UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, ~~2018~~2019

o☐ 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: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)



Delaware			73-0785597
(State or other jurisdiction of incorporation or organization)			(I.R.S. employer identification number)
1001 Noble Energy Way
Houston,	Texas		77070
(Address of principal executive offices)			(Zip Code)
(281)		872-3100
(Registrant’s telephone number, including area code)



Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	NBL	New York Stock Exchange

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.

Yesý☒ No o☐

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).

Yesý☒ No o☐

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

reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o☐ No ý☒

As of June 30, ~~2018,~~2019, there were ~~483,118,790~~478,253,121 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS



Part I. Financial Information	3

Item 1. Financial Statements	3

Consolidated Statements of Operations and Comprehensive Income (Loss)	3

Consolidated Balance Sheets	4

Consolidated Statements of Cash Flows	5

Consolidated Statements of Equity	6

Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2925

Item 3. Quantitative and Qualitative Disclosures About Market Risk	4638

Item 4. Controls and Procedures	4839

Part II. Other Information	4839

Item 1. Legal Proceedings	4839

Item 1A. Risk Factors	4840

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4840

Item 3. Defaults Upon Senior Securities	5040

Item 4. Mine Safety Disclosures	5040

Item 5. Other Information	5040

Item 6. Exhibits	5141

Signatures	5342

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(millions, except per share amounts)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Revenues
Oil, NGL and Gas Sales	$	1,100		$	1,017		$	2,273		$	2,011		$	954		$	1,100		$	1,891		$	2,273
Income from Equity Method Investees and Other	130			42			243			84
Sales of Purchased Oil and Gas													103			66			177			119
Other Revenue													36			64			77			124
Total	1,230			1,059			2,516			2,095			1,093			1,230			2,145			2,516
Costs and Expenses
Production Expense	292			283			613			586			260			290			565			609
Exploration Expense	29			30			64			72
Depreciation, Depletion and Amortization	465			503			933			1,031			528			465			1,036			933
Loss on Marcellus Shale Upstream Divestiture	—			2,322			—			2,322
General and Administrative													105			105			207			209
Cost of Purchased Oil and Gas													113			71			200			128
Other Operating Expense, Net													55			34			104			84
Gain on Divestitures, Net	(78		)	—			(666		)	—			—			(78		)	—			(666		)
Asset Impairments	—			—			168			—			—			—			—			168
General and Administrative	105			103			209			202
Other Operating Expense, Net	74			118			144			147
Firm Transportation Exit Cost													—			—			92			—
Total	887			3,359			1,465			4,360			1,061			887			2,204			1,465
Operating Income (Loss)	343			(2,300		)	1,051			(2,265		)	32			343			(59		)	1,051
Other (Income) Expense
Loss (Gain) on Commodity Derivative Instruments	249			(57		)	328			(167		)
Other Expense
(Gain) Loss on Commodity Derivative Instruments													(60		)	249			152			328
Interest, Net of Amount Capitalized	73			96			146			183			63			73			129			146
Other Non-Operating Expense (Income), Net	11			(5		)	24			(6		)
Other Non-Operating Expense, Net													1			11			5			24
Total	333			34			498			10			4			333			286			498
Income (Loss) Before Income Taxes	10			(2,334		)	553			(2,275		)	28			10			(345		)	553
Income Tax Expense (Benefit)	16			(836		)	(15		)	(824		)	20			16			(64		)	(15		)
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests	(6		)	(1,498		)	568			(1,451		)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests													8			(6		)	(281		)	568
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	17			14			37			25			18			17			42			37
Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy	$	(23	)	$	(1,512	)	$	531		$	(1,476	)
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy													$	(10	)	$	(23	)	$	(323	)	$	531

Net (Loss) Income Attributable to Noble Energy per Common Share
Net (Loss) Income Attributable to Noble Energy Common Shareholders per Share
Basic	$	(0.05	)	$	(3.20	)	$	1.09		$	(3.27	)	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
Diluted	$	(0.05	)	$	(3.20	)	$	1.09		$	(3.27	)	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
Weighted Average Number of Common Shares Outstanding
Basic	484			472			485			452			478			484			478			485
Diluted	484			472			487			452			478			484			478			487

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

June 30,
2018 December 31,
2017
ASSETS
Current Assets
Cash and Cash Equivalents $ 621
$ 675
Accounts Receivable, Net 743
748
Other Current Assets 187
780
Total Current Assets 1,551
2,203
Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method of Accounting) 28,334
29,678
Property, Plant and Equipment, Other 896
879
Total Property, Plant and Equipment, Gross 29,230
30,557
Accumulated Depreciation, Depletion and Amortization (11,313 ) (13,055 )
Total Property, Plant and Equipment, Net 17,917
17,502
Other Noncurrent Assets 984
461
Goodwill 1,402
1,310
Total Assets $ 21,854
$ 21,476
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable – Trade $ 1,308
$ 1,161
Other Current Liabilities 745
578
Total Current Liabilities 2,053
1,739
Long-Term Debt 6,555
6,746
Deferred Income Taxes 970
1,127
Other Noncurrent Liabilities 995
1,245
Total Liabilities 10,573
10,857
Commitments and Contingencies

Shareholders’ Equity

Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued —
—
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 526 Million and 529 Million Shares Issued, respectively 5
5
Additional Paid in Capital 8,329
8,438
Accumulated Other Comprehensive Loss (28 ) (30 )
Treasury Stock, at Cost; 39 Million Shares (731 ) (725 )
Retained Earnings 2,677
2,248
Noble Energy Share of Equity 10,252
9,936
Noncontrolling Interests 1,029
683
Total Equity 11,281
10,619
Total Liabilities and Equity $ 21,854
$ 21,476



	June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and Cash Equivalents	$	470		$	716
Accounts Receivable, Net	575			616
Other Current Assets	313			418
Total Current Assets	1,358			1,750
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	29,890			29,002
Property, Plant and Equipment, Other	1,038			891
Total Property, Plant and Equipment, Gross	30,928			29,893
Accumulated Depreciation, Depletion and Amortization	(12,153		)	(11,474		)
Total Property, Plant and Equipment, Net	18,775			18,419
Other Noncurrent Assets	1,516			841
Total Assets	$	21,649		$	21,010
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable – Trade	$	1,313		$	1,207
Other Current Liabilities	998			519
Total Current Liabilities	2,311			1,726
Long-Term Debt	6,866			6,574
Deferred Income Taxes	961			1,061
Other Noncurrent Liabilities	1,307			1,165
Total Liabilities	11,445			10,526
Commitments and Contingencies
Mezzanine Equity
Redeemable Noncontrolling Interest, Net	100			—
Shareholders’ Equity
Preferred Stock – Par Value $1.00 per share; 4 Million Shares Authorized; None Issued	—			—
Common Stock – Par Value $0.01 per share; 1 Billion Shares Authorized; 522 Million and 520 Million Shares Issued, respectively	5			5
Additional Paid in Capital	8,244			8,203
Accumulated Other Comprehensive Loss	(31		)	(32		)
Treasury Stock, at Cost; 39 Million Shares	(735		)	(730		)
Retained Earnings	1,546			1,980
Noble Energy Share of Equity	9,029			9,426
Noncontrolling Interests	1,075			1,058
Total Shareholders' Equity	10,104			10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity	$	21,649		$	21,010

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)


	Six Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2019			2018
Cash Flows From Operating Activities
Net Income (Loss) Including Noncontrolling Interests	$	568		$	(1,451	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Net (Loss) Income Including Noncontrolling Interests							$	(281	)	$	568
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	933			1,031			1,036			933
Loss on Marcellus Shale Upstream Divestiture	—			2,322
Deferred Income Tax Benefit							(101		)	(164		)
Loss on Commodity Derivative Instruments							152			328
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments							15			(93		)
Other Adjustments for Noncash Items Included in Income							59			57
Gain on Divestitures, Net	(666		)	—			—			(666		)
Asset Impairments	168			—			—			168
Deferred Income Tax Benefit	(164		)	(873		)
Loss (Gain) on Commodity Derivative Instruments	328			(167		)
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments	(93		)	14
Stock Based Compensation	35			67
Other Adjustments for Noncash Items Included in Income (Loss)	22			33
Firm Transportation Exit Cost							92			—
Changes in Operating Assets and Liabilities
Decrease (Increase) in Accounts Receivable	76			(123		)
(Decrease) Increase in Accounts Payable	(24		)	120
Decrease in Current Income Taxes Payable	3			(42		)
Decrease in Accounts Receivable							35			76
Increase (Decrease) in Accounts Payable							126			(24		)
Increase in Partner Advances							132			—
Other Current Assets and Liabilities, Net	(58		)	(42		)	(108		)	(55		)
Other Operating Assets and Liabilities, Net	(49		)	(12		)	(65		)	(49		)
Net Cash Provided by Operating Activities	1,079			877			1,092			1,079
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,782		)	(1,215		)	(1,405		)	(1,782		)
Proceeds from Sale of 7.5% Interest in Tamar Field	484			—
Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units	443			—
Proceeds from Gulf of Mexico Divestiture	383			—
Proceeds from Marcellus Shale Upstream Divestiture	—			1,028
Clayton Williams Energy Acquisition	—			(616		)
Acquisitions, Net of Cash Acquired	(650		)	(351		)
Proceeds from Other Divestitures	72			101
Acquisitions, Net of Cash Received							—			(650		)
Additions to Equity Method Investments	—			(68		)	(415		)	—
Other	—			—
Proceeds from Divestitures, Net							123			1,382
Net Cash Used in Investing Activities	(1,050		)	(1,121		)	(1,697		)	(1,050		)
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facility							50			905
Repayment of Revolving Credit Facility							(50		)	(1,135		)
Proceeds from Noble Midstream Services Revolving Credit Facility							560			610
Repayment of Noble Midstream Services Revolving Credit Facility							(250		)	(165		)
Proceeds from Commercial Paper Borrowings, Net							240			—
Dividends Paid, Common Stock	(102		)	(92		)	(111		)	(102		)
Purchase and Retirement of Common Stock	(130		)	—			—			(130		)
Proceeds from Noble Midstream Services Revolving Credit Facility	610			195
Repayment of Noble Midstream Services Revolving Credit Facility	(165		)	(5		)
Contributions from Noncontrolling Interest Owners	331			—			21			331
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	—			138
Proceeds from Revolving Credit Facility	905			1,310
Repayment of Revolving Credit Facility	(1,135		)	(1,310		)
Repayment of Clayton Williams Energy Long-term Debt	—			(595		)
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs							99			—
Repayment of Senior Notes	(384		)	—			(9		)	(384		)
Other	(51		)	(67		)	(62		)	(51		)
Net Cash Used in Financing Activities	(121		)	(426		)
Net Cash Provided by (Used in) Financing Activities							488			(121		)
Decrease in Cash, Cash Equivalents, and Restricted Cash	(92		)	(670		)	(117		)	(92		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	713			1,210			719			713
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	621		$	540		$	602		$	621

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)


	Attributable to Noble Energy																				Attributable to Noble Energy
	Common Stock		Additional Paid in Capital			Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Non- controlling Interests			Total Equity			Common Stock		Additional Paid in Capital			Accumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Non-controlling Interests			Total Equity
December 31, 2018																					$	5	$	8,203		$	(32	)	$	(730	)	$	1,980		$	1,058		$	10,484
Net (Loss) Income																					—		—			—			—			(313		)	24			(289		)
Stock-based Compensation																					—		14			—			—			—			—			14
Dividends (11 cents per share)																					—		—			—			—			(53		)	—			(53		)
Distributions to Noncontrolling Interest Owners																					—		—			—			—			—			(17		)	(17		)
Contributions from Noncontrolling Interest Owners																					—		—			—			—			—			10			10
Other																					—		2			—			(5		)	—			(3		)	(6		)
March 31, 2019																					$	5	$	8,219		$	(32	)	$	(735	)	$	1,614		$	1,072		$	10,143
Net (Loss) Income																					—		—			—			—			(10		)	18			8
Stock-based Compensation																					—		21			—			—			—			—			21
Dividends (12 cents per share)																					—		—			—			—			(58		)	—			(58		)
Distributions to Noncontrolling Interest Owners																					—		—			—			—			—			(19		)	(19		)
Contributions from Noncontrolling Interest Owners																					—		—			—			—			—			11			11
Other																					—		4			1			—			—			(7		)	(2		)
June 30, 2019																					$	5	$	8,244		$	(31	)	$	(735	)	$	1,546		$	1,075		$	10,104

December 31, 2017	$	5	$	8,438		$	(30	)	$	(725	)	$	2,248		$	683		$	10,619		$	5	$	8,438		$	(30	)	$	(725	)	$	2,248		$	683		$	10,619
Net Income	—		—			—			—			531			37			568			—		—			—			—			554			20			574
Stock-based Compensation	—		46			—			—			—			—			46			—		17			—			—			—			—			17
Dividends (21 cents per share)	—		—			—			—			(102		)	—			(102		)
Dividends (10 cents per share)																					—		—			—			—			(48		)	—			(48		)
Purchase and Retirement of Common Stock	—		(130		)	—			—			—			—			(130		)	—		(67		)	—			—			—			—			(67		)
Clayton Williams Energy Acquisition	—		(25		)	—			—			—			—			(25		)	—		(25		)	—			—			—			—			(25		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(22		)	(22		)	—		—			—			—			—			(11		)	(11		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			331			331			—		—			—			—			—			331			331
Other	—		—			2			(6		)	—			—			(4		)	—		—			1			(6		)	—			2			(3		)
June 30, 2018	$	5	$	8,329		$	(28	)	$	(731	)	$	2,677		$	1,029		$	11,281

December 31, 2016	$	5	$	6,450		$	(31	)	$	(692	)	$	3,556		$	312		$	9,600
March 31, 2018																					$	5	$	8,363		$	(29	)	$	(731	)	$	2,754		$	1,025		$	11,387
Net (Loss) Income	—		—			—			—			(1,476		)	25			(1,451		)	—		—			—			—			(23		)	17			(6		)
Clayton Williams Energy Acquisition	—		1,876			—			(25		)	—			—			1,851
Stock-based Compensation	—		65			—			—			—			—			65			—		29			—			—			—			—			29
Dividends (20 cents per share)	—		—			—			—			(92		)	—			(92		)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs	—		—			—			—			—			138			138
Dividends (11 cents per share)																					—		—			—			—			(54		)	—			(54		)
Purchase and Retirement of Common Stock																					—		(63		)	—			—			—			—			(63		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(12		)	(12		)	—		—			—			—			—			(11		)	(11		)
Other	—		8			1			(10		)	—			—			(1		)	—		—			1			—			—			(2		)	(1		)
June 30, 2017	$	5	$	8,399		$	(30	)	$	(727	)	$	1,988		$	463		$	10,098
June 30, 2018																					$	5	$	8,329		$	(28	)	$	(731	)	$	2,677		$	1,029		$	11,281

The accompanying notes are an integral part of these consolidated financial statements.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 1. Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJDenver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford ~~Shale and Marcellus Shale (until June 2017);~~Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns ~~operates, develops~~ and ~~acquires~~operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus areas being the DJ and Delaware Basins.

Note 2. Basis of Presentation

Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at June 30, ~~2018~~2019 and December 31, ~~2017~~2018 and for the three and six months ended June 30, ~~2018~~2019 and ~~2017~~2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, ~~activity within other comprehensive~~net income or loss ~~was de minimis; therefore, net income~~ is materially consistent with comprehensive income or loss.

Operating results for the three and six months ended June 30, ~~2018~~2019 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2018.~~2019.

These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.

Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

~~Investment~~Partner Advances Partner advances consist of cash advances from certain of our Eastern Mediterranean field partners pending allocation of capacity in ~~Shares~~the EMG Pipeline owned by Eastern Mediterranean Gas Company S.A.E (EMG) and pending closing of ~~Tamar Petroleum~~ ~~We account for~~the planned acquisition of EMG, which is expected to occur in third quarter 2019. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers. The acquisition of the equity interest in EMG is expected to support delivery of natural gas from our ~~investment in shares of Tamar Petroleum Ltd. at fair value and record changes in fair value in other non-operating expense (income), net~~producing fields offshore Israel into Egypt. The cash advances received are reported within restricted cash in our consolidated ~~statements of operations. See~~ ~~Note 3. Acquisitions and Divestitures~~ ~~and~~ ~~Note 6. Fair Value Measurements and Disclosures~~.balance sheets.

~~Intangible Assets~~ Leases~~Intangible assets consist of customer contracts~~We determine whether an arrangement contains a lease based on the conveyed rights and relationships acquired by Noble Midstream Partners in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets at their estimated fair valuesobligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, ~~of acquisition. Amortization is calculated using~~we record a right-of-use (ROU) asset and a corresponding lease liability based on the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset, which is currently over periods of seven to 13 years. As of June 30, 2018, the gross bookpresent value of the ~~intangible asset was $340 million. Amortization~~minimum lease payments.

As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below.

Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of ~~$9 million~~our leases include an option for early termination. We include renewal periods and ~~$14 million for~~exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the three and six months ended June 30, 2018, respectively, is included in depreciation, depletion and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See ~~Note 3. Acquisitions and Divestitures~~.option.

~~Stock Repurchase Program~~Lease Payments ~~On February 15, 2018, we announced~~Certain of our lease agreements include rental payments that ~~the Company's Board~~are adjusted periodically for inflation or passage of ~~Directors authorized a $750 million share repurchase program which expires December 31, 2020. All purchases will be made~~time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from time to time in the open market or private transactions, depending on market conditions, and may be discontinued at any time. During second quarter and the first six months of 2018, we repurchased and retired 1.8 million shares and 4.0 million shares of common stock at an average purchase price of $35.15 per share and $32.41 per share, respectively.

~~ASC 606, Revenue from Contracts with Customers~~Our revenue is derived from the sale of crude oil, NGL and natural gas production primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, ~~Revenue from Contracts with Customers~~ ~~(ASC 606), which we adopted on January 1, 2018 using the~~our present value calculation.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

~~modified retrospective method. Under ASC 606, performance obligations~~For example, drilling rig ROU assets and lease liabilities are recorded using the ~~unit of account~~contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use.

Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally ~~represent distinct~~accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments.

Revenue RecognitionWe recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer, at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered.

~~ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on~~using a gross basis if we control a promised good or service before transferring it to a customer. For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services. For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue.

~~Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815,~~ ~~Derivatives and Hedging, and will account for such contracts~~five-step process, in accordance with ASC ~~606.~~

In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.

~~ASC~~ 606 adoption did not have an impact on the opening balance of retained earnings. The adoption resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for second quarter and the first six months of 2018, respectively, but did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward.

Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, ~~Revenue Recognition~~, where we previously retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements.

Following the control model in ASC 606, we determined that we remain the principal in arrangements with the end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production in the downstream markets. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis.

Our commodity sale contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period.

~~The following is a summary of our types of revenue arrangements by commodity and geographic location.~~

~~EXPLORATION AND PRODUCTION (E&P) REVENUE ARRANGEMENTS~~

~~Crude Oil Sale Arrangements~~ – US ~~We sell the majority of our US crude oil productionunder short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale.~~

We sell our crude oil production either at the lease location or in downstream markets. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from ~~the sale of crude oil in downstream markets is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer.~~

In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing.

~~Crude Oil Buy/Sell Transactions – US~~ Contracts with CustomersWe enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, ~~Nonmonetary Transactions~~ (ASC 606). ~~We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations.~~

~~Crude Oil Sale Arrangements – West Africa~~Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees.

~~Natural Gas and NGLs Sale Arrangements – US~~ Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we record revenue when the processor takes physical possession of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor.

In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.

~~Natural Gas Purchase and Sale Arrangements – US~~Weenter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.

~~Natural Gas Sale Arrangements – West Africa~~ We sell our share of natural gas production from the Alba field under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.

~~Natural Gas Sale Arrangements – Israel~~ Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant toUnder ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations.

~~Transaction Price Allocated to Remaining Performance Obligations – Israel~~ ~~Remaining~~606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts, and long-term dedicated production agreements, are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However,In Israel, certain of our Tamar natural gas ~~sales~~ contracts ~~in Israel~~ have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, ~~based upon~~as of June 30, 2019, for those ~~certain agreements with fixed minimum take-or-pay sales volumes.~~agreements. Our actual future sales volumes ~~under these agreements~~ may exceed future minimum volume commitments.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~


(millions)	July - Dec 2018		2019		2020		Total		Remainder of 2019		2020		Total
Natural Gas Revenues ⁽¹⁾	$	107	$	137	$	169	$	413	$	72	$	116	$	188


⁽¹⁾	The remaining performance obligations are estimated using the contractual base or floor price provision in effect. Future revenues under these contracts will vary from the amounts above due to components of variable consideration exceeding the contractual base or floor price provision.

⁽¹⁾The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.

~~MIDSTREAM REVENUE ARRANGEMENTS~~

Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses.

~~Crude Oil Purchase and Sale Arrangements – US~~Redeemable Noncontrolling Interest ~~As part~~In March 2019, Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the ~~Saddle Butte acquisition~~commitment, with associated offering costs of $3 million, and the remaining $100 million is available for a one-year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first ~~quarter 2018, we acquired~~two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return.

As GIP’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of equity on the consolidated balance sheet and, ~~associated~~therefore, is reported as mezzanine equity. In addition, because the preferred equity was issued by a subsidiary of Noble Midstream Partners and is held by a third party, ~~contracts which include transactions for~~it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the ~~purchase and sale~~redemption value of ~~crude oil with varying counterparties. Revenues and expenses~~the preferred equity from the ~~sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control~~date of issuance to the earliest redemption date of the ~~purchased commodity before it~~preferred equity. The accretion is ~~transferred to the customer. The purchases~~offset against additional paid in capital. See Note 4. Acquisitions and ~~sales of crude oil are at the prevailing market prices.~~Divestitures and Note 13. Fair Value Measurements and Disclosures.

Recently Issued Accounting Standards

~~LeasesIn February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02):~~ ~~Leases.~~ The standard requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01): ~~Land Easement Practical Expedient for Transition to Topic 842~~, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): ~~Codification Improvements to Topic 842, Leases~~, to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): ~~Leases (Topic 842): Targeted Improvements~~, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.

In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We will adopt the new standard on the effective date of January 1, 2019. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software.

~~Accumulated Other Comprehensive Income~~ ~~In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02):~~ ~~Income Statement – Reporting Comprehensive Income,~~ to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. ASU 2018-02 will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. As of June 30, 2018, we have a disproportionate tax effect of approximately $7 million stranded in accumulated other comprehensive income. We are currently evaluating the provisions of this standard.

~~Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment~~ ~~In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04):~~ ~~Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment,~~ to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04.

Financial Instruments: Credit Losses In June 2016, the ~~FASB~~Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology used for certain financial instruments with a methodology that reflects current expected credit losses. The ~~update is intended to provide financial statement users with more useful information about~~current expected credit ~~losses. The amended standard~~loss (CECL) model applies to a broad scope of financial instruments, including financial assets measured at amortized cost. CECL also applies to off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption ~~permitted.~~ permitted, and shall be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period.

The FASB subsequently issued Accounting Standards Update No. 2019-04 (ASU 2019-04): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and Accounting Standards Update No. 2019-05 (ASU 2019-05): Financial Instruments-Credit Losses (Topic 326)-Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to CECL implementation and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments.

From evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses ~~would~~will not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements. We have developed and are executing an implementation plan, which includes data collection, contract review and

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

assessment, and evaluation of our systems, processes and internal controls. We will continue to monitor changes in our credit portfolio and off-balance sheet exposures as our implementation plan progresses.

Recently Adopted Accounting Standards

LeasesIn February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained.

The new standard provided a number of optional practical expedients. We elected:

the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;

the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and

the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class).

We adopted ASC 842 on January 1, 2019 using the modified retrospective method and, therefore, prior period financial statements were not adjusted. At adoption, we recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The difference between amounts recorded for ROU assets and amounts recorded for lease liabilities totaled $5 million. This amount was recognized as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases.

Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. We adopted this ASU on January 1, 2019. The adoption did not have an impact on our financial statements.

Intangibles—Goodwill and Other—Internal-Use SoftwareIn August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software, to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, ~~2018,~~2019, with early adoption permitted. We ~~are currently evaluating~~early adopted this ASU in second quarter 2019 using the ~~provisions of ASU 2017-12.~~prospective method. The adoption did not have a material impact on our financial statements.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Statements of Operations Information Other statements of operations information is as follows:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,					Six Months Ended June 30,
(millions)	2018			2017			2018			2017			2019		2018			2019		2018
Income From Equity Method Investees and Other
Income from Equity Method Investees	$	49		$	38		$	96		$	80
Sales of Purchased Oil and Gas ⁽¹⁾	66			—			119			—
Other Revenue
Income from Equity Method Investees and Other													$	16	$	49		$	33	$	96
Midstream Services Revenues – Third Party	15			4			28			4			20		15			44		28
Total	$	130		$	42		$	243		$	84		$	36	$	64		$	77	$	124
Production Expense
Lease Operating Expense	$	132		$	124		$	287		$	263		$	122	$	132		$	273	$	287
Production and Ad Valorem Taxes	50			32			104			73			41		50			90		104
Gathering, Transportation and Processing Expense	100			121			195			240			96		98			198		191
Other Royalty Expense	10			6			27			10			1		10			4		27
Total	$	292		$	283		$	613		$	586		$	260	$	290		$	565	$	609
Other Operating Expense, Net
Exploration Expense													$	33	$	29		$	57	$	64
Leasehold Impairment and Amortization	$	—		$	—		$	—		$	18
Seismic, Geological and Geophysical	2			8			13			13
Staff Expense	13			16			27			29
Other	14			6			24			12
Total	$	29		$	30		$	64		$	72
Other Operating Expense, Net
Marketing Expense ⁽²⁾	$	7		$	14		$	12		$	33
Purchased Oil and Gas⁽¹⁾	71			—			128			—
Clayton Williams Energy Acquisition Expenses	—			90			—			94
Marketing Expense													14		9			19		16
Other, Net	(4		)	14			4			20			8		(4		)	28		4
Total	$	74		$	118		$	144		$	147		$	55	$	34		$	104	$	84
Other Non-Operating Expense (Income), Net
Loss on Investment in Shares of Tamar Petroleum Ltd., Net⁽³⁾	$	11		$	—		$	26		$	—
Other	—			(5		)	(2		)	(6		)
Total	$	11		$	(5	)	$	24		$	(6	)

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

⁽¹⁾

As part of the Saddle Butte acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we have entered into certain transactions beginning in first quarter 2018 for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. The cost to purchase natural gas includes transportation expense incurred of $6 million and $11 million for second quarter and the first six months of 2018, respectively. See ~~Note~~ ~~11. Segment Information~~ ~~and~~ ~~Note~~ ~~12. Commitments and Contingencies.~~


⁽²⁾	~~Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.~~


⁽³⁾	Amounts for second quarter and the first six months of 2018 include losses of $11 million and $40 million, respectively, related to the change in fair value. The loss for the six months ended June 30, 2018 is partially offset by dividend income of $14 million. There was no dividend income for second quarter 2018.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Balance Sheet Information Other balance sheet information is as follows:


(millions)	June 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	460		$	455		$	346		$	383
Joint Interest Billings	210			207			153			137
Other	89			103			91			111
Allowance for Doubtful Accounts	(16		)	(17		)	(15		)	(15		)
Total	$	743		$	748		$	575		$	616
Other Current Assets
Commodity Derivative Assets							$	30		$	180
Inventories, Materials and Supplies	$	46		$	66		68			55
Inventories, Crude Oil	27			16
Commodity Derivative Assets	29			2
Assets Held for Sale⁽¹⁾	40			629			—			133
Restricted Cash ⁽²⁾	—			38			132			3
Prepaid Expenses and Other Current Assets	45			29			83			47
Total	$	187		$	780		$	313		$	418
Other Noncurrent Assets
Equity Method Investments ⁽³⁾	$	357		$	305		$	699		$	286
Customer-Related Intangible Assets ⁽⁴⁾	326			—
Investment in Shares of Tamar Petroleum Ltd. ⁽⁵⁾	150			—
Mutual Fund Investments	57			57
Net Deferred Income Tax Asset	25			25
Operating Lease Right-of-Use Assets ⁽⁴⁾							272			—
Customer-Related Intangible Assets, Net ⁽⁵⁾							294			310
Goodwill ⁽⁵⁾							110			110
Other Assets, Noncurrent	69			74			141			135
Total	$	984		$	461		$	1,516		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	111		$	84		$	132		$	103
Commodity Derivative Liabilities	250			58
Income Taxes Payable	5			18
Asset Retirement Obligations	92			51			85			118
Interest Payable	64			67			64			66
Current Portion of Capital Lease Obligations	47			61
Liabilities Associated with Assets Held for Sale ⁽¹⁾	—			55
Compensation and Benefits Payable	66			98
Operating Lease Liabilities ⁽⁴⁾							88			—
Commercial Paper Borrowings							240			—
Partner Advances ⁽²⁾							132			—
Other Liabilities, Current	110			86			257			232
Total	$	745		$	578		$	998		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	180		$	197		$	147		$	147
Asset Retirement Obligations	543			824			707			762
Marcellus Shale Firm Transportation Commitment ⁽⁶⁾	71			76
Operating Lease Liabilities ⁽⁴⁾							190			—
Firm Transportation Exit Cost Accrual ⁽⁶⁾							144			67
Production and Ad Valorem Taxes	39			69			24			83
Commodity Derivative Liabilities	85			15
Other Liabilities, Noncurrent	77			64			95			106
Total	$	995		$	1,245		$	1,307		$	1,165

⁽¹⁾

~~Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin.~~

Assets held for sale at December 31, ~~2017 include assets~~2018 related to the first quarter 2019 divestiture of non-core acreage in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See~~ ~~Note~~ ~~3. Acquisitions and Divestitures~~.


⁽²⁾	~~Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte acquisition.~~Reeves County, Texas. See Note 3.4. Acquisitions and Divestitures.


⁽²⁾	See Partner Advances, above.

⁽³⁾

~~Includes $49~~The 2019 amount includes Noble Midstream Partners' $369 million ~~for our~~ investment in ~~shares of CNX Midstream Partners LP. At December 31, 2017, this~~EPIC Y-Grade, LP (EPIC Y-Grade) and EPIC Crude Holdings and its $39 million investment ~~was included~~ in ~~assets held for sale.~~Delaware Crossing LLC. See Note 3.4. Acquisitions and Divestitures ~~and~~ ~~Note 6. Fair Value Measurements and Disclosures~~.


⁽⁴⁾	~~Amount relates~~Amounts relate to ~~intangible~~ assets ~~acquired~~and liabilities recorded as a result of ASC 842 adoption in ~~the Saddle Butte acquisition and is net of $14 million of accumulated amortization.~~first quarter 2019. See Note ~~3. Acquisitions and Divestitures.~~8. Leases.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

⁽⁵⁾

~~Amount relates~~Amounts relate to ~~our investment~~assets acquired in ~~shares~~the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at June 30, 2019 and December 31, 2018 are net of ~~Tamar Petroleum Ltd.~~ accumulated amortization of $46 million and $30 million, respectively. See Note 3.4. Acquisitions and Divestitures ~~and~~ ~~Note 6. Fair Value Measurements and Disclosures~~.


⁽⁶⁾	Amounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017, we recorded $12 million and $14 million, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note ~~12.~~9. Exit Cost – Transportation Commitments ~~and Contingencies~~.

Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:


	Six Months Ended June 30,				Six Months Ended June 30,
(millions)	2018		2017		2019		2018
Cash and Cash Equivalents at Beginning of Period	$	675	$	1,180	$	716	$	675
Restricted Cash at Beginning of Period	38		30		3		38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	713	$	1,210	$	719	$	713
Cash and Cash Equivalents at End of Period	$	621	$	540	$	470	$	621
Restricted Cash at End of Period	—		—		132		—
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	621	$	540	$	602	$	621

Note 3. ~~Acquisitions and Divestitures~~Segment Information

~~2018 Asset Transactions~~

~~Divestiture of~~We have the following reportable segments: United States (US onshore and Gulf of Mexico ~~Assets~~ ~~On February 15, 2018, we announced that we had signed a definitive agreement~~(until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Canada, New Ventures and Colombia); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners and other US onshore midstream assets.

The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other midstream projects. The chief operating decision maker analyzes income before income taxes to ~~sell~~assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our ~~Gulf of Mexico assets, including all~~operating and financial performance across periods.

Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our ~~interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with~~retained Marcellus Shale firm transportation agreements, are recorded at the ~~assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $168 million during first quarter 2018.~~

In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, we received net proceeds of $383 million and recorded an additional loss of $19 million.

In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of June 30, 2018, no amounts have been accrued related to the contingent payment.

~~Proved reserves associated with these properties totaled approximately 23 MMBoe as of December 31, 2017.~~

~~Divestiture of 7.5% Interest in Tamar Field~~ Corporate level.On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. The transaction had an effective date of January 1, 2018 and after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash.



			Oil and Gas Exploration and Production								Midstream
(millions)	Consolidated		United States		Eastern Mediter-ranean		West Africa		Other Int'l		United States			Intersegment Eliminations and Other ⁽¹⁾			Corporate
Three Months Ended June 30, 2019
Crude Oil Sales	$	688	$	617	$	2	$	69	$	—	$	—		$	—		$	—
NGL Sales	84		84		—		—		—		—			—			—
Natural Gas Sales	182		72		105		5		—		—			—			—
Total Crude Oil, NGL and Natural Gas Sales	954		773		107		74		—		—			—			—
Sales of Purchased Oil and Gas	103		28		—		—		—		52			—			23
Income (Loss) from Equity Method Investees and Other	16		1		—		17		—		(2		)	—			—
Midstream Services Revenues – Third Party	20		—		—		—		—		20			—			—
Intersegment Revenues	—		—		—		—		—		91			(91		)	—
Total Revenues	1,093		802		107		91		—		161			(91		)	23
Lease Operating Expense	122		114		9		10		—		1			(12		)	—
Production and Ad Valorem Taxes	41		40		—		—		—		1			—			—
Gathering, Transportation and Processing Expense	96		124		—		—		—		31			(59		)	—

Our shares of Tamar Petroleum are currently subject to certain temporary lock-up provisions and have no voting rights. Upon subsequent sale of the shares to a third party, the voting rights will be restored and granted to the third party. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares are currently being accounted for at fair value. See
~~Note 6. Fair Value Measurements and Disclosures~~.

Total consideration received was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. In connection with the transaction, we incurred tax expense of $86 million.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

The sale is in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021. We expect to sell the Tamar Petroleum shares before year-end 2021. Proved reserves related to the 7.5% interest totaled approximately 84 MMBoe as of December 31, 2017.



				Oil and Gas Exploration and Production											Midstream
(millions)	Consolidated			United States			Eastern Mediter-ranean		West Africa			Other Int'l			United States			Intersegment Eliminations and Other ⁽¹⁾			Corporate
Other Royalty Expense	1			1			—		—			—			—			—			—
Total Production Expense	260			279			9		10			—			33			(71		)	—
Depreciation, Depletion and Amortization	528			457			17		19			—			26			(6		)	15
Cost of Purchased Oil and Gas	113			28			—		—			—			48			—			37
Gain on Commodity Derivative Instruments	(60		)	(58		)	—		(2		)	—			—			—			—
Income (Loss) Before Income Taxes	28			70			65		59			(15		)	46			(15		)	(182		)
Additions to Long-Lived Assets, Excluding Acquisitions	647			478			119		12			2			52			(25		)	9
Investments in Equity Method Investees	144			—			—		—			—			144			—			—
Three Months Ended June 30, 2018
Crude Oil Sales	$	749		$	635		$	2	$	112		$	—		$	—		$	—		$	—
NGL Sales	137			137			—		—			—			—			—			—
Natural Gas Sales	214			98			111		5			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,100			870			113		117			—			—			—			—
Sales of Purchased Oil and Gas	66			—			—		—			—			42			—			24
Income from Equity Method Investees and Other	49			—			—		36			—			13			—			—
Midstream Services Revenues – Third Party	15			—			—		—			—			15			—			—
Intersegment Revenues	—			—			—		—			—			85			(85		)	—
Total Revenues	1,230			870			113		153			—			155			(85		)	24
Lease Operating Expense	132			114			5		19			—			—			(6		)	—
Production and Ad Valorem Taxes	50			48			—		—			—			2			—			—
Gathering, Transportation and Processing Expense	98			131			—		—			—			22			(55		)	—
Other Royalty Expense	10			10			—		—			—			—			—			—
Total Production Expense	290			303			5		19			—			24			(61		)	—
Depreciation, Depletion and Amortization	465			394			15		26			—			22			(4		)	12
(Gain) Loss on Divestitures, Net	(78		)	21			10		—			—			(109		)	—			—
Cost of Purchased Oil and Gas	71			—			—		—			—			40			—			31
Loss on Commodity Derivative Instruments	249			196			—		53			—			—			—			—
Income (Loss) Before Income Taxes	10			(90		)	62		48			(13		)	175			(18		)	(154		)
Additions to Long-Lived Assets, Excluding Acquisitions	935			561			216		3			—			155			(18		)	18
Six Months Ended June 30, 2019
Crude Oil Sales	$	1,300		$	1,162		$	3	$	135		$	—		$	—		$	—		$	—
NGL Sales	180			180			—		—			—			—			—			—
Natural Gas Sales	411			180			222		9			—			—			—			—

~~Divestiture of Southwest Royalties~~
In January 2018, we closed the sale of our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.

~~Divestiture of Marcellus Shale CONE Gathering~~ In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million.

After the sale, we continued to hold 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million of the common units, receiving net proceeds of approximately $135 million, net of underwriting fees, and recognized a gain of $109 million. As of June 30, 2018, we continue to hold 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners and account for the investment under equity method accounting.

~~Noble Midstream Partners Saddle Butte Acquisition~~ On January 31, 2018, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system.

Consideration totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity.

We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $111 million to implied goodwill. The purchase price allocation is preliminary as certain data necessary to complete the purchase price allocation is not yet available, such as analysis of the final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.

~~Other Divestitures~~ ~~During the first six months of 2018, we also closed the sale of certain other smaller US onshore properties and received total cash consideration of $12 million, recording a gain of $4 million.~~

~~2017 Asset Transactions~~

~~Delaware Basin Acquisition~~ During the first six months of 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold costs. The acquisition included interests in seven producing wells, four of which are operated by us.

~~Clayton Williams Energy Acquisition~~ On April 24, 2017, we completed the Clayton Williams Energy Acquisition. The acquisition was effected through the issuance of 56 million shares of Noble Energy common stock, with a fair value of $1.9 billion, and cash consideration of $637 million, for total consideration of $2.5 billion, in exchange for all of the outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.

The transaction was accounted for as a business combination using the acquisition method. The following table represents the final allocation of the total purchase price of Clayton Williams Energy to the assets acquired and liabilities assumed, based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable ne

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

~~t assets acquired recorded as goodwill.~~

(millions)
Fair Value of Common Stock Issued $ 1,851
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637
Total Purchase Price $ 2,488
Plus Liabilities Assumed by Noble Energy:
Accounts Payable 99
Other Current Liabilities 38
Long-Term Deferred Tax Liability 515
Long-Term Debt 595
Asset Retirement Obligations 63
Total Purchase Price Plus Liabilities Assumed $ 3,798

~~The fair value of Clayton Williams Energy's identifiable assets was as follows:~~

(millions)
Cash and Cash Equivalents $ 21
Other Current Assets 70
Oil and Gas Properties:
Proved Reserves 722
Undeveloped Leasehold Costs 1,571
Gathering and Processing Assets 48
Asset Retirement Costs 63
Other Noncurrent Assets 12
Implied Goodwill 1,291
Total Asset Value $ 3,798



				Oil and Gas Exploration and Production										Midstream
(millions)	Consolidated			United States			Eastern Mediter-ranean		West Africa		Other Int'l			United States		Intersegment Eliminations and Other ⁽¹⁾			Corporate
Total Crude Oil, NGL and Natural Gas Sales	1,891			1,522			225		144		—			—		—			—
Sales of Purchased Oil and Gas	177			42			—		—		—			85		—			50
Income from Equity Method Investees and Other	33			1			—		32		—			—		—			—
Midstream Services Revenues – Third Party	44			—			—		—		—			44		—			—
Intersegment Revenues	—			—			—		—		—			197		(197		)
Total Revenues	2,145			1,565			225		176		—			326		(197		)	50
Lease Operating Expense	273			239			19		34		—			2		(21		)	—
Production and Ad Valorem Taxes	90			87			—		—		—			3		—			—
Gathering, Transportation and Processing Expense	198			266			—		—		—			60		(128		)	—
Other Royalty Expense	4			4			—		—		—			—		—			—
Total Production Expense	565			596			19		34		—			65		(149		)	—
Depreciation, Depletion and Amortization	1,036			896			33		39		—			51		(13		)	30
Cost of Purchased Oil and Gas	200			42			—		—		—			79		—			79
Firm Transportation Exit Cost	92			—			—		—		—			—		—			92
Loss on Commodity Derivative Instruments	152			130			—		22		—			—		—			—
(Loss) Income Before Income Taxes	(345		)	(177		)	149		70		(31		)	119		(29		)	(446		)
Additions to Long-Lived Assets, Excluding Acquisitions	1,359			990			251		18		12			118		(48		)	18
Investments in Equity Method Investees	415			—			—		—		—			415		—			—
Six Months Ended June 30, 2018
Crude Oil Sales	$	1,522		$	1,317		$	4	$	201	$	—		$	—	$	—		$	—
NGL Sales	283			283			—		—		—			—		—			—
Natural Gas Sales	468			218			240		10		—			—		—			—
Total Crude Oil, NGL and Natural Gas Sales	2,273			1,818			244		211		—			—		—			—
Sales of Purchased Oil and Gas	119			—			—		—		—			64		—			55
Income from Equity Method Investees and Other	96			—			—		71		—			25		—			—
Midstream Services Revenues – Third Party	28			—			—		—		—			28		—			—
Intersegment Revenues	—			—			—		—		—			166		(166		)	—
Total Revenues	2,516			1,818			244		282		—			283		(166		)	55
Lease Operating Expense	287			240			12		41		—			—		(6		)	—
Production and Ad Valorem Taxes	104			101			—		—		—			3		—			—
Gathering, Transportation and Processing Expense	191			256			—		—		—			43		(108		)	—
Other Royalty Expense	27			27			—		—		—			—		—			—
Total Production Expense	609			624			12		41		—			46		(114		)	—

In connection with the acquisition, we assumed, and then subsequently retired in second quarter 2017, all of Clayton Williams Energy's long-term debt at a cost of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.

The fair value measurements of crude oil and natural gas properties and asset retirement obligations were based on inputs that are not observable in the market and, therefore, represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and were the most sensitive.

~~Based upon the final purchase price allocation, we recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit.~~

The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2017. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including: (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.

The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisitio

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)



				Oil and Gas Exploration and Production											Midstream
(millions)	Consolidated			United States			Eastern Mediter-ranean			West Africa		Other Int'l			United States			Intersegment Eliminations and Other ⁽¹⁾			Corporate
Depreciation, Depletion and Amortization	933			800			28			52		—			38			(8		)	23
(Gain) Loss on Divestitures, Net	(666		)	15			(376		)	—		—			(305		)	—			—
Asset Impairments	168			168			—			—		—			—			—			—
Cost of Purchased Oil and Gas	128			—			—			—		—			61			—			67
Loss on Commodity Derivative Instruments	328			260			—			68		—			—			—			—
Income (Loss) Before Income Taxes	553			(127		)	535			112		(27		)	428			(40		)	(328		)
Additions to Long-Lived Assets, Excluding Acquisitions	1,840			1,095			363			5		2			397			(50		)	28
June 30, 2019
Property, Plant and Equipment, Net	$	18,775		$	13,095		$	2,879		$	773	$	36		$	1,841		$	(185	)	$	336
December 31, 2018
Property, Plant and Equipment, Net	$	18,419		$	13,044		$	2,630		$	805	$	37		$	1,742		$	(145	)	$	306

~~n taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.~~

Three Months Ended June 30, Six Months Ended June 30,
(millions, except per share amounts)
2018 ⁽¹⁾
2017
2018⁽¹⁾
2017
Revenues $ 1,230
$ 1,070
$ 2,516
$ 2,141
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy (23 ) (1,354 ) 531
(1,324 )

Net (Loss) Income Attributable to Noble Energy per Common Share
Basic $ (0.05 ) $ (2.77 ) $ 1.09
$ (2.71 )
Diluted $ (0.05 ) $ (2.77 ) $ 1.09
$ (2.71 )

⁽¹⁾

~~No pro forma adjustments were made for~~The intersegment eliminations related to income before income taxes are the ~~period~~result of midstream expenditures. These costs are presented as ~~Clayton Williams Energy operations~~property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are ~~included in our historical results.~~eliminated upon consolidation.

~~Marcellus Shale Upstream Divestiture~~ On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The purchase price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The purchase price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. No amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See ~~Note 5. Debt~~.

In second quarter 2017, we recognized a total loss of $2.3 billion, or $1.5 billion after-tax, on this transaction. The aggregate net book value of the properties prior to the sale was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.

~~As part of the total loss, we recorded a charge of $41 million, discounted, relating to a retained transportation contract. See~~ ~~Note 12. Commitments and Contingencies~~.

During second quarter 2017, production from the Marcellus Shale upstream assets totaled 393 MMcfe/d. With the closing of the sale, we recorded a decrease in net proved reserves of approximately 241 MMBoe, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves.

~~Noble Midstream Partners Asset Contribution~~ On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy for $270 million.

Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.

The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.

~~Noble Midstream Partners Advantage Acquisition~~ On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed $66.5 million of cash to the joint venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. Noble Midstream Partners serves as the operator of the Advantage Pipeline system, which includes a crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Note 4. ~~Derivative Instruments~~Acquisitions and ~~Hedging Activities~~Divestitures

~~Objective~~We maintain an ongoing portfolio management program and ~~Strategies for Using Derivative Instruments~~have engaged in various transactions over recent years.

2019 Asset Transactions

Divestiture of Reeves County Assets In February 2019, we closed the sale of certain proved and unproved non-core acreage in the Delaware Basin totaling approximately 13,000 net acres in Reeves County, Texas. We ~~are exposed~~received cash consideration of approximately $131 million, recognizing no gain or loss on the sale.

EPIC Pipeline Investments In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to ~~fluctuations~~acquire a 15% equity interest in EPIC Y-Grade, which is constructing the EPIC Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil ~~natural gas~~pipeline also from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million. In second quarter 2019, Noble Midstream Partners made additional capital contributions of $28 million and ~~NGL pricing. In order~~$114 million to ~~mitigate~~EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.

~~While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.~~equity method. See Note 2. Basis of Presentation~~6. Fair Value Measurements and Disclosures~~ ~~for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.~~.

~~Unsettled Commodity Derivative Instruments~~Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. For the first six months of 2019, Noble Midstream Partners made capital contributions of $39 million for construction of the pipeline. This investment is accounted for using the equity method.

2018 Asset Transactions

Divestiture of Gulf of Mexico Assets In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of ~~June 30,~~March 31, 2018, we reduced the ~~following crude oil derivative contracts~~net book value of the Gulf of Mexico assets to $480 million. In addition, we retained certain transaction related obligations approximating $92 million which were ~~outstanding:~~

Swaps Collars
Settlement
Period
Type of Contract Index
Bbls Per
Day
Weighted Average Differential
Weighted
Average
Fixed
Price

Weighted
Average
Short Put
Price
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2018 Swaps NYMEX WTI 66,000 $ —
$ 60.30
$ —
$ —
$ —
2018 Collars NYMEX WTI 18,000 —
—
—
50.42
58.82
2018 Three-Way Collars NYMEX WTI 10,000 —
—
45.50
52.50
69.09
2018 Three-Way Collars Dated Brent 3,000 —
—
40.00
50.00
70.41
2018 Swaps ICE Brent 2,000 —
59.00
—
—
—
2018 Collars ICE Brent 2,000 —
—
—
50.00
55.25
2018 Three-Way Collars ICE Brent 5,000 —
—
43.00
50.00
59.50
2018 Basis Swaps
⁽¹⁾
20,000 (2.30 ) —
—
—
—
2019 Swaps NYMEX WTI 44,000 —
58.37
—
—
—
2019 Three-Way Collars NYMEX WTI 6,000 —
—
50.00
60.00
72.75
2019 Swaps ICE Brent 5,000 —
57.00
—
—
—
2019 Three-Way Collars ICE Brent 3,000 —
—
43.00
50.00
64.07
2019 Basis Swaps
⁽¹⁾
27,000 (3.23 ) —
—
—
—
2020
Swaption ⁽²⁾
NYMEX WTI 5,000 —
61.79
—
—
—
2020 Basis Swaps
⁽¹⁾
15,000 (5.01 ) —
—
—
—

⁽¹⁾subsequently settled upon closing. During first quarter 2018, we recorded impairment expense of $168 million associated with these assets held for sale. The transaction closed in second quarter 2018. We ~~have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas,~~received net proceeds of $383 million and ~~Cushing, Oklahoma. The weighted average differential represents the amount~~recorded an additional loss of ~~reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.~~

⁽²⁾~~We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~As of June 30, 2018, the following natural gas derivative contracts were outstanding:~~

Swaps Collars
Settlement
Period
Type of Contract Index
MMBtu
Per Day
Weighted
Average
Fixed
Price

Weighted
Average
Short Put
Price
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2018 Three-Way Collars NYMEX HH 120,000
$ —
$ 2.50
$ 2.88
$ 3.65

~~Fair Value Amounts and Loss (Gain) on Commodity Derivative InstrumentsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows:~~

Fair Value of Derivative Instruments
Asset Derivative Instruments Liability Derivative Instruments
June 30,
2018 December 31,
2017 June 30,
2018 December 31,
2017
(millions) Balance Sheet Location
Fair
Value
Balance Sheet Location
Fair
Value
Balance Sheet Location
Fair
Value
Balance Sheet Location
Fair
Value
Commodity Derivative Instruments
Current Assets $ 29
Current Assets $ 2
Current Liabilities $ 250
Current Liabilities $ 58
Noncurrent Assets —
Noncurrent Assets —
Noncurrent Liabilities 85
Noncurrent Liabilities 15
Total $ 29
$ 2
$ 335
$ 73

~~The effect of commodity derivative instruments on our consolidated statements of operations was as follows:~~

Three Months Ended June 30, Six Months Ended June 30,
(millions) 2018 2017 2018 2017
Cash Paid (Received) in Settlement of Commodity Derivative Instruments
Crude Oil $ 66
$ (11 ) $ 96
$ (16 )
Natural Gas (1 ) —
(3 ) 2
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments 65
(11 ) 93
(14 )
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
Crude Oil 181
(28 ) 231
(91 )
Natural Gas 3
(18 ) 4
(62 )
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 184
(46 ) 235
(153 )
Loss (Gain) on Commodity Derivative Instruments
Crude Oil 247
(39 ) 327
(107 )
Natural Gas 2
(18 ) 1
(60 )
Total Loss (Gain) on Commodity Derivative Instruments $ 249
$ (57 ) $ 328
$ (167 )

$19 million.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

~~Note 5. Debt~~

~~Debt consists~~Divestiture of ~~the following:~~

June 30,
2018 December 31,
2017
(millions, except percentages) Debt Interest Rate
Debt Interest Rate
Revolving Credit Facility, due March 9, 2023 $ —
— % $ 230
2.27 %
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 530
3.25 % 85
2.75 %
Leviathan Term Loan Facility, due February 23, 2025 —
— % —
— %
Senior Notes, due May 1, 2021 ⁽¹⁾
—
— % 379
5.63 %
Senior Notes, due December 15, 2021 1,000
4.15 % 1,000
4.15 %
Senior Notes, due October 15, 2023 100
7.25 % 100
7.25 %
Senior Notes, due November 15, 2024 650
3.90 % 650
3.90 %
Senior Notes, due April 1, 2027 250
8.00 % 250
8.00 %
Senior Notes, due January 15, 2028 600
3.85 % 600
3.85 %
Senior Notes, due March 1, 2041 850
6.00 % 850
6.00 %
Senior Notes, due November 15, 2043 1,000
5.25 % 1,000
5.25 %
Senior Notes, due November 15, 2044 850
5.05 % 850
5.05 %
Senior Notes, due August 15, 2047 500
4.95 % 500
4.95 %
Other Senior Notes and Debentures ⁽²⁾
92
7.13 % 92
7.13 %
Capital Lease Obligations 241
— % 273
— %
Total 6,663
6,859

Unamortized Discount (23 ) (24 )
Unamortized Premium ⁽¹⁾
—
12

Unamortized Debt Issuance Costs (38 ) (40 )
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 6,602
6,807

Less Amounts Due Within One Year
Capital Lease Obligations (47 ) (61 )
Long-Term Debt Due After One Year $ 6,555
$ 6,746

⁽¹⁾7.5% Interest in Tamar Field In ~~second quarter~~March 2018, we ~~redeemed all~~closed the sale of ~~the Senior Notes due May 1, 2021, writing off the associated premium. See Redemption of Senior Notes, below.~~

⁽²⁾~~Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average~~a 7.5% working interest ~~rate for these instruments is 7.13%.~~

~~Revolving Credit Facility~~ Our Credit Agreement, as amended, provides for a $4 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility.

In first quarter 2018, we extended the maturity date of the Revolving Credit Facility from August 2020 to March 2023. As of June 30, 2018, no borrowings were outstanding under the Revolving Credit Facility.

~~Noble Midstream Services Revolving Credit Facility~~Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, maintains a revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.

~~In first quarter 2018, the facility capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023.~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the ~~case of base rate borrowings, a rate equal~~Tamar field to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

As of June 30, 2018, $530 million was outstanding under the Noble Midstream Services Revolving Credit Facility. The increase from December 31, 2017 was primarily used to fund the Saddle Butte acquisition, as well as construction activities. See ~~Note 3. Acquisitions and Divestitures~~.

~~Leviathan Term Loan Agreement~~ ~~On February 24, 2017, Noble Energy Mediterranean~~Tamar Petroleum Ltd. ~~(NEML)~~, a wholly owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, $625 million of which is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel.

Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025, and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.

Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period.

The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries. As of June 30, 2018, there were no borrowings under the Leviathan Term Loan Facility.

~~See~~ ~~Note~~ ~~6. Fair Value Measurements and Disclosures~~ ~~for a discussion of methods and assumptions used to estimate the fair values of debt.~~

~~Redemption of Senior Notes~~ In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger (Rosetta Merger) with Rosetta Resources, Inc. in 2015 for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium and recognized a gain of $5 million, which is reflected in other non-operating (income) expense in our consolidated statements of operations.

~~Annual Debt Maturities~~ Our nearest annual maturity of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, is $1.0 billion of senior notes which mature in 2021. The Revolving Credit Facility and Noble Midstream Services Revolving Credit Facility both mature in March 2023. No other balances are due within the next five years.

~~Subsequent Event - Noble Midstream Services Term Credit Agreement~~ On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) that permits aggregate borrowings of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries.

Borrowings under the Noble Midstream Services Term Credit Agreement will bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum.

The Noble Midstream Services Term Credit Agreement contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Services Term Credit Agreement, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Credit Agreement to be immediately due and payable and exercise other remedies as provided by applicable law.

~~Note 6. Fair Value Measurements and Disclosures~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:~~

~~Cash, Cash Equivalents, Accounts Receivable and Accounts Payable~~ ~~The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.~~

~~Mutual Fund Investments~~ Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.

~~Commodity Derivative Instruments~~ Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See~~Note~~ ~~4. Derivative Instruments and Hedging Activities~~.

~~Investment in Tamar Petroleum Ltd~~ ~~Our investment in shares of Tamar Petroleum was acquired on March 14, 2018. The fair value of these shares is determined at the end of each quarter based on the trading price of Tamar Petroleum shares~~publicly traded entity on the Tel Aviv Stock Exchange (Tamar Petroleum, TASE: TMRP). Total consideration included cash of $484 million and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $386 million and tax expense of $90 million.

In October 2018, we sold our shares in Tamar Petroleum for pre-tax proceeds of $163 million, net of transaction expenses. The sale was in accordance with the Israel Natural Gas Framework and completed our obligation to reduce ownership interest in the Tamar field from 32.5% to 25% by year end-2021.

Divestiture of Southwest Royalties In January 2018, we closed the sale of our investment in Southwest Royalties, Inc. We received proceeds of $60 million, recognizing no gain or loss on the sale.

Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million.

After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million common units, receiving net proceeds of $135 million, net of underwriting fees, and recognized a gain of $109 million. During third quarter 2018, we sold the remaining 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners, receiving proceeds net of underwriting fees of approximately $248 million, and recognized a gain of $198 million.

Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owns a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is ~~reduced by~~consolidated as a ~~15% discount.~~VIE.

We accounted for the transaction as a business combination using the acquisition method. The ~~discount rate is~~total purchase price was allocated to assets acquired and liabilities assumed based on ~~analysis of historical discounts realized in private placements of public common stock, which~~acquisition date fair values, and we ~~believe represents a reasonable estimate~~recognized goodwill for the amount of the ~~impact of the temporary lock-up provisions applicable to the shares we own. See~~ ~~Note 2. Basis of Presentation~~ ~~and~~ ~~Note~~ ~~3. Acquisitions and Divestitures.~~

~~Deferred Compensation LiabilityThe value is dependent upon~~purchase price exceeding the fair values of ~~mutual fund investments~~the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and ~~shares of our common stock held in a rabbi trust.~~equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.

Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

Capitalized Exploratory Well Costs ~~See~~ We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.

There were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:



(millions, except number of projects)	June 30, 2019		December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	11	$	6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	351		348
Capitalized Exploratory Well Costs, End of Period	$	362	$	354
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	7		7

~~Mutual Fund Investments~~ ~~above~~.

~~Stock-Based Compensation Liability~~Undeveloped Leasehold Costs ~~A portion~~Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the ~~value~~other hand, if, based upon a change in exploration plans, timing and extent of ~~the liability associated with our phantom unit plan is dependent upon the fair value~~development activities, availability of ~~Noble Energy common stock as of the end of each reporting period.~~capital and suitable rig and drilling

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

~~Measurement information for assets~~equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record exploration expense related to the respective leases or licenses.

Changes in undeveloped leasehold costs were as follows:



(millions)	Six Months Ended June 30, 2019
Undeveloped Leasehold Costs, Beginning of Period	$	2,306
Additions to Undeveloped Leasehold Costs	50
Transfers to Proved Properties	(11		)
Assets Sold	(2		)
Undeveloped Leasehold Costs, End of Period	$	2,343

As of June 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $73 million, and ~~liabilities~~$59 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are ~~measured at fair value on a recurring basis was as follows:~~

Fair Value Measurements Using
(millions)
Quoted Prices in
Active Markets
(Level 1) ⁽¹⁾

Significant Other
Observable Inputs
(Level 2) ⁽²⁾

Significant
Unobservable
Inputs (Level 3) ⁽³⁾

Adjustment ⁽⁴⁾
Fair Value Measurement
June 30, 2018
Financial Assets:
Mutual Fund Investments $ 57
$ —
$ —
$ —
$ 57
Commodity Derivative Instruments —
72
—
(43 ) 29
Investment in Tamar Petroleum Ltd. (38,495,575 Shares)⁽⁵⁾
—
150
—
—
150
Financial Liabilities:
Commodity Derivative Instruments —
(378 ) —
43
(335 )
Portion of Deferred Compensation Liability Measured at Fair Value (73 ) —
—
—
(73 )
Stock Based Compensation Liability Measured at Fair Value (12 ) —
—
—
(12 )
December 31, 2017
Financial Assets:
Mutual Fund Investments $ 57
$ —
$ —
$ —
$ 57
Commodity Derivative Instruments —
7
—
(5 ) 2
Financial Liabilities:
Commodity Derivative Instruments —
(78 ) —
5
(73 )
Portion of Deferred Compensation Liability Measured at Fair Value (71 ) —
—
—
(71 )
Stock Based Compensation Liability Measured at Fair Value (10 ) —
—
—
(10 )


⁽¹⁾	Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.


⁽²⁾	~~Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.~~


⁽³⁾	~~Level 3 measurements are fair value measurements which use unobservable inputs.~~


⁽⁴⁾	~~Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.~~


⁽⁵⁾	~~As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 per share.~~

~~Noble Energy, Inc.~~

~~Notes~~subject to ~~Consolidated Financial Statements (Unaudited)~~

~~Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis~~

Certain assets and liabilities such, as oil and gas properties, goodwill and other intangible assets, are not required to be measured at fair value on a recurring basis. However, these assets are assessed for impairment, and a resulting asset impairment would requireexpiration over the ~~asset be recorded at fair value.~~

~~Asset Impairments~~ ~~During first quarter 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized an impairment of $168 million. See~~ ~~Note 3. Acquisitions and Divestitures. For second quarter 2018 and the first six months of 2017, we had no adjustments in fair value related to oil and gas properties.~~

~~Additional Fair Value Disclosures~~

~~Investment in CNX Midstream Partners~~ ~~Our investment in CNX Midstream Partners, which~~next several years unless production is ~~included in our Midstream reportable segment, is accounted for using the equity method. The fair value of the investment is based~~established on the ~~published market price of the common units for the date indicated below.~~

June 30, 2018 December 31, 2017
(millions) Carrying Amount Fair Value Carrying Amount Fair Value
Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) ⁽¹⁾
$ 49
$ 276
$ 70
$ 364


⁽¹⁾	~~During second quarter 2018, we sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See~~ ~~Note 3. Acquisitions and Divestitures~~.

~~Debt~~ ~~The fair value of fixed-rate, public debt~~acreage. Other costs pertain to acreage that is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.

Our Revolving Credit Facility, the Noble Midstream Services Revolving Credit Facility and the Leviathan Term Loan Facility are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See ~~Note~~ ~~5. Debt~~.

~~Fair value information regarding our debt is as follows:~~

June 30, 2018 December 31, 2017
(millions) Carrying Amount Fair Value Carrying Amount Fair Value
Long-Term Debt ⁽¹⁾
$ 6,422
$ 6,591
$ 6,586
$ 7,142


⁽¹⁾	~~Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.~~

being held by production.

Note ~~7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs~~

~~Capitalized Exploratory Well Costs~~We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.

~~Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:~~

(millions) Six Months Ended June 30, 2018
Capitalized Exploratory Well Costs, Beginning of Period $ 520
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 4
Divestitures ⁽¹⁾
(167 )
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1 )
Capitalized Exploratory Well Costs Charged to Expense —
Capitalized Exploratory Well Costs, End of Period $ 356

⁽¹⁾ ~~Represents costs primarily related to Gulf of Mexico assets.~~

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:~~

(millions) June 30,
2018 December 31,
2017
Exploratory Well Costs Capitalized for a Period of One Year or Less $ 8
$ 10
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 348
510
Balance at End of Period $ 356
$ 520
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7
8

~~Undeveloped Leasehold Costs~~ We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses.

As of June 30, 2018, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $2.6 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $859 million and $129 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing.

The remaining balance of undeveloped leasehold costs as of June 30, 2018 included $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.

During the first half of 2018, we transferred $247 million and $20 million of undeveloped leasehold costs associated with Delaware Basin and Eagle Ford Shale assets, respectively, to proved properties. These transfers resulted from additions of proved reserves through development activities. In addition, $43 million of capitalized costs associated with Gulf of Mexico leases and licenses was removed from undeveloped leasehold costs due to divestiture of the associated assets in second quarter 2018. See ~~Note 3. Acquisitions and Divestitures~~.

~~Note 8.~~6. Asset Retirement Obligations

Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:


	Six Months Ended June 30,						Six Months Ended June 30,
(millions)	2018			2017			2019			2018
Asset Retirement Obligations, Beginning Balance	$	875		$	935		$	880		$	875
Liabilities Incurred	14			82			15			14
Liabilities Settled	(261		)	(32		)	(56		)	(261		)
Revisions of Estimates	(10		)	(15		)	(70		)	(10		)
Accretion Expense ⁽¹⁾	17			23			23			17
Asset Retirement Obligations, Ending Balance	$	635		$	993		$	792		$	635

Six Months Ended June 30, 2019 Liabilities settled relate to abandonment of US onshore properties, primarily in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates relate primarily to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells.

⁽¹⁾

~~Accretion expense is included in depreciation, depletion and amortization (DD&A)expense in the consolidated statements ofoperations.~~

~~For the~~ Six Months Ended June 30, 2018 Liabilities settled include $216 million of liabilities assumed by the purchaser of the Gulf of Mexico ~~properties~~assets and $44 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily ~~relate~~ to decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean, partially offset by an increase ~~of $7 million for US onshore.~~

~~For theSix Months Ended June 30, 2017~~ Liabilities incurred include $59 million related to the Clayton Williams Energy Acquisition and $23 million primarily for other US onshore wells and facilities placed into service. Liabilities settled primarily related to US onshore property abandonments, as well as $12 million related to properties sold in the Marcellus Shale upstream divestiture. Revisions of estimates related to decreases in cost and timing estimates of ~~$30~~$7 million for US ~~onshore and Gulf of Mexico, partially offset by an increase of $15 million for West Africa.~~onshore.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 7. Debt

Debt consists of the following:



	June 30, 2019					December 31, 2018
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate
Noble Energy, Excluding Noble Midstream Partners
Revolving Credit Facility, due March 9, 2023	$	—		—	%	$	—		—	%
Commercial Paper Borrowings	240			⁽¹	⁾	—			—	%
Senior Notes and Debentures	5,884			⁽²	⁾	5,892			⁽²	⁾
Finance Lease Obligations	211			—	%	223			—	%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt	6,335					6,115
Noble Midstream Partners
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 ⁽³⁾	370			3.77	%	60			3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500			3.51	%	500			3.42	%
Total Noble Midstream Partners Debt	870					560
Total Debt	7,205					6,675
Net Unamortized Discounts and Debt Issuance Costs	(58		)			(60		)
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs	7,147					6,615
Less Amounts Due Within One Year
Commercial Paper Borrowings	(240		)			—
Finance Lease Obligations	(41		)			(41		)
Long-Term Debt Due After One Year	$	6,866				$	6,574


⁽¹⁾	As of June 30, 2019, the weighted average interest rate for outstanding commercial paper was 3.04%.


⁽²⁾	As of June 30, 2019 and December 31, 2018, the Senior Notes and Debentures had weighted average interest rates of 5.00% and 5.01%, respectively.


⁽³⁾	As of June 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity. Amounts available for borrowing totaled $430 million and $740 million, respectively.

Commercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and notes are either issued at a discounted price relative to the principal face value or bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest rates are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. At June 30, 2019, outstanding commercial paper borrowings totaled $240 million, leaving $3.8 billion available for borrowing under our $4.0 billion Revolving Credit Facility.

Redemption of Senior Notes In June 2019, we redeemed $8 million of Senior Notes due June 1, 2024 that we assumed in the 2015 merger with Rosetta Resources, Inc. for approximately $9 million, including call premium and interest.

Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures.

Note 8. Leases

In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases include primarily office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Balance Sheet Information ROU assets and lease liabilities are as follows:



(millions)	Balance Sheet Location	June 30, 2019
ROU Assets
Operating Leases ⁽¹⁾	Other Noncurrent Assets	$	272
Finance Leases ⁽²⁾	Total Property, Plant and Equipment, Net	175
Total ROU Assets		$	447
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	88
Finance Leases	Other Current Liabilities	41
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	190
Finance Leases	Long-Term Debt	170
Total Lease Liabilities		$	489


⁽¹⁾	Operating lease ROU assets include primarily office space of $117 million, compressors of $88 million, and drilling rigs of $35 million.


⁽²⁾	Finance lease ROU assets include primarily office space of $94 million, net of accumulated amortization.

Statement of Operations Information The components of lease cost are as follows:



(millions)	Statement of Operations Location	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating Lease Cost	⁽¹⁾	$	26		$	51
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	9			17
Interest Expense	Interest, Net of Amount Capitalized	4			7
Short-term Lease Cost ⁽²⁾	⁽¹⁾	143			269
Variable Lease Cost ⁽³⁾	⁽¹⁾	—			—
Sublease Income	General and Administrative	(1		)	(2		)
Total Lease Cost		$	181		$	342


⁽¹⁾	Cost classification varies depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred, as part of oil and gas properties on our consolidated balance sheet.


⁽²⁾	Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less.


⁽³⁾	Variable lease costs were de minimis for second quarter and the first six months of 2019.

Cash Flow Information Supplemental cash flow information is as follows:



	Six Months Ended June 30, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	30	$	6
Financing Cash Flows	—		20
Investing Cash Flows	18		—
ROU Assets Obtained in Exchange for Lease Liabilities ⁽¹⁾	58		8


⁽¹⁾	Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Maturity of Lease Liabilities Maturities of lease liabilities as of June 30, 2019 are as follows:



(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	50	$	25	$	75
2020	85		48		133
2021	48		33		81
2022	33		23		56
2023	21		21		42
2024 and Thereafter	80		105		185
Total Lease Liabilities, Undiscounted	317		255		572
Less: Imputed Interest	39		44		83
Total Lease Liabilities ⁽¹⁾	$	278	$	211	$	489


⁽¹⁾	Includes the current portions of $88 million and $41 million for operating and finance leases, respectively.

Lease commitments as of December 31, 2018 were as follows:



(millions)	Operating Leases		Finance Leases		Total
2019	$	91	$	52	$	143
2020	74		46		120
2021	59		31		90
2022	62		22		84
2023	50		20		70
2024 and Thereafter	176		104		280
Total Lease Liabilities, Undiscounted	$	512	$	275	$	787

Other Information Other information related to our leases is as follows:



	June 30, 2019
Weighted-Average Remaining Lease Term
Operating Leases	5.9 years
Finance Leases	7.9 years
Weighted-Average Discount Rate
Operating Leases	4.40	%
Finance Leases	5.01	%

Note 9. Exit Cost – Transportation Commitments

In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas.

Since closing, we have continued efforts to commercialize these firm transportation commitments, including permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractual commitment is reduced. In the event we execute a capacity release or utilize capacity through the purchase and transport of natural gas, we remain the primary obligor to the pipeline company. While our gross contractual commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties.

As of June 30, 2019, our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately three to fourteen years, is approximately $1.0 billion, undiscounted.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Leach Xpress and Rayne Xpress Permanent Assignment In January2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign remaining capacity to a third-party effective January 1, 2021, extending through the end of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million, undiscounted. As a result of the assignment, we recorded firm transportation exit cost of $92 million, discounted, related to future commitments to the third party. We will continue efforts to mitigate the impact of these transportation agreements during 2019 and 2020.

Financial Statement Impact In addition to the retained firm transportation commitments, we have the following accrued discounted liabilities associated with exit cost activities, including the permanent assignment described above:



	Six Months Ended June 30,
(millions)	2019			2018
Balance at Beginning of Period ⁽¹⁾	$	80		$	90
Firm Transportation Exit Cost Accrual	92			—
Payments, Net of Accretion	(5		)	(7		)
Balance at End of Period	167			83
Less: Current Portion Included in Other Current Liabilities	23			12
Long-term Portion Included in Other Noncurrent Liabilities	$	144		$	71


⁽¹⁾	Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets.

Revenues and expenses associated with capacity release agreements and purchases and sales of natural gas are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2019		2018		2019		2018
Sales of Purchased Gas ⁽¹⁾	$	23	$	24	$	50	$	55
Cost of Purchased Gas and Related Expense
Cost of Purchased of Gas	22		23		49		53
Utilized Firm Transportation Expense ⁽²⁾	15		6		30		11
Unutilized Firm Transportation Expense	—		2		—		3
Cost of Purchased Gas and Related Expense, Total ⁽³⁾	$	37	$	31	$	79	$	67


⁽¹⁾	Amounts are included in sales of purchased oil and gas within our statements of operations.


⁽²⁾	Includes the net impact of the difference in the firm transportation contract rates and rates agreed to in the capacity releases, as well as transportation expenses associated with transport of purchased natural gas.


⁽³⁾	Amounts are included in cost of purchased oil and gas within our statements of operations.

Note 10. Commitments and Contingencies

Legal ProceedingsWe are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) requesting an opportunity to discuss settlement of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 9.11. Income Taxes

~~The income~~Income tax expense (benefit) ~~expense~~ consists of the following:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(millions, except percentages)	2018			2017			2018			2017			2019			2018			2019			2018
Current	$	23		$	37		$	149		$	49		$	21		$	23		$	37		$	149
Deferred	(7		)	(873		)	(164		)	(873		)	(1		)	(7		)	(101		)	(164		)
Total Income Tax Expense (Benefit)	$	16		$	(836	)	$	(15	)	$	(824	)	$	20		$	16		$	(64	)	$	(15	)
Effective Tax Rate	160.0		%	35.8		%	(2.7		)%	36.2		%	71.4		%	160.0		%	18.6		%	(2.7		)%

~~Changes in US Tax Law~~ On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018. In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities as of December 31, 2017.

On April 2, 2018, the US Department of the Treasury and the Internal Revenue Service released Notice 2018-26, signaling intent to issue regulations related to the transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Notice 2018-26 clarifies that an Internal Revenue Code Section 965(n) election is available with respect to both current year operating losses and net operating losses from a prior year. As a result, during first quarter 2018, we released the valuation allowance recorded against foreign tax credits that will be utilized against the $268 million toll tax liability we had recorded as of December 31, 2017, resulting in a $252 million tax benefit, and reduced our estimated toll tax liability to $16 million to be paid in installments over eight years. We also recorded a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized net operating losses. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.

~~During second quarter 2018, we made no changes to the provisional amounts recognized in 2017.~~

The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted further in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined.

Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ~~effective tax rate (ETR)~~ETR to current period earnings or loss before tax, which can ~~result in significant~~produce interim ETR fluctuations. ~~Our~~The ETR for the six months ended June 30, ~~2018~~2019 varied as compared with ~~the six months ended June 30, 2017~~2018, primarily due to a ~~deferred tax benefit of~~ $145 million ~~recorded discretely in the current year, as discussed above, and a significant deferred~~discrete tax benefit recorded atin 2018 as a result of the ~~higher prior year~~intent of the US ~~tax rate~~Department of ~~35% on~~ the ~~Marcellus Shale upstream divestiture in second quarter 2017.~~Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, ~~the increase in the~~ current ~~income~~ tax expense for the six months ended June 30, 2018 ~~is primarily due to~~includes foreign taxes onrelated to a gain ~~associated with~~on the ~~first quarter~~ 2018 divestiture of a 7.5% interest in the Tamar ~~field, offshore Israel.~~field.

In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014, Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2013.

~~Noble Energy, Inc.~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~Note 10. Income Per Share Attributable to Noble Energy~~

Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share:

Three Months Ended June 30, Six Months Ended June 30,
(millions, except per share amounts) 2018 2017 2018 2017
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy $ (23 ) $ (1,512 ) $ 531
$ (1,476 )
Weighted Average Number of Shares Outstanding, Basic 484
472
485
452
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust —
—
2
—
Weighted Average Number of Shares Outstanding, Diluted 484
472
487
452
(Loss) Income Per Share, Basic $ (0.05 ) $ (3.20 ) $ 1.09
$ (3.27 )
(Loss) Income Per Share, Diluted (0.05 ) (3.20 ) 1.09
(3.27 )
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14
16
14
15

Note ~~11. Segment Information~~12. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative InstrumentsWe have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets.

~~The geographical reportable segments are in the business of~~enter into crude oil and natural gas ~~acquisition~~price hedging arrangements in an effort to mitigate the effects of commodity price volatility and ~~exploration, development,~~enhance the predictability of cash flows for a portion of our crude oil and ~~production (Oil~~natural gas production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.

Unsettled Commodity Derivative Instruments As of June 30, 2019, the following crude oil derivative contracts were outstanding:



				Swaps					Collars
Settlement Period	Type of Contract	Index	Bbls Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2019	Swaps	NYMEX WTI	28,000	$	—		$	58.70	$	—	$	—	$	—
2019	Three-Way Collars	NYMEX WTI	33,000	—			—		49.35		59.35		72.25
2019	Sold Calls ⁽¹⁾	NYMEX WTI	20,000	—			60.00		—		—		—
2019	Swaps	ICE Brent	5,000	—			57.00		—		—		—
2019	Three-Way Collars	ICE Brent	3,000	—			—		43.00		50.00		64.07
2019	Basis Swaps	⁽²⁾	27,000	(3.23		)	—		—		—		—
2020	Swaption	NYMEX WTI	5,000	—			61.79		—		—		—
2020	Swaps	NYMEX WTI	7,000	—			60.00		—		—		—
2020	Three-Way Collars	NYMEX WTI	30,000	—			—		48.33		57.87		64.27
2020	Basis Swaps	⁽²⁾	15,000	(5.01		)	—		—		—		—


⁽¹⁾	We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts.


⁽²⁾	We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

As of June 30, 2019, the following natural gas derivative contracts were outstanding:



				Swaps					Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2019	Three-Way Collars	NYMEX HH	104,000	$	—		$	—	$	2.25	$	2.65	$	2.95
2019	Swaps	NYMEX HH	46,000	—			3.00		—		—		—
2019	Basis Swaps	CIG ⁽¹⁾	123,500	(0.64		)	—		—		—		—
2019	Basis Swaps	WAHA ⁽¹⁾	47,500	(1.28		)	—		—		—		—
2020	Basis Swaps	CIG ⁽¹⁾	54,000	(0.61		)	—		—		—		—
2020	Basis Swaps	WAHA ⁽¹⁾	49,500	(1.05		)	—		—		—		—


⁽¹⁾	We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.

Fair Value AmountsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows:



	Asset Derivative Instruments					Liability Derivative Instruments
(millions)	Balance Sheet Location	June 30, 2019		December 31, 2018		Balance Sheet Location	June 30, 2019		December 31, 2018
Commodity Derivative Instruments	Other Current Assets	$	30	$	180	Other Current Liabilities	$	42	$	1
	Other Noncurrent Assets	11		—		Other Noncurrent Liabilities	13		26
	Total	$	41	$	180		$	55	$	27

See Note 13. Fair Value Measurements and ~~Gas Exploration~~Disclosures for a discussion of methods and ~~Production).~~ assumptions used to estimate the fair values of our derivative instruments.

Gains and Losses on Commodity Derivative Instruments The ~~Midstream reportable segment owns, acquires, operates,~~effect of commodity derivative instruments on our consolidated statements of operations and develops domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level.comprehensive income was as follows:

Oil and Gas Exploration and Production Midstream
(millions) Consolidated United
States Eastern
Mediter- ranean West
Africa Other Int'l United States
Intersegment Eliminations and Other ⁽¹⁾
Corporate
Three Months Ended June 30, 2018
Crude Oil Sales $ 749
$ 635
$ 2
$ 112
$ —
$ —
$ —
$ —
NGL Sales 137
137
—
—
—
—
—
—
Natural Gas Sales 214
98
111
5
—
—
—
—
Total Crude Oil, NGL and Natural Gas Sales 1,100
870
113
117
—
—
—
—
Income from Equity Method Investees and Other 64
—
—
36
—
28
—
—
Sales of Purchased Oil and Gas 66
24
—
—
—
42
—
—
Intersegment Revenues —
—
—
—
—
85
(85 ) —
Total Revenues 1,230
894
113
153
—
155
(85 ) —
Lease Operating Expense 132
114
5
19
—
—
(6 ) —
Production and Ad Valorem Taxes 50
48
—
—
—
2
—
—
Gathering, Transportation and Processing Expense 100
133
—
—
—
22
(55 ) —
Other Royalty Expense 10
10
—
—
—
—
—
—
Total Production Expense 292
305
5
19
—
24
(61 ) —
DD&A 465
394
15
26
—
22
(4 ) 12
Loss (Gain) on Divestitures (78 ) 21
10
—
—
(109 ) —
—



	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2019			2018			2019			2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	7		$	66		$	(2	)	$	96
Natural Gas	(8		)	(1		)	(13		)	(3		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(1		)	65			(15		)	93
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	(54		)	181			169			231
Natural Gas	(5		)	3			(2		)	4
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(59		)	184			167			235
Loss (Gain) on Commodity Derivative Instruments
Crude Oil	(47		)	247			167			327
Natural Gas	(13		)	2			(15		)	1
Total (Gain) Loss on Commodity Derivative Instruments	$	(60	)	$	249		$	152		$	328

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 13. Fair Value Measurements and Disclosures

Purchased Oil and Gas 71
31
—
—
—
40
—
—
Loss on Commodity Derivative Instruments 249
196
—
53
—
—
—
—
(Loss) Income Before Income Taxes 10
(90 ) 62
48
(13 ) 175
(18 ) (154 )

Three Months Ended June 30, 2017

Crude Oil Sales $ 557
$ 458
$ 1
$ 98
$ —
$ —
$ —
$ —
NGL Sales 108
108
—
—
—
—
—
—
Natural Gas Sales 352
214
132
6
—
—
—
—
Total Crude Oil, NGL and Natural Gas Sales 1,017
780
133
104
—
—
—
—
Income from Equity Method Investees and Other 42
—
—
25
—
17
—
—
Intersegment Revenues —
—
—
—
—
69
(69 ) —
Total Revenues 1,059
780
133
129
—
86
(69 ) —
Lease Operating Expense 124
105
6
18
—
—
(5 ) —
Production and Ad Valorem Taxes 32
32
—
—
—
—
—
—
Gathering, Transportation and Processing Expense 121
142
—
—
—
17
(38 ) —
Other Royalty Expense 6
6
—
—
—
—
—
—
Total Production Expense 283
285
6
18
—
17
(43 ) —
DD&A 503
427
19
39
1
5
—
12
Loss on Marcellus Shale Upstream Divestiture 2,322
2,322
—
—
—
—
—
—
Loss on Commodity Derivative Instruments (57 ) (51 ) —
(6 ) —
—
—
—
(Loss) Income Before Income Taxes (2,334 ) (2,319 ) 106
72
(4 ) 58
(13 ) (234 )

Six Months Ended June 30, 2018

Crude Oil Sales $ 1,522
$ 1,317
$ 4
$ 201
$ —
$ —
$ —
$ —
NGL Sales 283
283
—
—
—
—
—
—
Natural Gas Sales 468
218
240
10
—
—
—
—
Total Crude Oil, NGL and Natural Gas Sales 2,273
1,818
244
211
—
—
—
—
Income from Equity Method Investees and Other 124
—
—
71
—
53
—
—
Sales of Purchased Oil and Gas 119
55
—
—
—
64
—
—
Intersegment Revenues —
—
—
—
—
166
(166 ) —
Total Revenues 2,516
1,873
244
282
—
283
(166 ) —
Lease Operating Expense 287
240
12
41
—
—
(6 ) —
Production and Ad Valorem Taxes 104
101
—
—
—
3
—
—
Gathering, Transportation and Processing Expense 195
260
—
—
—
43
(108 ) —
Other Royalty Expense 27
27
—
—
—
—
—
—
Total Production Expense 613
628
12
41
—
46
(114 ) —
DD&A 933
800
28
52
—
38
(8 ) 23
Gain on Divestitures (666 ) 15
(376 ) —
—
(305 ) —
—
Assets and Liabilities Measured at Fair Value on a Recurring Basis

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. Fair values are based on quoted market prices for identical assets.

Commodity Derivative Instruments We estimate the fair values of our derivative instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the values of put options sold and contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. SeeNote 12. Derivative Instruments and Hedging Activities.

Deferred Compensation LiabilityFair value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments, above.

Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock at the end of each reporting period.

Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows:



	Fair Value Measurements Using
(millions)	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Adjustment ⁽¹⁾			Fair Value Measurement
June 30, 2019
Financial Assets:
Mutual Fund Investments	$	42		$	—		$	—	$	—		$	42
Commodity Derivative Instruments	—			63			—		(22		)	41
Financial Liabilities:
Commodity Derivative Instruments	—			(77		)	—		22			(55		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(2		)	—			—		—			(2		)
December 31, 2018
Financial Assets:
Mutual Fund Investments	$	38		$	—		$	—	$	—		$	38
Commodity Derivative Instruments	—			187			—		(7		)	180
Financial Liabilities:
Commodity Derivative Instruments	—			(34		)	—		7			(27		)
Portion of Deferred Compensation Liability Measured at Fair Value	(43		)	—			—		—			(43		)
Stock Based Compensation Liability Measured at Fair Value	(8		)	—			—		—			(8		)


⁽¹⁾	Amount represents the impact of netting provisions within our master agreements allowing us to net cash settled asset and liability positions with the same counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Asset Impairments 168
168
—
—
—
—
—
—
Purchased Oil and Gas 128
67
—
—
—
61
—
—
Loss on Commodity Derivative Instruments 328
260
—
68
—
—
—
—
Income (Loss) Before Income Taxes 553
(127 ) 535
112
(27 ) 428
(40 ) (328 )

Six Months Ended June 30, 2017

Crude Oil Sales $ 1,084
$ 897
$ 2
$ 185
$ —
$ —
$ —
$ —
NGL Sales 213
213
—
—
—
—
—
—
Natural Gas Sales 714
440
263
11
—
—
—
—
Total Crude Oil, NGL and Natural Gas Sales 2,011
1,550
265
196
—
—
—
—
Income from Equity Method Investees and Other 84
—
—
52
—
32
—
—
Intersegment Revenues —
—
—
—
—
127
(127 ) —
Total Revenues 2,095
1,550
265
248
—
159
(127 ) —
Lease Operating Expense 263
211
14
40
—
—
(2 ) —
Production and Ad Valorem Taxes 73
72
—
—
—
1
—
—
Gathering, Transportation and Processing Expense 240
280
—
—
—
32
(72 ) —
Other Royalty Expense 10
10
—
—
—
—
—
—
Total Production Expense 586
573
14
40
—
33
(74 ) —
DD&A 1,031
886
37
74
2
10
—
22
Loss on Marcellus Shale Upstream Divestiture 2,322
2,322
—
—
—
—
—
—
Gain on Commodity Derivative Instruments (167 ) (154 ) —
(13 ) —
—
—
—
Income (Loss) Before Income Taxes (2,275 ) (2,251 ) 207
138
(11 ) 107
(35 ) (430 )

June 30, 2018

Goodwill ⁽²⁾
$ 1,402
$ 1,291
$ —
$ —
$ —
$ 111
$ —
$ —
Total Assets 21,854
15,138
2,996
1,275
62
2,280
(140 ) 243
December 31, 2017

Goodwill ⁽²⁾
1,310
1,310
—
—
—
—
—
—
Total Assets 21,476
15,767
2,846
1,308
114
1,357
(163 ) 247

Firm Transportation Exit Cost Accrual In January 2019, we recorded a firm transportation exit cost liability at fair value of $92 million, representing the discounted present value of our remaining obligation under a permanent pipeline capacity assignment in the Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments.

⁽¹⁾Redeemable Noncontrolling Interest The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.

⁽²⁾ ~~Goodwill in the United States reportable segment is associated with our Texas reporting unit. Goodwill in the Midstream segment is~~In March 2019, we recorded redeemable noncontrolling interest associated with the ~~Saddle Butte acquisition.~~issuance of GIP preferred equity at fair value of $97 million, including issuance date proceeds of $100 million netted with associated issuance costs of $3 million. See Note 2. Basis of Presentation.

Additional Fair Value Disclosures

Debt The fair value of fixed-rate, public debt is estimated based on published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy.

Our non-public debt, including our Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, Noble Midstream Services Term Loan Credit Facility and commercial paper borrowings, are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt.

Fair value information regarding our debt is as follows:



	June 30, 2019				December 31, 2018
(millions)	Carrying Amount		Fair Value ⁽¹⁾		Carrying Amount		Fair Value
Debt ⁽²⁾	$	6,994	$	7,465	$	6,452	$	6,121


⁽¹⁾	As of June 30, 2019, the difference between the carrying amount and fair value is primarily due to low US treasury rates.


⁽²⁾	Excludes unamortized discount, debt issuance costs and finance lease obligations. See Note 8. Leases.

Note ~~12. Commitments and Contingencies~~14. Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders

~~Legal ProceedingsWe are involved in various legal proceedings in~~Noble Energy's basic (loss) income per share of common stock is computed by dividing net (loss) income attributable to Noble Energy by the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

~~Marcellus Shale Firm Transportation Contracts~~ In connection with the 2017 Marcellus Shale upstream divestiture, we retained certain firm transportation obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of approximately four to 15 years, is approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were placed into service in late 2017 and early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems, with estimated in-service dates in late 2018.

We are currently engaged in actions to commercialize these commitments which provide for the transportation of 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. We continue to expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce our financial commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment.

We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts. As of June 30, 2018, our exit cost accrual, relating to certain transportation arrangements, totals $83 million, discounted. For the first six months of 2018, we incurred expense of $3 million related to unutilized transportation related to these contracts.

~~Colorado Air Matter~~ In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at aweighted average number of ~~our condensate storage tanks that are part~~shares of ~~our upstream crude oil~~Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and ~~natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court for the District of Colorado on June 2, 2015.~~ diluted (loss) income per share:

The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $83 million to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.



	Three Months Ended June 30,						Six Months Ended June 30,
(millions, except per share amounts)	2019			2018			2019			2018
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy	$	(10	)	$	(23	)	$	(323	)	$	531
Weighted Average Number of Shares Outstanding, Basic ⁽¹⁾	478			484			478			485
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	—			—			—			2
Weighted Average Number of Shares Outstanding, Diluted	478			484			478			487
(Loss) Income Per Share, Basic	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
(Loss) Income Per Share, Diluted	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	15			14			15			14

Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.

We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.

~~Colorado Water Quality Control Division Matter~~ In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

~~Colorado Oil and Gas Conservation Commission Administrative Order on Consent~~ In November 2017, we received a proposed Administrative Order on Consent (AOC) from the Colorado Oil and Gas Conservation Commission (COGCC) to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time, but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

~~Colorado Mechanical Integrity Testing Matter~~ In July 2018, we received Notices of Alleged Violation (NOAVs) from the COGCC for alleged noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado. The NOAVs order us to repair or plug and abandon each of the eight wells (or provide proof that such work has been completed) and to submit to COGCC certain environmental data. We have met with COGCC enforcement leadership to discuss this matter and are working to timely complete the required corrective actions and submit the data requested in the NOAVs. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.


⁽¹⁾	Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:


•	Executive Overview;


•	Operating Outlook;


•	Results of Operations – ~~E&P~~Exploration and Production;


•	Results of Operations – Midstream;


•	Results of Operations – Corporate; and

Table of Contents


•	Liquidity and Capital Resources.

The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.

EXECUTIVE OVERVIEW

The following discussion highlights significant operating and financial results for second quarter ~~2018.~~2019. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

~~Recent Achievements~~ Operational Environment Update

~~Since 2015,~~Commodity Prices Crude oil prices remained volatile during second quarter 2019, with Brent and WTI averaging approximately $69 and $60 per barrel, respectively. The outlook for the remainder of 2019 will depend on competing factors for supply and demand. OPEC cuts and geopolitical factors in critical oil producing regions may support prices for the remainder of the year; however, weakening crude oil demand amid signs of a broader softening in the global economy could result in lower prices. In the Delaware Basin, new pipeline startups have begun to improve price differentials, while planned expansion of export infrastructure should help alleviate part of the discount of WTI to Brent going forward.

The US natural gas market continues to see depressed pricing as supply outpaced demand over the past year. Despite record domestic LNG exports and high natural gas fired electric generation, natural gas inventories are projected to remain at or slightly above historical five-year averages. Natural gas price differentials increased in the DJ Basin and in the Delaware Basin continue to be wide while awaiting new pipeline infrastructure with expected in-service during second half 2019. Additional Delaware Basin gas pipeline expansions are also targeted for in-service in late 2020.

NGL prices are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. Collectively, NGL prices have lagged compared to the recovery seen in crude oil prices in first half of 2019. NGL prices should strengthen as new processing and export facilities are brought online.

To mitigate the effect of commodity price volatility, we have ~~strategically repositioned~~entered into crude oil and natural gas price hedging arrangements which also serve to enhance the predictability of our ~~portfolio~~cash flows.

Colorado Senate Bill 19-181 For some time, initiatives have been underway in the State of Colorado to ~~focus capital investment primarily~~limit or ban crude oil and natural gas exploration, development or operations. During first quarter 2019, Senate Bill 19-181 (SB 181) was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislation makes changes in ~~US onshore plays,~~Colorado oil and gas law, including, among other matters, requiring the DJColorado Oil and ~~Delaware Basins~~Gas Conservation Commission (Commission) to prioritize public health and ~~Eagle Ford Shale,~~environmental concerns in its decisions, instructing the Commission to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts.

The majority of our acreage in Colorado is in rural, unincorporated areas of Weld County, and we continue to work closely with local regulators and communities to ensure safe and responsible operations and future planning. At this time, we do not foresee significant changes to our development plans, as we have all necessary approvals of more than 550 permits to drill wells over the next several years. The approved permits are for wells in multiple Integrated Development Plans (IDPs), many of which are in our Mustang Comprehensive Drilling Plan (CDP). We will continue to work closely with Weld County on the required local permits and agreements for the CDP. However, if additional regulatory measures are adopted, we could incur additional costs to comply with the requirements or we may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our ~~international offshore assets in the Eastern Mediterranean and West Africa. The focus of our capital programs in these areas is expected to positively impact our future~~ cash flows, results of operations, financial condition, and ~~margins. Going forward, we are concentrating our exploration capabilities on higher-impact opportunities that can drive substantial long-term value creation.~~liquidity.

Recent Activities

During second quarter ~~2018,~~2019, we ~~exited the Gulf of Mexico and~~ continued to progress our US onshore drilling and completions activities, ~~and~~ advanced our Eastern Mediterranean and West Africa regional natural gas ~~developments. Financially, we strengthened~~developments, and continued to advance our ~~balance sheet through reduction of debt.~~

new US onshore and international exploration opportunities. Second quarter ~~2018 achievements include~~2019 activities included the following:

Sales Volumes We delivered quarterly consolidated sales volumes of ~~346~~343 MBoe/d, with approximately 56% of our production mix attributable to crude oil and NGLs. ~~Reported volumes reflect the impact of adoption of ASC 606,~~ ~~Revenue from Contracts with Customers~~ ~~(ASC 606).~~ See Results of Operations – Exploration and Production ~~(E&P) – Results of Operations~~.

~~Gulf of Mexico Asset Sale~~Leviathan Natural Gas Project ~~In second quarter 2018, we completed~~We progressed the sale of our Gulf of Mexico assets, including our interests in six producing fields and all undeveloped leases. We received cash consideration of $383 million, net of customary price adjustments. We recognized impairment expense of $168 million in first quarter 2018 and an additional loss of $19 million in second quarter 2018.Leviathan natural gas project, offshore Israel, to 88% completion. See ~~Item 1. Financial Statements~~Results of Operations – ~~Note 3. Acquisitions~~Exploration and ~~Divestitures~~Production.

~~Agreement to Progress~~ Alen Natural Gas Development ~~In May 2018,~~On April 1, 2019, we announced sanction of the ~~execution of a Heads of Agreement establishing the framework for development of~~Alen natural gas ~~from the Alen field, resulting in access to global liquefied natural gas (LNG) markets. Sanction of the project is contingent upon final commercial agreements being executed.~~development, offshore Equatorial Guinea. See Results of Operations – Exploration and Production ~~(E&P) – Development Projects~~.

~~Strategic EPIC Pipeline Agreement~~ During second quarter 2018, we finalized a strategic agreement with EPIC Pipeline, LP (EPIC) to transport crude oil from our Delaware Basin acreage position to Corpus Christi, Texas. We have secured firm capacity for 100 MBbl/d, gross, of crude oil for a 10-year period beginning at pipeline start-up. In addition, we secured options for ownership interests in EPIC's crude oil and NGL pipelines. See ~~Exploration and Production (E&P) – Development Projects~~.

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Financial Initiatives

~~Delaware Basin Firm Crude Oil Sales Agreement~~Commercial Paper Program ~~In June 2018,~~During second quarter 2019, we ~~supplemented~~utilized our ~~Delaware Basin takeaway position through~~recently-established commercial paper program, which allows for a maximum of $4.0 billion of unsecured commercial paper borrowings to provide for short-term funding needs and is supported by Noble Energy’s Revolving Credit Facility. The commercial paper program typically enables us to access lower short-term interest rates than those available under the execution of a five-year agreement for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. See ~~Exploration and Production (E&P) – Development Projects~~.

~~Hedging Activities~~ We entered into additional strategic crude oil basis swap contracts for 2018-2020 in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma, thus mitigating the price risk associated with our Delaware Basin production.Revolving Credit Facility. See Item 1. Financial Statements – Note ~~4. Derivative Instruments and Hedging Activities~~.

~~CNX Midstream Partners Unit Sale~~ 7. DebtDuring second quarter 2018, we sold 7.5 million CNX Midstream Partners common units, or approximately one-third of our investment, receiving net proceeds of approximately $135 million, net of underwriting fees. We continue to hold 14.2 million common units. See ~~Item 1. Financial Statements – Note 3. Acquisitions and Divestitures~~.

~~Senior Note Redemption~~ To further strengthen our balance sheet and reduce nearer-term maturities, we redeemed $379 million of Senior Notes due May 1, 2021, which had been assumed in the 2015 Rosetta Merger, in May 2018 for $395 million and recognized a gain of $5 million. See ~~Item 1. Financial Statements – Note 5. Debt~~.

~~Share Repurchases~~In accordance with the $750 million share repurchase program authorized by our Board of Directors earlier this year, we repurchased and retired 1.8 million shares of common stock at an average purchase price of $35.15 per share during second quarter 2018.

Financial Flexibility, Liquidity and Balance Sheet Strength As we progress through the remainder of ~~2018,~~2019, we believe we are positioned for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. We remain committed to maintaining capital discipline and financial strength and will continuously evaluate commodity prices, along with well productivity and efficiency gains, as we optimize our activity levels in alignment with commodity price conditions. To this end, our 2018 capital investment program is responsive to positive or negative commodity price conditions that may develop.strength. See Operating Outlook – ~~2018~~2019 Capital Investment Program.

If commodity prices decline or operating costs ~~begin to~~ rise, we could experience material asset impairments, as well as material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider ~~reductions~~changes in our capital program, share repurchase program or dividends, asset sales or operating cost structure. Our ~~production~~revenues and our stock price could decline as a result of these potential developments.

~~Adoption of ASC 606~~

~~As of January 1, 2018, we adopted ASC 606~~, using the modified retrospective method. ASC 606 adoption did not have an impact on the opening balance of retained earnings, and resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for the second quarter and the first six months of 2018, respectively. ASC 606 adoption did not affect operating or net income or operating cash flows. Comparative information for the prior periods has not been recast and continues to be reported under the accounting standards in effect for those periods. Adoption of the new standard did not impact our financial position and we do not expect that it will going forward. See ~~Exploration and Production (E&P) – Results of Operations~~.

Recently Issued Accounting Standards

See Item 1. Financial Statements – Note 2. Basis of Presentation.

OPERATING OUTLOOK

~~2018 Production~~ ~~Our expected crude oil, natural gas and NGL sales for~~The current commodity price environment, along with the ~~remainder of 2018 may be impacted by several factors including:~~

~~commodity prices which, if subject to a significant decline, could result in certain existing production becoming uneconomic;~~

~~overall level and~~ timing of our capital expenditures ~~which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;~~

increased industry drilling activity in the basins in which we operate, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;

~~Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of the Israeli electricity portfolio from coal to natural gas;~~

~~timing of crude oil and condensate liftings impacting sales volumes in West Africa;~~

~~natural field decline in the US onshore and offshore Equatorial Guinea;~~

~~additional purchases of producing properties or divestments of operating assets;~~

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~~potential weather-related volume curtailments (e.g., due to winter storms and flooding) impacting US onshore operations;~~

~~availability or reliability of supplier materials and services, including access to support equipment and/or facilities which may cause delays in operations;~~

availability of, or curtailments imposed by, third party processing facilities, which could result in capacity constraints, and interruptions in midstream processing, which may cause production and sales volumes impacts;

~~occurrence of pipeline disruptions, which may cause delays, restrictions or interruptions in production and/or midstream processing;~~

access to transportation and takeaway pipelines for increasing US onshore production volumes, such as in the Delaware Basin, which may cause infield bottlenecks and/or widening of location-basis differentials;

~~malfunctions and/or mechanical failures at terminals or other US onshore delivery points;~~

~~impact of enhanced completion efforts~~ for US onshore ~~assets;~~

~~potential growth from participation~~development, Leviathan completion, and the Aseng development well, as well as Noble Midstream Partners' investments, is anticipated to result in ~~future, or decline from existing, non-operated wells;~~

~~abandonment~~capital expenditures in excess of ~~low-margin US onshore wells;~~

~~shut-in~~operating cash flows in 2019. Although we did not repurchase any shares under our $750 million share repurchase program in the first half of ~~US producing properties if storage capacity becomes unavailable;~~2019, we remain committed to shareholder return initiatives. For example, in both April and

~~potential drilling and/or completion permit delays due~~ July 2019, our Board of Directors approved quarterly cash dividends in amounts that represented a 9% increase over the prior year. This is our second straight year to ~~future regulatory changes.~~increase our dividend, reflecting our commitment to return value to shareholders.

~~2018~~2019 Capital Investment Program ~~Our 2018~~

Driven by US onshore efficiencies and offshore activity timing, we have lowered our full year organic capital ~~investment~~program by $100 million for 2019. As such, our 2019 organic capital program is ~~designed to deliver near and long-term value and is flexible~~ in the ~~current commodity price environment. Excluding~~range of $2.3 to $2.5 billion, with approximately 70% being allocated to US onshore development and approximately 20% being allocated to complete the Leviathan Phase 1 development project. The remaining portion of the organic capital program is designated for Noble retained midstream activities, drilling of the Aseng development well, and other exploration and corporate activities. Amounts exclude capital funded by Noble Midstream Partners ~~our initial 2018~~and acquisition capital related to the EMG Pipeline, as discussed below.

Our 2019 organic capital program ~~accommodated an investment~~anticipates a lower level of ~~approximately $2.7~~investment directed to ~~$2.9 billion and was contemplated using a West Texas Intermediate price assumption of $50 per barrel. We have revised~~ our ~~capital program to accommodate an investment level of approximately $3 billion, reflecting increased onshore facility spend from the first half of 2018 and inflation in the~~ US onshore assets, as ~~a result of the higher commodity price environment.~~

Approximately 95% of the capital program is being allocated to US onshore development, associated midstream infrastructure and the Eastern Mediterranean. In addition, given industry constraints in the Permian Basin, we plan to reallocate some near-term investment to our other US onshore basins. This will ensure that we are optimizing our development plans and timing our Delaware Basin activity to benefit from necessary takeaway infrastructure planned for next year.

The remaining portion of the capital program is designated for other activities, including lease acquisition, seismic and other geological analysis in support of future exploration prospects, as well as other corporate activities.

compared with 2018. We will continue to ~~evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns:~~

~~commodity prices, including price realizations on specific crude oil, natural gas and NGL production;~~

~~operating and development costs;~~

~~production, drilling and delivery commitments, or other contractual obligations;~~

~~access and availability of gathering, transportation, takeaway and processing capacity for~~advance our US onshore ~~production volumes;~~

~~drilling results;~~

~~property acquisitions~~program through investments in liquids-rich and ~~divestitures;~~

~~exploration activity;~~

~~cash flows from operations;~~

~~indebtedness levels;~~

~~availability of financing or other sources of funding;~~

~~impact of new laws~~higher-return projects that improve execution efficiency and ~~regulations on~~enhance our midstream business ~~practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and~~

~~potential changes in the fiscal regimes of the US and other countries in which we operate.~~

value. See Liquidity and Capital Resources ~~– Financing Activities~~.

~~Regulatory Update~~ During the first six months of 2018, the US Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from Argentina, Brazil, and South Korea (Australia has been exempted from the imposition of tariffs and implementation of quotas). Key US trading partners have threatened to retaliate, or already have retaliated, against imports of US-origin goods and have initiated litigation at the World Trade Organization. The US oil and gas industry relies on steel for drilling and completion of new wells, as well as for facility production at refineries, petrochemical plants and pipelines. Much of the steel required is in the form of specialty steel products, manufactured to exact specifications, and may not be available domestically in sufficient quantities.

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Implementation of these tariffs will likely increase prices for specialty and other products used in various aspects of upstream, midstream and downstream activities. Furthermore, the tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects, that the industry is relying on to transport its increasing onshore production to market, as well as endangering US LNG export projects resulting in negative impacts on natural gas production.

In addition, countries subject to the tariffs have threatened to retaliate with tariffs on American products, potentially resulting in escalating trade disputes with certain trade partners. Trade and/or tariff disputes could result in increased costs or shortages of materials and supplies the industry relies on to produce, process and transport its oil and gas production. Moreover, trade and/or tariff disputes, could have negative impacts on the US and global economies overall and could result in less demand for our products.

RESULTS OF OPERATIONS – EXPLORATION AND PRODUCTION (E&P)

We continue to advance our major development projects, which we expect to deliver incremental production and cash flows over the next several years.

Sanctioned Ongoing Development Projects

A ~~"sanctioned"~~“sanctioned” development project is one for which a final investment decision has been reached. Updates on major development projects are as follows:

~~DJ Basin (US Onshore)~~ Our activities during second quarter 2018 were focused primarily in the Wells Ranch and East Pony integrated development plan (IDP) areas. During the quarter, we operated one to two drilling rigs, completed 31 wells and commenced production on 16 wells. Average sales volumes during second quarter 2018 were 121 MBoe/d, including 10 MBoe/d due to ASC 606 adoption. We have expanded drilling and completion activities into the Mustang IDP area, where we have a large contiguous acreage position, and added a drilling rig in this IDP during second quarter 2018. Our development plan in this area includes applying multiple techniques from our other successful US ~~onshore plays, including utilizing row development concepts, enhanced completion designs, capital-efficient facility designs, and other techniques to optimize project returns.~~Onshore

~~Delaware Basin (US Onshore)~~ During second quarter 2018, we operated an average of six drilling rigs, completed 22 wells and commenced production on 23 wells, with the majority of our activity focused on long laterals and multi-well pads targeting multiple zones within the basin. We averaged 47 MBoe/d of sales volumes during second quarter 2018, with approximately 70% of our production mix attributable to crude oil. During second quarter 2018, we commenced operations at two additional central gathering facilities (CGFs).

Also during second quarter 2018, we secured firm capacity with EPIC for transport of 100 MBbl/d, gross, of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up. We have dedicated substantially all our Delaware Basin acreage position in Reeves County, Texas to the EPIC crude oil pipeline, which the operator anticipates will commence operations in the fourth quarter of 2019. This strategic agreement is expected to provide long-term flow assurance for our rapidly growing Delaware Basin crude oil volumes. With this agreement, we have further diversified2019, our US onshore ~~marketing outlets with access to the Texas Gulf Coast and global markets, at an attractive pipeline transport cost.~~

~~As part~~E&P activities consisted of the EPIC strategic relationship, we secured options to acquire up to 30% ownership interest in the company that owns the EPIC crude oil pipeline. In addition, Noble Midstream Partners secured an option to acquire up to 15% ownership interest in the company that owns the EPIC NGL pipeline. Both options expire in first quarter 2019.following:

In June 2018, we supplemented our Delaware Basin takeaway position with an additional firm sales agreement, which will result in our crude oil reaching the Gulf Coast. The five-year agreement provides for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. Crude oil sold under the agreement will initially utilize the buyer's existing firm transport capacity to Corpus Christi. Shortly following commencement of full service of the EPIC crude oil pipeline, it is anticipated that crude oil sales under the agreement will be transported by way of our firm transportation capacity. We previously executed firm sales agreements to the Texas Gulf Coast or Cushing, Oklahoma markets for Delaware Basin crude oil covering gross oil volumes of 10 MBbl/d for the second half of 2018 and 5 MBbl/d for 2019.

~~Eagle Ford Shale (US Onshore)~~ During second quarter 2018, we operated an average of one drilling rig, completed four wells and commenced production on nine wells, primarily focused within the Upper and Lower Eagle Ford formation zones. In addition, we commenced construction of a central gathering and production facility in the northern area of Gates Ranch. This facility will provide separation and compression capabilities for our upcoming multi-well completion program expected to begin later in 2018. We continue to execute our development plan and averaged sales volumes of 76 MBoe/d during second quarter 2018.



Location	Average Rigs Operated	Wells Drilled and Completed	Wells Brought Online	Average Sales Volumes (MBoe/d)
DJ Basin	2	33	36	145
Delaware Basin	4	17	25	64
Eagle Ford Shale	—	9	16	54
Total	6	59	77	263

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~~Tamar Natural Gas Project (Eastern Mediterranean)~~DJ Basin InDuring second quarter 2018, offshore Israel sales volumes averaged 227 MMcfe/d, net, and on a gross basis, sales volumes reached a cumulative milestone delivering 1.6 Tcf of natural gas to-date. Second quarter gross sales volumes established2019, we achieved a quarterly ~~production~~average sales volume record of ~~more than 1 Bcf/d, driven by continued coal displacement~~145 MBoe/d. Our activities were focused primarily on progressing development in ~~power generation~~the Mustang IDP, which benefits from our approved CDP, Wells Ranch and ~~warm seasonal weather.~~East Pony areas. In addition, we saw increased capital efficiencies as a result of improved drilling and completion performance.

Delaware Basin During second quarter 2019, we achieved a quarterly average sales volume record of 64 MBoe/d. Our activity focused primarily on row development with long laterals and multi-well pads.

Eagle Ford Shale During second quarter 2019, we focused on well completion activities in the North Gates Ranch area to bring online our drilled but uncompleted wells.

International

Leviathan Natural Gas Project ~~(Eastern Mediterranean)~~(Offshore Israel) ~~2018 represents the peak year for capital investments for the initial phase of Leviathan development, offshore Israel.~~ The project is now ~~nearly 60%~~more than 88% complete and remains on budget and on schedule. ~~We have commenced construction~~During second quarter 2019, we completed umbilical installation, tie-in of onshore pipelines to offshore pipelines, and tie-in to the ~~onshore pipeline, completed drilling of Leviathan 3~~Israel Natural Gas Lines grid. The first topsides set sail in July, and ~~7 wells,~~commissioning and ~~began completion operations at the Leviathan 4 well. First natural gas sales~~operational readiness activities are underway. Project start-up is anticipated by the end of 2019.

~~Unsanctioned Development Projects~~

~~West Africa~~Leviathan and Tamar Natural Gas ~~Monetization~~Transportation Agreements (Offshore Israel) We continue ~~efforts~~ to ~~monetize~~work with certain of our ~~significant natural gas discoveries~~Eastern Mediterranean field partners toward the acquisition of a 39% equity interest in EMG, which owns the EMG Pipeline, an approximately 90-kilometer pipeline, located primarily offshore, ~~West Africa. A natural gas~~connecting the Israel pipeline network from Ashkelon, Israel to the Egyptian pipeline network. We will own an effective, indirect interest of approximately 10%, net, in the pipeline.

Closing of the agreement to exclusively operate the EMG Pipeline and secure access to its full capacity is subject to fulfillment of certain conditions precedent, which is expected to occur in third quarter 2019. The estimated acquisition cost for our interest in the pipeline is approximately $200 million.

Aseng Development Well (Offshore Equatorial Guinea) During second quarter 2019, we awarded contracts and acquired equipment for a new development ~~team has been working with local governments~~well expected to ~~evaluate natural gas monetization concepts~~mitigate Aseng field decline. The well was spud in July 2019 and ~~progress negotiations of required contracts. In May 2018,~~production is expected to come online in fourth quarter 2019.

Alen Natural Gas Development (Offshore Equatorial Guinea) On April 1, 2019, we announced the ~~execution, along with~~sanction of the ~~Government~~Alen natural gas development. Natural gas from the Alen field will be processed through the existing Alba Plant LLC liquefied petroleum gas (LPG) processing plant (Alba Plant) and Equatorial Guinea's liquefied natural gas (LNG) production facility (EG LNG) located at Punta Europa, Bioko Island. Definitive agreements in support of the project have been executed among the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial ~~Guinea~~Guinea.

The Alen natural gas monetization project will produce through three existing high-capacity wells and ~~necessary third-parties,~~will require minor platform modifications to deliver sales gas from Alen to the Alba Plant and EG LNG facilities. The Alen field partners plan to construct a 24-inch pipeline capable of ~~a Heads~~handling 950 MMcfe/d to transport all natural gas processed through the Alen platform approximately 70 kilometers to the onshore facilities. First production is anticipated in the first half of ~~Agreement establishing the framework for development of~~2021. At start-up, natural gas sales from the Alen ~~field. The agreement outlines the high-level commercial terms for Alen natural gas~~field are anticipated to be ~~processed~~between 200 and 300 MMcfe/d, gross (approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled through the Alba Plant ~~LLC’s liquefied petroleum~~for additional liquids recovery before the dry gas ~~(LPG) plant and Equatorial Guinea~~is converted into LNG Holdings Limited’s LNG plant. Both plants are located in Punta Europa. The contemplated structure would result in Alen gas being marketed to global LNG markets. Sanction of the project is contingent upon final commercial agreements being executed.

~~Existing production and processing facilities in place~~ at the Alen platform and in Punta Europa require certain modifications to produce and process the Alen natural gas. The agreement contemplates construction of a 65-kilometer pipeline to transport natural gas from the Alen platform to the facilities in Punta Europa.EG LNG facility.

Unsanctioned Projects

Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently ~~planned,~~contemplated, would deliver natural gas to regional customers. In addition, we are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.

Exploration Program Update

We continue to seek and evaluate significant onshore and/or offshore opportunities for future exploration. Through our drilling activities, we do not always encounter ~~hydrocarbons. In addition,~~hydrocarbons or we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs will be recorded as dry hole expense.

Additionally, we may not be able to conduct exploration activities prior to lease ~~expirations. As a result,~~expirations or may choose to relinquish or exit licenses. Exploration opportunities in a future period could result in significant dry hole cost and/or leasehold abandonment ~~expense could be significant.~~expense. See Item 1. Financial Statements – Note 7.5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

US Onshore Acreage Our US onshore unconventional exploration position includes more than 175,000 acres residing in two plays in Wyoming. During second quarter 2019, we continued land acquisition, permitting and evaluation activities.

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Offshore Colombia We have signed an agreement for a 40% operated working interest in more than two million gross acres offshore Colombia, located on two blocks. We expect to drill an exploration well in 2020. During second quarter 2019, we continued well planning and permitting activities.

Results of Operations

Highlights for our E&P business were as follows:

Second Quarter ~~2018 Significant~~2019 E&P Operating Highlights Included:

total average ~~daily~~consolidated sales volumes of ~~346~~343 MBoe/d, net;

record average daily sales volumes of 117 MBbl/d, net, for US ~~onshore~~ crude oil driven by acceleration of ~~105 MBbl/d, net;~~development plans;

~~record~~ average daily sales volumes of ~~over 1 Bcf/~~1.0 Bcfe/d, gross, infor offshore Israel natural gas, primarily from the Tamar field;

~~closed the Gulf of Mexico asset divestiture;~~ and

~~executed Heads~~US onshore production expense per BOE of ~~Agreement regarding framework for development of natural gas from the Alen field, offshore Equatorial Guinea.~~$11.64.

Second Quarter ~~2018~~2019 E&P Financial Results Included:

~~net cash proceeds of $383 million, after closing adjustments, received from the Gulf of Mexico asset sale;~~

~~total loss of $249 million on commodity derivative instruments;~~

~~pre-tax income of $7 million, as compared with pre-tax loss of $2.1 billion for second quarter 2017; and~~

capital expenditures, excluding acquisitions, of ~~$787~~$596 million, as compared with ~~$613~~$787 million for second quarter ~~2017.~~2018;

pre-tax income of $179 million, as compared with pre-tax income of $7 million for second quarter 2018; and

net gain on commodity derivative instruments of $60 million, as compared with a net loss of $249 million for second quarter 2018.

The following is a summarized statement of operations for our E&P business:



	Three Months Ended June 30,					Six Months Ended June 30,
(millions)	2019			2018		2019		2018
Oil, NGL and Gas Sales to Third Parties	$	954		$	1,100	$	1,891	$	2,273
Sales of Purchased Oil and Gas	28			—		42		—
Income from Equity Method Investees and Other	18			36		33		71
Total Revenues	1,000			1,136		1,966		2,344
Production Expense	298			327		649		677
Exploration Expense	33			29		57		64
Depreciation, Depletion and Amortization	493			435		968		880
Loss (Gain) on Divestitures, Net	—			31		—		(361		)
Asset Impairments	—			—		—		168
Cost of Purchased Oil and Gas	28			—		42		—
(Gain) Loss on Commodity Derivative Instruments	(60		)	249		152		328
Income (Loss) Before Income Taxes	179			7		11		493

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~~Following is a summarized statement~~Average Oil, NGL and Gas Sales Volumes and PricesAverage daily sales volumes from our share of ~~operations for our E&P business:~~

production and realized sales prices were as follows:

Three Months Ended June 30, Six Months Ended June 30,
(millions) 2018 2017 2018 2017
Oil, NGL and Gas Sales to Third Parties ⁽¹⁾
$ 1,100
$ 1,017
$ 2,273
$ 2,011
Sales of Purchased Gas ⁽²⁾
24
—
55
—
Income from Equity Method Investees 36
25
71
52
Total Revenues 1,160
1,042
2,399
2,063
Production Expense ⁽¹⁾
329
309
681
627
Exploration Expense 29
30
64
72
Depreciation, Depletion and Amortization 435
486
880
999
Purchases of Gas ⁽²⁾
31
—
67
—
Loss on Marcellus Shale Upstream Divestiture —
2,322
—
2,322
(Loss) Gain on Divestitures ⁽³⁾
31
—
(361 ) —
Asset Impairments ⁽³⁾
—
—
168
—
Loss (Gain) on Commodity Derivative Instruments 249
(57 ) 328
(167 )
Clayton Williams Energy Acquisition Expenses ⁽³⁾
—
90
—
94
Income (Loss) Before Income Taxes 7
(2,145 ) 493
(1,917 )



	Average Sales Volumes ⁽¹⁾				Average Realized Sales Prices ⁽¹⁾
	Crude Oil & Condensate (MBbl/d)	NGLs (MBbl/d)	Natural Gas (MMcf/d)	Total (MBoe/d)	Crude Oil & Condensate (Per Bbl)		NGLs (Per Bbl)		Natural Gas (Per Mcf)
Three Months Ended June 30, 2019
United States	117	64	495	263	$	58.13	$	14.54	$	1.61
Eastern Mediterranean	—	—	209	35	—		—		5.53
West Africa ⁽²⁾	11	—	199	45	66.61		—		0.27
Total Consolidated Operations⁽³⁾	128	64	903	343	58.88		14.54		2.22
Equity Investees ⁽⁴⁾	2	4	—	6	65.75		31.22		—
Total ⁽³⁾	130	68	903	349	$	58.98	$	15.47	$	2.22
Three Months Ended June 30, 2018
United States ⁽⁵⁾	108	62	467	247	$	64.67	$	24.46	$	2.29
Eastern Mediterranean	—	—	225	38	—		—		5.46
West Africa ⁽²⁾	17	—	225	54	72.79		—		0.27
Total Consolidated Operations	125	62	917	339	65.77		24.46		2.57
Equity Investees⁽⁴⁾	2	5	—	7	76.07		43.36		—
Total	127	67	917	346	$	65.93	$	25.90	$	2.57
Six Months Ended June 30, 2019
United States	115	62	489	258	$	55.84	$	16.12	$	2.04
Eastern Mediterranean	—	—	220	37	—		—		5.55
West Africa ⁽²⁾	11	—	184	42	63.74		—		0.27
Total Consolidated Operations ⁽³⁾	126	62	893	337	56.57		16.12		2.55
Equity Investees ⁽⁴⁾	2	4	—	6	61.02		34.11		—
Total ⁽³⁾	128	66	893	343	$	56.62	$	17.21	$	2.55
Six Months Ended June 30, 2018
United States ⁽⁵⁾	115	63	486	259	$	63.23	$	25.00	$	2.47
Eastern Mediterranean	—	—	243	41	—		—		5.47
West Africa ⁽²⁾	16	—	215	51	70.65		—		0.27
Total Consolidated Operations	131	63	944	351	64.13		25.00		2.74
Equity Investees ⁽⁴⁾	2	5	—	7	71.56		41.61		—
Total	133	68	944	358	$	64.22	$	26.27	$	2.74

⁽¹⁾

On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. This presentation change resulted in increases to revenues, and corresponding increases to production expense, of $2 million and $7 million for second quarter and the first six months of 2018, respectively. See~~Item 1. Financial Statements – Note 2. Basis of Presentation~~.


⁽²⁾	Beginning in first quarter 2018, as part of our Marcellus Shale firm transportation mitigation efforts, we entered into certain transactions for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties.


⁽³⁾	~~Amount relates to the Gulf of Mexico asset sale. See~~ ~~Item 1. Financial Statements - Note3. Acquisitions and Divestitures~~.

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~~Oil, NGL and Gas Sales~~

~~Average daily sales volumes and average realized sales prices, which exclude gains and losses related to commodity derivative instruments, were as follows:~~

Sales Volumes ⁽¹⁾

Average Realized Sales Prices ⁽¹⁾

Crude Oil & Condensate
(MBbl/d)

NGLs
(MBbl/d)

Natural
Gas
(MMcf/d)

Total
(MBoe/d) ⁽²⁾

Crude Oil & Condensate
(Per Bbl)

NGLs
(Per Bbl)

Natural
Gas
(Per Mcf)
Three Months Ended June 30, 2018
United States⁽³⁾
108
62
467
247
$ 64.67
$ 24.46
$ 2.29
Eastern Mediterranean —
—
225
38
—
—
5.46
West Africa ⁽⁴⁾
17
—
225
54
72.79
—
0.27
Total Consolidated Operations 125
62
917
339
65.77
24.46
2.57
Equity Investees ⁽⁵⁾
2
5
—
7
76.07
43.36
—
Total 127
67
917
346
$ 65.93
$ 25.90
$ 2.57
Three Months Ended June 30, 2017
United States 110
63
736
296
$ 45.78
$ 18.79
$ 3.20
Eastern Mediterranean —
—
272
46
—
—
5.34
West Africa ⁽⁴⁾
22
—
231
60
49.53
—
0.27
Total Consolidated Operations 132
63
1,239
402
46.40
18.79
3.13
Equity Investees⁽⁵⁾
2
4
—
6
50.93
34.46
—
Total 134
67
1,239
408
$ 46.49
$ 19.84
$ 3.13
Six Months Ended June 30, 2018
United States ⁽³⁾
115
63
486
259
$ 63.23
$ 25.00
$ 2.47
Eastern Mediterranean —
—
243
41
—
—
5.47
West Africa ⁽⁴⁾
16
—
215
51
70.65
—
0.27
Total Consolidated Operations 131
63
944
351
64.13
25.00
2.74
Equity Investees ⁽⁵⁾
2
5
—
7
71.56
41.61
—
Total 133
68
944
358
$ 64.22
$ 26.27
$ 2.74
Six Months Ended June 30, 2017
United States 105
56
733
283
$ 47.31
$ 21.04
$ 3.32
Eastern Mediterranean —
—
272
46
—
—
5.33
West Africa ⁽⁴⁾
20
—
237
59
51.28
—
0.27
Total Consolidated Operations 125
56
1,242
388
47.95
21.04
3.18
Equity Investees ⁽⁵⁾
2
5
—
7
51.71
35.38
—
Total 127
61
1,242
395
$ 48.01
$ 22.29
$ 3.18


⁽¹⁾	On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. See~~Item 1. Financial Statements – Note 2. Basis of Presentation. This presentation change resulted in the following:~~


◦	~~increases in NGL revenues, and corresponding increases in production expense, of $4 million and $9 million for second quarter 2018 and the first six months of 2018, respectively;~~


◦	~~decreases in natural gas revenues, and corresponding decreases in production expense, of $2 million for both second quarter 2018 and the first six months of 2018;~~


◦	~~increases in NGL and natural gas sales volumes of 5 MBbl/d and 31 MMcf/d, respectively, for both second quarter 2018 and the first six months of 2018, respectively; and~~


◦	reductions in average realized NGL and natural gas sales prices of $1.31/Bbl and $0.11/Mcf, respectively, for second quarter 2018 and $1.09/Bbl and $0.10/Mcf, respectively, for the first six months of 2018.

~~Table of Contents~~

⁽²⁾

Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the prices for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity between reporting periods.


⁽³⁾	~~Includes 3 MBoe/d and 14 MBoe/d for second quarter and the first six months of 2018, respectively, related to Gulf of Mexico assets sold in April 2018. See~~ ~~Item Financial Statements – Note 3. Acquisitions and Divestitures.~~


⁽⁴⁾⁽²⁾	Natural gas from the Alba field ~~in Equatorial Guinea~~ is sold under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity ~~method of accounting.~~method.


⁽⁵⁾⁽³⁾	Includes a small amount of condensate sales from offshore Israel assets.


⁽⁴⁾	Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method ~~Investees,~~ ~~below.~~Investees.


⁽⁵⁾	Includes 3 MBoe/d and 14 MBoe/d for second quarter and the first six months of 2018, respectively, related to Gulf of Mexico assets sold in second quarter 2018. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

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An analysis of revenues from sales of crude oil, NGLs and natural gas ~~and NGLs~~ is as follows:


	Sales Revenues
(millions)	Crude Oil & Condensate			NGLs			Natural Gas			Total			Crude Oil & Condensate			NGLs			Natural Gas			Total
Three Months Ended June 30, 2017	$	557		$	108		$	352		$	1,017
Three Months Ended June 30, 2018													$	749		$	137		$	214		$	1,100
Changes due to
Increase (Decrease) in Sales Volumes													17			4			(10		)	11
Decrease in Sales Prices ⁽¹⁾													(78		)	(57		)	(22		)	(157		)
Three Months Ended June 30, 2019													$	688		$	84		$	182		$	954

Six Months Ended June 30, 2018													$	1,522		$	283		$	468		$	2,273
Changes due to
Decrease in Sales Volumes	(31		)	(10		)	(107		)	(148		)	(53		)	(4		)	(37		)	(94		)
Increase (Decrease) in Sales Prices ⁽¹⁾	223			35			(29		)	229
Impact of ASC 606 Adoption	—			4			(2		)	2
Three Months Ended June 30, 2018	$	749		$	137		$	214		$	1,100

Six Months Ended June 30, 2017	$	1,084		$	213		$	714		$	2,011
Changes due to
Increase (Decrease) in Sales Volumes	49			1			(192		)	(142		)
Increase (Decrease) in Sales Prices ⁽¹⁾	389			60			(52		)	397
Impact of ASC 606 Adoption	—			9			(2		)	7
Six Months Ended June 30, 2018	$	1,522		$	283		$	468		$	2,273
Decrease in Sales Prices ⁽¹⁾													(169		)	(99		)	(20		)	(288		)
Six Months Ended June 30, 2019													$	1,300		$	180		$	411		$	1,891

⁽¹⁾ ~~Changes exclude gains and losses related to commodity derivate instruments.~~


⁽¹⁾	Changes exclude gains and losses related to commodity derivative instruments. See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.

Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales ~~increased~~decreased in second quarter and the first six months of ~~2018~~2019 as compared with ~~2017~~2018 primarily due to the following:


•	decreases in average realized prices for second quarter and the first six months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices);

~~increases of 42% and 34% for second quarter and the first six months of 2018, respectively,~~reduction in ~~average realized prices due to the partial rebalancing of global supply and demand factors; and~~

~~higher US onshore~~ sales volumes of 173 MBbl/d and 2211 MBbl/d for second quarter and the first six months of ~~2018,~~2019, respectively, due to the sale of our Gulf of Mexico assets in second quarter 2018; and

lower West Africa sales volumes of 6 MBbl/d and 5 MBbl/d for second quarter and the first six months of 2019, respectively, due to timing of liftings and natural field decline;

partially offset by:

higher US onshore sales volumes of 12 MBbl/d and 11 MBbl/d for second quarter and the first six months of 2019, respectively, primarily ~~driven by~~due to an increase in development activity in the Delaware ~~Basin~~ and DJ ~~Basin~~Basins.

NGL SalesRevenues Revenuesfrom NGL sales decreased in second quarter and the ~~Clayton Williams Energy acquisition;~~first six months of 2019 as compared with 2018 primarily due to the following:

~~partially offset by:~~


•	decreases in average realized prices for second quarter and the first six months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices); and

lower ~~Gulf of Mexico~~Eagle Ford Shale sales volumes of 198 MBbl/d and 12 MBbl/d for second quarter and the first six months of ~~2018,~~2019, respectively, due to reduced activity and natural field ~~decline as well as the sale of the Gulf of Mexico assets in April 2018; and~~decline;

~~lower offshore Equatorial Guinea~~partially offset by:

higher sales volumes in the DJ and Delaware Basins of 511 MBbl/d and 412 MBbl/d for second quarter and the first six months of ~~2018,~~2019, respectively, due to ~~natural field decline.~~

~~NGL SalesRevenues~~ ~~Revenuesfrom NGL sales increased second quarter and the first six months of 2018 as compared with 2017 due to the following:~~

higher US onshore sales volumes of 4 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) and 13 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) for second quarter and the first six months of 2018, respectively, primarily attributable toan increase in development ~~activities in the southern area of Gates Ranch in the Eagle Ford Shale;~~

~~increases of 37% and 24% in average realized prices for second quarter and the first six months of 2018, respectively, due to the partial rebalancing of domestic supply and demand factors; and~~

~~increases of $4 million and $9 million for second quarter and the first six months of 2018, respectively, associated with the adoption of ASC 606;~~

~~partially offset by:~~

~~lower sales volumes of 9 MBbl/d for second quarter and the first six months of 2018, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.~~

~~Table of Contents~~

activities.

Natural Gas Sales Revenues Revenues from natural gas sales decreased in second quarter and the first six months of ~~2018~~2019 as compared with ~~2017~~2018 primarily due to the following:


•	decreases in average realized prices for second quarter and the first six months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices);

lower Eagle Ford Shale sales volumes of ~~331~~63 MMcf/d and ~~350~~72 MMcf/d for second quarter and the first six months of ~~2018,~~2019, respectively, due to ~~the divestiture of the Marcellus Shale upstream assets in second quarter 2017;~~reduced activity and natural field decline;

lower West Africa sales volumes ~~in Israel due to the sale~~ of ~~a 7.5% interest in the Tamar field;~~

~~lower Gulf of Mexico sales volume of 14~~26 MMcf/d and ~~8 MMcf/d for the second quarter and the first six months of 2018, respectively, due to natural field decline as well as the sale of the Gulf of Mexico assets in April 2018;~~

~~lower sales volumes of 6 MMcf/d and 21~~31 MMcf/d for second quarter and the first six months of ~~2018,~~2019, respectively, ~~from the Alba field, offshore Equatorial Guinea,~~ due to natural field decline and ~~timing~~planned maintenance at onshore facilities during first quarter 2019, which required field shut-in for a portion of ~~field maintenance;~~the period; and

~~decreases~~lower Israel sales volumes of ~~14%~~16 MMcf/d and ~~10% in average realized prices~~23 MMcf/d for second quarter and the first six months of ~~2018,~~2019, respectively, primarily due to planned maintenance and the ~~impact~~sale of ~~increased onshore US supply, as well as wider summer price differentials for both DJ and Delaware Basin volumes;~~a 7.5% interest in the Tamar field in March 2018;

partially offset by:

higher ~~US onshore~~ sales volumes in the DJ and Delaware Basins of 5392 MMcf/d ~~(exclusive of 31~~and 87 MMcf/d ~~from adoption of ASC 606) and 89 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) the~~for second quarter and the first six months of ~~2018,~~2019, respectively, ~~primarily attributable to development activities in the DJ Basin and the southern area of Gates Ranch in the Eagle Ford Shale; and~~

~~higher sales volumes in Israel~~ due to ~~increased demand.~~an increase in development activities.

Sales and Cost of Purchased Oil and Gas ~~Net~~ ~~Beginning in first quarter 2018, we~~ entered into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale natural gas firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. Transportation costs incurred related to utilization of the retained Marcellus Shale firm transportation agreements are recorded within purchases of gas in our consolidated statements of operations. ForIn second quarter and the first six months of ~~2018, the net effect of~~2019, we engaged in third party sales and purchases ~~and sales~~ of ~~natural gas were losses of $7 million and $12 million, respectively.~~

~~Income from Equity Method Investees~~ ~~Equity method investments are included~~crude oil in ~~other noncurrent assets in~~the DJ Basin for flow assurance on pipelines used to deliver our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.production to market.

Income from equity method investees increased during the first six months of 2018 as compared with 2017. The increase includes a $6 million increase from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and a $12 million increase from Alba Plant, our LPG investee, all primarily driven by rising commodity prices.

Table of Contents

Income from Equity Method Investees and OtherIncome from equity method investees and other decreased in first six months of 2019 as compared with 2018. The decrease includes a $20 million decrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and an $19 million decrease from Alba Plant, our LPG investee, primarily due to decreases in average realized methanol and LPG prices and planned maintenance activities.

Production Expense Components of production expense ~~from our E&P operations~~ were as follows:


(millions, except unit rate)	Total per BOE ^{(1) (2)}		Total		United States ⁽²⁾		Eastern Mediter- ranean		West Africa		Total per BOE ⁽¹⁾⁽²⁾		Total		United States ⁽²⁾		Eastern Mediterranean		West Africa
Three Months Ended June 30, 2019
Lease Operating Expense ⁽³⁾											$	4.26	$	133	$	114	$	9	$	10
Production and Ad Valorem Taxes											1.28		40		40		—		—
Gathering, Transportation and Processing											3.97		124		124		—		—
Other Royalty Expense											0.03		1		1		—		—
Total Production Expense											$	9.54	$	298	$	279	$	9	$	10
Total Production Expense per BOE													$	9.54	$	11.64	$	2.82	$	2.47
Three Months Ended June 30, 2018
Lease Operating Expense ⁽³⁾	$	4.47	$	138	$	114	$	5	$	19	$	4.47	$	138	$	114	$	5	$	19
Production and Ad Valorem Taxes	1.56		48		48		—		—		1.56		48		48		—		—
Gathering, Transportation and Processing ⁽⁴⁾	4.31		133		133		—		—
Gathering, Transportation and Processing											4.24		131		131		—		—
Other Royalty Expense	0.33		10		10		—		—		0.33		10		10		—		—
Total Production Expense	$	10.67	$	329	$	305	$	5	$	19	$	10.60	$	327	$	303	$	5	$	19
Total Production Expense per BOE			$	10.67	$	13.55	$	1.47	$	3.84			$	10.60	$	13.46	$	1.47	$	3.84
Three Months Ended June 30, 2017
Six Months Ended June 30, 2019
Lease Operating Expense ⁽³⁾	$	3.54	$	129	$	105	$	6	$	18	$	4.78	$	292	$	239	$	19	$	34
Production and Ad Valorem Taxes	0.89		32		32		—		—		1.42		87		87		—		—
Gathering, Transportation and Processing⁽⁴⁾	3.89		142		142		—		—
Gathering, Transportation and Processing											4.35		266		266		—		—
Other Royalty Expense	0.16		6		6		—		—		0.07		4		4		—		—
Total Production Expense	$	8.48	$	309	$	285	$	6	$	18	$	10.62	$	649	$	596	$	19	$	34
Total Production Expense per BOE			$	8.48	$	10.60	$	1.46	$	3.28			$	10.62	$	12.75	$	2.83	$	4.44
Six Months Ended June 30, 2018
Lease Operating Expense ⁽³⁾	$	4.62	$	293	$	240	$	12	$	41	$	4.62	$	293	$	240	$	12	$	41
Production and Ad Valorem Taxes	1.59		101		101		—		—		1.59		101		101		—		—
Gathering, Transportation and Processing ⁽⁴⁾	4.10		260		260		—		—
Gathering, Transportation and Processing											4.04		256		256		—		—
Other Royalty Expense	0.43		27		27		—		—		0.43		27		27		—		—
Total Production Expense	$	10.74	$	681	$	628	$	12	$	41	$	10.68	$	677	$	624	$	12	$	41
Total Production Expense per BOE			$	10.74	$	13.42	$	1.64	$	4.39			$	10.68	$	13.33	$	1.64	$	4.39
Six Months Ended June 30, 2017
Lease Operating Expense ⁽³⁾	$	3.78	$	265	$	211	$	14	$	40
Production and Ad Valorem Taxes	1.03		72		72		—		—
Gathering, Transportation and Processing ⁽⁴⁾	3.99		280		280		—		—
Other Royalty Expense	0.14		10		10		—		—
Total Production Expense	$	8.94	$	627	$	573	$	14	$	40
Total Production Expense per BOE			$	8.94	$	11.20	$	1.71	$	3.72


⁽¹⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.


⁽²⁾	~~United States E&P~~US production expense includes charges from our midstream operations that are eliminated on a consolidated basis. ~~See~~ ~~Item 1. Financial Statements – Note~~ ~~11. Segment Information~~.


⁽³⁾	Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

⁽⁴⁾

Upon adoption of ASC 606 on January 1, 2018, we changed the presentation for certain of our gathering, transportation and processing expenses in accordance with the control model under the new standard. As such, we reflected increases of $2 million and $7 million to gathering, transportation and processing expense related to US operations for second quarter and the first six months of 2018, respectively. On a per BOE basis, including the increase in production volumes, the presentation change resulted in decreases of $0.46/Boe and $0.35/Boe for US production

Production expense for the second quarter and the first six months of 2018, respectively. No other geographical locations were affected by the presentation change. Comparative information for the prior period has not been recast and continues to be reported under ASC 605, ~~Revenue Recognition, the accounting standard in effect for the prior period.~~

~~For~~ second quarter and the first six months of ~~2018, total production expense increased~~2019 decreased as compared with ~~2017~~2018, primarily due to the following:

an decrease in US production and ad valorem taxes and other royalty expense due to lower commodity prices;

decrease in US lease operating expense and gathering, transportation and processing (GTP) expense due to the sale of our Gulf of Mexico assets; and

decrease in West Africa lease operating expense due to timing of planned maintenance activities and liftings;

partially offset by:

increase in US lease operating expense and GTP expense, primarily due to increased development activities resulting in added production in ~~across each of~~ our ~~onshore US basins;~~DJ and Delaware Basins; and

an increase in ~~US production and ad valorem taxes~~Eastern Mediterranean lease operating expense due to ~~higher commodity prices;~~

an increase in US gathering, transportation and processing expense attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale which led to increased sales volumes; andmaintenance activities.

Table of Contents

~~an increase in~~The unit rate per BOE decreased for second quarter 2019 as compared with 2018 primarily due to cost reduction efforts within the DJ and Delaware Basins realized through workover optimization, contract renegotiation and fuel cost savings while increasing development activity and sales volumes within US onshore basins. Further, production and ad valorem taxes and other royalty expense declined due to lower commodity prices. The unit rate per BOE increased ~~commodity market prices;~~

~~partially offset by:~~

afor the first six months of 2019 as compared with 2018 primarily due to the decrease in ~~first quarter 2018 in US lease operating expense in~~total sales volumes partially resulting from the sales of the Gulf of Mexico ~~due to lower production caused by natural field decline and the subsequent sale of the~~ assets in second quarter ~~2018;~~2018 and

~~decreases~~ the 7.5% interest in ~~US lease operating and gathering, transportation and processing expenses due to~~Tamar in March 2018, coupled with an increase in GTP expense as noted above. Specifically, the ~~divestiture~~impact of the ~~Marcellus Shale upstream~~Gulf of Mexico assets indivestiture was offset by increased US onshore activity.

Exploration Expense Exploration expense for second quarter ~~2017.~~

~~Production~~and the first six months of 2019 totaled $33 million and $57 million, respectively, including staff expense ~~on a per BOE basis increased~~of $12 million and $24 million, respectively. Exploration expense for ~~the~~ second quarter and the first six months of 2018 as compared with 2017 primarily due to the decrease in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets in second quarter 2017, coupled with an increase in certain production expenses noted above. Specifically, the divestiture of the Marcellus Shale upstream assets removed lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in volumes from the Delaware Basintotaled $29 million and ~~Eagle Ford Shale contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production expense per BOE.~~

~~Exploration Expense~~ ~~Exploration expense for the first six months of 2018 totaled~~ $64 million, respectively, including ~~$24~~staff expense of $13 million ~~of lease rental expense primarily in the Delaware Basin~~ and $27 million, ~~of staff expense.~~respectively.

Exploration expense for the first six months of 2017 totaled $72 million, including $18 million of undeveloped leasehold impairment expense related to the impairment of leases in deepwater Gulf of Mexico and $29 million of staff expense.

Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense ~~for our E&P operations~~ was as follows:



(millions, except unit rate)	Total		United States		Eastern Mediterranean		West Africa
Three Months Ended June 30, 2019
DD&A Expense	$	493	$	457	$	17	$	19
Unit Rate per BOE ⁽¹⁾	$	15.80	$	19.07	$	5.33	$	4.69
Three Months Ended June 30, 2018
DD&A Expense	$	435	$	394	$	15	$	26
Unit Rate per BOE ⁽¹⁾	$	14.10	$	17.51	$	4.41	$	5.25
Six Months Ended June 30, 2019
DD&A Expense	$	968	$	896	$	33	$	39
Unit Rate per BOE ⁽¹⁾	$	15.84	$	19.17	$	4.92	$	5.10
Six Months Ended June 30, 2018
DD&A Expense	$	880	$	800	$	28	$	52
Unit Rate per BOE ⁽¹⁾	$	13.87	$	17.10	$	3.82	$	5.56

(millions, except unit rate) Total United
States Eastern
Mediter- ranean
West
Africa
Other Int'l
Three Months Ended June 30, 2018
DD&A Expense $ 435
$ 394
$ 15
$ 26
$ —
Unit Rate per BOE ⁽¹⁾
$ 14.10
$ 17.51
$ 4.41
$ 5.25
$ —
Three Months Ended June 30, 2017
DD&A Expense $ 486
$ 427
$ 19
$ 39
$ 1
Unit Rate per BOE ⁽¹⁾
$ 13.32
$ 15.89
$ 4.62
$ 7.11
$ —
Six Months Ended June 30, 2018
DD&A Expense $ 880
$ 800
$ 28
$ 52
$ —
Unit Rate per BOE ⁽¹⁾
$ 13.87
$ 17.10
$ 3.82
$ 5.56
$ —
Six Months Ended June 30, 2017
DD&A Expense $ 999
$ 886
$ 37
$ 74
$ 2
Unit Rate per BOE ⁽¹⁾
$ 14.25
$ 17.32
$ 4.52
$ 6.88
$ —

~~Table of Contents~~


⁽¹⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

~~Total~~ DD&A expense for second quarter and the first six months of ~~2018 decreased~~2019 increased as compared with ~~2017~~2018, primarily due to the following:

~~year-end reserve additions, primarily~~capital investment and development activities in ~~US onshore~~the Delaware and DJ Basins resulting in higher sales volumes; and

increase in Eastern Mediterranean due to ~~enhanced well design and completion techniques~~the retirement of certain capital assets resulting in accelerated depreciation;

partially offset by:

decrease resulting from the sale of our ~~horizontal drilling program as well as reserve additions in the Tamar field due to well results and geological evaluation, and globally due to positive commodity price revisions;~~

~~the Marcellus Shale upstream divestiture~~Gulf of Mexico assets in second quarter ~~2017, which~~ 2018; and

reduced ~~DD&A expense by $99 million and $118 million~~sales volumes in West Africa, as noted above.

The unit rate per BOE for second quarter and the first six months of 2019 increased as compared with 2018, ~~respectively;~~

~~lower sales volumes in Gulf of Mexico~~primarily due to ~~natural field decline and classification of~~ the ~~assets~~increase in total DD&A expense, as ~~held for sale in first quarter 2018, resulting~~noted above. Specifically, activity increased in the ~~cessation of DD&A expense, together resulting in decreases of $62 million~~higher-cost Delaware and ~~$109 million for second quarter~~DJ Basins and the ~~first six months~~sale of ~~2018, respectively; and~~

~~reclassification of a 7.5% working interest in~~lower-cost Tamar reserves increased the Tamar field, offshore Israel, as asset held for sale at December 31, 2017, resulting in the cessation of DD&A expense and decreases of $3 million and $7 million for second quarter and the first six months of 2018, respectively;

~~partially offset by:~~

~~higher sales volumes in the Delaware Basin, which more than doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017;~~

~~increased development activities in the southern area of Gates Ranch in the Eagle Ford Shale; and~~

~~higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.~~

~~The~~overall unit rate per ~~BOE for second quarter 2018, as compared with 2017, increased due to increased development activity and capital program~~BOE. The increase in the ~~Delaware Basin resulting in a higher depletable basis. The~~ unit rate ~~per BOE for the first six months of 2018, as compared with 2017, decreased due to~~is partially offset by the sale of higher-cost production from the Gulf of Mexico ~~assets. This decrease is partially offset by the sale of lower-cost production from the sale of 7.5% Tamar interest~~assets and lower sales volumes in ~~2018 and the sale of the Marcellus Shale upstream assets in 2017. In addition, an increase in reserves as of December 31, 2017 in Equatorial Guinea also contributed to a decline in unit rate per BOE.~~West Africa.

~~Other Operating Expense, Net~~ ~~See~~ ~~Item 1. Financial Statements – Note~~ ~~2. Basis of Presentation~~ ~~and~~ ~~Item 1. Financial Statements – Note~~ ~~11. Segment Information~~ ~~for discussion of other operating expense items for second quarter and the first six months of 2018 as compared with 2017.~~

(Gain) Loss ~~(Gain)~~ on Commodity Derivative Instruments Loss ~~(gain)~~ on commodity derivative instruments ~~includes (i) cash settlements (received) or paid relating to our crude oil and natural gas~~for the first six months of 2019 decreased as compared with 2018.

For the first six months of 2019, loss on commodity derivative ~~contracts;~~instruments included:

net cash settlement receipts of $15 million; and ~~(ii)~~

net non-cash ~~(increases) or decreases~~decrease of $167 million in the fair ~~values~~value of our ~~crude oil and natural gas~~net commodity derivative ~~contracts.~~liability, primarily driven by changes in the forward commodity price curves for crude oil.

For the first six months of 2018, loss on commodity derivative instruments included:

net cash settlement payment of $93 million; and

net non-cash increase of $235 million in the fair value of our net commodity derivative liability, primarily driven by ~~increases in the forward commodity price curve for crude oil.~~

~~For the first six months of 2017, gain on commodity derivative instruments included:~~

~~net cash settlement receipt of $14 million; and~~

~~net non-cash increase of $153 million in the fair value of our net commodity derivative asset, driven by~~ changes in the forward commodity price curves for ~~both~~ crude ~~oil and natural gas.~~oil.

See Item 1. Financial Statements – Note 4.12. Derivative Instruments and Hedging ~~Activities~~ ~~andNote~~ ~~6. Fair Value Measurements and Disclosures~~.Activities.

~~MIDSTREAM~~

~~The Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins.~~

~~Results of Operations~~

~~Highlights for our Midstream segment were as follows:~~

~~Second Quarter 2018 Significant Midstream Operating Highlights Included:~~

~~commenced gathering services in the Mustang IDP area in the DJ Basin;~~

~~completed construction of the Collier and Billy Miner Train II CGFs in the Delaware Basin;~~

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~~secured long-term dedications, from existing~~RESULTS OF OPERATIONS – MIDSTREAM

The Midstream segment develops, owns and ~~new third party customers, for the Black Diamond system, a large, integrated gathering system~~operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus in the DJ ~~Basin acquired in the Saddle Butte acquisition;~~ and Delaware Basins.

~~received a third party producer's activity set and development plan for Delaware Basin acreage, with gathering services expected to commence in late 2018.~~Results of Operations

Second Quarter ~~2018~~2019 Significant Midstream Operating Highlights and Financial Results Included:

~~net proceeds~~total revenues of ~~approximately $135~~$161 million, ~~received, and gain of $109~~as compared with $155 million ~~recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;~~for second quarter 2018;

pre-tax income of ~~$175~~$46 million, as compared with pre-tax income of ~~$58~~$175 million for second quarter ~~2017; and~~2018;

capital expenditures, excluding acquisitions, of ~~$157~~$52 million, as compared with ~~$88~~$157 million for second quarter ~~2017.~~2018; and

investments in equity method investees of $144 million related primarily to investments in EPIC Y-Grade and EPIC Crude Holdings, as compared with zero for second quarter 2018.

~~Following~~The following is a summarized statement of operations for our Midstream segment:


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2018			2017		2018			2017		2019			2018			2019		2018
Midstream Services Revenues – Third Party	$	15		$	4	$	28		$	4	$	20		$	15		$	44	$	28
Sales of Purchased Oil	42			—		64			—
Income from Equity Method Investees	13			13		25			28
Sales of Purchased Oil and Gas											52			42			85		64
(Loss) Income from Equity Method Investees											(2		)	13			—		25
Intersegment Revenues	85			69		166			127		91			85			197		166
Total Revenues	155			86		283			159		161			155			326		283
Operating Costs and Expenses	27			23		61			42		41			27			77		61
Depreciation and Amortization	22			5		38			10
Gain on Divestitures	(109		)	—		(305		)	—
Purchased Oil	40			—		61			—
Total (Income) Expense	(20		)	28		(145		)	52
Depreciation, Depletion and Amortization											26			22			51		38
Gain on Divestitures, Net											—			(109		)	—		(305		)
Cost of Purchased Oil and Gas											48			40			79		61
Total Expense (Income)											115			(20		)	207		(145		)
Income Before Income Taxes	$	175		$	58	$	428		$	107	$	46		$	175		$	119	$	428

Midstream Services Revenues – Third Party The amount of revenue generated by the ~~midstream business~~Midstream segment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to ~~the~~dedicated acreage for our E&P business and ~~third party~~to third-party customers. These volumes are ~~primarily~~ affected by the level of drilling and completion activity ~~in the areas of E&P operations~~ and by changes in the supply of, and demand for, crude oil, NGLs and natural gas ~~and NGLs~~ in the markets served directly or indirectly by our midstream assets.

~~Total~~Midstream services revenues for second quarter and the first six months of ~~2018~~2019 increased ~~from 2017~~as compared with 2018, primarily due to ~~an increase~~increases in crude oil, natural gas and produced water gathering services ~~revenue~~ and fresh water ~~delivery revenue~~delivery. The increases were due primarily to ~~the~~higher Delaware Basin throughput volumes, commencement of services in the ~~Greeley Crescent~~Mustang IDP ~~area~~in 2018, and ~~Delaware Basin subsequent to second quarter 2017. In addition, fresh water delivery revenue increased due~~services related to the ~~timing of well completion activity in the Mustang IDP area, and sales of purchased crude oil commenced in~~Black Diamond system, which was acquired during first quarter 2018 ~~as a result of~~in the Saddle Butte acquisition.

~~As part~~Sales and Costs of ~~the Saddle Butte acquisition in first quarter 2018, we acquired a large-scale integrated gathering system (Black Diamond gathering system)~~Purchased Oil and ~~associated third party contracts which include transactions~~Gas Sales and costs of purchased oil for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are at the prevailing market prices. For second quarter and the first six months of 2019 increased as compared with 2018 due to a full quarter and six months of services related to the ~~net effect~~Black Diamond system.

(Loss) Income from Equity Method Investees Income from equity method investees decreased for second quarter and the first six months of ~~third party purchases~~2019 as compared with 2018, primarily due to the sale of our investment in CNX Midstream Partners in second quarter 2018 and ~~sales~~operating losses associated with EPIC Y-Grade, EPIC Crude Holdings and Delaware Crossing. Operating losses were primarily due to expenses incurred for the formation of ~~crude oil was de minimis.~~the joint ventures and general and administrative expenses incurred prior to service commencement.

Operating Costs and Expenses ~~Total operating~~Operating costs and expenses for second quarter and the first six months of ~~2018~~2019 increased ~~from 2017~~as compared with 2018, primarily due to an increase in gathering systems ~~and facilities~~ operating expense associated with the ~~the Billy Miner CGF and Jesse James CGF, which commenced operations in the second half of 2017, along with the addition of~~Delaware Basin central gathering facilities (CGF) that were completed during 2018, additional expenses associated with the Black Diamond system and expenses associated with the commencement of gathering ~~system, acquired~~services in the ~~Saddle Butte acquisition~~Mustang IDP in ~~first quarter~~ 2018.

~~Depreciation and amortization~~DD&A Expense DD&A expense for second quarter and the first six months of 2019 increased as compared with 2018, ~~increased from 2017~~primarily due to certain assets being placed in service subsequent to ~~first~~second quarter ~~2017,~~2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full quarter and six months of amortization related to ~~tangible and~~ intangible assets acquired in the Saddle Butte ~~acquisition during first quarter 2018.~~acquisition.

Gain on Divestitures, Net Gain on divestitures, net relates to 2018 sales of our interest in CONE Gathering and a portion of our investment in CNX Midstream ~~Partners common units.~~Partners. See Item 1. Financial Statements –- Note 3.4. Acquisitions and Divestitures.

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RESULTS OF OPERATIONS – CORPORATE

~~Results~~Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of ~~Operations~~our retained Marcellus Shale firm transportation agreements, are recorded at the Corporate level.

Firm Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2019		2018		2019		2018
Sales of Purchased Oil and Gas ⁽¹⁾	$	23	$	24	$	50	$	55
Cost of Purchased Oil and Gas ⁽¹⁾	37		31		79		67
Firm Transportation Exit Cost⁽²⁾	—		—		92		—


⁽¹⁾	Relates to third party mitigation activities we engage in to utilize a portion of our Marcellus Shale firm transportation commitment. Cost of purchased oil and gas includes utilized and unutilized transportation expense.


⁽²⁾	Represents exit costs related to future commitments to a third party resulting from a permanent capacity assignment.

See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.

General and Administrative (G&A) Expense ~~General and administrative~~G&A expense ~~(G&A)~~ was as follows:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(millions, except unit rate)	2018		2017		2018		2017		2019		2018		2019		2018
G&A Expense	$	105	$	103	$	209	$	202	$	105	$	105	$	207	$	209
Unit Rate per BOE ⁽¹⁾	$	3.40	$	2.82	$	3.29	$	2.88	$	3.36	$	3.40	$	3.39	$	3.29


⁽¹⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

G&A expense for second quarter and the first six months of ~~2018 increased~~2019 remained flat as compared with ~~2017. This increase was driven by increased employee costs and~~2018 primarily due to decreases in third party transaction-related fees ~~in support of our development projects,~~ partially offset by aincreases in employee costs. The decrease in ~~contractor expenses.~~the unit rate per BOE for second quarter 2019 as compared with 2018 was due to the increase in total sales volumes. The increase in the unit rate per BOE for the first six months of ~~2018~~2019 as compared with ~~2017~~2018 was due ~~primarily~~ to the ~~increase in total G&A expense combined with the~~net decrease in total sales volumes ~~due to the divestiture~~primarily as a result of the ~~Marcellus Shale upstream~~sale of our Gulf of Mexico assets and the sale of 7.5% interest in ~~second quarter 2017.~~

~~Other Operating Expense, Net~~ the Tamar field. See ~~Item 1. Financial Statements~~Results of Operations – ~~Note~~ Exploration & Production~~2. Basis of Presentation~~ ~~and~~ ~~Item 1. Financial Statements – Note~~ ~~11. Segment Information~~ ~~for discussion of other operating expense items for second quarter and the first six months of 2018 as compared with 2017.~~.

Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(millions, except unit rate)	2018			2017			2018			2017			2019			2018			2019			2018
Interest Expense, Gross	$	91		$	107		$	181		$	206		$	90		$	91		$	177		$	181
Capitalized Interest	(18		)	(11		)	(35		)	(23		)	(27		)	(18		)	(48		)	(35		)
Interest Expense, Net	$	73		$	96		$	146		$	183		$	63		$	73		$	129		$	146
Unit Rate per BOE ⁽¹⁾	$	2.37		$	2.63		$	2.30		$	2.61		$	2.02		$	2.37		$	2.11		$	2.30


⁽¹⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

Interest expense, gross, for second quarter and the first six months of ~~2018 decreased~~2019 remained flat as compared with 2017 primarily due to a decrease in the overall debt balance. Specifically, subsequent to second quarter 2017, we repaid $550 million on our Term Loan Facility due January 6, 2019 and during the first six months of 2018, we repaid $379 million of Senior Notes due May 1, 2021. In addition, in second quarter 2017, we conducted a tender offer and subsequent redemption of our 8.25% Senior Notes, resulting in a lower interest rate and lower interest expense, gross. These were partially offset by an increase of $445 million in the amount outstanding under our Noble Midstream Services Revolving Credit Facility.2018. See Item 1. Financial Statements -– Note ~~5. Debt~~7. Debt..

Capitalized interest for second quarter and the first six months of ~~2018~~2019 increased as compared with ~~2017~~2018, primarily due to higher work in progress amounts related to the Leviathan ~~development. See~~ ~~Item 1. Financial Statements - Note~~ ~~7. Capitalized Exploratory Well Costs~~development and ~~Undeveloped Leasehold Costs~~.investments in equity method investees engaged in construction activities.

The unit rate ~~of interest expense, net,~~ per BOE for second quarter and the first six months of ~~2018~~2019 decreased as compared with ~~2017~~2018, primarily due to the ~~changes~~reduction in net interest expense, noted above, partially offset by the net decrease in total sales volumes.

LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout ~~the~~ commodity price ~~cycle,~~cycles, including a sustained period of low prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially

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attractive merger and acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.

We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of ~~our~~ liquidity are cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, and available borrowing capacity under our $4.0 billion unsecured ~~revolving credit facility (Revolving~~Revolving Credit ~~Facility) and proceeds from divestitures of properties.~~Facility. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt maturities.

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Given our investment grade credit rating, we established a $4.0 billion commercial paper program in first quarter 2019. This program can be accessed as needed to supplement operating cash flows for short-term funding needs. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

~~maturities.~~ We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. ~~See~~ ~~Operating Outlook – Impact~~Additionally, we enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of ~~Recent Changes in US Tax Law~~.

~~Our portfolio transformation strategy, primarily executed during 2017, has continued into 2018, with~~commodity price volatility and enhance the ~~sales~~predictability of ~~Gulf~~cash flows relating to the marketing of ~~Mexico assets, a 7.5% working interest in Tamar, our 50% interest in CONE Gathering LLC and~~ a portion of our ~~investment~~crude oil and natural gas production.

Thus far in ~~CNX Midstream Partners common units. As a result, our divestitures~~2019, we have ~~generated cash proceeds of approximately $3.5 billion during 2017-2018 and were used to improve our capital structure and strengthen our liquidity profile.~~

~~We strive to fund~~funded our capital program ~~through organic~~with cash flows from operations, cash on hand, commercial paper borrowings, and ~~when needed, utilize borrowings under our Revolving Credit Facility.~~

Asproceeds from divestments of ~~June 30, 2018, our outstanding debt (excluding capital lease obligations) totaled $6.4 billion.~~non-strategic assets. We may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in open market purchases, privately negotiated transactions or otherwise. Such repurchases, ifdid not repurchase any ~~will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be significant.~~

~~Second Quarter and Year-to-Date 2018 Highlights~~

During second quarter 2018, we continued to focus efforts on shareholder return initiatives, including share repurchases and dividend growth, as well as debt reduction with the following actions completed:

~~redemption of $379 million in outstanding senior notes;~~

~~acquisition of 1.8 million~~ shares of Noble Energy common stock ~~for $63 million, resulting in year to date repurchases of 4.0 million shares for $130 million, pursuant to~~under the Board of ~~Directors' authorized~~Directors-authorized $750 million share repurchase ~~program; and~~

~~announcement in July 2018 of an August 2018 dividend of 11 cents per common share, which continues the 10% increase over 2017.~~

~~In addition,~~program during the first six months of ~~2018,~~2019.

Second Quarter 2019 Highlights

During second quarter 2019, we completed the following financing activities:

~~repaid all amounts outstanding~~borrowed $240 million, net, under ~~the Revolving Credit Facility;~~our $4.0 billion commercial paper program for working capital purposes; and

~~extended the Revolving Credit Facility maturity date by two and a half years to March 2023;~~

~~amended~~borrowed $140 million, net, under the Noble Midstream Services Revolving Credit Facility primarily to ~~increase the capacity from $350 million~~fund contributions to ~~$800 million; and~~equity method investees.

~~extended the maturity date of the Noble Midstream Services Revolving Credit Facility by one and a half years to March 2023.~~

Also, during the first six months of 2018, we repatriated $404 million in payments from foreign operations on an outstanding note payable. This payment eliminates the balance on the note payable and has no US tax impact.Available Liquidity

~~Available Liquidity~~

~~Information regarding~~The following table summarizes our cash, debt and ~~debt balances is shown in the table below:~~available liquidity:

June 30, December 31,
(millions, except percentages) 2018 2017
Total Cash ⁽¹⁾
$ 621
$ 713
Amount Available to be Borrowed Under Revolving Credit Facility ⁽²⁾
4,000
3,770
Total Liquidity $ 4,621
$ 4,483
Total Debt ⁽³⁾
$ 6,663
$ 6,859
Noble Energy Share of Equity 10,252
9,936
Ratio of Debt-to-Book Capital ⁽⁴⁾
39 % 41 %

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	June 30, 2019							December 31, 2018
(millions, except percentages)	Noble Energy Excluding Noble Midstream Partners		Noble Midstream Partners		Total			Noble Energy Excluding Noble Midstream Partners		Noble Midstream Partners		Total
Total Cash ⁽¹⁾	$	593	$	9	$	602		$	707	$	12	$	719
Amounts Available for Borrowing ⁽²⁾	3,760		—		3,760			4,000		—		4,000
Total Liquidity	$	4,353	$	9	$	4,362		$	4,707	$	12	$	4,719

Total Debt ⁽³⁾	$	6,335	$	870	$	7,205		$	6,115	$	560	$	6,675
Noble Energy Share of Equity					$	9,029						$	9,426
Ratio of Debt-to-Book Capital ⁽⁴⁾					44		%					41		%


⁽¹⁾	As of June 30, 2019 and December 31, 2018, total cash ~~included cash~~includes $132 million and ~~cash equivalents~~$3 million of ~~$15 million related to Noble Midstream Partners. As of December 31, 2017, total cash included $18 million cash of Noble Midstream Partners and $38 million~~ restricted cash, ~~related to the Saddle Butte acquisition that closed first quarter 2018.~~respectively.


⁽²⁾	Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, ~~and Leviathan Term Loan Facility,~~ which ~~are~~is not available to Noble Energy for general corporate purposes. ~~See discussion below.~~


⁽³⁾	Total debt ~~includes capital lease obligations and~~ excludes unamortized debt discount/~~premium.~~premium and debt issuance costs. See Item 1. Financial Statements – Note ~~5. Debt~~.7. Debt.


⁽⁴⁾	We define our ratio of debt-to-book capital as total debt ~~(which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings)~~ divided by the sum of total debt plus Noble Energy's share of equity.

Cash and Cash Equivalents We had approximately ~~$621~~$470 million in unrestricted cash and cash equivalents at June 30, ~~2018,~~2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately ~~$428~~$435 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur any significant US income tax expense with respect to future repatriation of foreign cash.

Revolving Credit Facilities Noble Energy's $4.0 billion Revolving Credit Facility ~~of $4.0 billion matures in 2023. The~~and the $800 million Noble Midstream Services Revolving Credit Facility ~~of $800 million also matures~~both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. ~~At June 30, 2018, no amounts were outstanding under~~Because the Revolving Credit Facility and $530 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $4.0 billion and $270 million in remaining availability under the respective credit facilities. See ~~Item 1. Financial Statements – Note 6. Debt~~.

~~Leviathan Term Loan Facility~~ ~~The Leviathan Term Loan Facility provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million~~commercial paper program is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the Leviathan development program and to bring first production online by the end of 2019, we may borrow amounts under this facility in the near-term. As of June 30, 2018, no amounts were drawn under this facility.

~~Legacy Rosetta Note Redemption~~ In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021, that we had assumed in the Rosetta Merger, for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium, and recognized a gain of $5 million for the unamortized premium.

~~Interest Rate Risk~~ ~~Certain of our borrowings subject us to interest rate risk. See~~ ~~Item 1. Financial Statements – Note~~ ~~5. Debt~~ ~~andItem 3. Quantitative and Qualitative Disclosures About Market Risk.~~

~~Subsequent Event - Noble Midstream Services Term Credit Agreement~~ On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries. See ~~Item 1. Financial Statements – Note~~ ~~5. Debt.~~

~~Contractual Obligations~~

~~Exploration Commitments~~ The terms of some of our production sharing contracts, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.

~~Leviathan Development Obligations~~ The initial development of our Leviathan field requires substantial infrastructure and capital, and we have executed major equipment and installation contracts in support of our development activities. As of June 30, 2018, we had entered into approximately $235 million, net, of contracts to support the remaining development activities and bring first production online by the end of 2019.

~~Continuous Development Obligations~~Although the majority of our assets are held by production, certain of our US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas, the amount of which could be substantial, or exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases.

~~EPIC Firm Transportation Agreement~~ During second quarter 2018, we dedicated acreage to, and secured firm capacity with, EPIC for transport of 100 MBbl/d of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up.

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supported by the Revolving Credit Facility, outstanding commercial paper borrowings of $240 million at June 30, 2019 reduced the amount available for borrowing to $3.8 billion. Additionally, at June 30, 2019, $370 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $430 million available under the facility.

Commercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by the Revolving Credit Facility. As of June 30, 2019, $240 million of commercial paper borrowings were outstanding. See Item 1. Financial Statements – Note 7. Debt.

GIP Preferred Equity Commitment In March 2019, Noble Midstream Partners secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary holding Noble Midstream Partners’ 30% equity interest in EPIC Crude Holdings. Of the $200 million total commitment, $100 million was funded, with the remaining $100 million available for a one-year period, subject to certain conditions precedent. See Item 1. Financial Statements – Note4. Acquisitions and Divestitures.

Contractual Obligations

Marcellus Shale Firm Transportation Agreements We have remaining financial commitments of approximately ~~$1.4~~$1.0 billion, undiscounted, associated with Marcellus Shale firm transportation contracts. We have engaged in actions to commercialize a substantial portion of these commitments, which provide for the transportation of approximately 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements.

We expect these actions, some of which may require pipeline and/or FERC approval, to continue to reduce our financial commitment associated with these contracts. For pipelines currently under construction and targeted for in-service late 2018, we will evaluate our position at the date each pipeline is placed in service and our commitment begins. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment. These contracts represent approximately $890 million, undiscounted, of the total $1.4 billion commitment noted above. See Item 1. Financial Statements – Note ~~12.~~9. Exit Cost – Transportation Commitments ~~and Contingencies~~.

Letters of Credit ~~Rating Events~~ ~~We do not have any triggering events on our consolidated debt that would cause~~In the ordinary course of business, we maintain letters of credit and bank guarantees with a ~~default~~variety of banks in ~~case~~support of ~~a downgrade~~certain performance obligations of our subsidiaries. Outstanding letters of credit ~~rating. In addition, there are no existing ratings triggers in any~~and bank guarantees, including those of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.Noble Midstream Partners, totaled approximately $99 million at June 30, 2019.

Cash Flows

~~Summary~~The following table summarizes our total cash ~~flow information is as follows:~~provided by (used in) operating, investing and financing activities:


	Six Months Ended June 30,						Six Months Ended June 30,
(millions)	2018			2017			2019			2018
Total Cash Provided By (Used in)
Operating Activities	$	1,079		$	877		$	1,092		$	1,079
Investing Activities	(1,050		)	(1,121		)	(1,697		)	(1,050		)
Financing Activities	(121		)	(426		)	488			(121		)
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	$	(92	)	$	(670	)
Decrease in Cash, Cash Equivalents and Restricted Cash							$	(117	)	$	(92	)

Operating Activities Cash provided by operating activities ~~increased~~ for the first six months of ~~2018~~2019 increased $13 million as compared with ~~2017 by approximately $202 million.~~2018. The increase iswas primarily driven by cash settlements for commodity derivatives of $15 million, as compared with cash payments of $93 million in 2018, increase in accounts payable due to ~~higher realized crude oil prices and an~~timing of payments, increase in ~~crude oil production~~partner advances of $132 million and a decrease of $133 million in ~~the DJ and Delaware basins. In addition, changes in working capital included a significant~~assets held for sale. The increase ~~in the balance of the current portion of the commodity derivatives liability.~~

~~These increases were~~was partially offset by ~~lower realized natural gas prices,~~ a decrease in ~~natural gas production attributable to our exit from the Marcellus Shale~~net revenues driven by lower commodity prices and a reduction in ~~second quarter 2017, and higher production costs attributable to increased US onshore activity.~~sales volumes.

Investing Activities ~~Our~~Cash used in investing activities ~~include capital spending on a cash basis~~increased $647 million for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that occurred in prior periods.

~~Total additions to property, plant and equipment increased $567 million during~~ the first six months of ~~2018~~2019 as compared with ~~2017~~2018, primarily due to ~~increases~~a decrease in ~~spending related to development costs in the Delaware Basin, construction of midstream infrastructure and Leviathan development costs,~~net proceeds provided by divestitures, partially offset by ~~decreases~~a decrease in ~~development costs primarily~~capital spending for property, plant and equipment. In addition, Noble Midstream Partners invested $415 million in ~~the Marcellus Shale and Eagle Ford Shale. See~~ ~~Operating Outlook – 2018 Capital Investment Program, above.~~

~~During~~equity method investees. There were no acquisitions for the first six months of ~~2018, we completed certain portfolio activities including the Saddle Butte acquisition for~~2019 compared to $650 million ~~net. Also during the first six months of 2018, we received net proceeds of $1.4 billion from asset sales, including the sale of our Gulf of Mexico assets, a 7.5% interest~~ in the ~~Tamar field, our 50% interest in CONE Gathering LLC and a portion of our CNX Midstream Partners common units.~~

In comparison, during the first six months of 2017, we used $637 million of cash to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition and acquired Delaware Basin assets for $301 million. We received net cash proceeds of $1.0 billion from the Marcellus Shale upstream divestiture, and other investing activities provided net cash of $33 million.prior year.

Financing Activities Our financing activities ~~in general, include debt transactions,~~during the ~~issuance and repurchase~~first six months of ~~Noble Energy common stock and~~2019 included net borrowings of $240 million under the commercial paper program, net borrowings of $310 million on the Noble Midstream ~~Partners common units, payment~~Services Revolving Credit Facility and the receipt of $99 million of GIP preferred equity, net of offering costs. In addition, during the first six months of 2019, we paid $111 million of cash dividends to Noble Energy ~~shareholders, and payment~~shareholders. Other financing activities used net cash of ~~cash distributions to, and receipt of cash contributions from, Noble Midstream Partners noncontrolling interest owners.~~$50 million.

~~Table of Contents~~

Our ~~primary~~ financing activities during the first six months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $445 million, net, Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund anthe Saddle Butte acquisition. ~~We also~~During the first six months of 2018, we used $384 million of cash to redeem senior notes, ~~which had accrued interest~~repurchased $130 million of ~~$11 million and is reflected within operating activities.~~

~~In addition, during the first six months of 2018, we made~~ common stock ~~repurchases totaling $130 million~~ pursuant to our stock repurchase program, paid $102 million of cash dividends to Noble Energy shareholders and paid $22 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $331 million of contributions from noncontrolling interest owners. Other financing activities used net cash of $29 million.

In comparison, during the first six months of 2017, we borrowed and repaid $1.3 billion under our Revolving Credit Facility and borrowed a net $190 million under the Noble Midstream Services Revolving Credit Facility. We also repaid $595 million of assumed Clayton Williams Energy debt. We used cash of $92 million to pay dividends on our common stock and $12 million to pay distributions to noncontrolling interest owners. We received $138 million of net cash from the issuance of Noble Midstream Partners common units.

See Item 1. Financial Statements – Consolidated Statements of Cash Flows.

~~Dividends~~Table of Contents

Capital Expenditure Activities

Our capital expenditures (on an accrual basis) were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2019		2018		2019		2018
Unproved Property Acquisition ⁽¹⁾	$	4	$	9	$	39	$	13
Proved Property Acquisition ⁽¹⁾	—		—		4		—
Exploration and Development	582		762		1,210		1,414
Midstream⁽²⁾	52		157		118		616
Corporate and Other	13		16		31		27
Total	$	651	$	944	$	1,402	$	2,070
Other
Investment in Equity Method Investees ⁽³⁾	$	144	$	—	$	415	$	—
Increase in Finance Lease Obligations	1		—		3		—


⁽¹⁾	Costs for second quarter and the first six months of 2019 relate to US onshore leasehold activity.


⁽²⁾	Midstream expenditures for the six months ended June 30, 2018 include $206 million related to the Saddle Butte acquisition.


⁽³⁾	Costs for the six months ended June 30, 2019 primarily include Noble Midstream Partners' $369 million investment in EPIC Y-Grade and EPIC Crude Holdings and $39 million investment in Delaware Crossing. See Item 1. Financial Statements – Note4. Acquisitions and Divestitures.

Exploration and development costs for second quarter and the first six months of 2019 decreased as compared with 2018, due to our focus on US onshore capital efficiencies and the near-term completion of Leviathan development activities. Year to date exploration and development costs include approximately $940 million for US onshore and $251 million for Eastern Mediterranean, primarily related to Leviathan.

Midstream capital spending, excluding acquisitions, for second quarter and the first six months of 2019 decreased as compared with 2018. 2019 activities focused primarily on well connections in the DJ and Delaware Basins, as well as expansion of the Mustang IDP gathering system. 2018 activities included construction and commencement of services for the Mustang IDP gathering and fresh water systems, Delaware Basin CGFs, and connecting the Black Diamond system to a major crude oil takeaway outlet in the DJ Basin.

Dividends

On July ~~24, 2018,~~23, 2019, our Board of Directors declared a quarterly cash dividend of 1112 cents per Noble Energy common share, which will be paid on August ~~20, 2018~~19, 2019 to shareholders of record on August ~~6, 2018.~~5, 2019. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

~~Capital Expenditure Activities~~ ~~The following presents our capital expenditures (on an accrual basis) for the second quarter and the first six months of 2018 and 2017:~~

Three Months Ended June 30, Six Months Ended June 30,
(millions) 2018 2017 2018 2017
Acquisition, Capital and Exploration Expenditures

Unproved Property Acquisition ⁽¹⁾
$ —
$ 1,581
$ —
$ 1,826
Proved Property Acquisition ⁽²⁾
—
782
—
840
Exploration and Development 771
605
1,427
1,199
Midstream ⁽³⁾
157
152
616
245
Corporate and Other 16
10
27
15
Total $ 944
$ 3,130
$ 2,070
$ 4,125
Investment in Equity Method Investee ⁽⁴⁾
$ —
$ 67
$ —
$ 67

⁽¹⁾~~2017 acquisition costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin acquisition.~~

⁽²⁾2017 acquisition costs include $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.

⁽³⁾ Midstream expenditures for the six months ended June 30, 2018 include $206 million related to the Saddle Butte acquisition. Midstream expenditures for the first six months of 2017 include $67 million related to the Clayton Williams Energy Acquisition.

⁽⁴⁾~~2017 costs represent our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.~~

Development costs for second quarter and the first six months of 2018 increased as compared with second quarter and the first six months of 2017 due to increased US onshore activity and Leviathan development activities. Year to date development costs include approximately $1.1 billion for US onshore E&P operations and approximately $350 million for Leviathan. The increase in development costs was partially offset by a decrease due to the 2017 Marcellus Shale divestiture. In addition, midstream capital spending, exclusive of acquisitions, increased due to the construction of gathering systems in the DJ and Delaware Basins.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We are exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ~~- E&P~~– Results of Operations – Exploration & Production~~, above.~~.

Derivative Instruments Held for Non-Trading Purposes ~~Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.~~

~~Table of Contents~~

At June 30, 2018, we had various open commodity derivative instruments related to crude oil and natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our2019, our open commodity derivative instruments were in a net liability position with a fair value of ~~$306~~$14 million. Based on the June 30, ~~2018~~2019 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately ~~$280~~$146 million. ~~Our derivative instruments are executed under master agreements which allow us,~~Even with certain hedging arrangements in place to mitigate the ~~event~~risk of ~~default, to elect early termination~~commodity price volatility, our 2019 revenues and results of ~~all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would~~operations could be ~~net cash settled at the time of election.~~adversely affected if commodity prices decline. See Item 1. Financial Statements – Note 4.12. Derivative Instruments and Hedging ~~Activities~~.Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on certain of our ~~borrowings~~borrowings. Issuances of commercial paper under our commercial paper program and ~~the amount of interest we earn on our short-term investments.~~

At June 30, 2018, we had approximately $6.4 billion (excluding capital lease obligations) of long-term debt outstanding, net of unamortized discount and debt issuance costs. Of this amount, $5.8 billion was fixed-rate debt, net of unamortized discount and debt issuance costs, with a weighted average interest rate of 5.06%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.

However, we are exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2018, our cash and cash equivalents totaled $621 million, approximately 46% of which was invested in money market funds and short-term investments with major financial institutions.

~~In addition,~~ borrowings under the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and ~~Leviathan~~Noble Midstream Services Term Loan Credit Facility, which as of June 30, 2019 total $1.1 billion and have a weighted average interest rate of 3.50%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. ~~A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost.~~ While we currently have no interest rate derivative

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instruments as of June 30, ~~2018,~~2019, we may invest in such instruments in the future in order to mitigate interest rate risk.

A change in the interest rate applicable to ~~our short-term investments or~~ amounts, if any, outstanding under the ~~Noble Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility~~facilities or ~~Leviathan Term Loan Facility~~commercial paper issuances mentioned above, would have had a de minimis ~~impact.~~impact on interest expense for second quarter and the first six months of 2019. See Item 1. Financial Statements – Note 5.7. Debt.

~~Foreign Currency Risk~~

The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain local working capital items, are denominated in a foreign currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. Furthermore, our investment in Tamar Petroleum is denominated and settled in New Israeli Shekels.

~~Net transaction gains and losses were de minimis for the second quarter and the first six months of 2018.~~

We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.

Disclosure Regarding Forward-Looking Statements

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:

our growth strategies;

our future results of operations;

our liquidity and ability to finance our exploration and development ~~and acquisitions~~ activities;

~~our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;~~

~~our ability to make and integrate acquisitions;~~

our ability to successfully and economically explore for and develop crude oil, NGL and natural gas ~~and NGL~~ resources;

anticipated trends in our business;

~~Table of Contents~~

market conditions in the oil and gas industry;

the impact of governmental ~~fiscal~~ regulation, including US federal, state, local, and foreign host government tax regulations, ~~and/or~~fiscal policies and terms, ~~such~~ as ~~those~~well as that involving the protection of the environment or marketing of production ~~as well as~~and other regulations;

our ability to make and integrate acquisitions or execute divestitures; and

access to resources.

Any such projections or statements reflect Noble Energy’s views (as of the date such ~~projects~~projections were published or such statements were made) about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, information technology and security risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 and in this quarterly report on Form 10-Q, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 is available on our website at www.nblenergy.com.

Item 4. Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), are effective. There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.

Part II. Other Information

Item 1. Legal Proceedings

See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements -– Note ~~12.~~10. Commitments and Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1, as well as discussion in Item 3. Legal Proceedings, of our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~Table of Contents~~

The following table sets forth, for the periods indicated, our share repurchase activity:

Period
Total Number of
Shares
Purchased ⁽¹⁾

Average
Price Paid
Per Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs⁽²⁾

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
(millions)
4/1/2018 - 4/30/2018 216
$ 31.72
—

5/1/2018 - 5/31/2018 837,995
32.84
837,418

6/1/2018 - 6/30/2018 941,779
35.65
941,502

Total 1,779,990
$ 34.33
1,778,920
$ 620



Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(millions)
4/1/2019 - 4/30/2019	1,467	$	25.64	—
5/1/2019 - 5/31/2019	132	24.55		—
6/1/2019 - 6/30/2019	462	21.36		—
Total	2,061	$	24.61	—	$	455


⁽¹⁾	~~Includes stock~~Stock repurchases ~~of 1,070~~ during the period ~~relating~~related to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.


⁽²⁾	During second quarter ~~2018,~~2019, we ~~repurchased and retired 1.8 million~~did not repurchase shares ~~of common stock at an average purchase price of $35.15 per share pursuant to~~under the $750 million share repurchase program, authorized by ~~our~~the Board of Directors and announced on February 15, 2018, which expires December 31, 2020.

~~Table of Contents~~

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit Number		Exhibit*

2.1		Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K ~~(Date of Report: January 13, 2017)~~ filed on January 17, 2017 (File No. 001-07964) and incorporated herein by reference).

2.2		Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (Date of Report: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference).

~~2.3~~		Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (File No. 001-07964) and incorporated herein by reference).

3.1		Restated Certificate of Incorporation of Noble Energy Inc., (filed as Exhibit 3.3 to the Registrant’s Current Report on Form 8-K ~~(Date of Report: July 26, 2016)~~ filed on July 28, 2016 (File No. 001-07964) and incorporated herein by reference).

3.2		By-Laws of Noble Energy, Inc. (as amended through ~~January 30, 2018) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 30, 2018) filed on~~ February ~~1, 2018 and incorporated herein by reference).~~

~~3.3~~		Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

~~3.4~~		~~Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc.~~5, 2019) (filed as Exhibit 3.2 to the Registrant’s ~~Current~~Annual Report on Form ~~8-K (Date of Report: July 26, 2016)~~10-K filed on ~~July 28, 2016~~February 19, 2019 (File No. 001-07964) and incorporated herein by reference).

10.1*		Noble Energy, Inc. ~~Short-Term~~2017 Long-Term Incentive Plan ~~filed herewith.~~(Amended and Restated Effective April 23, 2019) (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).

~~12.1~~10.2*		~~Calculation~~Form of ~~ratio~~Restricted Stock Notice and Award Agreement (three-year vested one-third per year) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).

10.3*		Form of ~~earnings~~Option Award Notice and Agreement under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.3 to ~~fixed charges, filed herewith.~~the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).

10.4*		Form of Restricted Stock Notice and Award Agreement (three-year cliff vested) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).

10.5*		Form of Restricted Stock Notice and Award Agreement (three-year vested 20/30/50) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).

31.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.

31.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.

32.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.

32.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.

101.INS		Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

101.DEF		XBRL Definition Linkbase Document

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*	* Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
**	Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		NOBLE ENERGY, INC.
		(Registrant)

Date	August ~~3, 2018~~2, 2019	~~/s/~~By: /s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

5342



(millions)
Fair Value of Common Stock Issued	$	1,851
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders	637
Total Purchase Price	$	2,488
Plus Liabilities Assumed by Noble Energy:
Accounts Payable	99
Other Current Liabilities	38
Long-Term Deferred Tax Liability	515
Long-Term Debt	595
Asset Retirement Obligations	63
Total Purchase Price Plus Liabilities Assumed	$	3,798



				Swaps					Collars
Settlement Period	Type of Contract	Index	Bbls Per Day	Weighted Average Differential			Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2018	Swaps	NYMEX WTI	66,000	$	—		$	60.30	$	—	$	—	$	—
2018	Collars	NYMEX WTI	18,000	—			—		—		50.42		58.82
2018	Three-Way Collars	NYMEX WTI	10,000	—			—		45.50		52.50		69.09
2018	Three-Way Collars	Dated Brent	3,000	—			—		40.00		50.00		70.41
2018	Swaps	ICE Brent	2,000	—			59.00		—		—		—
2018	Collars	ICE Brent	2,000	—			—		—		50.00		55.25
2018	Three-Way Collars	ICE Brent	5,000	—			—		43.00		50.00		59.50
2018	Basis Swaps	⁽¹⁾	20,000	(2.30		)	—		—		—		—
2019	Swaps	NYMEX WTI	44,000	—			58.37		—		—		—
2019	Three-Way Collars	NYMEX WTI	6,000	—			—		50.00		60.00		72.75
2019	Swaps	ICE Brent	5,000	—			57.00		—		—		—
2019	Three-Way Collars	ICE Brent	3,000	—			—		43.00		50.00		64.07
2019	Basis Swaps	⁽¹⁾	27,000	(3.23		)	—		—		—		—
2020	Swaption ⁽²⁾	NYMEX WTI	5,000	—			61.79		—		—		—
2020	Basis Swaps	⁽¹⁾	15,000	(5.01		)	—		—		—		—



	Fair Value of Derivative Instruments
	Asset Derivative Instruments						Liability Derivative Instruments
	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments	Current Assets	$	29	Current Assets	$	2	Current Liabilities	$	250	Current Liabilities	$	58
	Noncurrent Assets	—		Noncurrent Assets	—		Noncurrent Liabilities	85		Noncurrent Liabilities	15
Total		$	29		$	2		$	335		$	73



	Fair Value Measurements Using
(millions)	Quoted Prices in Active Markets (Level 1) ⁽¹⁾			Significant Other Observable Inputs (Level 2) ⁽²⁾			Significant Unobservable Inputs (Level 3) ⁽³⁾		Adjustment ⁽⁴⁾			Fair Value Measurement
June 30, 2018
Financial Assets:
Mutual Fund Investments	$	57		$	—		$	—	$	—		$	57
Commodity Derivative Instruments	—			72			—		(43		)	29
Investment in Tamar Petroleum Ltd. (38,495,575 Shares)⁽⁵⁾	—			150			—		—			150
Financial Liabilities:
Commodity Derivative Instruments	—			(378		)	—		43			(335		)
Portion of Deferred Compensation Liability Measured at Fair Value	(73		)	—			—		—			(73		)
Stock Based Compensation Liability Measured at Fair Value	(12		)	—			—		—			(12		)
December 31, 2017
Financial Assets:
Mutual Fund Investments	$	57		$	—		$	—	$	—		$	57
Commodity Derivative Instruments	—			7			—		(5		)	2
Financial Liabilities:
Commodity Derivative Instruments	—			(78		)	—		5			(73		)
Portion of Deferred Compensation Liability Measured at Fair Value	(71		)	—			—		—			(71		)
Stock Based Compensation Liability Measured at Fair Value	(10		)	—			—		—			(10		)



(millions)	Six Months Ended June 30, 2018
Capitalized Exploratory Well Costs, Beginning of Period	$	520
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	4
Divestitures ⁽¹⁾	(167		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(1		)
Capitalized Exploratory Well Costs Charged to Expense	—
Capitalized Exploratory Well Costs, End of Period	$	356



Purchased Oil and Gas	71			31			—			—			—			40			—			—
Loss on Commodity Derivative Instruments	249			196			—			53			—			—			—			—
(Loss) Income Before Income Taxes	10			(90		)	62			48			(13		)	175			(18		)	(154		)

Three Months Ended June 30, 2017
Crude Oil Sales	$	557		$	458		$	1		$	98		$	—		$	—		$	—		$	—
NGL Sales	108			108			—			—			—			—			—			—
Natural Gas Sales	352			214			132			6			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,017			780			133			104			—			—			—			—
Income from Equity Method Investees and Other	42			—			—			25			—			17			—			—
Intersegment Revenues	—			—			—			—			—			69			(69		)	—
Total Revenues	1,059			780			133			129			—			86			(69		)	—
Lease Operating Expense	124			105			6			18			—			—			(5		)	—
Production and Ad Valorem Taxes	32			32			—			—			—			—			—			—
Gathering, Transportation and Processing Expense	121			142			—			—			—			17			(38		)	—
Other Royalty Expense	6			6			—			—			—			—			—			—
Total Production Expense	283			285			6			18			—			17			(43		)	—
DD&A	503			427			19			39			1			5			—			12
Loss on Marcellus Shale Upstream Divestiture	2,322			2,322			—			—			—			—			—			—
Loss on Commodity Derivative Instruments	(57		)	(51		)	—			(6		)	—			—			—			—
(Loss) Income Before Income Taxes	(2,334		)	(2,319		)	106			72			(4		)	58			(13		)	(234		)

Six Months Ended June 30, 2018
Crude Oil Sales	$	1,522		$	1,317		$	4		$	201		$	—		$	—		$	—		$	—
NGL Sales	283			283			—			—			—			—			—			—
Natural Gas Sales	468			218			240			10			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	2,273			1,818			244			211			—			—			—			—
Income from Equity Method Investees and Other	124			—			—			71			—			53			—			—
Sales of Purchased Oil and Gas	119			55			—			—			—			64			—			—
Intersegment Revenues	—			—			—			—			—			166			(166		)	—
Total Revenues	2,516			1,873			244			282			—			283			(166		)	—
Lease Operating Expense	287			240			12			41			—			—			(6		)	—
Production and Ad Valorem Taxes	104			101			—			—			—			3			—			—
Gathering, Transportation and Processing Expense	195			260			—			—			—			43			(108		)	—
Other Royalty Expense	27			27			—			—			—			—			—			—
Total Production Expense	613			628			12			41			—			46			(114		)	—
DD&A	933			800			28			52			—			38			(8		)	23
Gain on Divestitures	(666		)	15			(376		)	—			—			(305		)	—			—



	Sales Volumes ⁽¹⁾				Average Realized Sales Prices ⁽¹⁾
	Crude Oil & Condensate (MBbl/d)	NGLs (MBbl/d)	Natural Gas (MMcf/d)	Total (MBoe/d) ⁽²⁾	Crude Oil & Condensate (Per Bbl)		NGLs (Per Bbl)		Natural Gas (Per Mcf)
Three Months Ended June 30, 2018
United States⁽³⁾	108	62	467	247	$	64.67	$	24.46	$	2.29
Eastern Mediterranean	—	—	225	38	—		—		5.46
West Africa ⁽⁴⁾	17	—	225	54	72.79		—		0.27
Total Consolidated Operations	125	62	917	339	65.77		24.46		2.57
Equity Investees ⁽⁵⁾	2	5	—	7	76.07		43.36		—
Total	127	67	917	346	$	65.93	$	25.90	$	2.57
Three Months Ended June 30, 2017
United States	110	63	736	296	$	45.78	$	18.79	$	3.20
Eastern Mediterranean	—	—	272	46	—		—		5.34
West Africa ⁽⁴⁾	22	—	231	60	49.53		—		0.27
Total Consolidated Operations	132	63	1,239	402	46.40		18.79		3.13
Equity Investees⁽⁵⁾	2	4	—	6	50.93		34.46		—
Total	134	67	1,239	408	$	46.49	$	19.84	$	3.13
Six Months Ended June 30, 2018
United States ⁽³⁾	115	63	486	259	$	63.23	$	25.00	$	2.47
Eastern Mediterranean	—	—	243	41	—		—		5.47
West Africa ⁽⁴⁾	16	—	215	51	70.65		—		0.27
Total Consolidated Operations	131	63	944	351	64.13		25.00		2.74
Equity Investees ⁽⁵⁾	2	5	—	7	71.56		41.61		—
Total	133	68	944	358	$	64.22	$	26.27	$	2.74
Six Months Ended June 30, 2017
United States	105	56	733	283	$	47.31	$	21.04	$	3.32
Eastern Mediterranean	—	—	272	46	—		—		5.33
West Africa ⁽⁴⁾	20	—	237	59	51.28		—		0.27
Total Consolidated Operations	125	56	1,242	388	47.95		21.04		3.18
Equity Investees ⁽⁵⁾	2	5	—	7	51.71		35.38		—
Total	127	61	1,242	395	$	48.01	$	22.29	$	3.18



(millions, except unit rate)	Total		United States		Eastern Mediter- ranean		West Africa		Other Int'l
Three Months Ended June 30, 2018
DD&A Expense	$	435	$	394	$	15	$	26	$	—
Unit Rate per BOE ⁽¹⁾	$	14.10	$	17.51	$	4.41	$	5.25	$	—
Three Months Ended June 30, 2017
DD&A Expense	$	486	$	427	$	19	$	39	$	1
Unit Rate per BOE ⁽¹⁾	$	13.32	$	15.89	$	4.62	$	7.11	$	—
Six Months Ended June 30, 2018
DD&A Expense	$	880	$	800	$	28	$	52	$	—
Unit Rate per BOE ⁽¹⁾	$	13.87	$	17.10	$	3.82	$	5.56	$	—
Six Months Ended June 30, 2017
DD&A Expense	$	999	$	886	$	37	$	74	$	2
Unit Rate per BOE ⁽¹⁾	$	14.25	$	17.32	$	4.52	$	6.88	$	—



	June 30,			December 31,
(millions, except percentages)	2018			2017
Total Cash ⁽¹⁾	$	621		$	713
Amount Available to be Borrowed Under Revolving Credit Facility ⁽²⁾	4,000			3,770
Total Liquidity	$	4,621		$	4,483
Total Debt ⁽³⁾	$	6,663		$	6,859
Noble Energy Share of Equity	10,252			9,936
Ratio of Debt-to-Book Capital ⁽⁴⁾	39		%	41		%



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(millions)
4/1/2018 - 4/30/2018	216	$	31.72	—
5/1/2018 - 5/31/2018	837,995	32.84		837,418
6/1/2018 - 6/30/2018	941,779	35.65		941,502
Total	1,779,990	$	34.33	1,778,920	$	620