Edgar Filing: NOBLE ENERGY INC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)



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

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 ý No o

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 ý No o

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

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



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o

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

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

Yes o No ý



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

As of March 31, 2019, there were 478,231,487 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 (Loss) Income	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	22

Item 3. Quantitative and Qualitative Disclosures About Market Risk	35

Item 4. Controls and Procedures	36

Part II. Other Information	36

Item 1. Legal Proceedings	36

Item 1A. Risk Factors	36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3. Defaults Upon Senior Securities	36

Item 4. Mine Safety Disclosures	36

Item 5. Other Information	36

Item 6. Exhibits	37

Signatures	38

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Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations and Comprehensive (Loss) Income

(millions, except per share amounts)

(unaudited)



	Three Months Ended March 31,
	2019			2018
Revenues
Oil, NGL and Gas Sales	$	937		$	1,173
Sales of Purchased Oil and Gas	74			53
Other Revenue	41			60
Total	1,052			1,286
Costs and Expenses
Production Expense	305			319
Depreciation, Depletion and Amortization	508			468
General and Administrative	102			104
Cost of Purchased Oil and Gas	87			57
Other Operating Expense, Net	49			50
Gain on Divestitures, Net	—			(588		)
Asset Impairments	—			168
Firm Transportation Exit Cost	92			—
Total	1,143			578
Operating (Expense) Income	(91		)	708
Other Expense
Loss on Commodity Derivative Instruments	212			79
Interest, Net of Amount Capitalized	66			73
Other Non-Operating Expense, Net	4			13
Total	282			165
(Loss) Income Before Income Taxes	(373		)	543
Income Tax Benefit	(84		)	(31		)
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests	(289		)	574
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests	24			20
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy	$	(313	)	$	554

Net (Loss) Income Attributable to Noble Energy Common Shareholders per Share
Basic	$	(0.65	)	$	1.14
Diluted	$	(0.65	)	$	1.14
Weighted Average Number of Common Shares Outstanding
Basic	478			487
Diluted	478			488

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

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Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)



	March 31, 2019			December 31, 2018
ASSETS
Current Assets
Cash and Cash Equivalents	$	528		$	716
Accounts Receivable, Net	573			616
Other Current Assets	142			418
Total Current Assets	1,243			1,750
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	29,364			29,002
Property, Plant and Equipment, Other	1,012			891
Total Property, Plant and Equipment, Gross	30,376			29,893
Accumulated Depreciation, Depletion and Amortization	(11,675		)	(11,474		)
Total Property, Plant and Equipment, Net	18,701			18,419
Other Noncurrent Assets	1,376			841
Total Assets	$	21,320		$	21,010
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable – Trade	$	1,284		$	1,207
Other Current Liabilities	659			519
Total Current Liabilities	1,943			1,726
Long-Term Debt	6,738			6,574
Deferred Income Taxes	961			1,061
Other Noncurrent Liabilities	1,438			1,165
Total Liabilities	$	11,080		$	10,526
Commitments and Contingencies
Mezzanine Equity
Redeemable Noncontrolling Interest, Net	$	97		$	—
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	8,219			8,203
Accumulated Other Comprehensive Loss	(32		)	(32		)
Treasury Stock, at Cost; 39 Million Shares	(735		)	(730		)
Retained Earnings	1,614			1,980
Noble Energy Share of Equity	9,071			9,426
Noncontrolling Interests	1,072			1,058
Total Shareholders' Equity	10,143			10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity	$	21,320		$	21,010

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

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Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)



	Three Months Ended March 31,
	2019			2018
Cash Flows From Operating Activities
Net (Loss) Income Including Noncontrolling Interests	$	(289	)	$	574
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	508			468
Deferred Income Tax Benefit	(100		)	(157		)
Loss on Commodity Derivative Instruments	212			79
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments	14			(28		)
Other Adjustments for Noncash Items Included in Income	28			(2		)
Gain on Divestitures, Net	—			(588		)
Asset Impairments	—			168
Firm Transportation Exit Cost	92			—
Changes in Operating Assets and Liabilities
Decrease in Accounts Receivable	9			89
Increase (Decrease) in Accounts Payable	106			(33		)
Increase in Current Income Taxes Payable	45			14
Other Current Assets and Liabilities, Net	(52		)	(18		)
Other Operating Assets and Liabilities, Net	(45		)	17
Net Cash Provided by Operating Activities	528			583
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(763		)	(787		)
Acquisitions, Net of Cash Received	—			(650		)
Additions to Equity Method Investments	(271		)	—
Proceeds from Divestitures, Net	123			865
Net Cash Used in Investing Activities	(911		)	(572		)
Cash Flows From Financing Activities
Proceeds from Revolving Credit Facility	50			245
Repayment of Revolving Credit Facility	(50		)	(475		)
Proceeds from Noble Midstream Services Revolving Credit Facility	345			405
Repayment of Noble Midstream Services Revolving Credit Facility	(175		)	(55		)
Dividends Paid, Common Stock	(53		)	(48		)
Purchase and Retirement of Common Stock	—			(67		)
Contributions from Noncontrolling Interest Owners	10			333
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs	99			—
Other	(32		)	(40		)
Net Cash Provided by Financing Activities	194			298
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(189		)	309
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	719			713
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	530		$	1,022

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

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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

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

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

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

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

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

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

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

Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments.

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

Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.

Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use.

Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For 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.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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

Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of March 31, 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⁾	$	108	$	116	$	224


⁽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 On March 25, 2019, Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from Global Infrastructure Partners Capital Solutions Fund (GIP), of which $100 million has been funded, with associated offering costs of $3 million. The preferred equity was recorded initially at fair value on the issuance date. 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 such preferred equity is reported as mezzanine equity on the consolidated balance sheet. 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. Accretion for first quarter 2019 was also de minimis. See Note 4. Acquisitions and Divestitures.

Recently Issued Accounting Standards

Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and shall be applied using a modified retrospective approach. 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, based on our current portfolio, we do not believe adoption of the standard will have a material impact on our financial statements. As our implementation team progresses assessment, we will continue to monitor changes in our credit portfolio in light of the provisions in ASU 2016-13.

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 are currently evaluating the provisions of ASU 2018-15.

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 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).

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

We adopted ASC 842 on January 1, 2019 using the modified retrospective approach 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.

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



	Three Months Ended March 31,
(millions)	2019		2018
Other Revenue
Income from Equity Method Investees	$	17	$	47
Midstream Services Revenues – Third Party	24		13
Total	$	41	$	60
Production Expense
Lease Operating Expense	$	151	$	155
Production and Ad Valorem Taxes	49		54
Gathering, Transportation and Processing Expense	102		93
Other Royalty Expense	3		17
Total	$	305	$	319
Other Operating Expense, Net
Exploration Expense	$	24	$	35
Other, Net	25		15
Total	$	49	$	50

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Balance Sheet Information Other balance sheet information is as follows:



(millions)	March 31, 2019			December 31, 2018
Accounts Receivable, Net
Commodity Sales	$	384		$	383
Joint Interest Billings	124			137
Other	80			111
Allowance for Doubtful Accounts	(15		)	(15		)
Total	$	573		$	616
Other Current Assets
Commodity Derivative Assets	$	9		$	180
Inventories, Materials and Supplies	70			55
Assets Held for Sale⁽¹⁾	—			133
Prepaid Expenses and Other Current Assets	63			50
Total	$	142		$	418
Other Noncurrent Assets
Equity Method Investments ⁽²⁾	$	559		$	286
Operating Lease Right-of-Use Assets ⁽³⁾	273			—
Customer-Related Intangible Assets, Net ⁽⁴⁾	302			310
Goodwill ⁽⁴⁾	110			110
Other Assets, Noncurrent	132			135
Total	$	1,376		$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	106		$	103
Asset Retirement Obligations	118			118
Interest Payable	85			66
Other Liabilities, Current	350			232
Total	$	659		$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	149		$	147
Asset Retirement Obligations	749			762
Operating Lease Liabilities ⁽³⁾	194			—
Firm Transportation Exit Cost Accrual ⁽⁵⁾	156			67
Production and Ad Valorem Taxes	88			83
Other Liabilities, Noncurrent	102			106
Total	$	1,438		$	1,165


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


⁽²⁾	The 2019 amount includes Noble Midstream Partners' $227 million investment in EPIC Y-Grade, LP and EPIC Crude Holdings, LP and $38 million investment in Delaware Crossing LLC. See Note 4. Acquisitions and Divestitures.


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


⁽⁴⁾	Amounts relate to assets acquired in the first quarter 2018 Saddle Butte Acquisition. Intangible asset amounts at March 31, 2019 and December 31, 2018 are net of accumulated amortization of $38 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.


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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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



	Three Months Ended March 31,
(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	$	528	$	992
Restricted Cash at End of Period	2		30
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	530	$	1,022

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 and New Ventures, including 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.

Corporate level expenses include debt, 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.



			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 March 31, 2019
Crude Oil Sales	$	612	$	545	$	1	$	66	$	—	$	—	$	—		$	—
NGL Sales	96		96		—		—		—		—		—			—
Natural Gas Sales	229		108		117		4		—		—		—			—
Total Crude Oil, NGL and Natural Gas Sales	937		749		118		70		—		—		—			—
Sales of Purchased Oil and Gas	74		14		—		—		—		33		—			27
Income from Equity Method Investees	17		—		—		15		—		2		—			—
Midstream Services Revenues – Third Party	24		—		—		—		—		24		—			—
Intersegment Revenues	—		—		—		—		—		106		(106		)	—
Total Revenues	1,052		763		118		85		—		165		(106		)	27
Lease Operating Expense	151		125		10		24		—		1		(9		)	—
Production and Ad Valorem Taxes	49		47		—		—		—		2		—			—
Gathering, Transportation and Processing Expense	102		142		—		—		—		29		(69		)	—
Other Royalty Expense	3		3		—		—		—		—		—			—
Total Production Expense	305		317		10		24		—		32		(78		)	—
Depreciation, Depletion and Amortization	508		439		16		20		—		25		(7		)	15

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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
Cost of Purchased Oil and Gas	87			14			—			—		—			31			—			42
Firm Transportation Exit Cost	92			—			—			—		—			—			—			92
Loss on Commodity Derivative Instruments	212			188			—			24		—			—			—			—
(Loss) Income Before Income Taxes	(373		)	(247		)	84			11		(16		)	73			(14		)	(264		)
Additions to Long-Lived Assets, Excluding Acquisitions	712			511			132			5		10			66			(23		)	11
Investments in Equity Method Investees	271			—			—			—		—			271			—			—
Three Months Ended March 31, 2018
Crude Oil Sales	$	773		$	682		$	2		$	89	$	—		$	—		$	—		$	—
NGL Sales	146			146			—			—		—			—			—			—
Natural Gas Sales	254			120			129			5		—			—			—			—
Total Crude Oil, NGL and Natural Gas Sales	1,173			948			131			94		—			—			—			—
Sales of Purchased Oil and Gas	53			—			—			—		—			22			—			31
Income from Equity Method Investees	47			—			—			35		—			12			—			—
Midstream Services Revenues – Third Party	13			—			—			—		—			13			—			—
Intersegment Revenues	—			—			—			—		—			81			(81		)	—
Total Revenues	1,286			948			131			129		—			128			(81		)	31
Lease Operating Expense	155			126			7			22		—			—			—			—
Production and Ad Valorem Taxes	54			53			—			—		—			1			—			—
Gathering, Transportation and Processing Expense	93			128			—			—		—			20			(53		)	—
Other Royalty Expense	17			17			—			—		—			—			—			—
Total Production Expense	319			324			7			22		—			21			(53		)	—
Depreciation, Depletion and Amortization	468			404			13			26		—			17			(3		)	11
Gain on Divestitures, Net	(588		)	(6		)	(386		)	—		—			(196		)	—			—
Asset Impairments	168			168			—			—		—			—			—			—
Cost of Purchased Oil and Gas	57			—			—			—		—			21			—			36
Loss on Commodity Derivative Instruments	79			64			—			15		—			—			—			—
Income (Loss) Before Income Taxes	543			(43		)	473			64		(9		)	247			(15		)	(174		)
Additions to Long-Lived Assets, Excluding Acquisitions	905			534			147			2		2			242			(32		)	10
March 31, 2019
Property, Plant and Equipment, Net	$	18,701		$	13,145		$	2,728		$	736	$	119		$	1,801		$	(162	)	$	334
December 31, 2018
Property, Plant and Equipment, Net	$	18,419		$	13,044		$	2,630		$	805	$	37		$	1,742		$	(145	)	$	306

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)


⁽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 southwestern Reeves County, Texas. We received cash consideration of $131 million, recognizing no gain or loss on the sale.

EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-grade pipeline from the Delaware Basin to Corpus Christi, Texas, and a 30% equity interest in EPIC Crude Holdings, LP (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. These investments are accounted for using the equity method.

Also, on March 25, 2019, Noble Midstream Partners secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a subsidiary formed by Noble Midstream Partners to hold the 30% equity interest in EPIC Crude Holdings. GIP funded $100 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. In addition, 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. Proceeds from the preferred equity issuance were used to repay a portion of outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, which were drawn to fund its exercise of the option to invest in EPIC Crude Holdings. See Note. 2 Basis of Presentation and Note 13. Fair Value Measurements and Disclosures.

Other Divestitures, Net In first quarter 2019, we also closed the sales of certain other non-core US onshore properties which resulted in net payments of approximately $8 million.

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.

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 $487 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. The sale was in accordance with the terms of the Israel Natural Gas Framework and completed our obligation to reduce our 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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 33.5% limited partner interest, in CNX Midstream Partners, which were subsequently divested in 2018.

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 owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million 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.

Other Divestitures, Net In first quarter 2018, we also closed the sales of other non-core US onshore properties and received net cash consideration of approximately $10 million, recording a gain of $6 million.

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)	March 31, 2019		December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	9	$	6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	350		348
Capitalized Exploratory Well Costs, End of Period	$	359	$	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 equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses.

Changes in undeveloped leasehold costs were as follows:



(millions)	Three Months Ended March 31, 2019
Undeveloped Leasehold Costs, Beginning of Period	$	2,306
Additions to Undeveloped Leasehold Costs	47
Transfers to Proved Properties	—
Assets Sold	(2		)
Undeveloped Leasehold Costs, End of Period	$	2,351

As of March 31, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $70 million, and $59 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties and international properties, respectively.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 units containing 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:



	Three Months Ended March 31,
(millions)	2019			2018
Asset Retirement Obligations, Beginning Balance	$	880		$	875
Liabilities Incurred	2			2
Liabilities Settled	(27		)	(20		)
Revisions of Estimates	—			(11		)
Reclassification to Liabilities Associated with Assets Held for Sale	—			(227		)
Accretion Expense	12			9
Asset Retirement Obligations, Ending Balance	$	867		$	628

Three Months Ended March 31, 2019 Liabilities settled of $27 million 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.

Three Months Ended March 31, 2018 We transferred $227 million of ARO liabilities related to Gulf of Mexico properties to liabilities associated with assets held for sale. Liabilities settled include $20 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate to decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project.

Note 7. Debt

Debt consists of the following:



	March 31, 2019					December 31, 2018
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate
Revolving Credit Facility, due March 9, 2023 ⁽¹⁾	$	—		—	%	$	—		—	%
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 ⁽²⁾	230			3.66	%	60			3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500			3.41	%	500			3.42	%
Senior Notes and Debentures	5,892			⁽³	⁾	5,892			⁽³	⁾
Finance Lease Obligations ⁽⁴⁾	215			—	%	223			—	%
Total	6,837					6,675
Net Unamortized Discounts and Debt Issuance Costs	(58		)			(60		)
Total Debt	6,779					6,615
Less Amounts Due Within One Year
Finance Lease Obligations⁽⁴⁾	(41		)			(41		)
Long-Term Debt Due After One Year	$	6,738				$	6,574


⁽¹⁾	As of March 31, 2019 and December 31, 2018, the Revolving Credit Facility had $4.0 billion of capacity and the entire amount was available for borrowing.


⁽²⁾	As of March 31, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity. Amounts available for borrowing at totaled $570 million and $740 million, respectively.


⁽³⁾	The Senior Notes and Debentures have weighted average interest rates of 5.01% for both March 31, 2019 and December 31, 2018.


⁽⁴⁾	See Note 8. Leases.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Noble Energy’s Revolving Credit Facility. Commercial paper generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 397 days. The commercial paper is 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 will bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest amounts are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. No borrowings or repayments occurred during first quarter 2019 under the commercial paper program.

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.

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



(millions)	Balance Sheet Location	March 31, 2019
ROU Assets
Operating Leases ⁽¹⁾	Other Noncurrent Assets	$	273
Finance Leases ⁽²⁾	Total Property, Plant and Equipment, Net	179
Total ROU Assets		$	452
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	86
Finance Leases	Other Current Liabilities	41
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	194
Finance Leases	Long-Term Debt	174
Total Lease Liabilities		$	495


⁽¹⁾	Operating lease ROU assets include primarily office space of $107 million, compressors of $87 million, and drilling rigs of $40 million.


⁽²⁾	Finance lease ROU assets are recorded net of accumulated amortization of $449 million as of March 31, 2019. Assets include primarily office space of $96 million, net.

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



(millions)	Statement of Operations Location	Three Months Ended March 31, 2019
Operating Lease Cost	⁽¹⁾	$	25
Finance Lease Cost
Amortization Expense on ROU Assets	Depreciation, Depletion and Amortization	8
Interest Expense on Lease Liabilities	Interest, Net of Amount Capitalized	3
Short-term Lease Cost ⁽²⁾	⁽¹⁾	126
Variable Lease Cost ⁽³⁾	⁽¹⁾	—
Sublease Income	General and Administrative	(1		)
Total Lease Cost		$	161


⁽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 a term of one month or less.


⁽³⁾	Variable lease costs were de minimis for first quarter 2019.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Cash Flow Information Supplemental cash flow information is as follows:



	Three Months Ended March 31, 2019
(millions)	Operating Leases		Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	15	$	3
Financing Cash Flows	—		10
Investing Cash Flows	9		—
ROU Assets Obtained in Exchange for Lease Liabilities ⁽¹⁾	34		2


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

Maturity of Lease Liabilities Maturities of lease liabilities as of March 31, 2019 are as follows:



(millions)	Operating Leases		Finance Leases		Total
Remainder of 2019	$	73	$	37	$	110
2020	83		47		130
2021	47		32		79
2022	32		22		54
2023	19		20		39
2024 and Thereafter	67		105		172
Total Lease Liabilities, Undiscounted	321		263		584
Less: Imputed Interest	41		48
Total Lease Liabilities ⁽¹⁾	$	280	$	215


⁽¹⁾	Includes the current portion of $86 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:



	March 31, 2019
Weighted-Average Remaining Lease Term
Operating Leases	6.7 years
Finance Leases	8.0 years
Weighted-Average Discount Rate
Operating Leases	4.45	%
Finance Leases	5.61	%

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 March 31, 2019, our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately four to fourteen years, is approximately $1.1 billion, undiscounted.

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:



	Three Months Ended March 31,
(millions)	2019			2018
Balance at Beginning of Period ⁽¹⁾	$	80		$	90
Firm Transportation Exit Cost Accrual	92			—
Payments, Net of Accretion	(5		)	(6		)
Balance at End of Period	167			84
Less: Current Portion Included in Other Current Liabilities	11			11
Long-term Portion Included in Other Noncurrent Liabilities at End of Period	$	156		$	73


⁽¹⁾	Balances include current accruals of $13 million which are included in other current liabilities on 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 March 31,
(millions)	Statements of Operations Location	2019		2018
Sales of Purchased Gas	Sales of Purchased Oil and Gas	$	27	$	31
Cost of Purchased Gas and Related Expense
Cost of Purchased of Gas	Cost of Purchased Oil and Gas	27		30
Utilized Firm Transportation Expense ⁽¹⁾	Cost of Purchased Oil and Gas	15		5
Unutilized Firm Transportation Expense	Cost of Purchased Oil and Gas	—		1
Cost of Purchased Gas and Related Expense, Total	Cost of Purchased Oil and Gas	$	42	$	36


⁽¹⁾	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.

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 Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree, entered by the US District Court for the District of Colorado on June 2, 2015, requires us to perform certain corrective actions, to complete mitigation projects and supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $5 million, SEP costs of $4 million, and costs associated with the injunctive relief are being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $84 million, of which $78 million was incurred to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.

We have concluded that the penalties, injunctive relief, and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Note 6. Asset Retirement Obligations.

Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, we are unable to predict the ultimate outcome of this action at this time, but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. The letter requests an opportunity to discuss settlement of the alleged violations. Given the uncertainty associated with enforcement actions of this nature, we are unable to predict the ultimate outcome of this action at this time, but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

Note 11. Income Taxes

Income tax expense (benefit) consists of the following:



	Three Months Ended March 31,
(millions, except percentages)	2019			2018
Current	$	16		$	126
Deferred	(100		)	(157		)
Total Income Tax Benefit	$	(84	)	$	(31	)
Effective Tax Rate	22.5		%	(5.7		)%

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 first quarter 2019 varied as compared with 2018, primarily due to a $145 million discrete tax benefit recorded in first quarter 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 Tax Reform Legislation and the transition tax (toll tax). In addition, first quarter 2018 includes foreign taxes on a gain related to the divestiture of a 7.5% interest in the Tamar field, offshore Israel.

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 relating to the marketing of 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.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

Unsettled Commodity Derivative Instruments As of March 31, 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	22,000	$	—		$	56.96	$	—	$	—	$	—
2019	Three-Way Collars	NYMEX WTI	33,000	—			—		49.35		59.35		72.25
2019	Swaption	NYMEX WTI	5,000	—			62.50		—		—		—
2019	Swaps	ICE Brent	5,000	—			57.00		—		—		—
2019	Three-Way Collars	ICE Brent	3,000	—			—		43.00		50.00		64.07
2019	Basis Swaps	⁽¹⁾	27,000	(3.23		)	—		—		—		—
2020	Swaption	NYMEX WTI	5,000	—			61.79		—		—		—
2020	Three-Way Collars	NYMEX WTI	10,000	—			—		50.00		58.00		67.37
2020	Basis Swaps	⁽¹⁾	15,000	(5.01		)	—		—		—		—


⁽¹⁾	We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.

As of March 31, 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⁾	113,500	(0.65		)	—		—		—		—
2019	Basis Swaps	WAHA ⁽¹⁾	15,000	(1.44		)	—		—		—		—
2020	Basis Swaps	CIG ⁽¹⁾	44,000	(0.62		)	—		—		—		—
2020	Basis Swaps	WAHA ⁽¹⁾	17,000	(0.75		)	—		—		—		—


⁽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	March 31, 2019		December 31, 2018		Balance Sheet Location	March 31, 2019		December 31, 2018
Commodity Derivative Instruments	Other Current Assets	$	9	$	180	Other Current Liabilities	$	63	$	1
	Other Noncurrent Assets	1		—		Other Noncurrent Liabilities	20		26
	Total	$	10	$	180		$	83	$	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.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 March 31,
(millions)	2019			2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(9	)	$	30
Natural Gas	(5		)	(2		)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	$	(14	)	$	28
Non-cash Portion of Loss on Commodity Derivative Instruments
Crude Oil	$	223		$	50
Natural Gas	3			1
Total Non-cash Portion of Loss on Commodity Derivative Instruments	$	226		$	51
Loss (Gain) on Commodity Derivative Instruments
Crude Oil	$	214		$	80
Natural Gas	(2		)	(1		)
Total Loss on Commodity Derivative Instruments	$	212		$	79

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 Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values 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.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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



	Fair Value Measurements Using
(millions)	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Adjustment ⁽¹⁾			Fair Value Measurement
March 31, 2019
Financial Assets:
Mutual Fund Investments	$	41		$	—		$	—	$	—		$	41
Commodity Derivative Instruments	—			23			—		(13		)	10
Financial Liabilities:
Commodity Derivative Instruments	—			(96		)	—		13			(83		)
Portion of Deferred Compensation Liability Measured at Fair Value	(48		)	—			—		—			(48		)
Stock Based Compensation Liability Measured at Fair Value	(1		)	—			—		—			(1		)
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

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 As of March 31, 2019, we recorded redeemable noncontrolling interest, associated with the issuance of GIP preferred equity, at fair value of $97 million, representing issuance date proceeds of $100 million netted with associated issuance costs of $3 million. See Note 4. Acquisitions and Divestitures.

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 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 borrowings under the commercial paper program, 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:



	March 31, 2019				December 31, 2018
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt ⁽¹⁾	$	6,622	$	6,841	$	6,452	$	6,121


⁽¹⁾	Excludes unamortized discount, debt issuance costs and finance lease obligations. See Note 8. Leases.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements (Unaudited)

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 March 31,
(millions, except per share amounts)	2019			2018
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy	$	(313	)	$	554
Weighted Average Number of Shares Outstanding, Basic ⁽¹⁾	478			487
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	—			1
Weighted Average Number of Shares Outstanding, Diluted	478			488
(Loss) Income Per Share, Basic	$	(0.65	)	$	1.14
(Loss) Income Per Share, Diluted	$	(0.65	)	$	1.14
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	15			16


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

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

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


•	Executive Overview;


•	Operating Outlook;


•	Results of Operations – Exploration and Production;


•	Results of Operations – Midstream;


•	Results of Operations – Corporate; and


•	Liquidity and Capital Resources.

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

EXECUTIVE OVERVIEW

The following discussion highlights significant operating and financial results for first 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, although trending upward during first quarter 2019, did not reach comparable levels experienced in first quarter 2018, where Brent and WTI crude oil prices averaged in excess of $65 and $60 per barrel, respectively. The outlook for the remainder of 2019 will continue to depend on supply and demand dynamics, geopolitical and security factors in crude oil-producing nations and the spread between WTI and Brent prices, among other factors.

The US natural gas market remains oversupplied and prices have continued to be depressed during first quarter 2019. We expect 2019 natural gas prices to be at or near 2018 trading levels.

In addition, price differentials, specifically in the Delaware Basin, have continued to widen for both crude oil and natural gas due to takeaway capacity constraints. Infrastructure expansion in the Delaware Basin is expected to result in price improvement later in 2019.

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We have entered into crude oil and natural gas price hedging arrangements to mitigate the effect of commodity price volatility and enhance the predictability of our cash flows.

Cost Environment While materials and services costs have begun shifting downward in response to fourth quarter 2018 oil prices and lower activity, pricing for oilfield equipment, services and infrastructure has yet to fully adjust to the current commodity price environment. Internal initiatives to improve capital efficiency have led to improved US onshore productivity, such as increasing completion stages per day which in turn reduces cycle times and lowers well completion costs. While we progress capital efficiency initiatives, we continue to work with our service providers to reduce cost structure.

Colorado Senate Bill 19-181 For some time, initiatives have been underway in the State of Colorado to limit or ban hydraulic fracturing statewide and other facets of 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.

Most of our acreage in Colorado is in rural 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 State 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 first 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 engaged in new US onshore and international exploration opportunities. First quarter 2019 activities included the following:

Sales Volumes We delivered quarterly sales volumes of 337 MBoe/d, with approximately 56% of our production mix attributable to crude oil and NGLs. See Results of Operations – Exploration and Production.

Non-Core Acreage Sale We sold approximately 13,000 net acres in non-core southwestern Reeves County, Texas, receiving cash consideration of $131 million. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

Leviathan Natural Gas Project We progressed the Leviathan natural gas project, offshore Israel, to 81% 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.

US Onshore Exploration Opportunity We acquired additional US onshore undeveloped acreage. See Results of Operations – Exploration and Production.

Colombia Exploration Opportunity We finalized a strategic farmout arrangement for exploration acreage offshore Colombia. See Results of Operations – Exploration and Production.

EPIC Pipeline Investments Noble Midstream Partners exercised and closed options to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade) and a 30% equity interest in EPIC Crude Holdings, LP (EPIC Crude Holdings) and secured a $200 million preferred equity commitment from Global Infrastructure Partners Capital Solutions Fund (GIP), of which $100 million was funded during first quarter 2019. See Results of Operations – Midstream.

Financial Initiatives

Commercial Paper Program In first quarter 2019, we established a commercial paper program, which allows for a maximum of $4.0 billion of unsecured commercial paper notes to provide for short-term funding needs. The commercial paper program is supported by Noble Energy’s 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 and will continue to evaluate the commodity price

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environment, well productivity and efficiency gains in aligning our activity levels with commodity price conditions. To this end, our 2019 capital investment program is responsive to positive or negative commodity price conditions that may develop. See Operating Outlook – 2019 Capital Investment Program.

If commodity prices decline or operating costs continue to rise, we could experience material asset impairments, as well as material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider 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 cash flows in 2019. Although we did not repurchase any shares under our $750 million share repurchase program this quarter, we remain committed to shareholder return initiatives. For example, in April 2019, our Board of Directors announced a 9% increase in the quarterly cash dividend. This is our second straight year to increase our dividend, reflecting our commitment to return value to shareholders.

2019 Capital Investment Program

Our 2019 organic capital program is in the range of $2.4 to $2.6 billion, with approximately 70% being allocated to US onshore development and approximately 20% 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. See Results of Operations – Exploration and Production.

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 high-return projects, improve execution efficiency, and enhance our midstream business value.

We will continue to evaluate the level of capital spending throughout the year. 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 first 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	29	21	144
Delaware Basin	4	20	9	59
Eagle Ford Shale	—	7	7	50
Total	6	56	37	253

DJ Basin During first quarter 2019, we achieved a quarterly average sales volume record of 144 MBoe/d. Our activities were focused primarily on progressing development in the Mustang IDP area, which benefits from our approved CDP, and we saw increased capital efficiencies as a result of improved drilling performance.

Delaware Basin During first quarter 2019, much of our activity focused on row development with long laterals and multi-well pads targeting multiple zones within the northern portion of our acreage position. We are also focusing on completion operations to bring online our drilled but uncompleted wells.

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Eagle Ford Shale During first quarter 2019, we focused on well completion activities in North Gates Ranch.

International

Leviathan Natural Gas Project (Offshore Israel) The project is now 81% complete and remains on budget and on schedule. We have installed the in-field gathering and pipelines, completed installation of all subsea trees, finished completions on all four wells with successful flowbacks, completed the float of the main decks, finished flowline installation, completed jacket and piles installation and commenced yard commissioning of platform modules. Project start-up is anticipated by the end of 2019.

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

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 mid-year 2019. The estimated acquisition cost for our interest in the pipeline is approximately $200 million.

Tamar Natural Gas Project (Offshore Israel) In January 2019, the Petroleum Commissioner of Israel approved the development plan for our 2013 Tamar Southwest discovery, which includes tie-back to the existing Tamar platform, thus reinforcing the reliable operation of the Tamar project and supporting increased customer demand.

Aseng Development Well (Offshore Equatorial Guinea) During first quarter 2019, we awarded contracts and acquired equipment for a new development well expected to mitigate Aseng field decline. Production is expected to come online in late third quarter to early 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 between 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 utilize three existing high-capacity Alen production wells. Minor platform modifications will be made to deliver sales gas from Alen to the Alba Plant and EG LNG facilities. A 24-inch pipeline capable of handling 950 MMcfe/d will be constructed 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 In first quarter 2019, we acquired additional undeveloped acreage increasing our US onshore unconventional exploration position to more than 140,000 acres residing in two plays in Wyoming.

Offshore Colombia During first quarter 2019, we signed an agreement, pending customary approvals, for a 40% operated working interest in more than 2 million gross acres offshore Colombia, located on two offshore blocks. We expect to drill an exploration well in 2020.

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Results of Operations

Highlights for our E&P business were as follows:

First Quarter 2019 E&P Operating Highlights Included:


•	total average consolidated sales volumes of 332 MBoe/d, net;


•	average daily sales volumes of 113 MBbl/d, net, for US crude oil; and


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

First Quarter 2019 E&P Financial Results Included:


•	net loss on commodity derivative instruments of $212 million (which is net of cash settlement receipts of $14 million), as compared with a net loss of $79 million for first quarter 2018;


•	pre-tax loss of $168 million, as compared with pre-tax income of $485 million for first quarter 2018; and


•	capital expenditures, excluding acquisitions, of $648 million, as compared with $667 million for first quarter 2018.

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



	Three Months Ended March 31,
(millions)	2019			2018
Oil, NGL and Gas Sales to Third Parties	$	937		$	1,173
Sales of Purchased Oil and Gas	14			—
Income from Equity Method Investees	15			35
Total Revenues	966			1,208
Production Expense	351			353
Exploration Expense	24			35
Depreciation, Depletion and Amortization	475			443
Gain on Divestitures, Net	—			(392		)
Asset Impairments	—			168
Cost of Purchased Oil and Gas	14			—
Loss on Commodity Derivative Instruments	212			79
(Loss) Income Before Income Taxes	$	(168	)	$	485

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Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes 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 March 31, 2019
United States	113	59	483	253	$	53.46	$	17.86	$	2.49
Eastern Mediterranean	—	—	233	39	—		—		5.57
West Africa ⁽²⁾	12	—	168	40	61.01		—		0.27
Total Consolidated Operations ⁽³⁾	126	59	884	332	54.19		17.86		2.88
Equity Investees ⁽⁴⁾	1	4	—	5	53.01		36.81		—
Total ⁽³⁾	127	63	884	337	$	54.18	$	19.09	$	2.88
Three Months Ended March 31, 2018
United States ⁽⁵⁾	122	64	504	270	$	61.95	$	25.53	$	2.63
Eastern Mediterranean	—	—	261	44	—		—		5.48
West Africa ⁽²⁾	15	—	206	49	68.14		—		0.27
Total Consolidated Operations	137	64	971	363	62.60		25.53		2.90
Equity Investees ⁽⁴⁾	2	5	—	7	66.08		39.90		—
Total	139	69	971	370	$	62.64	$	26.62	$	2.90

⁽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⁾	Total includes a small amount of condensate sales from the 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 24 MBoe/d related to Gulf of Mexico assets sold in second quarter 2018. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

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 March 31, 2018	$	773		$	146		$	254		$	1,173
Changes due to
Decrease in Sales Volumes	(77		)	(7		)	(27		)	(111		)
(Decrease) Increase in Sales Prices ⁽¹⁾	(84		)	(43		)	2			(125		)
Three Months Ended March 31, 2019	$	612		$	96		$	229		$	937


⁽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 first quarter 2019 as compared with 2018 due to the following:


•	decrease of 12% in average realized prices (see Executive Overview – Operational Environment Update – Commodity Prices);


•	reduction of 19 MBbl/d due to the sale of our Gulf of Mexico assets in second quarter 2018; and


•	lower West Africa sales volumes of 3 MBbl/d due to timing of liftings and natural field decline;

partially offset by:


•	higher US onshore sales volumes of 10 MBbl/d primarily due to an increase in development activity in the Delaware and DJ Basins.

NGL Sales Revenues Revenues from NGL sales decreased in first quarter 2019 as compared with 2018 due to the following:

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•	decrease of 30% in average realized prices (see Executive Overview – Operational Environment Update – Commodity Prices); and


•	lower Eagle Ford Shale sales volumes of 15 MBbl/d due to reduced activity and natural field decline;

partially offset by:


•	higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d due to an increase in development activities.

Natural Gas Sales Revenues Revenues from natural gas sales decreased in first quarter 2019 as compared with 2018 due to the following:


•	lower Eagle Ford Shale sales volumes of 80 MMcf/d due to reduced activity and natural field decline;


•	lower Alba field sales volumes of 38 MMcf/d due to natural field decline and planned maintenance at the onshore facilities, which required field shut-in for a portion of the period;


•	lower Israel sales volumes of 28 MMcf/d primarily due to the sale of a 7.5% interest in the Tamar field in March 2018;


•	reduction of 22 MMcf/d resulting from the sale of the Gulf of Mexico assets; and


•	continued oversupply and reduced take away capacity in the Delaware Basin, resulting in high differentials which depressed our sales prices for the area (see Executive Overview – Operational Environment Update – Commodity Prices);

partially offset by:


•	higher sales volumes in the DJ and Delaware Basins of 81 MMcf/d due to an increase in development activities.

Sales and Cost of Purchased Oil and Gas, Net In first quarter 2019, we engaged in third party sales and purchases of oil and gas in the DJ Basin.

Income from Equity Method Investees Income from equity method investees decreased in first quarter 2019 as compared with 2018. The decrease includes a $10 million decrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and a $10 million decrease from Alba Plant, our LPG investee, primarily due to planned maintenance.

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 March 31, 2019
Lease Operating Expense ⁽³⁾	$	5.32	$	159	$	125	$	10	$	24
Production and Ad Valorem Taxes	1.57		47		47		—		—
Gathering, Transportation and Processing	4.75		142		142		—		—
Other Royalty Expense	0.10		3		3		—		—
Total Production Expense	$	11.74	$	351	$	317	$	10	$	24
Total Production Expense per BOE			$	11.74	$	13.91	$	2.84	$	6.67
Three Months Ended March 31, 2018
Lease Operating Expense ⁽³⁾	$	4.75	$	155	$	126	$	7	$	22
Production and Ad Valorem Taxes	1.62		53		53		—		—
Gathering, Transportation and Processing	3.92		128		128		—		—
Other Royalty Expense	0.52		17		17		—		—
Total Production Expense	$	10.81	$	353	$	324	$	7	$	22
Total Production Expense per BOE			$	10.81	$	13.31	$	1.79	$	5.01


⁽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 first quarter 2019 remained relatively flat as compared with 2018, primarily due to the following:


•	decrease of $25 million in lease operating expense and $6 million in gathering, transportation and processing (GTP) expense due to the sale of our Gulf of Mexico assets;


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

partially offset by:


•	increase of $24 million in lease operating expense and $20 million in GTP expense, primarily due to increased development activities resulting in added production in our DJ and Delaware Basins; and


•	increase in West Africa lease operating expense due to timing of planned maintenance activities.

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The unit rate per BOE increased for first quarter 2019 as compared with 2018, due to the decrease in total sales volumes resulting from the sales of Gulf of Mexico assets in second quarter 2018 and the 7.5% interest in Tamar in March 2018, coupled with an increase in certain production expenses noted above. Specifically, the divestiture of the Gulf of Mexico assets removed higher-cost, crude oil-focused sales volumes, which partially offset the increase in our average production expense per BOE.

Exploration Expense Exploration expense for first quarter 2019 totaled $24 million, including $12 million of staff expense. Exploration expense for first quarter 2018 totaled $35 million, including $13 million of lease rental expense, primarily in the Delaware Basin, and $22 million of staff expense and other.

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 March 31, 2019
DD&A Expense	$	475	$	439	$	16	$	20
Unit Rate per BOE ⁽¹⁾	$	15.89	$	19.27	$	4.55	$	5.56
Three Months Ended March 31, 2018
DD&A Expense	$	443	$	404	$	13	$	26
Unit Rate per BOE ⁽¹⁾	$	13.57	$	16.60	$	3.32	$	5.92


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

DD&A expense for first quarter 2019 increased 7% as compared with 2018, primarily due to the following:


•	higher sales volumes in the DJ and Delaware Basins due to recent development activities; and


•	increase in Eastern Mediterranean due to the impact of the sale of our 7.5% interest in Tamar;

partially offset by:


•	decrease of $27 million resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and


•	decrease in West Africa due to reduced sales volumes as noted above.

The unit rate per BOE for first quarter 2019 increased 17% as compared with 2018, primarily due to the increase in total DD&A expense resulting from increased development activity in the DJ and Delaware Basins, resulting in a higher depletable basis, combined with the sale of lower-cost Tamar reserves. The increase is partially offset by the sale of higher-cost production from the Gulf of Mexico assets in second quarter 2018 and a reduction in rate in West Africa driven by lower sales volumes.

Loss on Commodity Derivative Instruments Loss on commodity derivative instruments for first quarter 2019 increased, as compared with 2018.

For first quarter 2019, loss on commodity derivative instruments included:


•	net cash settlement receipts of $14 million; and


•	net non-cash decrease of $226 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curve for both crude oil and natural gas.

For first quarter 2018, loss on commodity derivative instruments included:


•	net cash settlement payments of $28 million; and


•	net non-cash increase of $51 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.

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

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.

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Recent Transactions

EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed its options to acquire equity interests in EPIC Y-Grade and EPIC Crude Holdings. The assets provide attractive economics and long-term growth potential for Noble Midstream Partners and will provide near-term flow assurance and long-term out-of-basin takeaway capacity for our E&P volumes. The EPIC crude oil pipeline will provide Noble Energy with firm transport of up to 100 MBbl/d from the Delaware Basin to Corpus Christi, Texas. In-service is expected in first quarter 2020; however, EPIC announced it will provide early access to crude oil transportation through the EPIC Y-grade pipeline in third quarter 2019. The EPIC Y-Grade pipeline, also running from the Delaware Basin to Corpus Christi, Texas, will have an NGL throughput capacity of approximately 440 MBbl/d with multiple origin points.

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. The 95-mile pipeline system will originate in Pecos County, Texas, with additional connections in Reeves and Winkler Counties, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of gathering pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to be operational in third quarter 2019.

Results of Operations

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


•	total revenues of $165 million, as compared with $128 million for first quarter 2018;


•	pre-tax income of $73 million, as compared with pre-tax income of $247 million for first quarter 2018;


•	capital expenditures, excluding acquisitions, of $66 million, as compared with $253 million for first quarter 2018; and


•	investments in equity method investees of $271 million, primarily related to investments in EPIC Y-Grade and EPIC Crude Holdings, as compared with zero for first quarter 2018.

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



	Three Months Ended March 31,
(millions)	2019		2018
Midstream Services Revenues – Third Party	$	24	$	13
Sales of Purchased Oil	33		22
Income from Equity Method Investees	2		12
Intersegment Revenues	106		81
Total Revenues	165		128
Operating Costs and Expenses	36		39
Depreciation, Depletion and Amortization	25		17
Gain on Divestitures, Net	—		(196		)
Cost of Purchased Oil	31		21
Total Expense (Income)	92		(119		)
Income Before Income Taxes	$	73	$	247

Revenues 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.

Total revenues for first quarter 2019 increased as compared with 2018, primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. This increase was due primarily to an increase in 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 of purchased crude oil also increased due to a full quarter of services related to the Black Diamond system.

Operating Costs and Expenses Operating costs and expenses for first quarter 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.

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DD&A Expense DD&A expense for first quarter 2019 increased as compared with 2018, primarily due to certain assets being placed in service subsequent to first 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 of amortization related to intangible assets acquired in the Saddle Butte Acquisition.

Cost of Purchased Oil Cost of purchased crude oil for first quarter 2019 increased as compared with 2018 due to a full quarter of services related to the Black Diamond system.

RESULTS OF OPERATIONS – CORPORATE

Our Corporate costs include exit costs, certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements and expenses related to debt, headquarters depreciation, and corporate general and administrative expenses.

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



	Three Months Ended March 31,
(millions)	2019		2018
Sales of Purchased Gas ⁽¹⁾	$	27	$	31
Cost of Purchased Gas ⁽¹⁾	42		36
Firm Transportation Exit Cost⁽²⁾	92		—


⁽¹⁾	Relates to third party mitigation activities which we engage in to utilize a portion of our Marcellus Shale firm commitment.


⁽²⁾	Represents exit costs related to future commitments to a third party resulting from a permanent pipeline 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 March 31,
(millions, except unit rate)	2019		2018
G&A Expense	$	102	$	104
Unit Rate per BOE ⁽¹⁾	$	3.41	$	3.18


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

G&A expense for first quarter 2019 remained relatively flat as compared with 2018 primarily due to decreases in third party transaction-related fees, offset by increases in employee costs. The increase in the unit rate per BOE for first quarter 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 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 March 31,
(millions, except unit rate)	2019			2018
Interest Expense, Gross	$	87		$	90
Capitalized Interest	(21		)	(17		)
Interest Expense, Net	$	66		$	73
Unit Rate per BOE ⁽¹⁾	$	2.21		$	2.24


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

Interest expense, gross, for first quarter 2019 remained flat as compared with 2018. Lower interest rates applicable to the Noble Midstream Partners Revolving Credit Facility were offset by interest expense related to the Noble Midstream Services Term Loan Credit Facility which commenced in third quarter 2018. See Item 1. Financial Statements – Note 7. Debt.

Capitalized interest for first quarter 2019 increased as compared with 2018, primarily due to higher work in progress amounts related to the Leviathan development.

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The unit rate of interest expense, net, per BOE for first quarter 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. See Results of Operations – Exploration & Production.

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 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. In first quarter 2019, we established a $4.0 billion commercial paper program, which can be accessed as needed to supplement operating cash flows for short-term funding needs. 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. We also 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, 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 first quarter 2019.

As of March 31, 2019, our consolidated outstanding debt (excluding finance lease obligations) totaled $6.6 billion. We may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in 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.

First Quarter and Year-to-Date 2019 Highlights

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


•	established a $4.0 billion commercial paper program, supported by Noble Energy’s Revolving Credit Facility; and


•	secured the $200 million GIP preferred equity commitment for Noble Midstream Partners, with $100 million funded during the quarter.

Available Liquidity

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



(millions, except percentages)	March 31, 2019			December 31, 2018
Total Cash ⁽¹⁾	$	530		$	719
Amount Available to be Borrowed Under Revolving Credit Facility ⁽²⁾	4,000			4,000
Total Liquidity	$	4,530		$	4,719
Total Debt ⁽³⁾	$	6,837		$	6,675
Noble Energy Share of Equity	9,071			9,426
Ratio of Debt-to-Book Capital ⁽⁴⁾	43		%	41		%


⁽¹⁾	As of March 31, 2019, total cash includes cash and cash equivalents of $10 million related to Noble Midstream Partners and $2 million of restricted cash. As of December 31, 2018, total cash includes cash and cash equivalents of $11 million related to Noble Midstream Partners and $3 million of restricted cash.


⁽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 includes long-term finance lease obligations and excludes unamortized debt discount/premium and debt issuance costs. Additionally, it includes Noble Midstream Partners' debt of $730 million and $560 million as of March 31, 2019 and December 31, 2018, respectively. See Item 1. Financial Statements – Note 7. Debt.

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

Cash and Cash Equivalents We had approximately $528 million in cash and cash equivalents at March 31, 2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $361 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 Revolving Credit Facility of $4.0 billion and the Noble Midstream Services Revolving Credit Facility of $800 million both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At March 31, 2019, no amounts were outstanding under the Noble Energy Revolving Credit Facility and $230 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $4.0 billion and $570 million in remaining availability under the respective facilities.

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 March 31, 2019, no commercial paper was outstanding. See Item 1. Financial Statements – Note 7. Debt.

GIP Preferred Equity Commitment On March 25, 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 $1.1 billion, undiscounted, associated with Marcellus Shale firm transportation contracts. See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.

Credit Rating Events We do not have any triggering events on our consolidated debt that would cause a default in case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.

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 $100 million at March 31, 2019.

Cash Flows

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



	Three Months Ended March 31,
(millions)	2019			2018
Operating Activities	$	528		$	583
Investing Activities	(911		)	(572		)
Financing Activities	194			298
(Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	$	(189	)	$	309

Operating Activities Cash provided by operating activities for first quarter 2019 decreased $55 million as compared with 2018, primarily due to a decrease in net revenues driven by declining crude oil and NGL sales prices, partially offset by higher production costs attributable to increased operational activity and rising costs in US onshore. In addition, we received cash in settlements for commodity derivatives of $14 million, as compared with cash payments of $28 million in the prior year.

Investing Activities Cash used in investing activities increased $339 million for first quarter 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, in first quarter 2019, Noble Midstream Partners' invested $271 million on equity

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method investees compared to none in prior year. Finally, there were no acquisitions in first quarter 2019 compared to $650 million in prior year. See Operating Outlook – 2019 Capital Investment Program.

Financing Activities Our financing activities during first quarter 2019 include net borrowings of $170 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 first quarter 2019, we paid $53 million of cash dividends to Noble Energy shareholders.

Our financing activities during first quarter 2018 included a net repayment of $230 million on the Revolving Credit Facility and net borrowings of $350 million on the Noble Midstream Services Revolving Credit Facility used primarily to fund the Saddle Butte acquisition. In addition, we made common stock repurchases totaling $67 million pursuant to our share repurchase program and paid $48 million of cash dividends to Noble Energy shareholders.

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

Capital Expenditure Activities

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



	Three Months Ended March 31,
(millions)	2019		2018
Unproved Property Acquisition ⁽¹⁾	$	35	$	4
Proved Property Acquisition ⁽¹⁾	4		—
Exploration and Development	628		652
Midstream⁽²⁾	66		459
Corporate and Other	18		11
Total	$	751	$	1,126
Other
Investment in Equity Method Investees ⁽³⁾	$	271	$	—
Increase in Finance Lease Obligations	2		—


⁽¹⁾	Costs for first quarter 2019 relate to US onshore leasehold activity.


⁽²⁾	Midstream expenditures for first quarter 2018 include $206 million related to the Saddle Butte Acquisition.


⁽³⁾	Costs include primarily Noble Midstream Partners' $227 million investment in EPIC Y-Grade and EPIC Crude Holdings and $38 million investment in Delaware Crossing. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.

Exploration and development costs for first quarter 2019 decreased as compared with 2018, due to our focus on US onshore capital efficiencies and the near-term completion of Leviathan development activities. Exploration and development costs include approximately $487 million for US onshore and $132 million for Eastern Mediterranean, primarily related to Leviathan.

Midstream capital spending, excluding acquisitions, for first quarter 2019 decreased as compared with 2018. First quarter 2019 activities focused primarily on well connections in the Mustang IDP and Black Diamond system while 2018 activities included construction of 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 April 22, 2019, our Board of Directors declared a quarterly cash dividend of 12 cents per Noble Energy common share, which will be paid on May 20, 2019 to shareholders of record on May 6, 2019. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Derivative Instruments Held for Non-Trading Purposes At March 31, 2019, our open commodity derivative instruments were in a net liability position with a fair value of $73 million. Based on the March 31, 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 $508 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 March 31, 2019 total $730 million and have a weighted average interest rate of 3.49%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. While we currently have no interest rate derivative instruments as of March 31, 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 first quarter 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 projects 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

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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.

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)
1/1/2019 - 1/31/2019	933	$	20.68	—
2/1/2019 - 2/28/2019	217,821	22.54		—
3/1/2019 - 3/31/2019	902	24.65		—
Total	219,656	$	22.54	—	$	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 first quarter 2019, we did not repurchase shares under the $750 million share repurchase program, authorized by the Board of Directors, 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 herewith.

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 herewith.

10.3*		Form of Option Award Notice and Agreement under the Noble Energy, Inc. 2017 Long-Term Incentive Plan, filed herewith.

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 herewith.

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 herewith.

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 filed as an exhibit hereto.

Table of Contents

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	May 3, 2019	By: /s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer