchases of crude oil, natural gas liquids and natural gas from our partners in Hess operated wells or other third parties, as well as rail transportation fees from our Bakken Midstream operating segment. The decrease in Cost of products sold in the third quarter and first nine months of 2016, compared with the same periods in 2015, principally reflects the decline in benchmark crude oil prices.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

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 third quarter and first nine months of 2016, compared to the same periods in 2015, due to lower production and ongoing cost reduction efforts, and lower production taxes in the Bakken shale play. Partially offsetting the lower operating costs was higher workover costs in 2016 to replace subsurface valves in the Gulf of Mexico.

Depreciation, Depletion and Amortization: DD&A expenses were lower in the third quarter and first nine months of 2016, compared with the prior-year periods, resulting from lower production and an improved portfolio average DD&A rate due to the production mix.

Bakken Midstream Tariffs Expense: Tariff expenses in the third quarter and first nine months of 2016 are comparable to the same periods in 2015.

Unit Cost Information: Unit cost per barrel of oil equivalent (boe) information is calculated based on total E&P production volumes and exclude items affecting comparability of earnings as described on page 25.

	Actual								Forecast Range
	Three Months Ended				Nine Months Ended				Three Months Ending	Twelve Months Ending
	September 30,				September 30,				December 31,	December 31,
	2016		2015		2016		2015		2016	2016

Cash operating costs	$	16.08	$	14.98	$	15.61	$	15.77	$17.50 — $18.50*	$16.00 — $16.50
Depreciation, depletion and amortization costs		27.09		27.53		26.85		28.14	26.00 — 27.00	26.50 — 27.00
Total Production Unit Costs	$	43.17	$	42.51	$	42.46	$	43.91	$ 43.50 — $45.50	$42.50 — $43.50

Bakken Midstream Tariffs Expense	$	3.92	$	3.36	$	3.74	$	3.26	$4.20 — $4.30	$3.85 — $3.95

* Includes approximately $2 per boe for planned workover costs to replace subsurface valves at the Tubular Bells Field and the Conger Field in the Gulf of Mexico.

Exploration Expenses: Exploration expenses were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In millions)
Exploratory dry hole costs	$	16	$	4	$	234	$	180
Exploration lease impairment		9		61		33		139
Geological and geophysical expense and exploration overhead		53		79		142		184
	$	78	$	144	$	409	$	503

Exploratory dry hole costs in the third quarter of 2016 primarily relate to the non-operated Skipjack well, offshore Guyana. Exploratory dry hole costs expensed in the first nine months of 2016 primarily relate to two wells at the non-operated Sicily prospect in the Gulf of Mexico where we decided not to pursue the project due to the current price environment and the limited time remaining on the leases, and to the non-operated Melmar exploration well in the Gulf of Mexico, where noncommercial quantities of hydrocarbons were encountered. Exploratory dry hole costs and exploratory lease impairment in the first nine months of 2015 included charges related to the Dinarta Block, in the Kurdistan Region of Iraq, an impairment charge for a relinquished lease in the Gulf of Mexico and the write down of a foreign exploration project to fair value. See further information below on page 25 under Items Affecting the Comparability of Earnings Between Periods.

Exploration expenses, excluding dry hole expense, are estimated to be in the range of $250 million to $260 million for the full year of 2016.

Income Taxes: Excluding items affecting comparability of earnings between periods, the effective income tax rate for E&P operations was a benefit of 41% and 42% in the third quarter and first nine months of 2016, respectively, compared to a benefit of 47% and 49% in the third quarter and first nine months of 2015, respectively. Excluding items affecting comparability of earnings between periods, the E&P effective income tax rate is expected to be a benefit in the range of 36% to 40% in the fourth quarter of 2016, and a benefit in the range of 40% to 44% for the full year of 2016, excluding any contribution from Libya.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

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,
	2016		2015			2016			2015
	(In millions)
Tax benefits	$	51	$	50		$	51		$	50
Exploratory dry hole cost and exploration lease impairment		—		(43	)		(52	)		(120	)
Contract termination costs		—		—			(22	)		(21	)
Gains on asset sale, net		—		31			17			31
Impairment		—		—			—			(385	)
Inventory write-off		—		—			—			(16	)
Exit costs and other		—		(5	)		—			(5	)
	$	51	$	33		$	(6	)	$	(466	)

Tax benefits: In the third quarter of 2016, we recorded a tax benefit of $51 million related to the resolution of certain international tax matters. In the third quarter of 2015, we received approval for an international investment incentive and recognized a tax benefit of $50 million. These benefits are included in Provision (benefit) for income taxes in the Statement of Consolidated Income.

Exploration expense: In the second quarter of 2016, we recorded a pre-tax charge of $83 million ($52 million after income taxes) to write-off the previously capitalized Sicily-1 exploration well completed in 2015. In the third quarter of 2015, we 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 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, we recorded 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. Exploration expenses also included a pre-tax charge of $16 million ($10 million after income taxes) to write down a foreign exploration project to fair value. These amounts are included in Exploration expenses, including dry holes and lease impairment in the Statement of Consolidated Income.

Contract termination costs: In the second quarter of 2016, we incurred a pre-tax charge of $36 million ($22 million after income taxes) associated with the termination of a drilling rig contract. In the second quarter of 2015, we incurred a pre-tax charge of $21 million ($21 million after income taxes) associated with terminated international office space. The rig termination charge is included in Operating costs and expenses and the charge for the terminated office lease is included in General and administrative expenses in the Statement of Consolidated Income.

Gains on asset sale: In the second quarter of 2016, we recognized a pre-tax gain of $27 million ($17 million after income taxes) related to the sale of undeveloped Onshore acreage in the United States. In the third quarter of 2015, we recognized a pre-tax gain of $49 million ($31 million after income taxes) resulting from the sale of dry gas acreage in the Utica shale play for consideration of approximately $120 million. These gains are included in Other, net in the Statement of Consolidated Income.

Impairment: In the second quarter of 2015, we incurred a noncash pre-tax goodwill impairment charge of $385 million ($385 million after income taxes) associated with our 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 allocation of goodwill to the Bakken Midstream segment and a goodwill impairment test for each of our reporting units.

Inventory write-off: In the first quarter of 2015, we incurred a pre-tax charge of $21 million ($16 million after income taxes) to write off surplus drilling materials in Equatorial Guinea. This charge is included in Operating costs and expenses in the Statement of Consolidated Income.

Exit costs and other: In 2015, we incurred charges of $6 million ($5 million after income taxes) related to employee severance.

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

Bakken Midstream

Following is a summarized income statement of our Bakken Midstream operations:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In millions)
Revenues and Non-Operating Income
Total revenues and non-operating income	$	120	$	148	$	358	$	423

Costs and Expenses
Operating costs and expenses		43		65		134		196
General and administrative expenses		4		4		13		9
Depreciation, depletion and amortization		25		22		73		65
Interest expense		4		4		14		6
Total costs and expenses		76		95		234		276

Results of Operations Before Income Taxes		44		53		124		147
Provision (benefit) for income taxes		9		10		24		45
Net Income (Loss)		35		43		100		102
Less: Net income (loss) attributable to noncontrolling interests (a)		22		27		62		27
Net Income (Loss) Attributable to Hess Corporation	$	13	$	16	$	38	$	75

(a)	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 third quarter and first nine months of 2016 decreased, compared to the same periods in 2015, as a result of lower rail export revenue. The decrease in Operating costs and expenses in the third quarter and first nine months of 2016, compared with the same period in 2015, primarily reflects the decrease in third-party rail charges. The increase in DD&A in the third quarter and first nine months of 2016, compared to the same periods in 2015, result from capital expenditures on gathering pipelines and railcars that have been placed in service. The increase in interest expense in the first nine months of 2016 reflects borrowings by Hess Infrastructure Partners LP (HIP) subsequent to its formation on July 1, 2015. Net income attributable to Hess Corporation from the Bakken Midstream segment is estimated to be in the range of $48 million to $53 million for the full year of 2016.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	31		$	57		$	97		$	165
Interest expense		95			92			284			282
Less: Capitalized interest		(15	)		(12	)		(44	)		(33	)
Interest expense, net		80			80			240			249
Corporate, Interest and Other expenses before income taxes		111			137			337			414
Provision (benefit) for income taxes		(43	)		(51	)		(122	)		(160	)
Net Corporate, Interest and Other expenses after income taxes		68			86			215			254
Items affecting comparability of earnings between periods, after-tax		50			8			50			12
Total Corporate, Interest and Other expenses After Income Taxes	$	118		$	94		$	265		$	266

Corporate and other expenses were lower in the third quarter and first nine months of 2016, compared to 2015, primarily due to reductions in employee costs, professional fees, and other general and administrative expenses. Capitalized interest was higher in the third quarter and first nine months of 2016, compared to 2015, following increased activity at the Hess operated Stampede development project. We estimate corporate expenses for full year 2016 to be in the range of $90 million to $95 million after income taxes, and interest expense to be in the range of $200 million to $205 million after income taxes.

Items Affecting Comparability of Earnings Between Periods:

In the third quarter of 2016, we purchased $650 million principal amount of tendered 8.125% notes due 2019. This transaction resulted in a debt extinguishment charge of $80 million ($50 million after income taxes).

PART I - FINANCIAL INFORMATION (CONT’D.)

Results of Operations (continued)

In the third quarter of 2015, we recorded a pre-tax charge of $10 million ($8 million after income taxes) related to HOVENSA, which was subsequently sold in the first quarter of 2016. In the first quarter of 2015, we incurred exit costs of $6 million ($4 million after income taxes).

Other Items Potentially Affecting Future Results:

Our future results may be impacted by a variety of factors, including but not limited to, volatility in the selling prices of crude oil, natural gas liquids and natural gas, reserve and production changes, asset sales, impairment charges and exploration expenses, industry cost inflation and/or deflation, changes in foreign exchange rates and income tax rates, changes in deferred tax asset valuation allowances associated with continued operating losses, the effects of weather, political risk, environmental risk and catastrophic risk. For a more comprehensive description of the risks that may affect our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015.

Liquidity and Capital Resources

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

	September 30,			December 31,
	2016			2015
	(In millions, except ratio)
Cash and cash equivalents	$	3,529		$	2,716
Current maturities of long-term debt		666			86
Total debt (a)		7,337			6,592
Total equity		20,915			20,401
Debt to capitalization ratio (b)		26.0	%		24.4	%

(a)	Includes $683 million of debt outstanding from our Bakken Midstream joint venture at September 30, 2016 that is non-recourse to Hess Corporation (December 31, 2015: $704 million).

(b)	Total debt as a percentage of the sum of total debt plus equity.

In October 2016, we purchased or redeemed notes for $625 million to complete the debt refinancing transaction. Pro forma for the notes purchased or redeemed in October and excluding the Bakken Midstream, debt amounted to $6,095 million at September 30, 2016. The Corporation’s pro forma debt to capitalization ratio was 24.5%.

Cash Flows

The following table summarizes our cash flows:

	Nine Months Ended
	September 30,
	2016			2015
	(In millions)
Cash Flows From Operating Activities:
Cash provided by (used in) operating activities - continuing operations	$	469		$	1,389
Cash provided by (used in) operating activities - discontinued operations		—			(31	)
Net cash provided by (used in) operating activities		469			1,358

Cash Flows From Investing Activities:
Additions to property, plant and equipment - E&P		(1,578	)		(3,232	)
Additions to property, plant and equipment - Bakken Midstream		(186	)		(154	)
Proceeds from asset sales		80			25
Other, net		18			(44	)
Cash provided by (used in) investing activities - continuing operations		(1,666	)		(3,405	)
Cash provided by (used in) investing activities - discontinued operations		—			108
Net cash provided by (used in) investing activities		(1,666	)		(3,297	)

Cash Flows From Financing Activities:
Cash provided by (used in) financing activities - continuing operations		2,010			2,508
Cash provided by (used in) financing activities - discontinued operations		—			—
Net cash provided by (used in) financing activities		2,010			2,508

Net increase (decrease) in cash and cash equivalents from continuing operations		813			492
Net increase (decrease) in cash and cash equivalents from discontinued operations		—			77
Net Increase (Decrease) in Cash and Cash Equivalents	$	813		$	569

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

Operating activities: Net cash provided by operating activities was $469 million in the first nine months of 2016, compared to $1,358 million in the first nine months of 2015. The reduction in 2016 operating cash flows primarily reflects lower production volumes and lower benchmark crude oil price in the first nine months of 2016.

Investing activities: The decrease in Additions to property, plant and equipment in the first nine months of 2016, as compared to the same period in 2015, is primarily due to reduced drilling activity (Bakken, Utica, Norway, Denmark and Equatorial Guinea) and reduced development expenditures (Tubular Bells, North Malay Basin and the JDA). Proceeds from asset sales in the first nine months of 2016 relates to the sale of undeveloped acreage, onshore United States and consideration received from the December 2015 sale of our assets in Algeria.

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

	Nine Months Ended
	September 30,
	2016			2015
	(In millions)
Capital expenditures incurred - E&P	$	(1,322	)	$	(2,915	)
Increase (decrease) in related liabilities		(256	)		(317	)
Additions to property, plant and equipment - E&P	$	(1,578	)	$	(3,232	)

Capital expenditures incurred - Bakken Midstream	$	(190	)	$	(193	)
Increase (decrease) in related liabilities		4			39
Additions to property, plant and equipment - Bakken Midstream	$	(186	)	$	(154	)

Financing activities: In the first nine months of 2016, we issued $1.5 billion of senior notes and we repaid total debt of $825 million. In the first quarter of 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock for total net proceeds of $1.64 billion. We paid common and preferred stock dividends in the first nine months of 2016 totaling $260 million (2015: $215 million). In July 2015, we received net cash consideration of approximately $2.6 billion from the sale of a 50% interest in our Bakken Midstream business. The Bakken Midstream joint venture received proceeds of $600 million under a term loan and distributed $300 million to each partner. In addition, we paid $142 million for the settlement of common stock repurchases during the first nine months of 2015.

Future Capital Requirements and Resources

We ended the quarter with $3.5 billion in cash and cash equivalents and total liquidity including available committed credit facilities of approximately $8.2 billion. In October 2016, we used $625 million to complete the purchase and redemption of notes under our debt refinancing transaction. We forecast a significant net loss and net operating cash flow deficit (including capital expenditures) in 2016. Based on current forward strip crude oil prices for 2017 which are higher than 2016 prices, we forecast a smaller net loss and net operating cash flow deficit (including capital expenditures) in 2017. We expect to fund our projected net operating cash flow deficit (including capital expenditures) through 2017 with cash on hand. Due to the low commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: further reduce our planned capital program and other cash outlays, borrow from our committed credit facilities, issue debt or equity securities, and pursue asset sales.

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

The table below summarizes the capacity, usage and available capacity of our borrowing and letter of credit facilities at September 30, 2016:

						Letters of
	Expiration					Credit				Available
	Date	Capacity		Borrowings		Issued (c)		Total Used		Capacity
		(In millions)
Revolving credit facility - Hess Corporation	January 2020	$	4,000	$	—	$	—	$	—	$	4,000
Revolving credit facility - HIP (a)	July 2020		400		96		—		96		304
Committed lines	Various (b)		625		—		2		2		623
Uncommitted lines	Various (b)		170		—		170		170		—
Total		$	5,195	$	96	$	172	$	268	$	4,927

(a)	This facility may only be utilized by HIP and is non-recourse to Hess Corporation.

(b)	Committed and uncommitted lines have expiration dates through 2018.

(c)	Primarily relate to our international operations.

Hess Corporation has a $4.0 billion syndicated revolving credit facility expiring in January 2020. Borrowings on the facility will generally bear interest at 1.3% above the London Interbank Offered Rate (LIBOR). The interest rate will be higher if our credit rating is lowered. The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 65% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity. As of September 30, 2016, Hess Corporation had no outstanding borrowings under this facility and was in compliance with this financial covenant.

HIP’s $400 million 5-year syndicated revolving credit facility can be used for borrowings and letters of credit to fund the joint venture’s operating activities and capital expenditures. Borrowings generally bear interest at the LIBOR plus an applicable margin ranging from 1.10% to 2.00%. The interest rate is subject to adjustment 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 the credit ratings in effect from time to time. 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, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. HIP is in compliance with these financial covenants at September 30, 2016.

At September 30, 2016, borrowings attributable to the joint venture, which are non-recourse to Hess Corporation, amounted to $593 million on the Term Loan A loan facility and $96 million on the revolving credit facility excluding deferred issuance costs.

We also have an effective shelf registration under which Hess Corporation may issue additional debt securities, warrants, common stock or preferred stock.

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

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 us or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to reduce risk in the selling price of a portion of our crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which we do business with the intent of reducing exposure to foreign currency fluctuations. Interest rate swaps may also be used, generally to convert fixed‑rate interest payments to floating.

We have outstanding foreign exchange contracts with notional amounts totaling $705 million at September 30, 2016, to reduce our exposure to fluctuating foreign exchange rates for various currencies, primarily the British Pound and Danish Krone. 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 $70 million at September 30, 2016.

At September 30, 2016, our outstanding long‑term debt of $7,337 million, including current maturities, had a fair value of $7,881 million. A 15% increase or decrease in the rate of interest would decrease or increase the fair value of long-term debt, including the impact of interest rate swaps, by approximately $510 million or $580 million, respectively.

We have no outstanding commodity price hedges at September 30, 2016.

PART I - FINANCIAL INFORMATION (CONT’D.)

Forward-looking Information

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

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, 2016, 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, 2016.

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, 2016 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 12, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

Item 2. Share Repurchase Activities.

Our share repurchase activities for the three months ended September 30, 2016, were as follows:

2016	Total Number of Shares Purchased (a)		Average Price Paid per Share (b)		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 (c) (In millions)
July		—	$	—		—	$	1,150
August		—		—		—		1,150
September		1,083		47.00		—		1,150
Total		1,083	$	47.00		—

(a)	Represents common shares repurchased at a price of $46.98 per common share on the open market, which were subsequently granted to Directors in accordance with the Non-Employee Directors’ Stock Plan.

(b)	The average price paid per share was inclusive of transaction fees.

(c)	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, 2016, Registrant filed the following reports on Form 8-K:
	(i)	Filing dated July 27, 2016 under Items 2.02 and 9.01, a news release dated July 27, 2016 reporting results for the second quarter of 2016.
	(ii)	Filing dated September 13, 2016 under Item 5.02, reporting changes to the board of directors.
	(iii)	Filing dated September 19, 2016 under Items 8.01 and 9.01, a news release dated September 19, 2016 reporting the commencement of tender offers to purchase certain of the Company’s debt securities.
	(iv)	Filing dated September 28, 2016 under Items 8.01 and 9.01, reporting the completion of the sale of $1.5 billion of senior notes.

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 2, 2016