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

TABLE OF CONTENTS

Part I. Financial Information	3
Item 1. Financial Statements	3
Consolidated Statements of Operations and Comprehensive Income (Loss)	3
Consolidated Balance Sheets	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Equity	6
Notes to Consolidated Financial Statements	7
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.  Controls and Procedures	39
Part II. Other Information	39
Item 1.  Legal Proceedings	39
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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
Oil, NGL and Gas Sales	$	954		$	1,100		$	1,891		$	2,273
Sales of Purchased Oil and Gas	103			66			177			119
Other Revenue	36			64			77			124
Total	1,093			1,230			2,145			2,516
Costs and Expenses
Production Expense	260			290			565			609
Depreciation, Depletion and Amortization	528			465			1,036			933
General and Administrative	105			105			207			209
Cost of Purchased Oil and Gas	113			71			200			128
Other Operating Expense, Net	55			34			104			84
Gain on Divestitures, Net	—			(78		)	—			(666		)
Asset Impairments	—			—			—			168
Firm Transportation Exit Cost	—			—			92			—
Total	1,061			887			2,204			1,465
Operating Income (Loss)	32			343			(59		)	1,051
Other Expense
(Gain) Loss on Commodity Derivative Instruments	(60		)	249			152			328
Interest, Net of Amount Capitalized	63			73			129			146
Other Non-Operating Expense, Net	1			11			5			24
Total	4			333			286			498
Income (Loss) Before Income Taxes	28			10			(345		)	553
Income Tax Expense (Benefit)	20			16			(64		)	(15		)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	8			(6		)	(281		)	568
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	18			17			42			37
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy	$	(10	)	$	(23	)	$	(323	)	$	531
Net (Loss) Income Attributable to Noble Energy Common Shareholders per Share
Basic	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
Diluted	$	(0.02	)	$	(0.05	)	$	(0.68	)	$	1.09
Weighted Average Number of Common Shares Outstanding
Basic	478			484			478			485
Diluted	478			484			478			487

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

3

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

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

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

4

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Six Months Ended June 30,
	2019			2018
Cash Flows From Operating Activities
Net (Loss) Income Including Noncontrolling Interests	$	(281	)	$	568
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,036			933
Deferred Income Tax Benefit	(101		)	(164		)
Loss on Commodity Derivative Instruments	152			328
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	15			(93		)
Other Adjustments for Noncash Items Included in Income	59			57
Gain on Divestitures, Net	—			(666		)
Asset Impairments	—			168
Firm Transportation Exit Cost	92			—
Changes in Operating Assets and Liabilities
Decrease in Accounts Receivable	35			76
Increase (Decrease) in Accounts Payable	126			(24		)
Increase in Partner Advances	132			—
Other Current Assets and Liabilities, Net	(108		)	(55		)
Other Operating Assets and Liabilities, Net	(65		)	(49		)
Net Cash Provided by Operating Activities	1,092			1,079
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,405		)	(1,782		)
Acquisitions, Net of Cash Received	—			(650		)
Additions to Equity Method Investments	(415		)	—
Proceeds from Divestitures, Net	123			1,382
Net Cash Used in Investing Activities	(1,697		)	(1,050		)
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facility	50			905
Repayment of Revolving Credit Facility	(50		)	(1,135		)
Proceeds from Noble Midstream Services Revolving Credit Facility	560			610
Repayment of Noble Midstream Services Revolving Credit Facility	(250		)	(165		)
Proceeds from Commercial Paper Borrowings, Net	240			—
Dividends Paid, Common Stock	(111		)	(102		)
Purchase and Retirement of Common Stock	—			(130		)
Contributions from Noncontrolling Interest Owners	21			331
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs	99			—
Repayment of Senior Notes	(9		)	(384		)
Other	(62		)	(51		)
Net Cash Provided by (Used in) Financing Activities	488			(121		)
Decrease in Cash, Cash Equivalents, and Restricted Cash	(117		)	(92		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	719			713
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	602		$	621

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
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		)
Other	—		—			1			—			—			(2		)	(1		)
June 30, 2018	$	5	$	8,329		$	(28	)	$	(731	)	$	2,677		$	1,029		$	11,281

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

6

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 June 30, 2019 and December 31, 2018 and for the three and six months ended June 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 six months ended June 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.

Partner Advances Partner advances consist of cash advances from certain of our Eastern Mediterranean field partners pending allocation of capacity in the EMG Pipeline owned by Eastern Mediterranean Gas Company S.A.E (EMG) and pending closing of the planned acquisition of EMG, which is expected to occur in third quarter 2019. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers. The acquisition of the equity interest in EMG is expected to support delivery of natural gas from our producing fields offshore Israel into Egypt. The cash advances received are reported within restricted cash in our consolidated balance sheets.

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.

7

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 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 June 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)	$	72	$	116	$	188

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

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 used for certain financial instruments with a methodology that reflects current expected credit losses. The current expected credit loss (CECL) model applies to a broad scope of financial instruments, including financial assets measured at amortized cost. CECL also applies to off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and shall be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period.

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

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

8

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

Recently Adopted Accounting Standards

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

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

Intangibles—Goodwill and Other—Internal-Use 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 early adopted this ASU in second quarter 2019 using the prospective method. The adoption did not have a material impact on our financial statements.

9

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended June 30,					Six Months Ended June 30,
(millions)	2019		2018			2019		2018
Other Revenue
Income from Equity Method Investees and Other	$	16	$	49		$	33	$	96
Midstream Services Revenues – Third Party	20		15			44		28
Total	$	36	$	64		$	77	$	124
Production Expense
Lease Operating Expense	$	122	$	132		$	273	$	287
Production and Ad Valorem Taxes	41		50			90		104
Gathering, Transportation and Processing Expense	96		98			198		191
Other Royalty Expense	1		10			4		27
Total	$	260	$	290		$	565	$	609
Other Operating Expense, Net
Exploration Expense	$	33	$	29		$	57	$	64
Marketing Expense	14		9			19		16
Other, Net	8		(4		)	28		4
Total	$	55	$	34		$	104	$	84

10

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	June 30, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	346		$	383
Joint Interest Billings	153			137
Other	91			111
Allowance for Doubtful Accounts	(15		)	(15		)
Total	$	575		$	616
Other Current Assets
Commodity Derivative Assets	$	30		$	180
Inventories, Materials and Supplies	68			55
Assets Held for Sale (1)	—			133
Restricted Cash (2)	132			3
Prepaid Expenses and Other Current Assets	83			47
Total	$	313		$	418
Other Noncurrent Assets
Equity Method Investments (3)	$	699		$	286
Operating Lease Right-of-Use Assets (4)	272			—
Customer-Related Intangible Assets, Net (5)	294			310
Goodwill (5)	110			110
Other Assets, Noncurrent	141			135
Total	$	1,516		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	132		$	103
Asset Retirement Obligations	85			118
Interest Payable	64			66
Operating Lease Liabilities (4)	88			—
Commercial Paper Borrowings	240			—
Partner Advances (2)	132			—
Other Liabilities, Current	257			232
Total	$	998		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	147		$	147
Asset Retirement Obligations	707			762
Operating Lease Liabilities (4)	190			—
Firm Transportation Exit Cost Accrual (6)	144			67
Production and Ad Valorem Taxes	24			83
Other Liabilities, Noncurrent	95			106
Total	$	1,307		$	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 Partner Advances, above.

⁽³⁾  The 2019 amount includes Noble Midstream Partners' $369 million investment in EPIC Y-Grade, LP (EPIC Y-Grade) and EPIC Crude Holdings and its $39 million investment in Delaware Crossing LLC. See Note 4. Acquisitions and Divestitures.

⁽⁴⁾  Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases.

11

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

⁽⁵⁾  Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at June 30, 2019 and December 31, 2018 are net of accumulated amortization of $46 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.

⁽⁶⁾  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:

	Six Months Ended June 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	$	470	$	621
Restricted Cash at End of Period	132		—
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	602	$	621

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 firm 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 June 30, 2019
Crude Oil Sales	$	688	$	617	$	2	$	69	$	—	$	—		$	—		$	—
NGL Sales	84		84		—		—		—		—			—			—
Natural Gas Sales	182		72		105		5		—		—			—			—
Total Crude Oil, NGL and Natural Gas Sales	954		773		107		74		—		—			—			—
Sales of Purchased Oil and Gas	103		28		—		—		—		52			—			23
Income (Loss) from Equity Method Investees and Other	16		1		—		17		—		(2		)	—			—
Midstream Services Revenues – Third Party	20		—		—		—		—		20			—			—
Intersegment Revenues	—		—		—		—		—		91			(91		)	—
Total Revenues	1,093		802		107		91		—		161			(91		)	23
Lease Operating Expense	122		114		9		10		—		1			(12		)	—
Production and Ad Valorem Taxes	41		40		—		—		—		1			—			—
Gathering, Transportation and Processing Expense	96		124		—		—		—		31			(59		)	—

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

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

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

⁽¹⁾  The intersegment eliminations related to income 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

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, which is constructing the EPIC Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline also from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million. In second quarter 2019, Noble Midstream Partners made additional capital contributions of $28 million and $114 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. See Note 2. Basis of Presentation.

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

2018 Asset Transactions

Divestiture of Gulf of Mexico Assets  In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of 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 an additional loss of $19 million.

15

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 $386 million and tax expense of $90 million.

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

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

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

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

Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owns a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is 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 We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.

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

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

Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling

16

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

Changes in undeveloped leasehold costs were as follows:

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

As of June 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $73 million, and $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:

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

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

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

17

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 7. Debt

Debt consists of the following:

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

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

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

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

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

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

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

Note 8. Leases

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

18

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

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

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

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

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

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

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

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

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

Cash Flow Information Supplemental cash flow information is as follows:

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

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

19

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

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

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

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

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

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

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

Note 9. Exit Cost – Transportation Commitments

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

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

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

20

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 impact of these transportation agreements during 2019 and 2020.

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

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

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

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

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

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

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

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

Note 10. Commitments and Contingencies

Legal 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.

21

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Note 11. Income Taxes

Income tax expense (benefit) consists of the following:

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

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 six months ended June 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 six months ended June 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.

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 in an effort to mitigate the 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 June 30, 2019, the following crude oil derivative contracts were outstanding:

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

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

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

22

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

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

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

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

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

See Note 13. Fair Value Measurements and 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 was as follows:

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

23

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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
June 30, 2019
Financial Assets:
Mutual Fund Investments	$	42		$	—		$	—	$	—		$	42
Commodity Derivative Instruments	—			63			—		(22		)	41
Financial Liabilities:
Commodity Derivative Instruments	—			(77		)	—		22			(55		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(2		)	—			—		—			(2		)
December 31, 2018
Financial Assets:
Mutual Fund Investments	$	38		$	—		$	—	$	—		$	38
Commodity Derivative Instruments	—			187			—		(7		)	180
Financial Liabilities:
Commodity Derivative Instruments	—			(34		)	—		7			(27		)
Portion of Deferred Compensation Liability Measured at Fair Value	(43		)	—			—		—			(43		)
Stock Based Compensation Liability Measured at Fair Value	(8		)	—			—		—			(8		)

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

24

Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 of GIP preferred equity at fair value of $97 million, including issuance date proceeds of $100 million netted with associated issuance costs of $3 million. See Note 2. Basis of Presentation.

Additional Fair Value Disclosures

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

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

Fair value information regarding our debt is as follows:

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

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

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

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

Noble Energy's basic (loss) income per share of common stock is computed by dividing net (loss) income 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 (loss) income per share:

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

⁽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

25

• Liquidity and Capital Resources.

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

EXECUTIVE OVERVIEW

The following discussion highlights significant operating and financial results for second quarter 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

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

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

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

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

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 majority of our acreage in Colorado is in rural, unincorporated areas of Weld County, and we continue to work closely with local regulators and communities to ensure safe and responsible operations and future planning. At this time, we do not foresee significant changes to our development plans, as we have all necessary approvals of more than 550 permits to drill wells over the next several years. The approved permits are for wells in multiple Integrated Development Plans (IDPs), many of which are in our Mustang Comprehensive Drilling Plan (CDP). We will continue to work closely with Weld County on the required local permits and agreements for the CDP.  However, if additional regulatory measures are adopted, we could incur additional costs to comply with the requirements or we may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity.

Recent Activities 

During second quarter 2019, we continued to progress our US onshore drilling and completions activities, advanced our Eastern Mediterranean and West Africa regional natural gas developments, and continued to advance our new US onshore and international exploration opportunities. Second quarter 2019 activities included the following:

Sales Volumes We delivered quarterly consolidated sales volumes of 343 MBoe/d, with approximately 56% of our production mix attributable to crude oil and NGLs. See Results of Operations – Exploration and Production.

Leviathan Natural Gas Project We progressed the Leviathan natural gas project, offshore Israel, to 88% completion. See Results of Operations – Exploration and Production.

Alen Natural Gas Development On April 1, 2019, we announced sanction of the Alen natural gas development, offshore Equatorial Guinea. See Results of Operations – Exploration and Production.

26

Financial Initiatives 

Commercial Paper Program During second quarter 2019, we utilized our recently-established commercial paper program, which allows for a maximum of $4.0 billion of unsecured commercial paper borrowings to provide for short-term funding needs and is supported by Noble Energy’s Revolving Credit Facility. The commercial paper program typically enables us to access lower short-term interest rates than those available under the Revolving Credit Facility. See Item 1. Financial Statements – Note 7. Debt.

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 or dividends, asset sales or operating cost structure. 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

The current commodity price environment, along with the timing of our capital expenditures for US onshore development, Leviathan completion, and the Aseng development well, as well as Noble Midstream Partners' investments, is anticipated to result in capital expenditures in excess of operating cash flows in 2019. Although we did not repurchase any shares under our $750 million share repurchase program in the first half of 2019, we remain committed to shareholder return initiatives. For example, in both April and July 2019, our Board of Directors approved quarterly cash dividends in amounts that represented a 9% increase over the prior year. This is our second straight year to increase our dividend, reflecting our commitment to return value to shareholders.

2019 Capital Investment Program 

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

Our 2019 organic capital program anticipates a lower level of investment directed to our US onshore assets, as compared with 2018. We will continue to advance our US onshore program through investments in liquids-rich and higher-return projects that improve execution efficiency and enhance our midstream business value. See Liquidity and Capital Resources.

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

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

27

DJ Basin   During second quarter 2019, we achieved a quarterly average sales volume record of 145 MBoe/d. Our activities were focused primarily on progressing development in the Mustang IDP, which benefits from our approved CDP, Wells Ranch and East Pony areas. In addition, we saw increased capital efficiencies as a result of improved drilling and completion performance.

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

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

International

Leviathan Natural Gas Project (Offshore Israel) The project is now more than 88% complete and remains on budget and on schedule. During second quarter 2019, we completed umbilical installation, tie-in of onshore pipelines to offshore pipelines, and tie-in to the Israel Natural Gas Lines grid. The first topsides set sail in July, and commissioning and operational readiness activities are underway. Project start-up is anticipated by the end of 2019.

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

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

Aseng Development Well (Offshore Equatorial Guinea) During second quarter 2019, we awarded contracts and acquired equipment for a new development well expected to mitigate Aseng field decline. The well was spud in July 2019 and production is expected to come online in fourth quarter 2019.

Alen Natural Gas Development (Offshore Equatorial Guinea)   On April 1, 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 liquefied natural gas (LNG) production facility (EG LNG) located at Punta Europa, Bioko Island. Definitive agreements in support of the project have been executed among the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial Guinea.

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 Alen 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

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. Exploration opportunities in a future period could result in significant dry hole cost and/or leasehold abandonment expense. See Item 1. Financial Statements – Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

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

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

Results of Operations

Highlights for our E&P business were as follows:

Second Quarter 2019 E&P Operating Highlights Included:

• total average consolidated sales volumes of 343 MBoe/d, net;

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

• average daily sales volumes of 1.0 Bcfe/d, gross, for offshore Israel natural gas, primarily from the Tamar field; and

• US onshore production expense per BOE of $11.64.

Second Quarter 2019 E&P Financial Results Included:

• capital expenditures, excluding acquisitions, of $596 million, as compared with $787 million for second quarter 2018;

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

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

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

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

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

⁽¹⁾  Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the prices for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity between reporting periods.

⁽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 Investees.

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

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

(millions)	Crude Oil & Condensate			NGLs			Natural Gas			Total
Three Months Ended June 30, 2018	$	749		$	137		$	214		$	1,100
Changes due to
Increase (Decrease) in Sales Volumes	17			4			(10		)	11
Decrease in Sales Prices (1)	(78		)	(57		)	(22		)	(157		)
Three Months Ended June 30, 2019	$	688		$	84		$	182		$	954
Six Months Ended June 30, 2018	$	1,522		$	283		$	468		$	2,273
Changes due to
Decrease in Sales Volumes	(53		)	(4		)	(37		)	(94		)
Decrease in Sales Prices (1)	(169		)	(99		)	(20		)	(288		)
Six Months Ended June 30, 2019	$	1,300		$	180		$	411		$	1,891

⁽¹⁾  Changes exclude gains and losses related to commodity 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 second quarter and the first six months of 2019 as compared with 2018 primarily due to the following:    

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

• reduction in sales volumes of 3 MBbl/d and 11 MBbl/d for second quarter and the first six months of 2019, respectively, due to the sale of our Gulf of Mexico assets in second quarter 2018; and

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

partially offset by:

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

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

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

• lower Eagle Ford Shale sales volumes of 8 MBbl/d and 12 MBbl/d for second quarter and the first six months of 2019, respectively, due to reduced activity and natural field decline;

partially offset by:

• higher sales volumes in the DJ and Delaware Basins of 11 MBbl/d and 12 MBbl/d for second quarter and the first six months of 2019, respectively, due to an increase in development activities.

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

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

• lower Eagle Ford Shale sales volumes of 63 MMcf/d and 72 MMcf/d for second quarter and the first six months of 2019, respectively, due to reduced activity and natural field decline;

• lower West Africa sales volumes of 26 MMcf/d and 31 MMcf/d for second quarter and the first six 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 16 MMcf/d and 23 MMcf/d for second quarter and the first six 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 92 MMcf/d and 87 MMcf/d for second quarter and the first six months of 2019, respectively, due to an increase in development activities.

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

Production Expense   Components of production expense were as follows:

(millions, except unit rate)	Total per BOE (1)(2)		Total		United States (2)		Eastern Mediterranean		West Africa
Three Months Ended June 30, 2019
Lease Operating Expense (3)	$	4.26	$	133	$	114	$	9	$	10
Production and Ad Valorem Taxes	1.28		40		40		—		—
Gathering, Transportation and Processing	3.97		124		124		—		—
Other Royalty Expense	0.03		1		1		—		—
Total Production Expense	$	9.54	$	298	$	279	$	9	$	10
Total Production Expense per BOE			$	9.54	$	11.64	$	2.82	$	2.47
Three Months Ended June 30, 2018
Lease Operating Expense (3)	$	4.47	$	138	$	114	$	5	$	19
Production and Ad Valorem Taxes	1.56		48		48		—		—
Gathering, Transportation and Processing	4.24		131		131		—		—
Other Royalty Expense	0.33		10		10		—		—
Total Production Expense	$	10.60	$	327	$	303	$	5	$	19
Total Production Expense per BOE			$	10.60	$	13.46	$	1.47	$	3.84
Six Months Ended June 30, 2019
Lease Operating Expense (3)	$	4.78	$	292	$	239	$	19	$	34
Production and Ad Valorem Taxes	1.42		87		87		—		—
Gathering, Transportation and Processing	4.35		266		266		—		—
Other Royalty Expense	0.07		4		4		—		—
Total Production Expense	$	10.62	$	649	$	596	$	19	$	34
Total Production Expense per BOE			$	10.62	$	12.75	$	2.83	$	4.44
Six Months Ended June 30, 2018
Lease Operating Expense (3)	$	4.62	$	293	$	240	$	12	$	41
Production and Ad Valorem Taxes	1.59		101		101		—		—
Gathering, Transportation and Processing	4.04		256		256		—		—
Other Royalty Expense	0.43		27		27		—		—
Total Production Expense	$	10.68	$	677	$	624	$	12	$	41
Total Production Expense per BOE			$	10.68	$	13.33	$	1.64	$	4.39

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

⁽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 second quarter and the first six months of 2019 decreased as compared with 2018, primarily due to the following:

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

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

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

partially offset by:

• increase in US lease operating expense and GTP expense, primarily due to increased development activities resulting in added production in our DJ and Delaware Basins; and

• increase in Eastern Mediterranean lease operating expense due to maintenance activities.

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The unit rate per BOE decreased for second quarter 2019 as compared with 2018 primarily due to cost reduction efforts within the DJ and Delaware Basins realized through workover optimization, contract renegotiation and fuel cost savings while increasing development activity and sales volumes within US onshore basins. Further, production and ad valorem taxes and other royalty expense declined due to lower commodity prices. The unit rate per BOE increased for the first six months of 2019 as compared with 2018 primarily due to the decrease in total sales volumes partially resulting from the sales of the Gulf of Mexico assets in second quarter 2018 and the 7.5% interest in Tamar in March 2018, coupled with an increase in GTP expense as noted above. Specifically, the impact of the Gulf of Mexico assets divestiture was offset by increased US onshore activity.

Exploration Expense Exploration expense for second quarter and the first six months of 2019 totaled $33 million and $57 million, respectively, including staff expense of $12 million and $24 million, respectively. Exploration expense for second quarter and the first six months of 2018 totaled $29 million and $64 million, respectively, including staff expense of $13 million and $27 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
Three Months Ended June 30, 2019
DD&A Expense	$	493	$	457	$	17	$	19
Unit Rate per BOE (1)	$	15.80	$	19.07	$	5.33	$	4.69
Three Months Ended June 30, 2018
DD&A Expense	$	435	$	394	$	15	$	26
Unit Rate per BOE (1)	$	14.10	$	17.51	$	4.41	$	5.25
Six Months Ended June 30, 2019
DD&A Expense	$	968	$	896	$	33	$	39
Unit Rate per BOE (1)	$	15.84	$	19.17	$	4.92	$	5.10
Six Months Ended June 30, 2018
DD&A Expense	$	880	$	800	$	28	$	52
Unit Rate per BOE (1)	$	13.87	$	17.10	$	3.82	$	5.56

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

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

• capital investment and development activities in the Delaware and DJ 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.

The unit rate per BOE for second quarter and the first six months of 2019 increased as compared with 2018, primarily due to the increase in total DD&A expense, as noted above. Specifically, activity increased in the higher-cost Delaware and DJ Basins and the sale of lower-cost Tamar reserves increased the overall unit rate per BOE. The increase in the unit rate is partially offset by the sale of higher-cost production from the Gulf of Mexico assets and lower sales volumes in West Africa.

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

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

• net cash settlement receipts of $15 million; and

• net non-cash decrease of $167 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for crude oil.     

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

• net cash settlement payment of $93 million; and

• net non-cash increase of $235 million in the fair value of our net commodity derivative liability, primarily driven by 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 financially attractive midstream projects, with current focus in the DJ and Delaware Basins.

Results of Operations

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

• total revenues of $161 million, as compared with $155 million for second quarter 2018;

• pre-tax income of $46 million, as compared with pre-tax income of $175 million for second quarter 2018;

• capital expenditures, excluding acquisitions, of $52 million, as compared with $157 million for second quarter 2018; and

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

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

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

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 second quarter and the first six 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 second quarter and the first six months of 2019 increased as compared with 2018 due to a full quarter and six months of services related to the Black Diamond system.

(Loss) Income from Equity Method Investees Income from equity method investees decreased for second quarter and the first six 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 second quarter and the first six 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 second quarter and the first six months of 2019 increased as compared with 2018, primarily due to certain assets being placed in service subsequent to second 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 quarter and six 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 a portion of our investment in CNX Midstream Partners. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.

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RESULTS OF OPERATIONS – CORPORATE

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 firm transportation agreements, are recorded at the Corporate level.

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

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

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

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

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

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

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

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

G&A expense for second quarter and the first six months of 2019 remained flat as compared with 2018 primarily due to decreases in third party transaction-related fees partially offset by increases in employee costs. The decrease in the unit rate per BOE for second quarter 2019 as compared with 2018 was due to the increase in total sales volumes. The increase in the unit rate per BOE for the first six months of 2019 as compared with 2018 was due to the net decrease in total sales volumes primarily as a result of the sale of our Gulf of Mexico assets and the sale of 7.5% interest in the Tamar field. See Results of Operations – Exploration & Production.

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

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

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

We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of 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.

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

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 six months of 2019.

Second Quarter 2019 Highlights

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

• borrowed $240 million, net, under our $4.0 billion commercial paper program for working capital purposes; and

• borrowed $140 million, net, under the Noble Midstream Services Revolving Credit Facility primarily to fund contributions to equity method investees.

Available Liquidity

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

	June 30, 2019							December 31, 2018
(millions, except percentages)	Noble Energy Excluding Noble Midstream Partners		Noble Midstream Partners		Total			Noble Energy Excluding Noble Midstream Partners		Noble Midstream Partners		Total
Total Cash (1)	$	593	$	9	$	602		$	707	$	12	$	719
Amounts Available for Borrowing (2)	3,760		—		3,760			4,000		—		4,000
Total Liquidity	$	4,353	$	9	$	4,362		$	4,707	$	12	$	4,719
Total Debt (3)	$	6,335	$	870	$	7,205		$	6,115	$	560	$	6,675
Noble Energy Share of Equity					$	9,029						$	9,426
Ratio of Debt-to-Book Capital (4)					44		%					41		%

⁽¹⁾  As of June 30, 2019 and December 31, 2018, total cash includes $132 million and $3 million of restricted cash, respectively.

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

Revolving Credit Facilities Noble Energy's $4.0 billion Revolving Credit Facility 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. Because the commercial paper program is

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

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

GIP Preferred Equity Commitment In March 2019, Noble Midstream Partners secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary holding Noble Midstream Partners’ 30% equity interest in EPIC Crude Holdings. Of the $200 million total commitment, $100 million was funded, with the remaining $100 million available for a one-year period, subject to certain conditions precedent. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

Contractual Obligations

Marcellus Shale Firm Transportation Agreements We have remaining financial commitments of approximately $1.0 billion, undiscounted, associated with Marcellus Shale firm 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 $99 million at June 30, 2019.

Cash Flows

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

	Six Months Ended June 30,
(millions)	2019			2018
Operating Activities	$	1,092		$	1,079
Investing Activities	(1,697		)	(1,050		)
Financing Activities	488			(121		)
Decrease in Cash, Cash Equivalents and Restricted Cash	$	(117	)	$	(92	)

Operating Activities   Cash provided by operating activities for the first six months of 2019 increased $13 million as compared with 2018. The increase was primarily driven by cash settlements for commodity derivatives of $15 million, as compared with cash payments of $93 million in 2018, increase in accounts payable due to timing of payments, increase in partner advances of $132 million and a decrease of $133 million in assets held for sale. The increase was partially offset by a decrease in net revenues driven by lower commodity prices and a reduction in sales volumes.

Investing Activities   Cash used in investing activities increased $647 million for the first six months of 2019 as compared with 2018, primarily due to a decrease in net proceeds provided by divestitures, partially offset by a decrease in capital spending for property, plant and equipment. In addition, Noble Midstream Partners invested $415 million in equity method investees. There were no acquisitions for the first six months of 2019 compared to $650 million in the prior year.

Financing Activities   Our financing activities during the first six months of 2019 included net borrowings of $240 million under the commercial paper program, net borrowings of $310 million on the Noble Midstream Services Revolving Credit Facility and the receipt of $99 million of GIP preferred equity, net of offering costs. In addition, during the first six months of 2019, we paid $111 million of cash dividends to Noble Energy shareholders. Other financing activities used net cash of $50 million.

Our financing activities during the first six months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $445 million, net, Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund the Saddle Butte acquisition. During the first six months of 2018, we used $384 million of cash to redeem senior notes, repurchased $130 million of common stock pursuant to our stock repurchase program, paid $102 million of cash dividends to Noble Energy shareholders and paid $22 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $331 million of contributions from noncontrolling interest owners. Other financing activities used net cash of $29 million.

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

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Capital Expenditure Activities

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

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

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

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

⁽³⁾  Costs for the six months ended June 30, 2019 primarily include Noble Midstream Partners' $369 million investment in EPIC Y-Grade and EPIC Crude Holdings and $39 million investment in Delaware Crossing. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

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

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

Dividends

On July 23, 2019, our Board of Directors declared a quarterly cash dividend of 12 cents per Noble Energy common share, which will be paid on August 19, 2019 to shareholders of record on August 5, 2019. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

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 June 30, 2019, our open commodity derivative instruments were in a net liability position with a fair value of $14 million. Based on the June 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 increase the fair value of our net commodity derivative liability by approximately $146 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. Issuances of commercial paper under our commercial paper program and borrowings under the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services Term Loan Credit Facility, which as of June 30, 2019 total $1.1 billion and have a weighted average interest rate of 3.50%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. While we currently have no interest rate derivative

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instruments as of June 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 second quarter and the first six 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 and in this quarterly report on Form 10-Q, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our Annual Report on Form 10-K for the year ended December 31, 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.

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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)
4/1/2019 - 4/30/2019	1,467	$	25.64	—
5/1/2019 - 5/31/2019	132	24.55		—
6/1/2019 - 6/30/2019	462	21.36		—
Total	2,061	$	24.61	—	$	455

 

⁽¹⁾  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 second 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).
10.1*	Noble Energy, Inc. 2017 Long-Term Incentive Plan (Amended and Restated Effective April 23, 2019) (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).
10.2*	Form of Restricted Stock Notice and Award Agreement (three-year vested one-third per year) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).
10.3*	Form of Option Award Notice and Agreement under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).
10.4*	Form of Restricted Stock Notice and Award Agreement (three-year cliff vested) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).
10.5*	Form of Restricted Stock Notice and Award Agreement (three-year vested 20/30/50) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (File No. 001-07964) and incorporated herein by reference).
31.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
31.2	Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
32.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.
32.2	Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.
101.INS	Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

* Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

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Signatures

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

		NOBLE ENERGY, INC.
		(Registrant)
Date	August 2, 2019	By: /s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

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