10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

OR

☐  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.

Yes ☒    No ☐ 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒    No ☐

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth 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. ☐

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

Yes ☐    No ☒

As of September 30, 2019, there were 478,298,006 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	8
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.  Controls and Procedures	40
Part II. Other Information	40
Item 1.  Legal Proceedings	40
Item 1A.  Risk Factors	40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3. Defaults Upon Senior Securities	40
Item 4. Mine Safety Disclosures	40
Item 5.  Other Information	40
Item 6.  Exhibits	41
Signatures	42

2

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Oil, NGL and Gas Sales	$	1,003		$	1,136		$	2,894		$	3,409
Sales of Purchased Oil and Gas	87			72			264			191
Other Revenue	29			65			106			189
Total	1,119			1,273			3,264			3,789
Costs and Expenses
Production Expense	297			273			862			886
Depreciation, Depletion and Amortization	583			485			1,619			1,418
General and Administrative	91			107			298			316
Cost of Purchased Oil and Gas	96			76			296			204
Other Operating Expense, Net	61			27			257			107
Gain on Divestitures, Net	—			(193		)	—			(859		)
Asset Impairments	—			—			—			168
Total	1,128			775			3,332			2,240
Operating (Loss) Income	(9		)	498			(68		)	1,549
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments	(129		)	155			23			483
Interest, Net of Amount Capitalized	67			70			196			216
Other Non-Operating Expense (Income), Net	2			(34		)	7			(10		)
Total	(60		)	191			226			689
Income (Loss) Before Income Taxes	51			307			(294		)	860
Income Tax Expense (Benefit)	15			59			(49		)	44
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	36			248			(245		)	816
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	19			21			61			58
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	17		$	227		$	(306	)	$	758
Net Income (Loss) Attributable to Noble Energy Common Shareholders per Share
Basic	$	0.04		$	0.47		$	(0.64	)	$	1.57
Diluted	$	0.04		$	0.47		$	(0.64	)	$	1.56
Weighted Average Number of Common Shares Outstanding
Basic	478			482			478			484
Diluted	480			484			478			486

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

3

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

	September 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and Cash Equivalents	$	473		$	716
Accounts Receivable, Net	677			616
Other Current Assets	277			418
Total Current Assets	1,427			1,750
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,445			29,002
Property, Plant and Equipment, Other	1,045			891
Total Property, Plant and Equipment, Gross	31,490			29,893
Accumulated Depreciation, Depletion and Amortization	(12,693		)	(11,474		)
Total Property, Plant and Equipment, Net	18,797			18,419
Other Noncurrent Assets	1,780			841
Total Assets	$	22,004		$	21,010
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable – Trade	$	1,395		$	1,207
Other Current Liabilities	1,190			519
Total Current Liabilities	2,585			1,726
Long-Term Debt	6,941			6,574
Deferred Income Taxes	954			1,061
Other Noncurrent Liabilities	1,338			1,165
Total Liabilities	11,818			10,526
Commitments and Contingencies
Mezzanine Equity
Redeemable Noncontrolling Interest, Net	103			—
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	8,258			8,203
Accumulated Other Comprehensive Loss	(30		)	(32		)
Treasury Stock, at Cost; 39 Million Shares	(735		)	(730		)
Retained Earnings	1,506			1,980
Noble Energy Share of Equity	9,004			9,426
Noncontrolling Interests	1,079			1,058
Total Shareholders' Equity	10,083			10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity	$	22,004		$	21,010

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

4

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Nine Months Ended September 30,
	2019			2018
Cash Flows From Operating Activities
Net (Loss) Income Including Noncontrolling Interests	$	(245	)	$	816
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,619			1,418
Deferred Income Tax Benefit	(110		)	(150		)
Loss on Commodity Derivative Instruments	23			483
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	28			(160		)
Other Adjustments for Noncash Items Included in Income	115			45
Gain on Divestitures, Net	—			(859		)
Asset Impairments	—			168
Firm Transportation Exit Cost	92			—
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	(13		)	114
Increase (Decrease) in Accounts Payable	142			(91		)
Other Current Assets and Liabilities, Net	(76		)	73
Other Operating Assets and Liabilities, Net	(46		)	(81		)
Net Cash Provided by Operating Activities	1,529			1,776
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,998		)	(2,589		)
Acquisitions, Net of Cash Received	—			(653		)
Additions to Equity Method Investments	(686		)	—
Proceeds from Divestitures, Net	131			1,740
Other	25			—
Net Cash Used in Investing Activities	(2,528		)	(1,502		)
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facility	50			1,450
Repayment of Revolving Credit Facility	(50		)	(1,680		)
Proceeds from Noble Midstream Services Revolving Credit Facility	655			690
Repayment of Noble Midstream Services Revolving Credit Facility	(665		)	(725		)
Proceeds from Noble Midstream Services Term Loan Credit Facilities	400			500
Proceeds from Commercial Paper Borrowings, Net	511			—
Dividends Paid, Common Stock	(168		)	(156		)
Purchase and Retirement of Common Stock	—			(223		)
Contributions from Noncontrolling Interest Owners	27			348
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs	97			—
Repayment of Senior Notes	(9		)	(384		)
Other	(95		)	(86		)
Net Cash Provided by (Used in) Financing Activities	753			(266		)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(246		)	8
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	719			713
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	473		$	721

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

5

Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)

	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
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
Net Income	—		—			—			—			17			19			36
Stock-based Compensation	—		16			—			—			—			—			16
Dividends (12 cents per share)	—		—			—			—			(57		)	—			(57		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(19		)	(19		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			6			6
Other	—		(2		)	1			—			—			(2		)	(3		)
September 30, 2019	$	5	$	8,258		$	(30	)	$	(735	)	$	1,506		$	1,079		$	10,083

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

6

Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)

	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
December 31, 2017	$	5	$	8,438		$	(30	)	$	(725	)	$	2,248		$	683		$	10,619
Net Income	—		—			—			—			554			20			574
Stock-based Compensation	—		17			—			—			—			—			17
Dividends (10 cents per share)	—		—			—			—			(48		)	—			(48		)
Purchase and Retirement of Common Stock	—		(67		)	—			—			—			—			(67		)
Clayton Williams Energy Acquisition	—		(25		)	—			—			—			—			(25		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(11		)	(11		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			331			331
Other	—		—			1			(6		)	—			2			(3		)
March 31, 2018	$	5	$	8,363		$	(29	)	$	(731	)	$	2,754		$	1,025		$	11,387
Net (Loss) Income	—		—			—			—			(23		)	17			(6		)
Stock-based Compensation	—		29			—			—			—			—			29
Dividends (11 cents per share)	—		—			—			—			(54		)	—			(54		)
Purchase and Retirement of Common Stock	—		(63		)	—			—			—			—			(63		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(11		)	(11		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			—			—
Other	—		—			1			—			—			(2		)	(1		)
June 30, 2018	$	5	$	8,329		$	(28	)	$	(731	)	$	2,677		$	1,029		$	11,281
Net Income	—		—			—			—			227			21			248
Stock-based Compensation	—		17			—			—			—			—			17
Dividends (11 cents per share)	—		—			—			—			(54		)	—			(54		)
Purchase and Retirement of Common Stock	—		(103		)	—			—			—			—			(103		)
Distributions to Noncontrolling Interest Owners	—		—			—			—			—			(13		)	(13		)
Contributions from Noncontrolling Interest Owners	—		—			—			—			—			17			17
Other	—		6			1			—			—			(6		)	1
September 30, 2018	$	5	$	8,249		$	(27	)	$	(731	)	$	2,850		$	1,048		$	11,394

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

7

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 Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns and 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 September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 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, net income or loss is materially consistent with comprehensive income or loss.

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

Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the 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 our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.

Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of 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 our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the 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 accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as 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.

8

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Revenue Recognition   We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606).

Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of September 30, 2019, for those agreements. Our actual future sales volumes may exceed future minimum volume commitments.

(millions)	Remainder of 2019		2020		Total
Natural Gas Revenues (1)	$	36	$	199	$	235

⁽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.

Redeemable Noncontrolling Interest 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 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 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, 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, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures.

Recently Issued Accounting Standards

Financial Instruments: Credit Losses In June 2016, the 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 with a methodology that reflects current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and 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.

We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements.

Recently Adopted Accounting Standards

Leases In 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).

9

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

We adopted ASC 842 on January 1, 2019 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements.

Intangibles—Goodwill and Other—Internal-Use Software In 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, 2019, with early adoption permitted. We used the prospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our financial statements.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2019		2018			2019		2018
Other Revenue
Income from Equity Method Investments and Other	$	10	$	44		$	43	$	140
Midstream Services Revenues – Third Party	19		21			63		49
Total	$	29	$	65		$	106	$	189
Production Expense
Lease Operating Expense	$	132	$	124		$	405	$	411
Production and Ad Valorem Taxes	52		47			142		151
Gathering, Transportation and Processing Expense	108		97			306		292
Other Royalty Expense	5		5			9		32
Total	$	297	$	273		$	862	$	886
Other Operating Expense, Net
Exploration Expense	$	25	$	25		$	82	$	89
Marketing Expense	7		11			26		21
Firm Transportation Exit Cost	—		—			92		—
Other, Net	29		(9		)	57		(3		)
Total	$	61	$	27		$	257	$	107

10

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	405		$	383
Joint Interest Billings	177			137
Other	103			111
Allowance for Doubtful Accounts	(8		)	(15		)
Total	$	677		$	616
Other Current Assets
Commodity Derivative Assets	$	90		$	180
Inventories, Materials and Supplies	74			55
Assets Held for Sale (1)	—			133
Prepaid Expenses and Other Current Assets	113			50
Total	$	277		$	418
Other Noncurrent Assets
Equity Method Investments (2)	$	959		$	286
Operating Lease Right-of-Use Assets (3)	275			—
Customer-Related Intangible Assets, Net (4)	286			310
Goodwill (4)	110			110
Other Assets, Noncurrent	150			135
Total	$	1,780		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	147		$	103
Asset Retirement Obligations	89			118
Interest Payable	87			66
Operating Lease Liabilities (3)	97			—
Commercial Paper Borrowings	511			—
Other Liabilities, Current	259			232
Total	$	1,190		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	148		$	147
Asset Retirement Obligations	699			762
Operating Lease Liabilities (3)	209			—
Firm Transportation Exit Cost Accrual (5)	133			67
Other Liabilities, Noncurrent	149			189
Total	$	1,338		$	1,165

⁽¹⁾  Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.

⁽²⁾  See Note 4. Acquisitions and Divestitures.

⁽³⁾  Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases.

⁽⁴⁾  Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.

⁽⁵⁾  See Note 9. Exit Cost – Transportation Commitments.

11

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

	Nine Months Ended September 30,
(millions)	2019		2018
Cash and Cash Equivalents at Beginning of Period	$	716	$	675
Restricted Cash at Beginning of Period	3		38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	719	$	713
Cash and Cash Equivalents at End of Period	$	473	$	720
Restricted Cash at End of Period	—		1
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	473	$	721

Note 3. Segment Information

We 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 (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 assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our 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 retained Marcellus Shale transportation agreements, are recorded at the Corporate level.

			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 September 30, 2019
Crude Oil Sales	$	724	$	645	$	1	$	78	$	—	$	—		$	—		$	—
NGL Sales	78		78		—		—		—		—			—			—
Natural Gas Sales	201		79		118		4		—		—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,003		802		119		82		—		—			—			—
Sales of Purchased Oil and Gas	87		22		—		—		—		47			—			18
Income (Loss) from Equity Method Investments and Other	10		1		—		14		—		(5		)	—			—
Midstream Services Revenues – Third Party	19		—		—		—		—		19			—			—
Intersegment Revenues	—		—		—		—		—		125			(125		)	—
Total Revenues	1,119		825		119		96		—		186			(125		)	18
Lease Operating Expense	132		111		7		22		—		1			(9		)	—
Production and Ad Valorem Taxes	52		51		—		—		—		1			—			—
Gathering, Transportation and Processing Expense	108		173		1		—		—		5			(71		)	—
Other Royalty Expense	5		5		—		—		—		—			—			—
Total Production Expense	297		340		8		22		—		7			(80		)	—

12

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	583			505			17		21			1			26			(8		)	21
Cost of Purchased Oil and Gas	96			17			—		—			—			46			—			33
Gain on Commodity Derivative Instruments	(129		)	(123		)	—		(6		)	—			—			—			—
Income (Loss) Before Income Taxes	51			92			74		56			(17		)	83			(23		)	(214		)
Additions to Long-Lived Assets, Excluding Acquisitions	595			377			129		46			2			56			(26		)	11
Additions to Equity Method Investments	271			—			185		—			—			86			—			—
Three Months Ended September 30, 2018
Crude Oil Sales	$	744		$	655		$	2	$	87		$	—		$	—		$	—		$	—
NGL Sales	166			166			—		—			—			—			—			—
Natural Gas Sales	226			98			122		6			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,136			919			124		93			—			—			—			—
Sales of Purchased Oil and Gas	72			—			—		—			—			46			—			26
Income from Equity Method Investments and Other	44			—			—		34			—			10			—			—
Midstream Services Revenues – Third Party	21			—			—		—			—			21			—			—
Intersegment Revenues	—			—			—		—			—			91			(91		)	—
Total Revenues	1,273			919			124		127			—			168			(91		)	26
Lease Operating Expense	124			114			7		15			—			—			(12		)	—
Production and Ad Valorem Taxes	47			46			—		—			—			1			—			—
Gathering, Transportation and Processing Expense	97			129			—		—			—			28			(60		)	—
Other Royalty Expense	5			5			—		—			—			—			—			—
Total Production Expense	273			294			7		15			—			29			(72		)	—
Depreciation, Depletion and Amortization	485			414			16		25			1			24			(5		)	10
(Gain) Loss on Divestitures, Net	(193		)	5			—		—			—			(198		)	—			—
Cost of Purchased Oil and Gas	76			—			—		—			—			44			—			32
Loss on Commodity Derivative Instruments	155			140			—		15			—			—			—			—
Income (Loss) Before Income Taxes	307			31			143		68			(17		)	268			(16		)	(170		)
Additions to Long-Lived Assets, Excluding Acquisitions	768			535			170		4			1			82			(22		)	(2		)
Nine Months Ended September 30, 2019
Crude Oil Sales	$	2,024		$	1,807		$	4	$	213		$	—		$	—		$	—		$	—
NGL Sales	258			258			—		—			—			—			—			—
Natural Gas Sales	612			259			340		13			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	2,894			2,324			344		226			—			—			—			—

13

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
Sales of Purchased Oil and Gas	264			64			—		—		—			132			—			68
Income (Loss) from Equity Method Investments and Other	43			2			—		46		—			(5		)	—			—
Midstream Services Revenues – Third Party	63			—			—		—		—			63			—			—
Intersegment Revenues	—			—			—		—		—			322			(322		)	—
Total Revenues	3,264			2,390			344		272		—			512			(322		)	68
Lease Operating Expense	405			350			26		56		—			3			(30		)	—
Production and Ad Valorem Taxes	142			138			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	306			439			1		—		—			65			(199		)	—
Other Royalty Expense	9			9			—		—		—			—			—			—
Total Production Expense	862			936			27		56		—			72			(229		)	—
Depreciation, Depletion and Amortization	1,619			1,401			50		60		1			77			(21		)	51
Cost of Purchased Oil and Gas	296			59			—		—		—			125			—			112
Firm Transportation Exit Cost	92			—			—		—		—			—			—			92
Loss on Commodity Derivative Instruments	23			7			—		16		—			—			—			—
(Loss) Income Before Income Taxes	(294		)	(85		)	223		126		(48		)	202			(52		)	(660		)
Additions to Long-Lived Assets, Excluding Acquisitions	1,954			1,367			380		64		14			174			(74		)	29
Additions to Equity Method Investments	686			—			185		—		—			501			—			—
Nine Months Ended September 30, 2018
Crude Oil Sales	$	2,266		$	1,972		$	6	$	288	$	—		$	—		$	—		$	—
NGL Sales	449			449			—		—		—			—			—			—
Natural Gas Sales	694			316			362		16		—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	3,409			2,737			368		304		—			—			—			—
Sales of Purchased Oil and Gas	191			—			—		—		—			110			—			81
Income from Equity Method Investments and Other	140			—			—		105		—			35			—			—
Midstream Services Revenues – Third Party	49			—			—		—		—			49			—			—
Intersegment Revenues	—			—			—		—		—			257			(257		)	—
Total Revenues	3,789			2,737			368		409		—			451			(257		)	81
Lease Operating Expense	411			354			19		56		—			—			(18		)	—
Production and Ad Valorem Taxes	151			147			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	292			389			—		—		—			71			(168		)	—
Other Royalty Expense	32			32			—		—		—			—			—			—
Total Production Expense	886			922			19		56		—			75			(186		)	—
Depreciation, Depletion and Amortization	1,418			1,214			44		77		1			62			(13		)	33

14

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
(Gain) Loss on Divestitures, Net	(859		)	20			(376		)	—		—			(503		)	—			—
Asset Impairments	168			168			—			—		—			—			—			—
Cost of Purchased Oil and Gas	204			—			—			—		—			106			—			98
Loss on Commodity Derivative Instruments	483			400			—			83		—			—			—			—
Income (Loss) Before Income Taxes	860			(94		)	678			180		(44		)	690			(52		)	(498		)
Additions to Long-Lived Assets, Excluding Acquisitions	2,608			1,630			533			9		3			479			(72		)	26
September 30, 2019
Property, Plant and Equipment, Net	$	18,797		$	13,170		$	3,001		$	801	$	39		$	1,682		$	(198	)	$	302
December 31, 2018
Property, Plant and Equipment, Net	$	18,419		$	13,044		$	2,630		$	805	$	37		$	1,742		$	(145	)	$	306

⁽¹⁾  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.

Note 4. Acquisitions and Divestitures

We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.

2019 Asset Transactions

Eastern Mediterranean Investment During third quarter 2019, we invested $185 million for a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.) in support of its planned acquisition of an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s planned equity acquisition of EMG, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers and support delivery of natural gas from our producing fields offshore Israel into Egypt.

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 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 acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline. Both pipelines will transport production from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million and Noble Midstream Partners has since made additional capital contributions of $46 million and $168 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method.

Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC 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 nine months of 2019, Noble Midstream Partners has made capital contributions of $53 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 March 31, 2018, we reduced the 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 subsequently settled upon closing.

15

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 received net proceeds of $383 million and recorded a loss of $24 million.

Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a 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 $376 million and tax expense of $86 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.

Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin, receiving proceeds of $64 million, resulting in no gain or loss on the sale.

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 consolidated as a VIE.

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 acquisition date fair values, and we recognized goodwill for the amount of the purchase price exceeding the fair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and 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 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)	September 30, 2019		December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	15	$	6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	354		348
Capitalized Exploratory Well Costs, End of Period	$	369	$	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

16

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows:

(millions)	Nine Months Ended September 30, 2019
Undeveloped Leasehold Costs, Beginning of Period	$	2,306
Additions to Undeveloped Leasehold Costs	63
Transfers to Proved Properties	(20		)
Undeveloped Leasehold Costs, End of Period	$	2,349

As of September 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $76 million, and $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 subject to expiration over the next several years unless production is established on the acreage. Other costs pertain to acreage that is being held by production.

Note 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:

	Nine Months Ended September 30,
(millions)	2019			2018
Asset Retirement Obligations, Beginning Balance	$	880		$	875
Liabilities Incurred	17			16
Liabilities Settled	(82		)	(309		)
Revisions of Estimates	(60		)	67
Accretion Expense	33			25
Asset Retirement Obligations, Ending Balance	$	788		$	674

Nine Months Ended September 30, 2019 Liabilities settled relate primarily to abandonment of US onshore properties, principally 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, partially offset by acceleration of timing estimates of $13 million for wells offshore Israel.

Nine Months Ended September 30, 2018 Liabilities settled include $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $69 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily to increases in cost and timing of estimates of $84 million for US onshore, primarily in the DJ Basin, partially offset by decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean.

17

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 7. Debt

Debt consists of the following:

	September 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	511			(1	)	—			—	%
Senior Notes and Debentures	5,884			(2	)	5,892			(2	)
Finance Lease Obligations	206			—	%	223			—	%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt	6,601					6,115
Noble Midstream Partners
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3)	50			3.45	%	60			3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500			3.17	%	500			3.42	%
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022	400			3.05	%	—			—	%
Total Noble Midstream Partners Debt	950					560
Total Debt	7,551					6,675
Net Unamortized Discounts and Debt Issuance Costs	(57		)			(60		)
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs	7,494					6,615
Less Amounts Due Within One Year
Commercial Paper Borrowings	(511		)			—
Finance Lease Obligations	(42		)			(41		)
Long-Term Debt Due After One Year	$	6,941				$	6,574

⁽¹⁾  As of September 30, 2019, the weighted average interest rate for outstanding commercial paper was 2.63%.

⁽²⁾  As of September 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 September 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity, of which $750 million and $740 million were available for borrowing, 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 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 discount 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 September 30, 2019, outstanding commercial paper borrowings totaled $511 million, leaving approximately $3.5 billion available for borrowing under our $4.0 billion Revolving Credit Facility.

Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility.

Subsequent Event On October 1, 2019, we issued $500 million of 3.25% notes due October 15, 2029 and $500 million of 4.20% notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations.

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

18

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 8. Leases

In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include 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.

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

(millions)	Balance Sheet Location	September 30, 2019
ROU Assets
Operating Leases (1)	Other Noncurrent Assets	$	275
Finance Leases (2)	Total Property, Plant and Equipment, Net	172
Total ROU Assets		$	447
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	97
Finance Leases	Other Current Liabilities	42
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	209
Finance Leases	Long-Term Debt	164
Total Lease Liabilities		$	512

⁽¹⁾  Operating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and drilling rigs of $29 million.

⁽²⁾  Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.

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

(millions)	Statement of Operations Location	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating Lease Cost	(1)	$	30		$	81
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	10			27
Interest Expense	Interest, Net of Amount Capitalized	3			10
Short-term Lease Cost (2)	(1)	88			357
Sublease Income	General and Administrative	(1		)	(3		)
Total Lease Cost		$	130		$	472

⁽¹⁾  Cost classifications vary 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 and, therefore, are included as part of oil and gas properties on our consolidated balance sheets.

⁽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.

19

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Cash Flow Information Supplemental cash flow information is as follows:

	Nine Months Ended September 30, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	50	$	9
Investing Cash Flows	27		—
Financing Cash Flows	—		31
Non-Cash Activities
ROU Assets Obtained in Exchange for Lease Liabilities (1)	93		15

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

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

(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	28	$	13	$	41
2020	100		49		149
2021	61		35		96
2022	44		25		69
2023	29		22		51
2024 and Thereafter	85		106		191
Total Lease Liabilities, Undiscounted	347		250		597
Less: Imputed Interest	41		44		85
Total Lease Liabilities (1)	$	306	$	206	$	512

⁽¹⁾  Includes the current portions of $97 million and $42 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 as of September 30, 2019 is as follows:

	Operating Leases		Finance Leases
Weighted-Average Remaining Lease Term	5.7 years		7.7 years
Weighted-Average Discount Rate	4.40	%	5.02	%

Note 9. Exit Cost – Transportation Commitments

In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of September 30, 2019, our undiscounted financial commitment for the remaining obligations under these agreements was approximately $1.0 billion, which excludes the impact of future mitigation activities. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and

20

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations.

Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, 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 remaining component of these transportation agreements through 2020.

Exit Costs Reconciliation of accrued costs at September 30, 2019 is as follows:

	Nine Months Ended September 30,
(millions)	2019			2018
Balance at Beginning of Period (1)	$	80		$	90
Firm Transportation Exit Cost Accrual	92			—
Payments, Net of Accretion	(6		)	(9		)
Balance at End of Period	166			81
Less: Current Portion Included in Other Current Liabilities	33			12
Long-term Portion Included in Other Noncurrent Liabilities	$	133		$	69

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

Note 10. Commitments and Contingencies

Legal Proceedings   We 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.

Note 11. Income Taxes

Income tax expense (benefit) consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except percentages)	2019			2018			2019			2018
Current	$	24		$	45		$	61		$	194
Deferred	(9		)	14			(110		)	(150		)
Total Income Tax Expense (Benefit)	$	15		$	59		$	(49	)	$	44
Effective Tax Rate	29.4		%	19.2		%	16.7		%	5.1		%

Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the nine months ended September 30, 2019 varied as compared with 2018, primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the nine months ended September 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar 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.

21

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 12. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   We enter into crude oil and natural gas price hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and 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 September 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	35,000	$	—		$	59.04	$	—	$	—	$	—
2019	Three-Way Collars	NYMEX WTI	33,000	—			—		49.35		59.35		72.25
2019	Sold Calls (1)	NYMEX WTI	4,000	—			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	12,000	—			59.73		—		—		—
2020	Sold Calls (1)	NYMEX WTI	8,000	—			65.59		—		—		—
2020	Swaps	NYMEX WTI	28,000	—			58.09		—		—		—
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.

As of September 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	Swaps	NYMEX HH	90,000	—			2.60		—		—		—
2020	Sold Puts (2)	NYMEX HH	90,000	—			—		2.15		—		—
2020	Swaption	NYMEX HH	90,000	—			2.60		—		—		—
2020	Basis Swaps	CIG (1)	54,000	(0.61		)	—		—		—		—
2020	Basis Swaps	WAHA (1)	49,500	(1.05		)	—		—		—		—
2021	Basis Swaps	WAHA (1)	14,000	(0.60		)	—		—		—		—

⁽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.

⁽²⁾  We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.

22

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Fair Value Amounts   The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions):

Asset Derivative Instruments					Liability Derivative Instruments
Balance Sheet Location	September 30, 2019		December 31, 2018		Balance Sheet Location	September 30, 2019		December 31, 2018
Other Current Assets	$	90	$	180	Other Current Liabilities	$	10	$	1
Other Noncurrent Assets	25		—		Other Noncurrent Liabilities	3		26
Total	$	115	$	180		$	13	$	27

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

Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2019			2018			2019			2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(6	)	$	68		$	(8	)	$	164
Natural Gas	(7		)	(1		)	(20		)	(4		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(13		)	67			(28		)	160
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	(115		)	85			54			316
Natural Gas	(1		)	3			(3		)	7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(116		)	88			51			323
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(121		)	153			46			480
Natural Gas	(8		)	2			(23		)	3
Total (Gain) Loss on Commodity Derivative Instruments	$	(129	)	$	155		$	23		$	483

Note 13. Fair Value Measurements and Disclosures 

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. See Note 12. Derivative Instruments and Hedging Activities. 

Deferred Compensation Liability   Fair 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.

23

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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
September 30, 2019
Financial Assets:
Mutual Fund Investments	$	42		$	—		$	—	$	—		$	42
Commodity Derivative Instruments	—			155			—		(40		)	115
Financial Liabilities:
Commodity Derivative Instruments	—			(53		)	—		40			(13		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(3		)	—			—		—			(3		)
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 settle asset and liability positions with the same counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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.

Redeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with the issuance to GIP of preferred equity in Noble Midstream Partners 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, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans 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:

	September 30, 2019				December 31, 2018
(millions)	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value
Debt (2)	$	7,345	$	7,963	$	6,452	$	6,121

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

⁽²⁾  Represents total debt excluding finance lease obligations. See Note 7. Debt.

24

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 14. Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders

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 September 30,				Nine Months Ended September 30,
(millions, except per share amounts)	2019		2018		2019			2018
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	17	$	227	$	(306	)	$	758
Weighted Average Number of Shares Outstanding, Basic (1)	478		482		478			484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	2		2		—			2
Weighted Average Number of Shares Outstanding, Diluted	480		484		478			486
Income (Loss) Per Share, Basic	$	0.04	$	0.47	$	(0.64	)	$	1.57
Income (Loss) Per Share, Diluted	$	0.04	$	0.47	$	(0.64	)	$	1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14		13		15			14

⁽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 – Exploration and Production;

• Results of Operations – Midstream;

• Results of Operations – Corporate; and

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

Operational Environment Update

Recent Activities During third quarter 2019, we progressed our US onshore drilling and completions activities, advanced our Eastern Mediterranean and West Africa regional natural gas developments and continued advancement of our US onshore and international exploration opportunities. We continue to execute capital and operating cost reduction efforts and reduce cycle times through operational improvements. During the quarter, we delivered consolidated sales volumes of 379 MBoe/d and achieved quarterly sales volumes records in both the DJ and Delaware Basins. This increased production was achieved with reduced capital investment. We continue to focus on progressing the Leviathan natural gas project, which was over 90% complete at quarter-end. Our focus on cost and capital efficiency and the startup of the Leviathan natural gas project should provide sustainable cash flows beginning in 2020.

Commodity Prices Crude oil prices remained volatile during third quarter 2019, with Brent and WTI averaging approximately $61 and $56 per barrel, respectively. The outlook for fourth quarter 2019 will depend on competing factors for supply and demand. Production cuts by the Organization of Petroleum Exporting Countries and geopolitical factors in critical oil producing regions remain constructive for global oil prices. However, a weakening of crude oil demand amid signs of a potential softening

25

in the global economy could result in lower prices. In addition, US and China trade tensions threaten further damage to global trade and economic growth and, consequently, crude oil demand. In the Delaware Basin, new pipeline startups, including interim crude oil service on the EPIC Y-Grade pipeline, have begun to improve basis differentials, while planned expansion of export infrastructure should help alleviate a portion of the discount of WTI to Brent going forward.

The US natural gas market continues to see depressed levels as supply outpaced demand over the past year. Despite record domestic liquefied natural gas (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, while differentials in the Delaware Basin continue to be wide despite additional pipeline capacity from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin natural gas pipeline expansions are targeted for in-service in late 2020.

NGL prices are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. US NGL prices should strengthen as new processing and export facilities are brought online.

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

Financial Initiatives 

Financial Flexibility, Liquidity and Balance Sheet Strength As we progress through the remainder of 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. See Operating Outlook – 2019 Capital Investment Program.

If commodity prices decline or operating costs 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 changes in our capital program, share repurchase program, dividends policy or operating cost structure, and/or potential asset sales. Our revenues and our stock price could decline as a result of these potential developments.

Recently Issued Accounting Standards

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

OPERATING OUTLOOK

2019 Organic Capital Investment Program  Our initial 2019 organic capital program, which excludes capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline, ranged from $2.4 to $2.6 billion and was primarily allocated to US onshore development and completion of the Leviathan natural gas project. In second quarter 2019, we lowered our full year organic capital program by $100 million. In third quarter 2019, as a result of US onshore well cost reductions and the Leviathan project spending below budget, we lowered our full year organic capital program by an additional $100 million. Fourth quarter 2019 expected organic capital expenditures range from $425 to $475 million and will primarily be allocated to continued US onshore development and completion of the Leviathan natural gas project. Amounts exclude capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline. See Liquidity and Capital Resources.

Dividends In April, July and October 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 increase our dividend, reflecting our commitment to return value to shareholders.

Colorado Senate Bill 19-181 For some time, initiatives have been underway in the State of Colorado to 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 Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (Commission) to prioritize public health and 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 Commission has initiated new rulemakings related to, among other things, incorporating new public health, safety, and environmental priorities into their regulations, updating wellbore integrity and flowline rules, and adopting new alternative location analysis and cumulative impact procedures. In addition, some local communities have adopted further restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the Commission publishes new rules in keeping with SB 181.

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

26

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 cash flows, results of operations, financial condition, and liquidity.

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

US Onshore

During third quarter 2019, our US onshore E&P activities consisted of the following:

Location	Average Rigs Operated	Wells Drilled (1)	Wells Brought Online	Average Sales Volumes  (MBoe/d)
DJ Basin	2	28	38	158
Delaware Basin	3	20	17	70
Eagle Ford Shale	—	—	—	65
Total	5	48	55	293

⁽¹⁾  The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated.

DJ Basin   During third quarter 2019, we achieved a quarterly average sales volume record of 158 MBoe/d. Our activities were focused primarily on progressing development in the Mustang, which benefits from our approved CDP, Wells Ranch and East Pony areas. We continue to see increased capital efficiencies as a result of improved drilling and completion performance. In the Mustang, we utilized our first electric powered drilling rig, resulting in reduced noise, emissions and fuel costs.

In addition, we submitted an application for approval of the North Wells Ranch CDP. This CDP covers approximately 38,000 net acres and up to 250 potential drilling permits. Final approval is targeted for early 2020.

Delaware Basin During third quarter 2019, we achieved a quarterly average sales volume record of 70 MBoe/d. Our activity focused primarily on drilling and completion optimization, leading to capital and operational cost efficiencies. We brought online our first field power substation, which will provide a reliable power source to support field operations.

Eagle Ford Shale During third quarter 2019, we focused on maximizing cash flows from existing production and conducted two well refractures on Gates Ranch. We continue to evaluate and assess our development plan for the area and are incorporating learnings from our refracture results.

International

Leviathan Natural Gas Project (Offshore Israel) As of September 30, 2019, the project was over 90% complete and is ahead of schedule and below budget. During third quarter 2019, the topsides set sail and arrived in Israel, where they were installed, and we completed all subsea construction scope and pre-commissioning activities. The remaining commissioning and operational readiness activities are underway, with first production anticipated in December 2019.

Leviathan and Tamar Gas Sales and Purchase Agreements (Offshore Israel) In October 2019, we announced that we and our partners had amended the agreements for the sale of natural gas to Dolphinus Holdings Limited from the Leviathan and Tamar fields. The amended agreements, which are subject to certain regulatory approvals, provide for total combined firm contract quantities of 3.0 trillion cubic feet (Tcf) of natural gas, more than doubling the firm volume commitments previously agreed. In addition, each agreement has been extended by five years to reflect 15-year terms and include take-or-pay commitments. 

During the two-year period ending June 30, 2022, the Leviathan field will backstop any volume commitment that the Tamar field is unable to deliver under the amended agreement.

EMG Pipeline (Offshore Israel) During third quarter 2019, we funded a $185 million investment in EMED Pipeline B.V. in support of its planned acquisition of an approximate 39% equity interest in EMG, which owns the EMG Pipeline. Upon closing of the planned equity transaction, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of

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approximately 10%, net, in EMG. The EMG Pipeline will support delivery of natural gas from our producing fields offshore Israel into Egypt.

Aseng Development Well (Offshore Equatorial Guinea) During third quarter 2019, the Aseng field surpassed 100 MMBbl of crude oil produced. In addition, we drilled and completed a development well which is expected to mitigate field decline. Production came online in October 2019.

Alen Natural Gas Development (Offshore Equatorial Guinea)   In second quarter 2019, we announced the sanction of the 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 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.

The Alen natural gas monetization project will produce through three existing high-capacity wells and will require minor platform modifications to deliver sales gas from the Alen field to the Alba Plant and EG LNG facilities. The Alen field partners plan to construct a 24-inch pipeline capable of 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 2021. At start-up, natural gas sales from the Alen field are anticipated to be 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 for additional liquids recovery before the dry gas is converted into LNG at the 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 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

US Onshore Acreage Our US onshore unconventional exploration position includes more than 175,000 acres residing in two plays in Wyoming. During third quarter 2019, we progressed activities to obtain required approvals and permits in support of planned future drilling activities.

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 third quarter 2019, we continued well planning and permitting activities.

Potential for Future Dry Hole Costs, Lease Abandonment Expense or Property Impairments

Exploration Activities 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 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. Additionally, we may not be able to conduct exploration activities prior to lease expirations or may choose to relinquish or exit licenses or leases. Therefore, future dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

Producing Properties A decline in future commodity prices could result in some of our properties becoming uneconomic, resulting in an impairment charge, decrease in proved reserves and/or shut-in of currently producing wells. In addition, in certain US onshore areas, transportation bottlenecks caused by production above transportation capacity and/or lack of infrastructure may reduce the amount of production reaching markets, resulting in lower in-basin pricing (i.e. higher basis differential). An increase in basis differentials could also reduce cash flows and result in property impairment charges.

Results of Operations

Third Quarter 2019 E&P Operating Highlights Included:

• total average consolidated sales volumes of 379 MBoe/d, net;

• record average daily sales volumes of 127 MBbl/d, net, for US crude oil;

• average daily sales volumes of 1.1 Bcfe/d, gross, of natural gas from the Tamar field, offshore Israel;

• reached total gross volumes of 2 Tcf of natural gas produced from the Tamar field; and

• commencement of crude oil shipments on the EPIC Y-Grade pipeline, which began interim crude service in August.

Third Quarter 2019 E&P Financial Results Included:

• additions to equity method investments of $185 million, as compared with zero for third quarter 2018;

• capital expenditures, excluding acquisitions, of $540 million, as compared with $696 million for third quarter 2018;

• pre-tax income of $205 million, as compared with $225 million for third quarter 2018; and

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• net gain on commodity derivative instruments of $129 million, as compared with a net loss of $155 million for third quarter 2018.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2019			2018		2019		2018
Oil, NGL and Gas Sales to Third Parties	$	1,003		$	1,136	$	2,894	$	3,409
Sales of Purchased Oil and Gas	22			—		64		—
Income from Equity Method Investments and Other	15			34		48		105
Total Revenues	1,040			1,170		3,006		3,514
Production Expense	370			316		1,019		997
Exploration Expense	25			25		82		89
Depreciation, Depletion and Amortization	544			456		1,512		1,336
Loss (Gain) on Divestitures, Net	—			5		—		(356		)
Asset Impairments	—			—		—		168
Cost of Purchased Oil and Gas	17			—		59		—
(Gain) Loss on Commodity Derivative Instruments	(129		)	155		23		483
Income Before Income Taxes	205			225		216		720

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Average Oil, NGL and Gas Sales Volumes and Prices  Average daily sales volumes from our share of production and realized sales prices were as follows:

	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 September 30, 2019
United States	127	76	542	293	$	55.13	$	11.18	$	1.57
Eastern Mediterranean	—	—	231	39	—		—		5.55
West Africa (2)	15	—	190	47	58.62		—		0.27
Total Consolidated Operations (3)	142	76	963	379	55.48		11.18		2.27
Equity Investments (4)	1	5	—	6	57.44		25.85		—
Total (3)	143	81	963	385	$	55.50	$	12.06	$	2.27
Three Months Ended September 30, 2018
United States (5)	109	63	464	249	$	65.54	$	28.58	$	2.31
Eastern Mediterranean	—	—	241	41	—		—		5.49
West Africa (2)	13	—	217	49	73.70		—		0.27
Total Consolidated Operations	122	63	922	339	66.41		28.58		2.66
Equity Investments (4)	1	5	—	6	74.88		48.27		—
Total	123	68	922	345	$	66.50	$	29.92	$	2.66
Nine Months Ended September 30, 2019
United States	119	67	507	270	$	55.59	$	14.22	$	1.87
Eastern Mediterranean	—	—	224	38	—		—		5.55
West Africa (2)	13	—	186	44	61.75		—		0.27
Total Consolidated Operations (3)	132	67	917	352	56.18		14.22		2.45
Equity Investments (4)	1	4	—	5	59.81		30.94		—
Total (3)	133	71	917	357	$	56.22	$	15.23	$	2.45
Nine Months Ended September 30, 2018
United States (5)	113	63	479	255	$	63.98	$	26.22	$	2.42
Eastern Mediterranean	—	—	242	41	—		—		5.48
West Africa (2)	15	—	216	51	71.55		—		0.27
Total Consolidated Operations	128	63	937	347	64.86		26.22		2.71
Equity Investments (4)	2	5	—	7	72.46		43.70		—
Total	130	68	937	354	$	64.95	$	27.50	$	2.71

⁽¹⁾  Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent (BOE). 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.

⁽²⁾  Natural gas from the Alba field 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.

⁽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 Investments.

⁽⁵⁾  Includes 9 MBoe/d for first nine months of 2018 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 is as follows:

(millions)	Crude Oil & Condensate			NGLs			Natural Gas			Total
Three Months Ended September 30, 2018	$	744		$	166		$	226		$	1,136
Changes due to
Increase in Sales Volumes	123			30			7			160
Decrease in Sales Prices (1)	(143		)	(118		)	(32		)	(293		)
Three Months Ended September 30, 2019	$	724		$	78		$	201		$	1,003
Nine Months Ended September 30, 2018	$	2,266		$	449		$	694		$	3,409
Changes due to
Increase (Decrease) in Sales Volumes	123			22			(30		)	115
Decrease in Sales Prices (1)	(365		)	(213		)	(52		)	(630		)
Nine Months Ended September 30, 2019	$	2,024		$	258		$	612		$	2,894

⁽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 decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:    

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

• reduction in sales volumes of 7 MBbl/d for the first nine months of 2019 due to the sale of our Gulf of Mexico assets in second quarter 2018; and

• lower West Africa sales volumes of 2 MBbl/d for the first nine months of 2019 due to timing of liftings and natural field decline;

partially offset by:

• higher US onshore sales volumes of 18 MBbl/d and 13 MBbl/d for third quarter and the first nine months of 2019, respectively, primarily due to an increase in development activity in the DJ and Delaware Basins.

NGL Sales Revenues Revenues from NGL sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:

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

• lower Eagle Ford Shale sales volumes of 8 MBbl/d for the first nine months of 2019 due to reduced activity and natural field decline;

partially offset by:

• higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d and 12 MBbl/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.

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

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

• lower Eagle Ford Shale sales volumes of 10 MMcf/d and 51 MMcf/d for third quarter and the first nine months of 2019, respectively, due to reduced activity and natural field decline;

• lower West Africa sales volumes of 27 MMcf/d and 30 MMcf/d for third quarter and the first nine months of 2019, respectively, due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required field shut-in for a portion of the period; and

• lower Israel sales volumes of 10 MMcf/d and 18 MMcf/d for third quarter and the first nine months of 2019, respectively, primarily due to planned maintenance and the sale of a 7.5% interest in the Tamar field in March 2018;

partially offset by:

• higher sales volumes in the DJ and Delaware Basins of 88 MMcf/d and 87 MMcf/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.

Sales and Cost of Purchased Oil and Gas  In third quarter and the first nine months of 2019, we engaged in third party sales and purchases of crude oil in the DJ Basin for flow assurance on pipelines used to deliver our production to market.

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Income from Equity Method Investments and Other  Income from equity method investments and other decreased in the first nine months of 2019 as compared with 2018. The decrease includes a $34 million decrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investment, and a $24 million decrease from Alba Plant, our LPG investment, primarily due to decreases in average realized methanol and LPG prices and plant downtime due to planned maintenance activities.

Production Expense   Components of production expense were as follows:

(millions, except unit rate)	Total per BOE (1)(2)		Total		United States (2)		Eastern Mediterranean		West Africa
Three Months Ended September 30, 2019
Lease Operating Expense (3)	$	4.02	$	140	$	111	$	7	$	22
Production and Ad Valorem Taxes	1.47		51		51		—		—
Gathering, Transportation and Processing	5.00		174		173		1		—
Other Royalty Expense	0.14		5		5		—		—
Total Production Expense	$	10.64	$	370	$	340	$	8	$	22
Total Production Expense per BOE			$	10.64	$	12.61	$	2.24	$	5.17
Three Months Ended September 30, 2018
Lease Operating Expense (3)	$	4.37	$	136	$	114	$	7	$	15
Production and Ad Valorem Taxes	1.48		46		46		—		—
Gathering, Transportation and Processing	4.14		129		129		—		—
Other Royalty Expense	0.16		5		5		—		—
Total Production Expense	$	10.15	$	316	$	294	$	7	$	15
Total Production Expense per BOE			$	10.15	$	12.82	$	1.90	$	3.32
Nine Months Ended September 30, 2019
Lease Operating Expense (3)	$	4.50	$	432	$	350	$	26	$	56
Production and Ad Valorem Taxes	1.44		138		138		—		—
Gathering, Transportation and Processing	4.59		440		439		1		—
Other Royalty Expense	0.09		9		9		—		—
Total Production Expense	$	10.63	$	1,019	$	936	$	27	$	56
Total Production Expense per BOE			$	10.63	$	12.70	$	2.63	$	4.70
Nine Months Ended September 30, 2018
Lease Operating Expense (3)	$	4.54	$	429	$	354	$	19	$	56
Production and Ad Valorem Taxes	1.55		147		147		—		—
Gathering, Transportation and Processing	4.11		389		389		—		—
Other Royalty Expense	0.34		32		32		—		—
Total Production Expense	$	10.54	$	997	$	922	$	19	$	56
Total Production Expense per BOE			$	10.54	$	13.22	$	1.73	$	4.04

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

⁽²⁾  US production expense includes charges from our midstream operations that are eliminated on a consolidated basis.

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

Production expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:

• increase in US gathering, transportation and processing (GTP) expense primarily due to increased development activities in our DJ and Delaware Basins and higher rates in our DJ Basin;

• increase in Eastern Mediterranean lease operating expense due to planned maintenance activities; and

• increase in West Africa lease operating expense due to increase in volumes lifted from the higher-cost Alen field;

partially offset by:

• decrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts in our US onshore basins; and

• decrease in US other royalty expense due to lower commodity prices.

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The unit rate per BOE increased for third quarter and the first nine months of 2019 as compared with 2018 primarily due to an increase in GTP expense, as noted above, and an increase in volumes from higher-cost areas within US onshore and West Africa, partially offset by cost reduction efforts in our US onshore basins.

Exploration Expense Exploration expense for third quarter and the first nine months of 2019 totaled $25 million and $82 million, respectively, including staff expense of $10 million and $34 million, respectively. Exploration expense for third quarter and the first nine months of 2018 totaled $25 million and $89 million, respectively, including staff expense of $14 million and $41 million, respectively.

Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as follows:

(millions, except unit rate)	Total		United States		Eastern Mediterranean		West Africa		Other Int'l
Three Months Ended September 30, 2019
DD&A Expense	$	544	$	505	$	17	$	21	$	1
Unit Rate per BOE (1)	$	15.64	$	18.73	$	4.76	$	4.94	$	—
Three Months Ended September 30, 2018
DD&A Expense	$	456	$	414	$	16	$	25	$	1
Unit Rate per BOE (1)	$	14.64	$	18.05	$	4.34	$	5.53	$	—
Nine Months Ended September 30, 2019
DD&A Expense	$	1,512	$	1,401	$	50	$	60	$	1
Unit Rate per BOE (1)	$	15.77	$	19.01	$	4.86	$	5.04	$	—
Nine Months Ended September 30, 2018
DD&A Expense	$	1,336	$	1,214	$	44	$	77	$	1
Unit Rate per BOE (1)	$	14.12	$	17.41	$	4.00	$	5.55	$	—

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

DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:

• capital investment and development activities in the DJ and Delaware Basins resulting in higher sales volumes; and

• increase in Eastern Mediterranean due to the retirement of certain capital assets resulting in accelerated depreciation;

partially offset by:

• decrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and

• reduced sales volumes in West Africa, as noted above, and reserves additions subsequent to third quarter 2018.

The unit rate per BOE for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the increase in total DD&A expense, as noted above. Specifically, development activity increased in the higher-cost Delaware Basin and the 2018 sale of lower-cost Tamar reserves increased the overall unit rate per BOE. The rate was also impacted by year-end 2018 update to proved reserves quantities used to calculate DD&A, which reflected negative non-price reserves revisions recorded for the Delaware Basin attributable to changes in expected recoveries and higher operating and capital costs. The increase in the unit rate is partially offset by the sale of higher-cost production from the Gulf of Mexico assets.

Loss on Commodity Derivative Instruments  Loss on commodity derivative instruments for the first nine months of 2019 decreased as compared with 2018.

For the first nine months of 2019, loss on commodity derivative instruments included:

• net cash receipts of $28 million; and

• net non-cash decrease of $51 million in the fair value of our net commodity derivative asset, primarily driven by changes in the forward commodity price curves for crude oil.     

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

• net cash payments of $160 million; and

• net non-cash decrease of $323 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for crude oil.

See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.

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RESULTS OF OPERATIONS – MIDSTREAM

The Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus in the DJ and Delaware Basins.

Results of Operations

Third Quarter 2019 Midstream Operating Highlights and Financial Results Included:

• entered into a strategic relationship with Saddlehorn Pipeline Company, LLC (Saddlehorn);

• total revenues of $186 million, as compared with $168 million for third quarter 2018;

• pre-tax income of $83 million, as compared with pre-tax income of $268 million for third quarter 2018; and

• additions to equity method investments of $86 million, as compared with zero for third quarter 2018.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2019			2018			2019			2018
Midstream Services Revenues – Third Party	$	19		$	21		$	63		$	49
Sales of Purchased Oil and Gas	47			46			132			110
(Loss) Income from Equity Method Investments	(5		)	10			(5		)	35
Intersegment Revenues	125			91			322			257
Total Revenues	186			168			512			451
Operating Costs and Expenses	31			30			108			96
Depreciation, Depletion and Amortization	26			24			77			62
Gain on Divestitures, Net	—			(198		)	—			(503		)
Cost of Purchased Oil and Gas	46			44			125			106
Total Expense (Income)	103			(100		)	310			(239		)
Income Before Income Taxes	$	83		$	268		$	202		$	690

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

Midstream services revenues for the first nine months of 2019 increased as compared with 2018, primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. The increases were due primarily to higher Delaware Basin throughput volumes, commencement of services in the Mustang IDP in 2018, and services related to the Black Diamond system, which was acquired during first quarter 2018 in the Saddle Butte acquisition.

Sales and Costs of Purchased Oil and Gas Sales and costs of purchased oil for third quarter and the first nine months of 2019 increased as compared with 2018 due to a full nine months of services related to the Black Diamond system.

(Loss) Income from Equity Method Investments Income from equity method investments decreased for third quarter and the first nine months of 2019 as compared with 2018, primarily due to the sale of our investment in CNX Midstream Partners in second quarter 2018 and 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 the joint ventures and general and administrative expenses incurred prior to service commencement.

Operating Costs and Expenses Operating costs and expenses for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to an increase in gathering systems operating expense associated with the 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 services in the Mustang IDP in 2018.

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

Gain on Divestitures, Net Gain on divestitures, net relates to 2018 sales of our interest in CONE Gathering and our investment in CNX Midstream Partners. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.

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Saddlehorn In third quarter 2019, Noble Midstream Partners entered into a strategic relationship with Saddlehorn, resulting in new long-term firm transportation commitments and an option to acquire up to a 20% ownership interest in Saddlehorn, which transports crude oil and condensate from the DJ and Powder River Basins to storage facilities in Cushing, Oklahoma. The investment option expires in April 2020.

RESULTS OF OPERATIONS – CORPORATE

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(millions)	2019		2018		2019		2018
Sales of Purchased Gas (1)	$	18	$	26	$	68	$	81
Cost of Purchased Gas (1)	33		32		112		98
Firm Transportation Exit Cost (2)	—		—		92		—

⁽¹⁾  Relates to third party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitment. Cost of purchased gas includes utilized and unutilized transportation expense. Amounts for the nine months ended 2019 increased as compared to 2018 due to increased transportation expense for pipelines that came into service in fourth quarter 2018.

⁽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 Expense   G&A expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(millions, except unit rate)	2019		2018		2019		2018
G&A Expense	$	91	$	107	$	298	$	316
Unit Rate per BOE (1)	$	2.62	$	3.44	$	3.11	$	3.34

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

Due to our focus on overall G&A cost reductions, expense for third quarter and the first nine months of 2019 decreased as compared with 2018, and we achieved a 15% reduction as compared to third quarter 2018. Decreases were primarily due to reduced employee, office and travel expenses, partially offset by increases in technology costs. The unit rate per BOE for third quarter and the first nine months of 2019 also decreased as compared with 2018 due to the reduction in G&A expense and the increase in the total sales volumes.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except unit rate)	2019			2018			2019			2018
Interest Expense, Gross	$	92		$	88		$	269		$	269
Capitalized Interest	(25		)	(18		)	(73		)	(53		)
Interest Expense, Net	$	67		$	70		$	196		$	216
Unit Rate per BOE (1)	$	1.93		$	2.25		$	2.04		$	2.28

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

Interest expense, gross, for third quarter and the first nine months of 2019 remained relatively flat as compared with 2018. See Item 1. Financial Statements – Note 7. Debt. Capitalized interest for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to higher work in progress amounts related to Leviathan development and additions to equity method investments engaged in construction activities.

The unit rate per BOE for third quarter and the first nine months of 2019 decreased as compared with 2018, primarily due to the reduction in net interest expense, noted above, and the increase 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 commodity price cycles, including a sustained period of low prices.

35

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 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 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. 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. Refer to Noble Midstream Services 2019 Term Loan Credit Facility and Subsequent Event below for recently completed capital market activities.

Supported by 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.

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. Additionally, we enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production.

Thus far in 2019, we have funded our capital program with cash flows from operations, cash on hand, commercial paper borrowings, and proceeds from divestments of non-strategic assets. We did not repurchase any shares of Noble Energy common stock under the Board of Directors-authorized $750 million share repurchase program during the first nine months of 2019.

Third Quarter 2019 Highlights

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

• borrowed $271 million, net, under our $4.0 billion commercial paper program for working capital purposes;

• repaid $320 million, net, under the Noble Midstream Services Revolving Credit Facility; and

• borrowed $400 million under the Noble Midstream Services 2019 Term Loan Credit Facility, primarily to repay a portion of borrowings outstanding under the Noble Midstream Services Revolving Credit Facility.

Available Liquidity

The following table summarizes our cash, debt and available liquidity:

	September 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)	$	455	$	18	$	473		$	707	$	12	$	719
Amounts Available for Borrowing (2)	3,489		—		3,489			4,000		—		4,000
Total Liquidity	$	3,944	$	18	$	3,962		$	4,707	$	12	$	4,719
Total Debt (3)	$	6,601	$	950	$	7,551		$	6,115	$	560	$	6,675
Noble Energy Share of Equity					$	9,004						$	9,426
Ratio of Debt-to-Book Capital (4)					46		%					41		%

⁽¹⁾  Total cash includes $3 million of restricted cash at December 31, 2018.

⁽²⁾  Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.

⁽³⁾  Total debt excludes unamortized debt discount/premium and debt issuance costs. See Item 1. Financial Statements – Note 7. Debt.

⁽⁴⁾  We define our ratio of debt-to-book capital as total debt divided by the sum of total debt plus Noble Energy's share of equity.

Cash and Cash Equivalents   We had $473 million in cash and cash equivalents at September 30, 2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately

36

$430 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur significant US income tax expense with respect to future repatriation of foreign cash.

Revolving Credit Facilities and Commercial Paper Program Noble Energy's $4.0 billion Revolving Credit Facility and the $800 million Noble Midstream Services Revolving Credit Facility both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. Additionally, 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 Revolving Credit Facility.

At September 30, 2019, outstanding commercial paper borrowings of $511 million reduced the amount available for borrowing under Noble Energy's Revolving Credit Facility to approximately $3.5 billion. Additionally, at September 30, 2019, $50 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $750 million available for borrowing. See Item 1. Financial Statements – Note 7. Debt.

Noble Midstream Services 2019 Term Loan Credit Facility In August 2019, Noble Midstream Services entered into a three-year senior unsecured term loan agreement, which provides for aggregate borrowings of up to $400 million. Noble Midstream Services borrowed $400 million in third quarter 2019. 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 – Note 4. Acquisitions and Divestitures.

Subsequent Event On October 1, 2019, we issued $1.0 billion of notes, using proceeds from the issuance to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations. See Item 1. Financial Statements – Note 7. Debt.

Contractual Obligations

Marcellus Shale Transportation Commitments We have remaining financial commitments of approximately $1.0 billion, undiscounted, associated with Marcellus Shale transportation contracts. See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.

Letters of Credit In the ordinary course of business, we maintain letters of credit and bank guarantees with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit and bank guarantees, including those of Noble Midstream Partners, totaled approximately $121 million at September 30, 2019.

Cash Flows

The following table summarizes our total cash provided by (used in) operating, investing and financing activities:

	Nine Months Ended September 30,
(millions)	2019			2018
Operating Activities	$	1,529		$	1,776
Investing Activities	(2,528		)	(1,502		)
Financing Activities	753			(266		)
(Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	$	(246	)	$	8

Operating Activities   Cash provided by operating activities for the first nine months of 2019 decreased $247 million as compared with 2018. The decrease was primarily driven by a decrease in net revenues driven by lower commodity prices and higher production costs attributable to increased operational activity in US onshore, partially offset by cash received in settlements for commodity derivatives of $28 million, as compared with cash payments of $160 million in the prior year.

Investing Activities   Cash used in investing activities increased approximately $1.0 billion for the first nine months of 2019 as compared with 2018, primarily due to a decrease in net proceeds provided by divestitures and additions to equity method investments of $686 million. These were partially offset by a decrease in capital spending for property, plant and equipment and the absence of spending on acquisitions, compared to $653 million in the prior year.

Financing Activities   Our financing activities during the first nine months of 2019 included net borrowings of $511 million under the commercial paper program, Noble Midstream Partners' borrowings of $400 million on the Noble Midstream Services 2019 Term Loan Credit Facility, the receipt of $97 million of GIP preferred equity, net of offering costs, and net repayments of

37

$10 million on the Noble Midstream Services Revolving Credit Facility. Proceeds from the 2019 Term Loan Credit Facility were used to repay borrowings on Noble Midstream Services Revolving Credit Facility. In addition, during the first nine months of 2019, we paid $168 million of cash dividends to Noble Energy shareholders.

Our financing activities during the first nine months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $35 million, net, Noble Midstream Services Revolving Credit Facility repayment, which included borrowings of $465 million primarily used to fund the Saddle Butte acquisition, offset by a repayment of $500 million drawn under the Noble Midstream Services 2018 Term Loan Credit Facility. We used $384 million of cash to redeem senior notes, repurchased $223 million of common stock pursuant to our stock repurchase program, paid $156 million of cash dividends to Noble Energy shareholders and paid $35 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $348 million of contributions from noncontrolling interest owners. See Item 1. Financial Statements – Consolidated Statements of Cash Flows.

Capital Expenditure Activities

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2019			2018		2019		2018
Unproved Property Acquisition (1)	$	(4	)	$	8	$	35	$	21
Proved Property Acquisition (1)	—			—		4		—
Exploration and Development	518			676		1,728		2,090
Midstream (2)	56			69		174		685
Corporate and Other	21			11		52		38
Total	$	591		$	764	$	1,993	$	2,834
Additions to Equity Method Investments
EMED Pipeline B.V.	$	185		$	—	$	185	$	—
EPIC Y-Grade	18			—		169		—
EPIC Crude Holdings	54			—		273		—
Delaware Crossing	14			—		53		—
Other	—			—		6		—
Total Additions to Equity Method Investments (3)	$	271		$	—	$	686	$	—
Increase in Finance Lease Obligations	$	1		$	9	$	4	$	9

⁽¹⁾  Costs relate to US onshore leasehold activity.

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

⁽³⁾  See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

Exploration and development costs for third quarter and the first nine 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 $1.3 billion for US onshore and $368 million for Eastern Mediterranean, primarily related to Leviathan.

Midstream capital spending, excluding acquisitions, for third quarter and the first nine 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 October 22, 2019, our Board of Directors declared a quarterly cash dividend of 12 cents per Noble Energy common share, which will be paid on November 18, 2019 to shareholders of record on November 4, 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.

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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 – Results of Operations – Exploration & Production.

Derivative Instruments Held for Non-Trading Purposes   At September 30, 2019, our open commodity derivative instruments were in a net asset position with a fair value of $102 million. Based on the September 30, 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 decrease the fair value of our net commodity derivative asset by approximately $228 million. Even with certain hedging arrangements in place to mitigate the risk of commodity price volatility, our 2019 revenues and results of operations could be adversely affected if commodity prices decline. See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on certain of our borrowings. Borrowings under our commercial paper program, the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, and Noble Midstream Services Term Loan Credit Facilities, which as of September 30, 2019 total $1.5 billion and have a weighted average interest rate of 2.96%, 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. While we currently have no interest rate derivative instruments as of September 30, 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 amounts, if any, outstanding under the facilities or commercial paper issuances mentioned above, would have had a de minimis impact on interest expense for third quarter and the first nine months of 2019. See Item 1. Financial Statements – Note 7. Debt.

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 activities;

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

• anticipated trends in our business;

• market conditions in the oil and gas industry;

• the impact of governmental regulation, including US federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production 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 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, 2018, which describe factors that could cause our actual results to differ from

39

those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 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 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, 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, 2018.

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

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)
7/1/2019 - 7/31/2019	—	$	—	—
8/1/2019 - 8/31/2019	10,931	$	22.20	—
9/1/2019 - 9/30/2019	—	$	—	—
Total	10,931	$	22.20	—	$	455

 

⁽¹⁾  Stock repurchases during the period 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 third quarter 2019, we did not repurchase shares under the $750 million share repurchase program, authorized by the Board of Directors and announced on February 15, 2018, which expires December 31, 2020.

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 filed on January 17, 2017 (File No. 001-07964) and incorporated herein by reference).
2.2	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 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 February 5, 2019) (filed as Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K filed on February 19, 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	The following materials from Noble Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Operations and Comprehensive Income (Loss); (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; (iv) Consolidated Statements of Equity; and (v) Notes to Consolidated Financial Statements.
104	Cover Page Interactive Data File (formatted in iXBRL and contained in Exhibit 101).

41

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	November 7, 2019	By: /s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

42

EX-31.1

Exhibit 31.1

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 7241)

I, David L. Stover, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Noble Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019
/s/ David L. Stover
David L. Stover
Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 7241)

I, Kenneth M. Fisher, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Noble Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019
/s/ Kenneth M. Fisher
Kenneth M. Fisher
Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2019 (the “Report”), I, David L. Stover, Chief Executive Officer of the Company, hereby certify that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2019	/s/ David L. Stover
		David L. Stover
		Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2019 (the “Report”), I, Kenneth M. Fisher, Chief Financial Officer of the Company, hereby certify that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2019	/s/ Kenneth M. Fisher
		Kenneth M. Fisher
		Chief Financial Officer

XML

Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table includes estimated revenues, as of September 30, 2019, for those agreements. Our actual future sales volumes may exceed future minimum volume commitments.

(millions)	Remainder of 2019		2020		Total
Natural Gas Revenues (1)	$	36	$	199	$	235

⁽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.

Statement of Operations Information

Other statements of operations information is as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2019		2018			2019		2018
Other Revenue
Income from Equity Method Investments and Other	$	10	$	44		$	43	$	140
Midstream Services Revenues – Third Party	19		21			63		49
Total	$	29	$	65		$	106	$	189
Production Expense
Lease Operating Expense	$	132	$	124		$	405	$	411
Production and Ad Valorem Taxes	52		47			142		151
Gathering, Transportation and Processing Expense	108		97			306		292
Other Royalty Expense	5		5			9		32
Total	$	297	$	273		$	862	$	886
Other Operating Expense, Net
Exploration Expense	$	25	$	25		$	82	$	89
Marketing Expense	7		11			26		21
Firm Transportation Exit Cost	—		—			92		—
Other, Net	29		(9		)	57		(3		)
Total	$	61	$	27		$	257	$	107

Balance Sheet Information Table

Other balance sheet information is as follows:

(millions)	September 30, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	405		$	383
Joint Interest Billings	177			137
Other	103			111
Allowance for Doubtful Accounts	(8		)	(15		)
Total	$	677		$	616
Other Current Assets
Commodity Derivative Assets	$	90		$	180
Inventories, Materials and Supplies	74			55
Assets Held for Sale (1)	—			133
Prepaid Expenses and Other Current Assets	113			50
Total	$	277		$	418
Other Noncurrent Assets
Equity Method Investments (2)	$	959		$	286
Operating Lease Right-of-Use Assets (3)	275			—
Customer-Related Intangible Assets, Net (4)	286			310
Goodwill (4)	110			110
Other Assets, Noncurrent	150			135
Total	$	1,780		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	147		$	103
Asset Retirement Obligations	89			118
Interest Payable	87			66
Operating Lease Liabilities (3)	97			—
Commercial Paper Borrowings	511			—
Other Liabilities, Current	259			232
Total	$	1,190		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	148		$	147
Asset Retirement Obligations	699			762
Operating Lease Liabilities (3)	209			—
Firm Transportation Exit Cost Accrual (5)	133			67
Other Liabilities, Noncurrent	149			189
Total	$	1,338		$	1,165

⁽¹⁾  Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.

⁽²⁾  See Note 4. Acquisitions and Divestitures.

⁽³⁾  Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases.

⁽⁴⁾  Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.

⁽⁵⁾ 

See Note 9. Exit Cost – Transportation Commitments.

Summary of Cash, Cash Equivalents and Restricted Cash

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

	Nine Months Ended September 30,
(millions)	2019		2018
Cash and Cash Equivalents at Beginning of Period	$	716	$	675
Restricted Cash at Beginning of Period	3		38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	719	$	713
Cash and Cash Equivalents at End of Period	$	473	$	720
Restricted Cash at End of Period	—		1
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	473	$	721

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Debt (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Schedule of Debt

Debt consists of the following:

	September 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	511			(1	)	—			—	%
Senior Notes and Debentures	5,884			(2	)	5,892			(2	)
Finance Lease Obligations	206			—	%	223			—	%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt	6,601					6,115
Noble Midstream Partners
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3)	50			3.45	%	60			3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500			3.17	%	500			3.42	%
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022	400			3.05	%	—			—	%
Total Noble Midstream Partners Debt	950					560
Total Debt	7,551					6,675
Net Unamortized Discounts and Debt Issuance Costs	(57		)			(60		)
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs	7,494					6,615
Less Amounts Due Within One Year
Commercial Paper Borrowings	(511		)			—
Finance Lease Obligations	(42		)			(41		)
Long-Term Debt Due After One Year	$	6,941				$	6,574

⁽¹⁾  As of September 30, 2019, the weighted average interest rate for outstanding commercial paper was 2.63%.

⁽²⁾  As of September 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 September 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity, of which $750 million and $740 million were available for borrowing, respectively.

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Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ 7,345	$ 6,452
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ 7,963	$ 6,121

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Debt - Summary of Debt (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Finance Lease Obligations	$ 206
Total Debt	7,551	$ 6,675
Net Unamortized Discounts and Debt Issuance Costs	(57)	(60)
Total Debt	7,494	6,615
Commercial Paper Borrowings	(511)	0
Finance Lease Obligations	(42)	(41)
Long-Term Debt Due After One Year	6,941	6,574
Noble Midstream Services Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	800
Available borrowing capacity	$ 750	$ 740
Senior Notes and Debentures
Debt Instrument [Line Items]
Weighted average interest rate	5.00%	5.01%
Noble Energy
Debt Instrument [Line Items]
Finance Lease Obligations	$ 206	$ 223
Finance Lease Obligations, Interest Rate	0.00%	0.00%
Total Debt	$ 6,601	$ 6,115
Noble Energy | Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt	$ 0	$ 0
Interest Rate	0.00%	0.00%
Noble Energy | Commercial Paper
Debt Instrument [Line Items]
Debt	$ 511	$ 0
Weighted average interest rate, commercial paper	2.63%
Noble Energy | Senior Notes and Debentures
Debt Instrument [Line Items]
Debt	$ 5,884	5,892
Noble Midstream Partners
Debt Instrument [Line Items]
Total Debt	950	560
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Revolving Credit Facility, due March 9, 2023
Debt Instrument [Line Items]
Debt	$ 50	$ 60
Interest Rate	3.45%	3.67%
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due July 31, 2021
Debt Instrument [Line Items]
Debt	$ 500	$ 500
Interest Rate	3.17%	3.42%
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due August 23, 2022
Debt Instrument [Line Items]
Debt	$ 400
Interest Rate	3.05%	0.00%

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Rollforward of Undeveloped Leasehold Costs (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Proved Developed and Undeveloped Reserves [Roll Forward]
Undeveloped Leasehold Costs, Beginning of Period	$ 2,306
Additions to Undeveloped Leasehold Costs	63
Transfers to Proved Properties	(20)
Undeveloped Leasehold Costs, End of Period	$ 2,349

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Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.12	$ 0.12	$ 0.11	$ 0.11	$ 0.11	$ 0.10

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 473	$ 716
Accounts Receivable, Net	677	616
Other Current Assets	277	418
Total Current Assets	1,427	1,750
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,445	29,002
Property, Plant and Equipment, Other	1,045	891
Total Property, Plant and Equipment, Gross	31,490	29,893
Accumulated Depreciation, Depletion and Amortization	(12,693)	(11,474)
Total Property, Plant and Equipment, Net	18,797	18,419
Other Noncurrent Assets	1,780	841
Total Assets	22,004	21,010
Current Liabilities
Accounts Payable – Trade	1,395	1,207
Other Current Liabilities	1,190	519
Total Current Liabilities	2,585	1,726
Long-Term Debt	6,941	6,574
Deferred Income Taxes	954	1,061
Other Noncurrent Liabilities	1,338	1,165
Total Liabilities	11,818	10,526
Commitments and Contingencies
Mezzanine Equity
Redeemable Noncontrolling Interest, Net	103	0
Shareholders’ Equity
Preferred Stock – Par Value $1.00 per share; 4 Million Shares Authorized; None Issued	0	0
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	8,258	8,203
Accumulated Other Comprehensive Loss	(30)	(32)
Treasury Stock, at Cost; 39 Million Shares	(735)	(730)
Retained Earnings	1,506	1,980
Noble Energy Share of Equity	9,004	9,426
Noncontrolling Interests	1,079	1,058
Total Shareholders' Equity	10,083	10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity	$ 22,004	$ 21,010

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Exit Costs - Transportation Commitments - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018
Long-term Purchase Commitment [Line Items]
Reduction of transportation contracts	$ 350
Marcellus Shale Firm Transportation Agreement
Long-term Purchase Commitment [Line Items]
Commitment amount		$ 1,000
Firm Transportation Exit Cost Accrual	$ 92	$ 92	$ 0

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Derivative Instruments and Hedging Activities - Summary of Outstanding Derivative Contracts (Details)	Sep. 30, 2019 bbl / d MMBTU / d $ / bbl $ / MMBTU
Crude Oil Contract | NYMEX WTI - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	35,000
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	33,000
Crude Oil Contract | NYMEX WTI - Sold Calls 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	4,000
Crude Oil Contract | ICE Brent - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	5,000
Crude Oil Contract | ICE Brent - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	3,000
Crude Oil Contract | Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	27,000
Crude Oil Contract | NYMEX WTI - Swaption 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	12,000
Crude Oil Contract | NYMEX WTI - Sold Calls 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	8,000
Crude Oil Contract | NYMEX WTI - Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	28,000
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	30,000
Crude Oil Contract | Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | bbl / d	15,000
Natural Gas Contract | NYMEX HH - Three-Way Collars 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	104,000
Natural Gas Contract | NYMEX HH - Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	46,000
Natural Gas Contract | CIG - Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	123,500
Natural Gas Contract | WAHA - Basis Swaps 2019
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	47,500
Natural Gas Contract | NYMEX HH - Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | NYMEX HH - Sold Puts 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | NYMEX HH - Swaption 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	90,000
Natural Gas Contract | CIG - Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	54,000
Natural Gas Contract | WAHA - Basis Swaps 2020
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	49,500
Natural Gas Contract | WAHA - Basis Swaps 2021
Derivative [Line Items]
Bbls Per Day (Bbls per day) | MMBTU / d	14,000
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	59.04
Swaps | Crude Oil Contract | NYMEX WTI - Sold Calls 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	60.00
Swaps | Crude Oil Contract | ICE Brent - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	57.00
Swaps | Crude Oil Contract | Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl)	(3.23)
Swaps | Crude Oil Contract | NYMEX WTI - Swaption 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	59.73
Swaps | Crude Oil Contract | NYMEX WTI - Sold Calls 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	65.59
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl)	58.09
Swaps | Crude Oil Contract | Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl)	(5.01)
Swaps | Natural Gas Contract | NYMEX HH - Swaps 2019
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	3.00
Swaps | Natural Gas Contract | CIG - Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.64)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2019
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(1.28)
Swaps | Natural Gas Contract | NYMEX HH - Swaps 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	2.60
Swaps | Natural Gas Contract | NYMEX HH - Swaption 2020
Derivative [Line Items]
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU	2.60
Swaps | Natural Gas Contract | CIG - Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.61)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2020
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(1.05)
Swaps | Natural Gas Contract | WAHA - Basis Swaps 2021
Derivative [Line Items]
Weighted Average Differential ($ per bbl) | $ / MMBTU	(0.60)
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	49.35
Weighted Average Floor Price ($ per bbl)	59.35
Weighted Average Ceiling Price ($ per bbl)	72.25
Collars | Crude Oil Contract | ICE Brent - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	43.00
Weighted Average Floor Price ($ per bbl)	50.00
Weighted Average Ceiling Price ($ per bbl)	64.07
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl)	48.33
Weighted Average Floor Price ($ per bbl)	57.87
Weighted Average Ceiling Price ($ per bbl)	64.27
Collars | Natural Gas Contract | NYMEX HH - Three-Way Collars 2019
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU	2.25
Weighted Average Floor Price ($ per bbl) | $ / MMBTU	2.65
Weighted Average Ceiling Price ($ per bbl) | $ / MMBTU	2.95
Collars | Natural Gas Contract | NYMEX HH - Sold Puts 2020
Derivative [Line Items]
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU	2.15

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Basis of Presentation - Statements of Operations Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Other Revenue
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Production Expense
Lease Operating Expense	132	124	405	411
Production and Ad Valorem Taxes	52	47	142	151
Gathering, Transportation and Processing Expense	108	97	306	292
Total	297	273	862	886
Other Operating Expense, Net
Exploration Expense	25	25	82	89
Marketing Expense	7	11	26	21
Firm Transportation Exit Cost	0	0	92	0
Other, Net	29	(9)	57	(3)
Total	61	27	257	107
Other Revenue
Other Revenue
Revenue from Sales	29	65	106	189
Income from Equity Method Investments and Other
Other Revenue
Revenue from Sales	10	44	43	140
Midstream Services Revenues – Third Party
Other Revenue
Revenue from Sales	19	21	63	49
Other Royalty Expense
Production Expense
Cost of Purchased Oil and Gas	$ 5	$ 5	$ 9	$ 32

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Fair Value Measurements and Disclosures (Tables)

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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
September 30, 2019
Financial Assets:
Mutual Fund Investments	$	42		$	—		$	—	$	—		$	42
Commodity Derivative Instruments	—			155			—		(40		)	115
Financial Liabilities:
Commodity Derivative Instruments	—			(53		)	—		40			(13		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(3		)	—			—		—			(3		)
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 settle asset and liability positions with the same counterparty.

Additional fair value disclosures

Fair value information regarding our debt is as follows:

	September 30, 2019				December 31, 2018
(millions)	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value
Debt (2)	$	7,345	$	7,963	$	6,452	$	6,121

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

⁽²⁾ 

Represents total debt excluding finance lease obligations. See Note 7. Debt.

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Acquisitions and Divestitures

Note 4. Acquisitions and Divestitures

We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.

2019 Asset Transactions

Eastern Mediterranean Investment During third quarter 2019, we invested $185 million for a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.) in support of its planned acquisition of an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s planned equity acquisition of EMG, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers and support delivery of natural gas from our producing fields offshore Israel into Egypt.

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 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 acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline. Both pipelines will transport production from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million and Noble Midstream Partners has since made additional capital contributions of $46 million and $168 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method.

Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC 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 nine months of 2019, Noble Midstream Partners has made capital contributions of $53 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 March 31, 2018, we reduced the 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 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 received net proceeds of $383 million and recorded a loss of $24 million.

Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a 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 $376 million and tax expense of $86 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.

Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin, receiving proceeds of $64 million, resulting in no gain or loss on the sale.

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 consolidated as a VIE.

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 acquisition date fair values, and we recognized goodwill for the amount of the purchase price exceeding the fair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.

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Leases

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Leases

Note 8. Leases

In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include 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.

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

(millions)	Balance Sheet Location	September 30, 2019
ROU Assets
Operating Leases (1)	Other Noncurrent Assets	$	275
Finance Leases (2)	Total Property, Plant and Equipment, Net	172
Total ROU Assets		$	447
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	97
Finance Leases	Other Current Liabilities	42
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	209
Finance Leases	Long-Term Debt	164
Total Lease Liabilities		$	512

⁽¹⁾  Operating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and drilling rigs of $29 million.

⁽²⁾  Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.

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

(millions)	Statement of Operations Location	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating Lease Cost	(1)	$	30		$	81
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	10			27
Interest Expense	Interest, Net of Amount Capitalized	3			10
Short-term Lease Cost (2)	(1)	88			357
Sublease Income	General and Administrative	(1		)	(3		)
Total Lease Cost		$	130		$	472

⁽¹⁾  Cost classifications vary 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 and, therefore, are included as part of oil and gas properties on our consolidated balance sheets.

⁽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.

Cash Flow Information Supplemental cash flow information is as follows:

	Nine Months Ended September 30, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	50	$	9
Investing Cash Flows	27		—
Financing Cash Flows	—		31
Non-Cash Activities
ROU Assets Obtained in Exchange for Lease Liabilities (1)	93		15

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

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

(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	28	$	13	$	41
2020	100		49		149
2021	61		35		96
2022	44		25		69
2023	29		22		51
2024 and Thereafter	85		106		191
Total Lease Liabilities, Undiscounted	347		250		597
Less: Imputed Interest	41		44		85
Total Lease Liabilities (1)	$	306	$	206	$	512

⁽¹⁾  Includes the current portions of $97 million and $42 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 as of September 30, 2019 is as follows:

	Operating Leases		Finance Leases
Weighted-Average Remaining Lease Term	5.7 years		7.7 years
Weighted-Average Discount Rate	4.40	%	5.02	%

Leases

Note 8. Leases

In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include 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.

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

(millions)	Balance Sheet Location	September 30, 2019
ROU Assets
Operating Leases (1)	Other Noncurrent Assets	$	275
Finance Leases (2)	Total Property, Plant and Equipment, Net	172
Total ROU Assets		$	447
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	97
Finance Leases	Other Current Liabilities	42
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	209
Finance Leases	Long-Term Debt	164
Total Lease Liabilities		$	512

⁽¹⁾  Operating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and drilling rigs of $29 million.

⁽²⁾  Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.

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

(millions)	Statement of Operations Location	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating Lease Cost	(1)	$	30		$	81
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	10			27
Interest Expense	Interest, Net of Amount Capitalized	3			10
Short-term Lease Cost (2)	(1)	88			357
Sublease Income	General and Administrative	(1		)	(3		)
Total Lease Cost		$	130		$	472

⁽¹⁾  Cost classifications vary 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 and, therefore, are included as part of oil and gas properties on our consolidated balance sheets.

⁽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.

Cash Flow Information Supplemental cash flow information is as follows:

	Nine Months Ended September 30, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	50	$	9
Investing Cash Flows	27		—
Financing Cash Flows	—		31
Non-Cash Activities
ROU Assets Obtained in Exchange for Lease Liabilities (1)	93		15

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

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

(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	28	$	13	$	41
2020	100		49		149
2021	61		35		96
2022	44		25		69
2023	29		22		51
2024 and Thereafter	85		106		191
Total Lease Liabilities, Undiscounted	347		250		597
Less: Imputed Interest	41		44		85
Total Lease Liabilities (1)	$	306	$	206	$	512

⁽¹⁾  Includes the current portions of $97 million and $42 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 as of September 30, 2019 is as follows:

	Operating Leases		Finance Leases
Weighted-Average Remaining Lease Term	5.7 years		7.7 years
Weighted-Average Discount Rate	4.40	%	5.02	%

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Note 12. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   We enter into crude oil and natural gas price hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and 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 September 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	35,000	$	—		$	59.04	$	—	$	—	$	—
2019	Three-Way Collars	NYMEX WTI	33,000	—			—		49.35		59.35		72.25
2019	Sold Calls (1)	NYMEX WTI	4,000	—			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	12,000	—			59.73		—		—		—
2020	Sold Calls (1)	NYMEX WTI	8,000	—			65.59		—		—		—
2020	Swaps	NYMEX WTI	28,000	—			58.09		—		—		—
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.

As of September 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	Swaps	NYMEX HH	90,000	—			2.60		—		—		—
2020	Sold Puts (2)	NYMEX HH	90,000	—			—		2.15		—		—
2020	Swaption	NYMEX HH	90,000	—			2.60		—		—		—
2020	Basis Swaps	CIG (1)	54,000	(0.61		)	—		—		—		—
2020	Basis Swaps	WAHA (1)	49,500	(1.05		)	—		—		—		—
2021	Basis Swaps	WAHA (1)	14,000	(0.60		)	—		—		—		—

⁽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.

⁽²⁾  We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.

Fair Value Amounts   The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions):

Asset Derivative Instruments					Liability Derivative Instruments
Balance Sheet Location	September 30, 2019		December 31, 2018		Balance Sheet Location	September 30, 2019		December 31, 2018
Other Current Assets	$	90	$	180	Other Current Liabilities	$	10	$	1
Other Noncurrent Assets	25		—		Other Noncurrent Liabilities	3		26
Total	$	115	$	180		$	13	$	27

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

Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2019			2018			2019			2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(6	)	$	68		$	(8	)	$	164
Natural Gas	(7		)	(1		)	(20		)	(4		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(13		)	67			(28		)	160
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	(115		)	85			54			316
Natural Gas	(1		)	3			(3		)	7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(116		)	88			51			323
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(121		)	153			46			480
Natural Gas	(8		)	2			(23		)	3
Total (Gain) Loss on Commodity Derivative Instruments	$	(129	)	$	155		$	23		$	483

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Leases - Lease Term and Discount Rates (Details)	Sep. 30, 2019	Dec. 31, 2018
Weighted-Average Remaining Lease Term (Years)
Operating Leases	5 years 8 months 12 days
Finance Leases		7 years 8 months 12 days
Weighted-Average Discount Rate
Operating Leases	4.40%
Finance Leases		5.02%

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Mar. 31, 2018
Operating Loss Carryforwards [Line Items]
Tax benefit from Tax Reform Legislation and Toll Tax	$ 145
Tamar and Dalit Fields | Disposed by sale
Operating Loss Carryforwards [Line Items]
Percentage of divestiture farmed out		7.50%

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Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid in Capital	Accumulated Other Comprehensive Loss	Treasury Stock at Cost	Retained Earnings	Non-controlling Interests
Balance at Beginning of Period at Dec. 31, 2017	$ 10,619	$ 5	$ 8,438	$ (30)	$ (725)	$ 2,248	$ 683
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	574					554	20
Stock-based Compensation	17		17
Dividends	(48)					(48)
Purchase and Retirement of Common Stock	(67)		(67)
Clayton Williams Energy Acquisition	(25)		(25)
Distributions to Noncontrolling Interest Owners	(11)						(11)
Contributions from Noncontrolling Interest Owners	331						331
Other	(3)			1	(6)		2
Balance at End of Period at Mar. 31, 2018	11,387	5	8,363	(29)	(731)	2,754	1,025
Balance at Beginning of Period at Dec. 31, 2017	10,619	5	8,438	(30)	(725)	2,248	683
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	816
Balance at End of Period at Sep. 30, 2018	11,394	5	8,249	(27)	(731)	2,850	1,048
Balance at Beginning of Period at Mar. 31, 2018	11,387	5	8,363	(29)	(731)	2,754	1,025
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(6)					(23)	17
Stock-based Compensation	29		29
Dividends	(54)					(54)
Purchase and Retirement of Common Stock	(63)		(63)
Distributions to Noncontrolling Interest Owners	(11)						(11)
Other	(1)			1			(2)
Balance at End of Period at Jun. 30, 2018	11,281	5	8,329	(28)	(731)	2,677	1,029
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	248					227	21
Stock-based Compensation	17		17
Dividends	(54)					(54)
Purchase and Retirement of Common Stock	(103)		(103)
Distributions to Noncontrolling Interest Owners	(13)						(13)
Contributions from Noncontrolling Interest Owners	17						17
Other	1		6	1			(6)
Balance at End of Period at Sep. 30, 2018	11,394	5	8,249	(27)	(731)	2,850	1,048
Balance at Beginning of Period at Dec. 31, 2018	10,484	5	8,203	(32)	(730)	1,980	1,058
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(289)					(313)	24
Stock-based Compensation	14		14
Dividends	(53)					(53)
Distributions to Noncontrolling Interest Owners	(17)						(17)
Contributions from Noncontrolling Interest Owners	10						10
Other	(6)		2		(5)		(3)
Balance at End of Period at Mar. 31, 2019	10,143	5	8,219	(32)	(735)	1,614	1,072
Balance at Beginning of Period at Dec. 31, 2018	10,484	5	8,203	(32)	(730)	1,980	1,058
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	(245)
Balance at End of Period at Sep. 30, 2019	10,083	5	8,258	(30)	(735)	1,506	1,079
Balance at Beginning of Period at Mar. 31, 2019	10,143	5	8,219	(32)	(735)	1,614	1,072
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	8					(10)	18
Stock-based Compensation	21		21
Dividends	(58)					(58)
Distributions to Noncontrolling Interest Owners	(19)						(19)
Contributions from Noncontrolling Interest Owners	11						11
Other	(2)		4	1			(7)
Balance at End of Period at Jun. 30, 2019	10,104	5	8,244	(31)	(735)	1,546	1,075
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (Loss) Income	36					17	19
Stock-based Compensation	16		16
Dividends	(57)					(57)
Distributions to Noncontrolling Interest Owners	(19)						(19)
Contributions from Noncontrolling Interest Owners	6						6
Other	(3)		(2)	1			(2)
Balance at End of Period at Sep. 30, 2019	$ 10,083	$ 5	$ 8,258	$ (30)	$ (735)	$ 1,506	$ 1,079

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Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Total	1,119	1,273	3,264	3,789
Costs and Expenses
Production Expense	297	273	862	886
Depreciation, Depletion and Amortization	583	485	1,619	1,418
General and Administrative	91	107	298	316
Other Operating Expense, Net	61	27	257	107
Gain on Divestitures, Net	0	(193)	0	(859)
Asset Impairments	0	0	0	168
Total	1,128	775	3,332	2,240
Operating (Loss) Income	(9)	498	(68)	1,549
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Interest, Net of Amount Capitalized	67	70	196	216
Other Non-Operating Expense (Income), Net	2	(34)	7	(10)
Total	(60)	191	226	689
Income (Loss) Before Income Taxes	51	307	(294)	860
Income Tax Expense (Benefit)	15	59	(49)	44
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	36	248	(245)	816
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	19	21	61	58
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$ 17	$ 227	$ (306)	$ 758
Net Income (Loss) Attributable to Noble Energy Common Shareholders per Share
Basic ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.57
Diluted ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.56
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	478	482	478	484
Diluted (in shares)	480	484	478	486
Oil, NGL and Gas Sales
Revenues
Revenue from Sales	$ 1,003	$ 1,136	$ 2,894	$ 3,409
Sales of Purchased Oil and Gas
Revenues
Revenue from Sales	87	72	264	191
Costs and Expenses
Cost of Purchased Oil and Gas	96	76	296	204
Other Revenue
Revenues
Revenue from Sales	$ 29	$ 65	$ 106	$ 189

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Basis of Presentation - Balance Sheet Information (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Accounts Receivable, Net
Commodity Sales	$ 405	$ 383
Joint Interest Billings	177	137
Other	103	111
Allowance for Doubtful Accounts	(8)	(15)
Total	677	616
Other Current Assets
Commodity Derivative Assets	90	180
Inventories, Materials and Supplies	74	55
Assets Held for Sale	0	133
Prepaid Expenses and Other Current Assets	113	50
Total	277	418
Other Noncurrent Assets
Equity Method Investments	959	286
Operating Lease Right of Use Assets	275	0
Customer-Related Intangible Assets, Net	286	310
Goodwill	110	110
Other Assets, Noncurrent	150	135
Total	1,780	841
Other Current Liabilities
Production and Ad Valorem Taxes	147	103
Asset Retirement Obligations	89	118
Interest Payable	87	66
Operating Lease Liabilities	97	0
Commercial Paper Borrowings	511	0
Other Liabilities, Current	259	232
Total	1,190	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	148	147
Asset Retirement Obligations	699	762
Operating Lease Liabilities	209	0
Firm Transportation Exit Cost Accrual	133	67
Other Liabilities, Noncurrent	149	189
Total	1,338	1,165
Accumulated amortization	$ 54	$ 30

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Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders (Tables)

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Schedule of earnings per share

The following table summarizes the calculation of basic and diluted income (loss) per share:

	Three Months Ended September 30,				Nine Months Ended September 30,
(millions, except per share amounts)	2019		2018		2019			2018
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	17	$	227	$	(306	)	$	758
Weighted Average Number of Shares Outstanding, Basic (1)	478		482		478			484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	2		2		—			2
Weighted Average Number of Shares Outstanding, Diluted	480		484		478			486
Income (Loss) Per Share, Basic	$	0.04	$	0.47	$	(0.64	)	$	1.57
Income (Loss) Per Share, Diluted	$	0.04	$	0.47	$	(0.64	)	$	1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14		13		15			14

⁽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.

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Income Taxes

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Note 11. Income Taxes

Income tax expense (benefit) consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except percentages)	2019			2018			2019			2018
Current	$	24		$	45		$	61		$	194
Deferred	(9		)	14			(110		)	(150		)
Total Income Tax Expense (Benefit)	$	15		$	59		$	(49	)	$	44
Effective Tax Rate	29.4		%	19.2		%	16.7		%	5.1		%

Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the nine months ended September 30, 2019 varied as compared with 2018, primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the nine months ended September 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar 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.

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Segment Information

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Segment Information

Note 3. Segment Information

We 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 (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 assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our 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 retained Marcellus Shale transportation agreements, are recorded at the Corporate level.

			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 September 30, 2019
Crude Oil Sales	$	724	$	645	$	1	$	78	$	—	$	—		$	—		$	—
NGL Sales	78		78		—		—		—		—			—			—
Natural Gas Sales	201		79		118		4		—		—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,003		802		119		82		—		—			—			—
Sales of Purchased Oil and Gas	87		22		—		—		—		47			—			18
Income (Loss) from Equity Method Investments and Other	10		1		—		14		—		(5		)	—			—
Midstream Services Revenues – Third Party	19		—		—		—		—		19			—			—
Intersegment Revenues	—		—		—		—		—		125			(125		)	—
Total Revenues	1,119		825		119		96		—		186			(125		)	18
Lease Operating Expense	132		111		7		22		—		1			(9		)	—
Production and Ad Valorem Taxes	52		51		—		—		—		1			—			—
Gathering, Transportation and Processing Expense	108		173		1		—		—		5			(71		)	—
Other Royalty Expense	5		5		—		—		—		—			—			—
Total Production Expense	297		340		8		22		—		7			(80		)	—

				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	583			505			17		21			1			26			(8		)	21
Cost of Purchased Oil and Gas	96			17			—		—			—			46			—			33
Gain on Commodity Derivative Instruments	(129		)	(123		)	—		(6		)	—			—			—			—
Income (Loss) Before Income Taxes	51			92			74		56			(17		)	83			(23		)	(214		)
Additions to Long-Lived Assets, Excluding Acquisitions	595			377			129		46			2			56			(26		)	11
Additions to Equity Method Investments	271			—			185		—			—			86			—			—
Three Months Ended September 30, 2018
Crude Oil Sales	$	744		$	655		$	2	$	87		$	—		$	—		$	—		$	—
NGL Sales	166			166			—		—			—			—			—			—
Natural Gas Sales	226			98			122		6			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,136			919			124		93			—			—			—			—
Sales of Purchased Oil and Gas	72			—			—		—			—			46			—			26
Income from Equity Method Investments and Other	44			—			—		34			—			10			—			—
Midstream Services Revenues – Third Party	21			—			—		—			—			21			—			—
Intersegment Revenues	—			—			—		—			—			91			(91		)	—
Total Revenues	1,273			919			124		127			—			168			(91		)	26
Lease Operating Expense	124			114			7		15			—			—			(12		)	—
Production and Ad Valorem Taxes	47			46			—		—			—			1			—			—
Gathering, Transportation and Processing Expense	97			129			—		—			—			28			(60		)	—
Other Royalty Expense	5			5			—		—			—			—			—			—
Total Production Expense	273			294			7		15			—			29			(72		)	—
Depreciation, Depletion and Amortization	485			414			16		25			1			24			(5		)	10
(Gain) Loss on Divestitures, Net	(193		)	5			—		—			—			(198		)	—			—
Cost of Purchased Oil and Gas	76			—			—		—			—			44			—			32
Loss on Commodity Derivative Instruments	155			140			—		15			—			—			—			—
Income (Loss) Before Income Taxes	307			31			143		68			(17		)	268			(16		)	(170		)
Additions to Long-Lived Assets, Excluding Acquisitions	768			535			170		4			1			82			(22		)	(2		)
Nine Months Ended September 30, 2019
Crude Oil Sales	$	2,024		$	1,807		$	4	$	213		$	—		$	—		$	—		$	—
NGL Sales	258			258			—		—			—			—			—			—
Natural Gas Sales	612			259			340		13			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	2,894			2,324			344		226			—			—			—			—

				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
Sales of Purchased Oil and Gas	264			64			—		—		—			132			—			68
Income (Loss) from Equity Method Investments and Other	43			2			—		46		—			(5		)	—			—
Midstream Services Revenues – Third Party	63			—			—		—		—			63			—			—
Intersegment Revenues	—			—			—		—		—			322			(322		)	—
Total Revenues	3,264			2,390			344		272		—			512			(322		)	68
Lease Operating Expense	405			350			26		56		—			3			(30		)	—
Production and Ad Valorem Taxes	142			138			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	306			439			1		—		—			65			(199		)	—
Other Royalty Expense	9			9			—		—		—			—			—			—
Total Production Expense	862			936			27		56		—			72			(229		)	—
Depreciation, Depletion and Amortization	1,619			1,401			50		60		1			77			(21		)	51
Cost of Purchased Oil and Gas	296			59			—		—		—			125			—			112
Firm Transportation Exit Cost	92			—			—		—		—			—			—			92
Loss on Commodity Derivative Instruments	23			7			—		16		—			—			—			—
(Loss) Income Before Income Taxes	(294		)	(85		)	223		126		(48		)	202			(52		)	(660		)
Additions to Long-Lived Assets, Excluding Acquisitions	1,954			1,367			380		64		14			174			(74		)	29
Additions to Equity Method Investments	686			—			185		—		—			501			—			—
Nine Months Ended September 30, 2018
Crude Oil Sales	$	2,266		$	1,972		$	6	$	288	$	—		$	—		$	—		$	—
NGL Sales	449			449			—		—		—			—			—			—
Natural Gas Sales	694			316			362		16		—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	3,409			2,737			368		304		—			—			—			—
Sales of Purchased Oil and Gas	191			—			—		—		—			110			—			81
Income from Equity Method Investments and Other	140			—			—		105		—			35			—			—
Midstream Services Revenues – Third Party	49			—			—		—		—			49			—			—
Intersegment Revenues	—			—			—		—		—			257			(257		)	—
Total Revenues	3,789			2,737			368		409		—			451			(257		)	81
Lease Operating Expense	411			354			19		56		—			—			(18		)	—
Production and Ad Valorem Taxes	151			147			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	292			389			—		—		—			71			(168		)	—
Other Royalty Expense	32			32			—		—		—			—			—			—
Total Production Expense	886			922			19		56		—			75			(186		)	—
Depreciation, Depletion and Amortization	1,418			1,214			44		77		1			62			(13		)	33

				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
(Gain) Loss on Divestitures, Net	(859		)	20			(376		)	—		—			(503		)	—			—
Asset Impairments	168			168			—			—		—			—			—			—
Cost of Purchased Oil and Gas	204			—			—			—		—			106			—			98
Loss on Commodity Derivative Instruments	483			400			—			83		—			—			—			—
Income (Loss) Before Income Taxes	860			(94		)	678			180		(44		)	690			(52		)	(498		)
Additions to Long-Lived Assets, Excluding Acquisitions	2,608			1,630			533			9		3			479			(72		)	26
September 30, 2019
Property, Plant and Equipment, Net	$	18,797		$	13,170		$	3,001		$	801	$	39		$	1,682		$	(198	)	$	302
December 31, 2018
Property, Plant and Equipment, Net	$	18,419		$	13,044		$	2,630		$	805	$	37		$	1,742		$	(145	)	$	306

⁽¹⁾ 

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.

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Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt

Note 7. Debt

Debt consists of the following:

	September 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	511			(1	)	—			—	%
Senior Notes and Debentures	5,884			(2	)	5,892			(2	)
Finance Lease Obligations	206			—	%	223			—	%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt	6,601					6,115
Noble Midstream Partners
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3)	50			3.45	%	60			3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500			3.17	%	500			3.42	%
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022	400			3.05	%	—			—	%
Total Noble Midstream Partners Debt	950					560
Total Debt	7,551					6,675
Net Unamortized Discounts and Debt Issuance Costs	(57		)			(60		)
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs	7,494					6,615
Less Amounts Due Within One Year
Commercial Paper Borrowings	(511		)			—
Finance Lease Obligations	(42		)			(41		)
Long-Term Debt Due After One Year	$	6,941				$	6,574

⁽¹⁾  As of September 30, 2019, the weighted average interest rate for outstanding commercial paper was 2.63%.

⁽²⁾  As of September 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 September 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity, of which $750 million and $740 million were available for borrowing, 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 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 discount 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 September 30, 2019, outstanding commercial paper borrowings totaled $511 million, leaving approximately $3.5 billion available for borrowing under our $4.0 billion Revolving Credit Facility.

Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility.

Subsequent Event On October 1, 2019, we issued $500 million of 3.25% notes due October 15, 2029 and $500 million of 4.20% notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations.

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

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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 September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 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, net income or loss is materially consistent with comprehensive income or loss.

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

Consolidation

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

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.

Leases

Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the 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 our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.

Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of 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 our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the 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 accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as 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 Recognition

Revenue Recognition   We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606).

Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations.

Redeemable Noncontrolling Interest

Redeemable Noncontrolling Interest 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 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 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, 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, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital.

Recently Issued and Recently Adopted Accounting Standards

Recently Issued Accounting Standards

Financial Instruments: Credit Losses In June 2016, the 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 with a methodology that reflects current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and 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.

We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements.

Recently Adopted Accounting Standards

Leases In 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 recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements.

Intangibles—Goodwill and Other—Internal-Use Software In 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, 2019, with early adoption permitted. We used the prospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our financial statements.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Changes in Asset Retirement Obligations

Changes in ARO are as follows:

	Nine Months Ended September 30,
(millions)	2019			2018
Asset Retirement Obligations, Beginning Balance	$	880		$	875
Liabilities Incurred	17			16
Liabilities Settled	(82		)	(309		)
Revisions of Estimates	(60		)	67
Accretion Expense	33			25
Asset Retirement Obligations, Ending Balance	$	788		$	674

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Fair Value Measurements and Disclosures - Narrative (Details) - USD ($) $ in Millions	1 Months Ended		9 Months Ended
	Mar. 31, 2019	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Redeemable Noncontrolling Interest, Net	$ 97		$ 103		$ 0
Proceeds from issuance of preferred equity			97	$ 0
Noble Midstream
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proceeds from issuance of preferred equity	100
Issuance costs of preferred equity	$ 3
Marcellus Shale Firm Transportation Agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Firm transportation exit cost accrual		$ 92	$ 92	$ 0

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Debt - Narrative (Details) - USD ($)	3 Months Ended	9 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Commercial paper		$ 511,000,000
Commercial Paper
Debt Instrument [Line Items]
Borrowing capacity		4,000,000,000.0
Available borrowing capacity		3,500,000,000
Senior Notes October 2029
Debt Instrument [Line Items]
Borrowing capacity		$ 500,000,000
Interest Rate		3.25%
Senior Notes October 2049
Debt Instrument [Line Items]
Borrowing capacity		$ 500,000,000
Interest Rate		4.20%
Senior Notes December 2021
Debt Instrument [Line Items]
Interest Rate		4.15%
Debt redemption		$ 1,000,000,000.0
Scenario, Forecast
Debt Instrument [Line Items]
Debt extinguishment fees	$ 44,000,000
Revolving Credit Facility | Noble Midstream | Noble Midstream Services Term Loan Credit Facility, due August 23, 2022
Debt Instrument [Line Items]
Debt		$ 400,000,000
Interest Rate		3.05%	0.00%

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Delaware Basin
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	$ 2,100
Eagle Ford Shale
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	100
Other US Onshore Properties
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	76
Other Int'l
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Capitalized undeveloped leasehold cost	$ 59

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Leases - Cash Flow Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows, Operating Leases	$ 50
Operating Cash Flows, Finance Leases	9
Investing Cash Flows, Operating Leases	27
Financing Cash Flows, Finance Leases	31
ROU Assets Obtained in Exchange for Lease Liability, Operating	93
ROU Assets Obtained in Exchange for Lease Liability, Finance	$ 15

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Organization and Nature of Operations

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

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 Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus areas being the DJ and Delaware Basins.

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Exit Costs - Transportation Commitments - Rollfoward of Accrued Transportation Commitment (Details) - Marcellus Shale Firm Transportation Agreement - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Rollforward Of Contractual Obligations [Roll Forward]
Balance at Beginning of Period	$ 80	$ 80	$ 90
Firm Transportation Exit Cost Accrual	$ 92	92	0
Payments, Net of Accretion		(6)	(9)
Balance at End of Period		166	81
Other Current Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at End of Period		33	12
Accrued exit costs, current				$ 13
Other Noncurrent Liabilities
Rollforward Of Contractual Obligations [Roll Forward]
Balance at End of Period		$ 133	$ 69

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value per share (in dollars per share)	$ 1	$ 1
Preferred stock, shares authorized (in shares)	4,000,000	4,000,000
Preferred stock, shares issued (in shares)	0	0
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000,000,000	1,000,000,000
Common stock, shares issued (in shares)	522,000,000	520,000,000
Treasury stock, shares (in shares)	39,000,000	39,000,000

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Derivative Instruments and Hedging Activities - Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 115		$ 115		$ 180
Derivative Liability, Fair Value	13		13		27
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(13)	$ 67	(28)	$ 160
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(116)	88	51	323
Total (Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	90		90		180
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	10		10		1
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	25		25		0
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	3		3		$ 26
Crude Oil
Derivatives, Fair Value [Line Items]
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(6)	68	(8)	164
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(115)	85	54	316
Total (Gain) Loss on Commodity Derivative Instruments	(121)	153	46	480
Natural Gas
Derivatives, Fair Value [Line Items]
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(7)	(1)	(20)	(4)
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(1)	3	(3)	7
Total (Gain) Loss on Commodity Derivative Instruments	$ (8)	$ 2	$ (23)	$ 3

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

9 Months Ended

Sep. 30, 2019

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

Capitalized Exploratory Well Costs 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)	September 30, 2019		December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	15	$	6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	354		348
Capitalized Exploratory Well Costs, End of Period	$	369	$	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

Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows:

(millions)	Nine Months Ended September 30, 2019
Undeveloped Leasehold Costs, Beginning of Period	$	2,306
Additions to Undeveloped Leasehold Costs	63
Transfers to Proved Properties	(20		)
Undeveloped Leasehold Costs, End of Period	$	2,349

As of September 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $76 million, and $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 subject to expiration over the next several years unless production is established on the acreage. Other costs pertain to acreage that is being held by production.

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Exit Costs - Transportation Commitments

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Exit Costs - Transportation Commitments

Note 9. Exit Cost – Transportation Commitments

In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of September 30, 2019, our undiscounted financial commitment for the remaining obligations under these agreements was approximately $1.0 billion, which excludes the impact of future mitigation activities. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and

transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations.

Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, 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 remaining component of these transportation agreements through 2020.

Exit Costs Reconciliation of accrued costs at September 30, 2019 is as follows:

	Nine Months Ended September 30,
(millions)	2019			2018
Balance at Beginning of Period (1)	$	80		$	90
Firm Transportation Exit Cost Accrual	92			—
Payments, Net of Accretion	(6		)	(9		)
Balance at End of Period	166			81
Less: Current Portion Included in Other Current Liabilities	33			12
Long-term Portion Included in Other Noncurrent Liabilities	$	133		$	69

⁽¹⁾ 

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

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Segment Information - Operating Results by Segment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenue from Sales	$ 1,119	$ 1,273	$ 3,264	$ 3,789
Lease Operating Expense	132	124	405	411
Production and Ad Valorem Taxes	52	47	142	151
Gathering, Transportation and Processing Expense	108	97	306	292
Total Production Expense	297	273	862	886
Depreciation, Depletion and Amortization	583	485	1,619	1,418
Firm Transportation Exit Cost	0	0	92	0
(Gain) Loss on Divestitures, Net	0	(193)	0	(859)
Asset Impairments				168
(Gain) Loss on Commodity Derivative Instruments	(129)	155	23	483
Income (Loss) Before Income Taxes	51	307	(294)	860
Additions to Long-Lived Assets, Excluding Acquisitions	595	768	1,954	2,608
Additions to Equity Method Investments	271		686	0
Property, Plant and Equipment, Net	18,797		18,797		$ 18,419
Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	(125)	(91)	(322)	(257)
Lease Operating Expense	(9)	(12)	(30)	(18)
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	(71)	(60)	(199)	(168)
Total Production Expense	(80)	(72)	(229)	(186)
Depreciation, Depletion and Amortization	(8)	(5)	(21)	(13)
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(23)	(16)	(52)	(52)
Additions to Long-Lived Assets, Excluding Acquisitions	(26)	(22)	(74)	(72)
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	(198)		(198)		(145)
Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	18	26	68	81
Lease Operating Expense	0	0	0	0
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	0	0	0	0
Depreciation, Depletion and Amortization	21	10	51	33
Firm Transportation Exit Cost			92
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(214)	(170)	(660)	(498)
Additions to Long-Lived Assets, Excluding Acquisitions	11	(2)	29	26
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	302		302		306
United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	825	919	2,390	2,737
Lease Operating Expense	111	114	350	354
Production and Ad Valorem Taxes	51	46	138	147
Gathering, Transportation and Processing Expense	173	129	439	389
Total Production Expense	340	294	936	922
Depreciation, Depletion and Amortization	505	414	1,401	1,214
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		5		20
Asset Impairments				168
(Gain) Loss on Commodity Derivative Instruments	(123)	140	7	400
Income (Loss) Before Income Taxes	92	31	(85)	(94)
Additions to Long-Lived Assets, Excluding Acquisitions	377	535	1,367	1,630
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	13,170		13,170		13,044
United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	186	168	512	451
Lease Operating Expense	1	0	3	0
Production and Ad Valorem Taxes	1	1	4	4
Gathering, Transportation and Processing Expense	5	28	65	71
Total Production Expense	7	29	72	75
Depreciation, Depletion and Amortization	26	24	77	62
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		(198)		(503)
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	83	268	202	690
Additions to Long-Lived Assets, Excluding Acquisitions	56	82	174	479
Additions to Equity Method Investments	86		501
Property, Plant and Equipment, Net	1,682		1,682		1,742
United States | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	125	91	322	257
Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	119	124	344	368
Lease Operating Expense	7	7	26	19
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	1	0	1	0
Total Production Expense	8	7	27	19
Depreciation, Depletion and Amortization	17	16	50	44
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		(376)
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	74	143	223	678
Additions to Long-Lived Assets, Excluding Acquisitions	129	170	380	533
Additions to Equity Method Investments	185		185
Property, Plant and Equipment, Net	3,001		3,001		2,630
West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	96	127	272	409
Lease Operating Expense	22	15	56	56
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	22	15	56	56
Depreciation, Depletion and Amortization	21	25	60	77
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	(6)	15	16	83
Income (Loss) Before Income Taxes	56	68	126	180
Additions to Long-Lived Assets, Excluding Acquisitions	46	4	64	9
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	801		801		805
Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Lease Operating Expense	0	0	0	0
Production and Ad Valorem Taxes	0	0	0	0
Gathering, Transportation and Processing Expense	0	0	0	0
Total Production Expense	0	0	0	0
Depreciation, Depletion and Amortization	1	1	1	1
Firm Transportation Exit Cost			0
(Gain) Loss on Divestitures, Net		0		0
Asset Impairments				0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
Income (Loss) Before Income Taxes	(17)	(17)	(48)	(44)
Additions to Long-Lived Assets, Excluding Acquisitions	2	1	14	3
Additions to Equity Method Investments	0		0
Property, Plant and Equipment, Net	39		39		$ 37
Oil, NGL and Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	1,003	1,136	2,894	3,409
Oil, NGL and Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	802	919	2,324	2,737
Oil, NGL and Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Oil, NGL and Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	119	124	344	368
Oil, NGL and Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	82	93	226	304
Oil, NGL and Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales
Segment Reporting Information [Line Items]
Revenue from Sales	724	744	2,024	2,266
Crude Oil Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	645	655	1,807	1,972
Crude Oil Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Crude Oil Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	1	2	4	6
Crude Oil Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	78	87	213	288
Crude Oil Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales
Segment Reporting Information [Line Items]
Revenue from Sales	78	166	258	449
NGL Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	78	166	258	449
NGL Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
NGL Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales
Segment Reporting Information [Line Items]
Revenue from Sales	201	226	612	694
Natural Gas Sales | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	79	98	259	316
Natural Gas Sales | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Natural Gas Sales | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	118	122	340	362
Natural Gas Sales | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	4	6	13	16
Natural Gas Sales | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased of Gas
Segment Reporting Information [Line Items]
Revenue from Sales	87	72	264	191
Cost of Purchased Oil and Gas	96	76	296	204
Cost of Purchased of Gas | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	18	26	68	81
Cost of Purchased Oil and Gas	33	32
Cost of Purchased of Gas | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	22	0	64	0
Cost of Purchased Oil and Gas	17	0
Cost of Purchased of Gas | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	47	46	132	110
Cost of Purchased Oil and Gas	46	44
Cost of Purchased of Gas | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Cost of Purchased of Gas | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Cost of Purchased Oil and Gas	0	0
Income (Loss) from Equity Method Investments and Other
Segment Reporting Information [Line Items]
Revenue from Sales	10	44	43	140
Income (Loss) from Equity Method Investments and Other | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	1	0	2	0
Income (Loss) from Equity Method Investments and Other | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	(5)	10	(5)	35
Income (Loss) from Equity Method Investments and Other | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Income (Loss) from Equity Method Investments and Other | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	14	34	46	105
Income (Loss) from Equity Method Investments and Other | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party
Segment Reporting Information [Line Items]
Revenue from Sales	19	21	63	49
Midstream Services Revenues – Third Party | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | Corporate
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | United States | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | United States | Noble Midstream
Segment Reporting Information [Line Items]
Revenue from Sales	19	21	63	49
Midstream Services Revenues – Third Party | United States | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Revenue from Sales	0		0
Midstream Services Revenues – Third Party | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Midstream Services Revenues – Third Party | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Revenue from Sales	0	0	0	0
Other Royalty Expense
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	5	5	9	32
Other Royalty Expense | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Corporate
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | United States | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	5	5	9	32
Other Royalty Expense | United States | Noble Midstream
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	0	0	0	0
Other Royalty Expense | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas	$ 0	$ 0	0	0
Cost of Purchased Oil and Gas
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			296	204
Cost of Purchased Oil and Gas | Intersegment Eliminations and Other
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | Corporate
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			112	98
Cost of Purchased Oil and Gas | United States | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			59	0
Cost of Purchased Oil and Gas | United States | Noble Midstream
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			125	106
Cost of Purchased Oil and Gas | Eastern Mediterranean | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | West Africa | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			0	0
Cost of Purchased Oil and Gas | Other Int'l | Operating Segments
Segment Reporting Information [Line Items]
Cost of Purchased Oil and Gas			$ 0	$ 0

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Basis of Presentation - Narrative (Details) - USD ($) $ in Millions		1 Months Ended	9 Months Ended
	Jan. 01, 2019	Mar. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Goodwill			$ 110		$ 110
ROU Assets			275		$ 0
Lease liabilities			306
Proceeds from issuance of preferred equity			97	$ 0
ASU 2016-02
Finite-Lived Intangible Assets [Line Items]
ROU Assets	$ 282
Lease liabilities	287
Deferred tax impact	$ 5
Noble Midstream
Finite-Lived Intangible Assets [Line Items]
Equity commitment		$ 200	$ 100
Proceeds from issuance of preferred equity		100
Issuance costs of preferred equity		$ 3
Annual dividend rate			6.50%
EPIC Crude Holdings, LP | Noble Midstream
Finite-Lived Intangible Assets [Line Items]
Step acquisition, percentage acquired			30.00%

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Unsettled Derivative Instruments

As of September 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	35,000	$	—		$	59.04	$	—	$	—	$	—
2019	Three-Way Collars	NYMEX WTI	33,000	—			—		49.35		59.35		72.25
2019	Sold Calls (1)	NYMEX WTI	4,000	—			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	12,000	—			59.73		—		—		—
2020	Sold Calls (1)	NYMEX WTI	8,000	—			65.59		—		—		—
2020	Swaps	NYMEX WTI	28,000	—			58.09		—		—		—
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.

As of September 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	Swaps	NYMEX HH	90,000	—			2.60		—		—		—
2020	Sold Puts (2)	NYMEX HH	90,000	—			—		2.15		—		—
2020	Swaption	NYMEX HH	90,000	—			2.60		—		—		—
2020	Basis Swaps	CIG (1)	54,000	(0.61		)	—		—		—		—
2020	Basis Swaps	WAHA (1)	49,500	(1.05		)	—		—		—		—
2021	Basis Swaps	WAHA (1)	14,000	(0.60		)	—		—		—		—

⁽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.

⁽²⁾ 

We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.

Fair Value of Derivative Instruments

The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions):

Asset Derivative Instruments					Liability Derivative Instruments
Balance Sheet Location	September 30, 2019		December 31, 2018		Balance Sheet Location	September 30, 2019		December 31, 2018
Other Current Assets	$	90	$	180	Other Current Liabilities	$	10	$	1
Other Noncurrent Assets	25		—		Other Noncurrent Liabilities	3		26
Total	$	115	$	180		$	13	$	27

Derivative Instruments, (Gain) Loss

The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2019			2018			2019			2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(6	)	$	68		$	(8	)	$	164
Natural Gas	(7		)	(1		)	(20		)	(4		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(13		)	67			(28		)	160
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	(115		)	85			54			316
Natural Gas	(1		)	3			(3		)	7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(116		)	88			51			323
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(121		)	153			46			480
Natural Gas	(8		)	2			(23		)	3
Total (Gain) Loss on Commodity Derivative Instruments	$	(129	)	$	155		$	23		$	483

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Fair Value Measurements and Disclosures

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements and Disclosures

Note 13. Fair Value Measurements and Disclosures 

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. See Note 12. Derivative Instruments and Hedging Activities. 

Deferred Compensation Liability   Fair 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
September 30, 2019
Financial Assets:
Mutual Fund Investments	$	42		$	—		$	—	$	—		$	42
Commodity Derivative Instruments	—			155			—		(40		)	115
Financial Liabilities:
Commodity Derivative Instruments	—			(53		)	—		40			(13		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(3		)	—			—		—			(3		)
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 settle asset and liability positions with the same counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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.

Redeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with the issuance to GIP of preferred equity in Noble Midstream Partners 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, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans 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:

	September 30, 2019				December 31, 2018
(millions)	Carrying Amount		Fair Value (1)		Carrying Amount		Fair Value
Debt (2)	$	7,345	$	7,963	$	6,452	$	6,121

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

⁽²⁾ 

Represents total debt excluding finance lease obligations. See Note 7. Debt.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Segment Information

			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 September 30, 2019
Crude Oil Sales	$	724	$	645	$	1	$	78	$	—	$	—		$	—		$	—
NGL Sales	78		78		—		—		—		—			—			—
Natural Gas Sales	201		79		118		4		—		—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,003		802		119		82		—		—			—			—
Sales of Purchased Oil and Gas	87		22		—		—		—		47			—			18
Income (Loss) from Equity Method Investments and Other	10		1		—		14		—		(5		)	—			—
Midstream Services Revenues – Third Party	19		—		—		—		—		19			—			—
Intersegment Revenues	—		—		—		—		—		125			(125		)	—
Total Revenues	1,119		825		119		96		—		186			(125		)	18
Lease Operating Expense	132		111		7		22		—		1			(9		)	—
Production and Ad Valorem Taxes	52		51		—		—		—		1			—			—
Gathering, Transportation and Processing Expense	108		173		1		—		—		5			(71		)	—
Other Royalty Expense	5		5		—		—		—		—			—			—
Total Production Expense	297		340		8		22		—		7			(80		)	—

				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	583			505			17		21			1			26			(8		)	21
Cost of Purchased Oil and Gas	96			17			—		—			—			46			—			33
Gain on Commodity Derivative Instruments	(129		)	(123		)	—		(6		)	—			—			—			—
Income (Loss) Before Income Taxes	51			92			74		56			(17		)	83			(23		)	(214		)
Additions to Long-Lived Assets, Excluding Acquisitions	595			377			129		46			2			56			(26		)	11
Additions to Equity Method Investments	271			—			185		—			—			86			—			—
Three Months Ended September 30, 2018
Crude Oil Sales	$	744		$	655		$	2	$	87		$	—		$	—		$	—		$	—
NGL Sales	166			166			—		—			—			—			—			—
Natural Gas Sales	226			98			122		6			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,136			919			124		93			—			—			—			—
Sales of Purchased Oil and Gas	72			—			—		—			—			46			—			26
Income from Equity Method Investments and Other	44			—			—		34			—			10			—			—
Midstream Services Revenues – Third Party	21			—			—		—			—			21			—			—
Intersegment Revenues	—			—			—		—			—			91			(91		)	—
Total Revenues	1,273			919			124		127			—			168			(91		)	26
Lease Operating Expense	124			114			7		15			—			—			(12		)	—
Production and Ad Valorem Taxes	47			46			—		—			—			1			—			—
Gathering, Transportation and Processing Expense	97			129			—		—			—			28			(60		)	—
Other Royalty Expense	5			5			—		—			—			—			—			—
Total Production Expense	273			294			7		15			—			29			(72		)	—
Depreciation, Depletion and Amortization	485			414			16		25			1			24			(5		)	10
(Gain) Loss on Divestitures, Net	(193		)	5			—		—			—			(198		)	—			—
Cost of Purchased Oil and Gas	76			—			—		—			—			44			—			32
Loss on Commodity Derivative Instruments	155			140			—		15			—			—			—			—
Income (Loss) Before Income Taxes	307			31			143		68			(17		)	268			(16		)	(170		)
Additions to Long-Lived Assets, Excluding Acquisitions	768			535			170		4			1			82			(22		)	(2		)
Nine Months Ended September 30, 2019
Crude Oil Sales	$	2,024		$	1,807		$	4	$	213		$	—		$	—		$	—		$	—
NGL Sales	258			258			—		—			—			—			—			—
Natural Gas Sales	612			259			340		13			—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	2,894			2,324			344		226			—			—			—			—

				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
Sales of Purchased Oil and Gas	264			64			—		—		—			132			—			68
Income (Loss) from Equity Method Investments and Other	43			2			—		46		—			(5		)	—			—
Midstream Services Revenues – Third Party	63			—			—		—		—			63			—			—
Intersegment Revenues	—			—			—		—		—			322			(322		)	—
Total Revenues	3,264			2,390			344		272		—			512			(322		)	68
Lease Operating Expense	405			350			26		56		—			3			(30		)	—
Production and Ad Valorem Taxes	142			138			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	306			439			1		—		—			65			(199		)	—
Other Royalty Expense	9			9			—		—		—			—			—			—
Total Production Expense	862			936			27		56		—			72			(229		)	—
Depreciation, Depletion and Amortization	1,619			1,401			50		60		1			77			(21		)	51
Cost of Purchased Oil and Gas	296			59			—		—		—			125			—			112
Firm Transportation Exit Cost	92			—			—		—		—			—			—			92
Loss on Commodity Derivative Instruments	23			7			—		16		—			—			—			—
(Loss) Income Before Income Taxes	(294		)	(85		)	223		126		(48		)	202			(52		)	(660		)
Additions to Long-Lived Assets, Excluding Acquisitions	1,954			1,367			380		64		14			174			(74		)	29
Additions to Equity Method Investments	686			—			185		—		—			501			—			—
Nine Months Ended September 30, 2018
Crude Oil Sales	$	2,266		$	1,972		$	6	$	288	$	—		$	—		$	—		$	—
NGL Sales	449			449			—		—		—			—			—			—
Natural Gas Sales	694			316			362		16		—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	3,409			2,737			368		304		—			—			—			—
Sales of Purchased Oil and Gas	191			—			—		—		—			110			—			81
Income from Equity Method Investments and Other	140			—			—		105		—			35			—			—
Midstream Services Revenues – Third Party	49			—			—		—		—			49			—			—
Intersegment Revenues	—			—			—		—		—			257			(257		)	—
Total Revenues	3,789			2,737			368		409		—			451			(257		)	81
Lease Operating Expense	411			354			19		56		—			—			(18		)	—
Production and Ad Valorem Taxes	151			147			—		—		—			4			—			—
Gathering, Transportation and Processing Expense	292			389			—		—		—			71			(168		)	—
Other Royalty Expense	32			32			—		—		—			—			—			—
Total Production Expense	886			922			19		56		—			75			(186		)	—
Depreciation, Depletion and Amortization	1,418			1,214			44		77		1			62			(13		)	33

				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
(Gain) Loss on Divestitures, Net	(859		)	20			(376		)	—		—			(503		)	—			—
Asset Impairments	168			168			—			—		—			—			—			—
Cost of Purchased Oil and Gas	204			—			—			—		—			106			—			98
Loss on Commodity Derivative Instruments	483			400			—			83		—			—			—			—
Income (Loss) Before Income Taxes	860			(94		)	678			180		(44		)	690			(52		)	(498		)
Additions to Long-Lived Assets, Excluding Acquisitions	2,608			1,630			533			9		3			479			(72		)	26
September 30, 2019
Property, Plant and Equipment, Net	$	18,797		$	13,170		$	3,001		$	801	$	39		$	1,682		$	(198	)	$	302
December 31, 2018
Property, Plant and Equipment, Net	$	18,419		$	13,044		$	2,630		$	805	$	37		$	1,742		$	(145	)	$	306

⁽¹⁾ 

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.

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Summary of Operating and Finance Lease

ROU assets and lease liabilities are as follows:

(millions)	Balance Sheet Location	September 30, 2019
ROU Assets
Operating Leases (1)	Other Noncurrent Assets	$	275
Finance Leases (2)	Total Property, Plant and Equipment, Net	172
Total ROU Assets		$	447
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	97
Finance Leases	Other Current Liabilities	42
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	209
Finance Leases	Long-Term Debt	164
Total Lease Liabilities		$	512

⁽¹⁾  Operating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and drilling rigs of $29 million.

⁽²⁾ 

Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.

Other information related to our leases as of September 30, 2019 is as follows:

	Operating Leases		Finance Leases
Weighted-Average Remaining Lease Term	5.7 years		7.7 years
Weighted-Average Discount Rate	4.40	%	5.02	%

Lease Expense

The components of lease cost are as follows:

(millions)	Statement of Operations Location	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating Lease Cost	(1)	$	30		$	81
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	10			27
Interest Expense	Interest, Net of Amount Capitalized	3			10
Short-term Lease Cost (2)	(1)	88			357
Sublease Income	General and Administrative	(1		)	(3		)
Total Lease Cost		$	130		$	472

⁽¹⁾  Cost classifications vary 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 and, therefore, are included as part of oil and gas properties on our consolidated balance sheets.

⁽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.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	50	$	9
Investing Cash Flows	27		—
Financing Cash Flows	—		31
Non-Cash Activities
ROU Assets Obtained in Exchange for Lease Liabilities (1)	93		15

⁽¹⁾ 

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

Operating Lease Liability Maturity

Maturities of lease liabilities as of September 30, 2019 are as follows:

(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	28	$	13	$	41
2020	100		49		149
2021	61		35		96
2022	44		25		69
2023	29		22		51
2024 and Thereafter	85		106		191
Total Lease Liabilities, Undiscounted	347		250		597
Less: Imputed Interest	41		44		85
Total Lease Liabilities (1)	$	306	$	206	$	512

⁽¹⁾ 

Includes the current portions of $97 million and $42 million for operating and finance leases, respectively.

Finance Lease Liability Maturity

Maturities of lease liabilities as of September 30, 2019 are as follows:

(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	28	$	13	$	41
2020	100		49		149
2021	61		35		96
2022	44		25		69
2023	29		22		51
2024 and Thereafter	85		106		191
Total Lease Liabilities, Undiscounted	347		250		597
Less: Imputed Interest	41		44		85
Total Lease Liabilities (1)	$	306	$	206	$	512

⁽¹⁾ 

Includes the current portions of $97 million and $42 million for operating and finance leases, respectively.

Schedule of Future Minimum Rental Payments for Operating Leases

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

Schedule of Future Minimum Lease Payments for Finance Leases

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

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Leases - Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases [Abstract]
Operating Lease Cost	$ 30	$ 81
Finance Lease Cost
Amortization Expense	10	27
Interest Expense	3	10
Short-term Lease Cost	88	357
Sublease Income	(1)	(3)
Total Lease Cost	$ 130	$ 472

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Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	$ (60)	$ 67
Liabilities Settled	82	309
DJ Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	(73)
Offshore Israel
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates	$ 13
Gulf of Mexico Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		216
Greeley Crescent
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities Settled		24
Onshore US
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		84
Liabilities Settled		69
North Sea abandonment project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		(11)
Eastern Mediterranean
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions of Estimates		$ (6)

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Capitalized Exploratory Well Costs (Details) $ in Millions	Sep. 30, 2019 USD ($) project	Dec. 31, 2018 USD ($) project
Extractive Industries [Abstract]
Exploratory Well Costs Capitalized for a Period of One Year or Less	$ 15	$ 6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	354	348
Capitalized Exploratory Well Costs, End of Period	$ 369	$ 354
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project	7	7

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Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$ 17	$ 227	$ (306)	$ 758
Weighted Average, Number of Shares Outstanding, Basic (in shares)	478	482	478	484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (in shares)	2	2	0	2
Weighted Average, Number of Shares Outstanding, Diluted (in shares)	480	484	478	486
(Loss) Income Per Share, Basic ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.57
(Loss) Income Per Share, Diluted ($ per share)	$ 0.04	$ 0.47	$ (0.64)	$ 1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above (in shares)	14	13	15	14
Share purchase plan, authorized amount	$ 750		$ 750

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Exit Costs - Transportation Commitments (Tables)

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Rollforward of Accrued Transportation Commitment

Reconciliation of accrued costs at September 30, 2019 is as follows:

	Nine Months Ended September 30,
(millions)	2019			2018
Balance at Beginning of Period (1)	$	80		$	90
Firm Transportation Exit Cost Accrual	92			—
Payments, Net of Accretion	(6		)	(9		)
Balance at End of Period	166			81
Less: Current Portion Included in Other Current Liabilities	33			12
Long-term Portion Included in Other Noncurrent Liabilities	$	133		$	69

⁽¹⁾ 

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

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Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders

Note 14. Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders

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 September 30,				Nine Months Ended September 30,
(millions, except per share amounts)	2019		2018		2019			2018
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	17	$	227	$	(306	)	$	758
Weighted Average Number of Shares Outstanding, Basic (1)	478		482		478			484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	2		2		—			2
Weighted Average Number of Shares Outstanding, Diluted	480		484		478			486
Income (Loss) Per Share, Basic	$	0.04	$	0.47	$	(0.64	)	$	1.57
Income (Loss) Per Share, Diluted	$	0.04	$	0.47	$	(0.64	)	$	1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14		13		15			14

⁽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.

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)

9 Months Ended

Sep. 30, 2019

Extractive Industries [Abstract]

Aging of Capitalized Well Costs

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

(millions, except number of projects)	September 30, 2019		December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	15	$	6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	354		348
Capitalized Exploratory Well Costs, End of Period	$	369	$	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

Rollforward of Undeveloped Lease Costs

Changes in undeveloped leasehold costs are as follows:

(millions)	Nine Months Ended September 30, 2019
Undeveloped Leasehold Costs, Beginning of Period	$	2,306
Additions to Undeveloped Leasehold Costs	63
Transfers to Proved Properties	(20		)
Undeveloped Leasehold Costs, End of Period	$	2,349

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Asset Retirement Obligations - ARO Activity (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance	$ 880	$ 875
Liabilities Incurred	17	16
Liabilities Settled	(82)	(309)
Revisions of Estimates	(60)	67
Accretion Expense	33	25
Asset Retirement Obligations, Ending Balance	$ 788	$ 674

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Acquisitions and Divestitures - Narrative (Details) a in Thousands, shares in Millions, $ in Millions	1 Months Ended					3 Months Ended				9 Months Ended
	Feb. 28, 2019 USD ($) a MMBbls	Oct. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Mar. 31, 2018 USD ($) shares	Jan. 31, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($) shares	Jun. 30, 2018 USD ($) shares	Mar. 31, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2021	Dec. 31, 2019	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Feb. 28, 2018 USD ($)	Feb. 01, 2018 shares
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 271				$ 686	$ 0
Cash consideration						959				959					$ 286
Asset Impairments						0	$ 0			0	168
Proceeds from divestiture										131	1,740
Gain (loss) on divestiture						0	193			0	859
Cash consideration										0	$ (653)
Intangible assets						286				286					310
Goodwill						110				$ 110					$ 110
CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture					$ 308		248	$ 135
Gain (loss) on divestiture					196		$ 198	$ 109
Shares sold (in shares) | shares							14.2	7.5
Greeley Crescent
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture			$ 64
Noble Midstream | Saddle Butte
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration					681
Property, plant and equipment					206
Intangible assets					340
Goodwill					$ 110
EMED Pipeline BV
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 185
Percentage acquired						25.00%				25.00%
EMG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired						39.00%				39.00%
EPIC Y-Grade, LP | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 46
Step acquisition, percentage acquired						15.00%				15.00%
Cash consideration														$ 227
EPIC Crude Holdings, LP | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capital contributions						$ 168
Step acquisition, percentage acquired						30.00%				30.00%
Delaware Crossing JV | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration						$ 53				$ 53
Pipeline capacity (in MBbl/d) | MMBbls	160
Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest				32.50%					32.50%
CNX Midstream Partners
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity owned (units) | shares																	21.7
Saddle Butte | Noble Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest					54.40%
Disposed by sale | Reeves County Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved and unproved non-core acreage sold (in acres) | a	13
Proceeds from divestitures	$ 131
Disposed by sale | Gulf of Mexico Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value				$ 480					$ 480							$ 480
Retained transaction related obligations				92					92
Asset Impairments									$ 168
Proceeds from divestiture								$ 383
Gain (loss) on divestiture								$ (24)
Disposed by sale | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on divestiture				$ 376
Percentage ownership sold				7.50%					7.50%
Cash consideration				$ 484
Shares received in divestiture (in shares) | shares				38.5
Value of shares				$ 224
Tax effect				$ 86
Proceeds from sale, net of expenses		$ 163
Disposed by sale | Southwest Royalties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale					$ 60
Scenario, Forecast | EMG Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired													10.00%
Scenario, Forecast | Tamar and Dalit Fields
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest												25.00%
CNX Midstream Partners | CONE Gathering LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership			22.30%		50.00%		22.30%				22.30%						34.10%

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Leases - Right-of-use Assets and Liability (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
ROU Assets
Operating Leases	$ 275	$ 0
Finance Leases	172
Total ROU Assets	447
Current Liabilities
Operating Leases	97	0
Finance Leases	42	41
Noncurrent Liabilities
Operating Leases	209	$ 0
Finance Leases	164
Total Lease Liabilities	512
Office Space
ROU Assets
Operating Leases	117
Finance Leases	92
Compressors
ROU Assets
Operating Leases	93
Drilling Rigs
ROU Assets
Operating Leases	29
Trunklines
ROU Assets
Operating Leases	$ 32

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash Flows From Operating Activities
Net (Loss) Income Including Noncontrolling Interests	$ (245)	$ 816
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,619	1,418
Deferred Income Tax Benefit	(110)	(150)
Loss on Commodity Derivative Instruments	23	483
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	28	(160)
Other Adjustments for Noncash Items Included in Income	115	45
Gain on Divestitures, Net	0	(859)
Asset Impairments	0	168
Firm Transportation Exit Cost	92	0
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	(13)	114
Increase (Decrease) in Accounts Payable	142	(91)
Other Current Assets and Liabilities, Net	(76)	73
Other Operating Assets and Liabilities, Net	(46)	(81)
Net Cash Provided by Operating Activities	1,529	1,776
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,998)	(2,589)
Acquisitions, Net of Cash Received	0	(653)
Additions to Equity Method Investments	(686)	0
Proceeds from Divestitures, Net	131	1,740
Other	(25)	0
Net Cash Used in Investing Activities	(2,528)	(1,502)
Cash Flows From Financing Activities
Proceeds from Commercial Paper Borrowings, Net	511	0
Dividends Paid, Common Stock	(168)	(156)
Purchase and Retirement of Common Stock	0	(223)
Contributions from Noncontrolling Interest Owners	27	348
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs	97	0
Repayment of Senior Notes	(9)	(384)
Other	(95)	(86)
Net Cash Provided by (Used in) Financing Activities	753	(266)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(246)	8
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	719	713
Cash, Cash Equivalents, and Restricted Cash at End of Period	473	721
Revolving Credit Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	50	1,450
Repayment of Revolving Credit Facilities	(50)	(1,680)
Term Loan Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	400	500
Noble Midstream Services Revolving Credit Facility | Revolving Credit Facility
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facilities	655	690
Repayment of Revolving Credit Facilities	$ (665)	$ (725)

XML

Cover Page	9 Months Ended
	Sep. 30, 2019 shares
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	001-07964
Entity Registrant Name	NOBLE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-0785597
Entity Address, Address Line One	1001 Noble Energy Way
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77070
City Area Code	(281)
Local Phone Number	872-3100
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	NBL
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	478,298,006
Entity Central Index Key	0000072207
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false

XML

Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Financial Assets:
Mutual Fund Investments		$ 38
Commodity Derivative Instruments	$ 115	180
Financial Liabilities:
Commodity Derivative Instruments	(13)	(27)
Portion of Deferred Compensation Liability Measured at Fair Value	(48)	(43)
Stock Based Compensation Liability Measured at Fair Value	(3)	(8)
Quoted Prices in Active Markets (Level 1)
Financial Assets:
Mutual Fund Investments		38
Commodity Derivative Instruments	0	0
Financial Liabilities:
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	(48)	(43)
Stock Based Compensation Liability Measured at Fair Value	(3)	(8)
Significant Other Observable Inputs (Level 2)
Financial Assets:
Mutual Fund Investments		0
Commodity Derivative Instruments	155	187
Financial Liabilities:
Commodity Derivative Instruments	(53)	(34)
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	0
Significant Unobservable Inputs (Level 3)
Financial Assets:
Mutual Fund Investments		0
Commodity Derivative Instruments	0	0
Financial Liabilities:
Commodity Derivative Instruments	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	0
Scenario, Adjustment
Financial Assets:
Mutual Fund Investments		0
Commodity Derivative Instruments	(40)	(7)
Financial Liabilities:
Commodity Derivative Instruments	40	7
Portion of Deferred Compensation Liability Measured at Fair Value	0	0
Stock Based Compensation Liability Measured at Fair Value	0	$ 0
Mutual Fund Investments
Financial Assets:
Mutual Fund Investments	42
Mutual Fund Investments | Quoted Prices in Active Markets (Level 1)
Financial Assets:
Mutual Fund Investments	42
Mutual Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Assets:
Mutual Fund Investments	0
Mutual Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Assets:
Mutual Fund Investments	0
Mutual Fund Investments | Scenario, Adjustment
Financial Assets:
Mutual Fund Investments	$ 0

XML

Leases - Lease Maturity (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Operating Leases
Remainder of 2019	$ 28
2020	100
2021	61
2022	44
2023	29
2024 and thereafter	85
Total Lease Liabilities, Undiscounted	347
Less: Imputed Interest	41
Total Lease Liabilities	306
Finance Leases
Remainder of 2019	13
2020	49
2021	35
2022	25
2023	22
2024 and Thereafter	106
Total Lease Liabilities, Undiscounted	250
Less: Imputed Interest	44
Total Lease Liabilities	206
Total
Remainder of 2019	41
2019		$ 143
2020	149	120
2021	96	90
2022	69	84
2023	51	70
2024 and Thereafter	191	280
Total Lease Liabilities, Undiscounted	597	787
Liabilities, Undiscounted Excess Amount	85
Lease Liability	512
Operating lease liability, current	97	0
Finance lease liability, current	$ 42	41
Operating Leases
2019		91
2020		74
2021		59
2022		62
2023		50
2024 and Thereafter		176
Total Lease Liabilities, Undiscounted		512
Finance Leases
2019		52
2020		46
2021		31
2022		22
2023		20
2024 and Thereafter		104
Total Lease Liabilities, Undiscounted		$ 275

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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 September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 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, net income or loss is materially consistent with comprehensive income or loss.

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

Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the 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 our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.

Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of 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 our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the 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 accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as 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 Recognition   We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606).

Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of September 30, 2019, for those agreements. Our actual future sales volumes may exceed future minimum volume commitments.

(millions)	Remainder of 2019		2020		Total
Natural Gas Revenues (1)	$	36	$	199	$	235

⁽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.

Redeemable Noncontrolling Interest 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 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 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, 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, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures.

Recently Issued Accounting Standards

Financial Instruments: Credit Losses In June 2016, the 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 with a methodology that reflects current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and 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.

We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements.

Recently Adopted Accounting Standards

Leases In 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 recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements.

Intangibles—Goodwill and Other—Internal-Use Software In 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, 2019, with early adoption permitted. We used the prospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our financial statements.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2019		2018			2019		2018
Other Revenue
Income from Equity Method Investments and Other	$	10	$	44		$	43	$	140
Midstream Services Revenues – Third Party	19		21			63		49
Total	$	29	$	65		$	106	$	189
Production Expense
Lease Operating Expense	$	132	$	124		$	405	$	411
Production and Ad Valorem Taxes	52		47			142		151
Gathering, Transportation and Processing Expense	108		97			306		292
Other Royalty Expense	5		5			9		32
Total	$	297	$	273		$	862	$	886
Other Operating Expense, Net
Exploration Expense	$	25	$	25		$	82	$	89
Marketing Expense	7		11			26		21
Firm Transportation Exit Cost	—		—			92		—
Other, Net	29		(9		)	57		(3		)
Total	$	61	$	27		$	257	$	107

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	405		$	383
Joint Interest Billings	177			137
Other	103			111
Allowance for Doubtful Accounts	(8		)	(15		)
Total	$	677		$	616
Other Current Assets
Commodity Derivative Assets	$	90		$	180
Inventories, Materials and Supplies	74			55
Assets Held for Sale (1)	—			133
Prepaid Expenses and Other Current Assets	113			50
Total	$	277		$	418
Other Noncurrent Assets
Equity Method Investments (2)	$	959		$	286
Operating Lease Right-of-Use Assets (3)	275			—
Customer-Related Intangible Assets, Net (4)	286			310
Goodwill (4)	110			110
Other Assets, Noncurrent	150			135
Total	$	1,780		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	147		$	103
Asset Retirement Obligations	89			118
Interest Payable	87			66
Operating Lease Liabilities (3)	97			—
Commercial Paper Borrowings	511			—
Other Liabilities, Current	259			232
Total	$	1,190		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	148		$	147
Asset Retirement Obligations	699			762
Operating Lease Liabilities (3)	209			—
Firm Transportation Exit Cost Accrual (5)	133			67
Other Liabilities, Noncurrent	149			189
Total	$	1,338		$	1,165

⁽¹⁾  Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.

⁽²⁾  See Note 4. Acquisitions and Divestitures.

⁽³⁾  Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases.

⁽⁴⁾  Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.

⁽⁵⁾  See Note 9. Exit Cost – Transportation Commitments.

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

	Nine Months Ended September 30,
(millions)	2019		2018
Cash and Cash Equivalents at Beginning of Period	$	716	$	675
Restricted Cash at Beginning of Period	3		38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	719	$	713
Cash and Cash Equivalents at End of Period	$	473	$	720
Restricted Cash at End of Period	—		1
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	473	$	721

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Income Taxes - Components of Income Tax (Benefit) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Current	$ 24	$ 45	$ 61	$ 194
Deferred	(9)	14	(110)	(150)
Total Income Tax Expense (Benefit)	$ 15	$ 59	$ (49)	$ 44
Effective Tax Rate	29.40%	19.20%	16.70%	5.10%

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 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:

	Nine Months Ended September 30,
(millions)	2019			2018
Asset Retirement Obligations, Beginning Balance	$	880		$	875
Liabilities Incurred	17			16
Liabilities Settled	(82		)	(309		)
Revisions of Estimates	(60		)	67
Accretion Expense	33			25
Asset Retirement Obligations, Ending Balance	$	788		$	674

Nine Months Ended September 30, 2019 Liabilities settled relate primarily to abandonment of US onshore properties, principally 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, partially offset by acceleration of timing estimates of $13 million for wells offshore Israel.

Nine Months Ended September 30, 2018 Liabilities settled include $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $69 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily to increases in cost and timing of estimates of $84 million for US onshore, primarily in the DJ Basin, partially offset by decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 10. Commitments and Contingencies

Legal Proceedings   We 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.

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Basis of Presentation - Performance Obligation, Expected Timing (Details) $ in Millions	Sep. 30, 2019 USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 235
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-10-01
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 36
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Natural Gas Revenues	$ 199
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing	1 year

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income Tax Provision (Benefit)

Income tax expense (benefit) consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except percentages)	2019			2018			2019			2018
Current	$	24		$	45		$	61		$	194
Deferred	(9		)	14			(110		)	(150		)
Total Income Tax Expense (Benefit)	$	15		$	59		$	(49	)	$	44
Effective Tax Rate	29.4		%	19.2		%	16.7		%	5.1		%

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Basis of Presentation - Components of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and Cash Equivalents	$ 473	$ 716	$ 720	$ 675
Restricted Cash	0	3	1	38
Cash, Cash Equivalents, and Restricted Cash	$ 473	$ 719	$ 721	$ 713