NOBLE ENERGY INC - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - NOBLE ENERGY INC	nbl-20170331x10qxex322.htm
EX-32.1 - EXHIBIT 32.1 - NOBLE ENERGY INC	nbl-20170331x10qxex321.htm
EX-31.2 - EXHIBIT 31.2 - NOBLE ENERGY INC	nbl-20170331x10qxex312.htm
EX-31.1 - EXHIBIT 31.1 - NOBLE ENERGY INC	nbl-20170331x10qxex311.htm
EX-12.1 - EXHIBIT 12.1 - NOBLE ENERGY INC	nbl-20170331x10qxex121.htm
EX-10.9 - EXHIBIT 10.9 - NOBLE ENERGY INC	nbl-20170331x10qxex109.htm
EX-10.8 - EXHIBIT 10.8 - NOBLE ENERGY INC	nbl-20170331x10qxex108.htm
EX-10.7 - EXHIBIT 10.7 - NOBLE ENERGY INC	nbl-20170331x10qxex107.htm
EX-10.6 - EXHIBIT 10.6 - NOBLE ENERGY INC	nbl-20170331x10qxex106.htm
EX-10.5 - EXHIBIT 10.5 - NOBLE ENERGY INC	nbl-20170331x10qxex105.htm

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, 2017

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes 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
		(Do not check if a smaller reporting company)

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

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

Yes o No ý

As of March 31, 2017, there were 431,414,543 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS



Part I. Financial Information	3

Item 1. Financial Statements	3

Consolidated Statements of Operations and Comprehensive Income (Loss)	3

Consolidated Balance Sheets	4

Consolidated Statements of Cash Flows	5

Consolidated Statements of Equity	6

Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3. Quantitative and Qualitative Disclosures About Market Risk	37

Item 4. Controls and Procedures	38

Part II. Other Information	39

Item 1. Legal Proceedings	39

Item 1A. Risk Factors	39

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 3. Defaults Upon Senior Securities	40

Item 4. Mine Safety Disclosures	40

Item 5. Other Information	40

Item 6. Exhibits	40

Signatures	41

Index to Exhibits	42

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(millions, except per share amounts)

(unaudited)



	Three Months Ended March 31,
	2017			2016
Revenues
Oil, NGL and Gas Sales	$	994		$	705
Income from Equity Method Investees	42			19
Total	1,036			724
Costs and Expenses
Production Expense	303			276
Exploration Expense	42			163
Depreciation, Depletion and Amortization	528			617
General and Administrative	99			91
Other Operating Expense, Net	29			(1		)
Total	1,001			1,146
Operating Income (Loss)	35			(422		)
Other Expense (Income)
Gain on Commodity Derivative Instruments	(110		)	(44		)
Interest, Net of Amount Capitalized	87			79
Other Non-Operating Income, Net	(1		)	(4		)
Total	(24		)	31
Income (Loss) Before Income Taxes	59			(453		)
Income Tax Provision (Benefit)	12			(166		)
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests	47			(287		)
Less: Net Income and Comprehensive Income (Loss) Attributable to Noncontrolling Interests	11			—
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	36		$	(287	)

Net Income (Loss) Attributable to Noble Energy Per Share of Common Stock
Basic	$	0.08		$	(0.67	)
Diluted	$	0.08		$	(0.67	)

Weighted Average Number of Shares Outstanding
Basic	431			429
Diluted	434			429

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

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Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)



	March 31, 2017				December 31, 2016
ASSETS
Current Assets
Cash and Cash Equivalents	$	787			$	1,180
Accounts Receivable, Net	523				615
Other Current Assets	135				160
Total Current Assets	1,445				1,955
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	31,301				30,355
Property, Plant and Equipment, Other	907				909
Total Property, Plant and Equipment, Gross	32,208				31,264
Accumulated Depreciation, Depletion and Amortization	(13,180		)		(12,716		)
Total Property, Plant and Equipment, Net	19,028				18,548
Other Noncurrent Assets	535				508
Total Assets	$	21,008			$	21,011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	895			$	736
Other Current Liabilities	598				742
Total Current Liabilities	1,493				1,478
Long-Term Debt	6,995				7,011
Deferred Income Taxes	1,819				1,819
Other Noncurrent Liabilities	1,092				1,103
Total Liabilities	11,399				11,411
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued	—				—
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 473 Million and 471 Million Shares Issued, respectively	5				5
Additional Paid in Capital	6,472				6,450
Accumulated Other Comprehensive Loss	(31		)		(31		)
Treasury Stock, at Cost; 38 Million Shares	(703		)		(692		)
Retained Earnings	3,549				3,556
Noble Energy Share of Equity	9,292				9,288
Noncontrolling Interests	317			—	312
Total Equity	9,609				9,600
Total Liabilities and Equity	$	21,008			$	21,011

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

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Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)



	Three Months Ended March 31,
	2017			2016
Cash Flows From Operating Activities
Net Income (Loss) Including Noncontrolling Interests	$	47		$	(287	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	528			617
Dry Hole Cost	—			93
Gain on Extinguishment of Debt	—			(80		)
Deferred Income Tax Benefit	—			(186		)
Gain on Commodity Derivative Instruments	(110		)	(44		)
Net Cash Received in Settlement of Commodity Derivative Instruments	3			178
Other Adjustments for Noncash Items Included in Income	20			96
Changes in Operating Assets and Liabilities
Decrease (Increase) in Accounts Receivable	59			(38		)
Increase (Decrease) in Accounts Payable	45			(24		)
(Decrease) in Current Income Taxes Payable	(23		)	(16		)
Other Current Assets and Liabilities, Net	(35		)	(64		)
Other Operating Assets and Liabilities, Net	2			6
Net Cash Provided by Operating Activities	536			251
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(587		)	(496		)
Asset Acquisition	(316		)	—
Proceeds from Divestitures and Other	40			232
Net Cash Used in Investing Activities	(863		)	(264		)
Cash Flows From Financing Activities
Dividends Paid, Common Stock	(44		)	(41		)
Proceeds from Term Loan Facility	—			1,400
Repayment of Senior Notes	—			(1,383		)
Other	(22		)	(38		)
Net Cash Used in Financing Activities	(66		)	(62		)
Decrease in Cash and Cash Equivalents	(393		)	(75		)
Cash and Cash Equivalents at Beginning of Period	1,180			1,028
Cash and Cash Equivalents at End of Period	$	787		$	953

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

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Noble Energy, Inc.

Consolidated Statements of 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, 2016	$	5	$	6,450		$	(31	)	$	(692	)	$	3,556		$	312		$	9,600
Net Income	—		—			—			—			36			11			47
Stock-based Compensation	—		13			—			—			—			—			13
Dividends (10 cents per share)	—		—			—			—			(44		)	—			(44		)
Distribution to Noncontrolling Interest Owners	—		—			—			—			—			(6		)	(6		)
Other	—		9			—			(11		)	1			—			(1		)
March 31, 2017	$	5	$	6,472		$	(31	)	$	(703	)	$	3,549		$	317		$	9,609

December 31, 2015	$	5	$	6,360		$	(33	)	$	(688	)	$	4,726		$	—		$	10,370
Net Loss	—		—			—			—			(287		)	—			(287		)
Stock-based Compensation	—		19			—			—			—			—			19
Dividends (10 cents per share)	—		—			—			—			(41		)	—			(41		)
Other	—		(1		)	—			(8		)	—			—			(9		)
March 31, 2016	$	5	$	6,378		$	(33	)	$	(696	)	$	4,398		$	—		$	10,052

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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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 operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale; offshore US Gulf of Mexico; Eastern Mediterranean; and West Africa.

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, 2017 and December 31, 2016 and for the three months ended March 31, 2017 and 2016 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is identical to comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.

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, 2016.

Consolidation Our consolidated accounts 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.

Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.

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.

Recently Issued Accounting Standards

Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. At this time, we can not reasonably estimate the financial impact this ASU will have on our financial statements; however, we do believe adoption and implementation of this ASU will likely materially impact our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation.

Business Combinations - Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations - Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of business transactions, which take more time and cost more than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition (defined below) will not be impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption in 2018.

Financial Instruments - Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses, which replaces the incurred loss impairment methodology in current US GAAP 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 guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures.

Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. Based upon our evaluation of the ASU and our analysis to-date, we have not identified any material impact on our financial statements other than enhanced disclosures.

Statement of Cash Flows - Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows - Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures.

Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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



	Three Months Ended March 31,
(millions)	2017			2016
Production Expense
Lease Operating Expense	$	139		$	161
Production and Ad Valorem Taxes ⁽¹⁾	45			4
Gathering, Transportation and Processing Expense ⁽²⁾	119			111
Total	$	303		$	276
Other Operating (Income) Expense, Net
Marketing Expense ⁽³⁾	$	19		$	18
Gain on Extinguishment of Debt ⁽⁴⁾	—			(80		)
Loss on Asset Due to Terminated Contract ⁽⁵⁾	4			42
Other, Net	6			19
Total	$	29		$	(1	)
Other Non-Operating Expense (Income), Net
Other Income, Net	(1		)	(4		)
Total	$	(1	)	$	(4	)


⁽¹⁾	For first quarter 2017, total production expense increased as compared with 2016 due to higher production taxes associated with higher realized commodity prices, as well as a $28 million US onshore severance tax refund recorded in first quarter 2016 and a $7 million US onshore severance tax charge recorded in first quarter 2017.

⁽²⁾

Certain of our processing expense was historically presented as a component of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect processing expense as a component of production expense. These costs are now included within gathering, transportation and processing expense. For the three month period ended March 31, 2017, these costs totaled $3 million, and the prior year amount of $4 million for the three months ended March 31, 2016 has been reclassified from marketing expense to conform to the current presentation.


⁽³⁾	Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.


⁽⁴⁾	Amount relates to the tendering of senior notes. See Note 6. Debt.


⁽⁵⁾	Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Balance Sheet Information Other balance sheet information is as follows:



(millions)	March 31, 2017			December 31, 2016
Accounts Receivable, Net
Commodity Sales	$	362		$	403
Joint Interest Billings	119			106
Proceeds Receivable ⁽¹⁾	—			40
Other	63			86
Allowance for Doubtful Accounts	(21		)	(20		)
Total	$	523		$	615
Other Current Assets
Inventories, Materials and Supplies	$	71		$	71
Inventories, Crude Oil	21			18
Restricted Cash ⁽²⁾	—			30
Prepaid Expenses and Other Current Assets	43			41
Total	$	135		$	160
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries	$	407		$	400
Mutual Fund Investments	74			71
Other Assets	54			37
Total	$	535		$	508
Other Current Liabilities
Production and Ad Valorem Taxes	$	116		$	115
Commodity Derivative Liabilities	23			102
Income Taxes Payable	30			53
Asset Retirement Obligations	160			160
Interest Payable	93			76
Current Portion of Capital Lease Obligations	66			63
Other	110			173
Total	$	598		$	742
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	215		$	218
Asset Retirement Obligations	772			775
Production and Ad Valorem Taxes	61			47
Other	44			63
Total	$	1,092		$	1,103


⁽¹⁾	Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017.


⁽²⁾	Balance at December 31, 2016 represented amount held in escrow for the purchase of certain Delaware Basin properties. The transaction closed in first quarter 2017. See Note 4. Acquisitions and Divestitures.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 3. Clayton Williams Energy Acquisition

In January 2017, we announced the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) which was approved by Clayton Williams Energy stockholders on April 24, 2017. On April 24, 2017, subsequent to first quarter 2017, we completed the acquisition which increases our Southern Delaware position to approximately 118,000 net acres.

The acquisition was effected through the issuance of approximately 55 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion, and cash consideration of $665 million, for total consideration of approximately $2.6 billion, in exchange for all outstanding shares of Clayton Williams Energy, including options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. The results of Clayton Williams Energy's operations will be included in our consolidated statements of operations beginning April 24, 2017.

We will account for the transaction as a business combination, using the acquisition method. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final reserve reports and operating information for the properties acquired, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the allocation, including any goodwill, will be revised if necessary.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 4. Acquisitions and Divestitures

US Onshore Properties

2017 Asset Transactions In first quarter 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. The acquisition included seven producing wells, of which four are operated by us.

2016 Asset Transactions In first quarter 2016, we sold certain US onshore crude oil and natural gas properties, generating net proceeds of $20 million. Proceeds were primarily applied to the basis of the DJ Basin field, with no recognition of gain or loss.

Subsequent Event On May 1, 2017, we entered into a purchase and sale agreement for the divestiture of all of our upstream assets in the Marcellus Shale for approximately $1.2 billion. We expect to receive approximately $1.1 billion of cash proceeds at closing. With an effective date of January 1, 2017, the transaction includes contingent consideration of up to $100 million based on future commodity price thresholds and is subject to customary sales price adjustments.

The aggregate net book value of properties being sold was approximately $3.3 billion as of March 31, 2017. As a result, we expect to recognize an estimated loss of approximately $2.2 billion during second quarter 2017. In addition, we expect to record a loss for exit costs associated with certain operating leases, including firm transportation agreements that will be retained after the transaction closes.

The transaction is anticipated to close in second quarter 2017 and we plan to use the proceeds from the transaction to repay indebtedness under our Revolving Credit Facility. Our interest in CONE Midstream Partners, LP, a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in support of Marcellus Shale activities, is not included in this transaction.

Cyprus Project (Offshore Cyprus) In first quarter 2017, we received the remaining $40 million consideration for the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery. Proceeds received, including $131 million in first quarter 2016, were applied to the Cyprus project asset with no gain or loss recognized.

Offshore Israel Assets In first quarter 2016, we closed the divestment of our 47% interest in the Alon A and Alon C licenses, which include the Karish and Tanin fields, for a total sales price of $73 million ($67 million for asset consideration and $6 million for cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.

Note 5. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil, natural gas and natural gas liquids pricing. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.

While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 7. 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

Unsettled Commodity Derivative Instruments As of March 31, 2017, the following crude oil derivative contracts were outstanding:



				Swaps		Collars
Settlement Period	Type of Contract	Index	Bbls Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
1H17⁽²⁾	Swaps	NYMEX WTI	6,000	$	55.08	$	—	$	—	$	—
1H17⁽²⁾	Two-Way Collars	NYMEX WTI	2,000	—		—		40.00		50.44
1H17⁽²⁾	Swaps	Dated Brent	3,000	62.80		—		—		—
2H17 ⁽²⁾	Call Option ⁽¹⁾	NYMEX WTI	3,000	—		—		—		60.12
2H17 ⁽²⁾	Swaptions ⁽³⁾	Dated Brent	3,000	62.80		—		—		—
2H17 ⁽²⁾	Swaptions ⁽³⁾	NYMEX WTI	3,000	50.05		—		—		—
2017	Two-Way Collars	NYMEX WTI	7,000	—		—		40.00		53.38
2017	Call Option ⁽¹⁾	NYMEX WTI	3,000	—		—		—		57.00
2017	Swaps	NYMEX WTI	4,000	50.90		—		—		—
2017	Three-Way Collars	NYMEX WTI	24,000	—		39.08		47.71		61.20
2017	Three-Way Collars	Dated Brent	2,000	—		35.00		45.00		66.33
2017	Three-Way Collars	ICE Brent	2,000	—		43.00		50.00		63.15
2018	Three-Way Collars	NYMEX WTI	10,000	—		45.50		52.50		69.09
2018	Swaptions ⁽³⁾	NYMEX WTI	3,000	56.10		—		—		—
2018	Three-Way Collars	Dated Brent	3,000	—		40.00		50.00		70.41


⁽¹⁾	We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms.


⁽²⁾	We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year.


⁽³⁾	We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

As of March 31, 2017, the following natural gas derivative contracts were outstanding:



				Swaps		Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day	Weighted Average Fixed Price		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
1H17	Swaps	NYMEX HH	30,000	$	2.92	$	—	$	—	$	—
2H17	Swaps	NYMEX HH	30,000	3.45		—		—		—
2H17	Swaptions ⁽¹⁾	NYMEX HH	30,000	2.92		—		—		—
2017	Swaps	NYMEX HH	110,000	3.19		—		—		—
2017	Three-Way Collars	NYMEX HH	210,000	—		2.54		2.96		3.62
2017	Two-Way Collars	NYMEX HH	70,000	—		—		2.93		3.32
2018	Three-Way Collars	NYMEX HH	110,000	—		2.50		2.87		3.67


⁽¹⁾	We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.

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



	Fair Value of Derivative Instruments
	Asset Derivative Instruments						Liability Derivative Instruments
	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments	Current Assets	$	6	Current Assets	$	—	Current Liabilities	$	23	Current Liabilities	$	102
	Noncurrent Assets	8		Noncurrent Assets	—		Noncurrent Liabilities	—		Noncurrent Liabilities	14
Total		$	14		$	—		$	23		$	116

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



	Three Months Ended March 31,
(millions)	2017			2016
Cash Paid (Received) in Settlement of Commodity Derivative Instruments
Crude Oil	$	(5	)	$	(156	)
Natural Gas	2			(22		)
Total Cash Received in Settlement of Commodity Derivative Instruments	(3		)	(178		)
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
Crude Oil	(63		)	127
Natural Gas	(44		)	7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments	(107		)	134
Gain on Commodity Derivative Instruments
Crude Oil	(68		)	(29		)
Natural Gas	(42		)	(15		)
Total Gain on Commodity Derivative Instruments	$	(110	)	$	(44	)

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 6. Debt

Debt consists of the following:



	March 31, 2017					December 31, 2016
(millions, except percentages)	Debt			Interest Rate		Debt			Interest Rate
Revolving Credit Facility, due August 27, 2020	$	—		—	%	$	—		—	%
Noble Midstream Services Revolving Credit Facility, due September 20, 2021	—			—	%	—			—	%
Term Loan Facility, due January 6, 2019	550			2.20	%	550			2.01	%
Leviathan Term Loan Facility, due February 23, 2025	—			—	%	—			—	%
8.25% Senior Notes, due March 1, 2019	1,000			8.25	%	1,000			8.25	%
5.625% Senior Notes, due May 1, 2021	379			5.625	%	379			5.625	%
4.15% Senior Notes, due December 15, 2021	1,000			4.15	%	1,000			4.15	%
5.875% Senior Notes, due June 1, 2022	18			5.875	%	18			5.875	%
7.25% Senior Notes, due October 15, 2023	100			7.25	%	100			7.25	%
5.875% Senior Notes, due June 1, 2024	8			5.875	%	8			5.875	%
3.90% Senior Notes, due November 15, 2024	650			3.90	%	650			3.90	%
8.00% Senior Notes, due April 1, 2027	250			8.00	%	250			8.00	%
6.00% Senior Notes, due March 1, 2041	850			6.00	%	850			6.00	%
5.25% Senior Notes, due November 15, 2043	1,000			5.25	%	1,000			5.25	%
5.05% Senior Notes, due November 15, 2044	850			5.05	%	850			5.05	%
7.25% Senior Debentures, due August 1, 2097	84			7.25	%	84			7.25	%
Capital Lease and Other Obligations	361			—	%	375			—	%
Total	7,100					7,114
Unamortized Discount	(22		)			(23		)
Unamortized Premium	15					17
Unamortized Debt Issuance Costs	(32		)			(34		)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	7,061					7,074
Less Amounts Due Within One Year
Capital Lease Obligations	(66		)			(63		)
Long-Term Debt Due After One Year	$	6,995				$	7,011

Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating.

Noble Midstream Services Revolving Credit Facility In 2016, Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility) which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.

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

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

Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025 and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.

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

The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries.

Term Loan Agreement and Completed Tender Offers In 2016, we entered into a term loan agreement (Term Loan Facility) which provides for a three-year term loan facility for a principal amount of $1.4 billion. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) LIBOR plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) LIBOR plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating.

Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in the Rosetta Merger. As a result, we recognized a gain of $80 million in first quarter 2016 which is reflected in other operating (income) expense, net in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. As of March 31, 2017, $550 million was outstanding under the facility.

Subsequent Event On April 24, 2017, we borrowed $1.3 billion under our Revolving Credit Facility in connection with the Clayton Williams Energy Acquisition. The interest rate on our Revolving Credit Facility is a floating interest rate and was 2.0% on April 24, 2017.

See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Note 7. Fair Value Measurements and Disclosures

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

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

Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and enhanced swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 5. Derivative Instruments and Hedging Activities.

Deferred Compensation Liability The 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.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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 as of the end of each reporting period.

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



	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1) ⁽¹⁾			Significant Other Observable Inputs (Level 2) ⁽²⁾			Significant Unobservable Inputs (Level 3) ⁽³⁾		Adjustment ⁽⁴⁾			Fair Value Measurement
(millions)
March 31, 2017
Financial Assets
Mutual Fund Investments	$	74					$	—	$	—		$	74
Commodity Derivative Instruments	—			23			—		(9		)	14
Financial Liabilities
Commodity Derivative Instruments	—			(32		)	—		9			(23		)
Portion of Deferred Compensation Liability Measured at Fair Value	(89		)	—			—		—			(89		)
Stock Based Compensation Liability Measured at Fair Value	(10		)	—			—		—			(10		)
December 31, 2016
Financial Assets
Mutual Fund Investments	$	71		$	—		$	—	$	—		$	71
Commodity Derivative Instruments	—			5			—		(5		)	—
Financial Liabilities
Commodity Derivative Instruments	—			(121		)	—		5			(116		)
Portion of Deferred Compensation Liability Measured at Fair Value	(88		)	—			—		—			(88		)
Stock Based Compensation Liability Measured at Fair Value	(9		)	—			—		—			(9		)


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


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


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


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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities such as inventory, assets, and assets held for sale are measured at fair value on a nonrecurring basis in our consolidated balance sheets. For the three months ended March 31, 2017 and 2016, we had no adjustments in fair value related to these items.

Additional Fair Value Disclosures

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

Our Term Loan Facility is variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of our Term Loan Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Fair value information regarding our debt is as follows:



	March 31, 2017				December 31, 2016
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt, Net ⁽¹⁾	$	6,700	$	7,200	$	6,699	$	7,112


⁽¹⁾	Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

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

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



(millions)	Three Months Ended March 31, 2017
Capitalized Exploratory Well Costs, Beginning of Period	$	768
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	6
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves ⁽¹⁾	(203		)
Capitalized Exploratory Well Costs, End of Period	$	571


⁽¹⁾	Amount relates to the approval and sanction of the first phase of development of the Leviathan field offshore Israel. Initial Leviathan field proved reserves are expected to be recorded in 2017.

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



(millions)	March 31, 2017		December 31, 2016
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	58	$	69
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling ⁽¹⁾	513		699
Balance at End of Period	$	571	$	768


⁽¹⁾	The decrease from December 31, 2016 is attributable to the reclassification of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells.

Undeveloped Leasehold Costs

Undeveloped leasehold costs as of March 31, 2017 totaled $2.3 billion, primarily comprised of $2.2 billion related to US onshore unproved properties. These costs were derived from allocated fair values as a result of a business combination or other purchase of unproved properties and, in that the properties are primarily held by production, they are subject to impairment testing utilizing a future cash flows analysis.

The remaining undeveloped leasehold costs as of March 31, 2017 included $86 million related to Gulf of Mexico unproved properties and $52 million related to international unproved properties. These costs are evaluated as part of our periodic impairment review. If, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective leases.

During first quarter 2017, we completed a geological evaluation of certain deepwater Gulf of Mexico leases and determined that $18 million of undeveloped leasehold cost should be written-off.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 9. 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)	2017			2016
Asset Retirement Obligations, Beginning Balance	$	935		$	989
Liabilities Incurred	1			2
Liabilities Settled	(9		)	(8		)
Revision of Estimate	(7		)	5
Accretion Expense ⁽¹⁾	12			12
Asset Retirement Obligations, Ending Balance	$	932		$	1,000


⁽¹⁾	Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations.

For the three months ended March 31, 2017 Liabilities incurred were due to new wells and facilities placed into service for US onshore. Liabilities settled primarily related to US onshore property abandonments. Revisions of estimates related to changes in cost estimates of $7 million for deepwater Gulf of Mexico.

For the three months ended March 31, 2016 Liabilities incurred were due to new wells and facilities for US onshore. Liabilities settled primarily related to US onshore property abandonments. Revisions of estimates relate to changes in cost estimates of $5 million for Equatorial Guinea.

Note 10. Income (Loss) Per Share Attributable to Noble Energy

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



	Three Months Ended March 31,
(millions, except per share amounts)	2017		2016
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy	$	36	$	(287	)

Weighted Average Number of Shares Outstanding, Basic	431		429
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust ⁽¹⁾	3		—
Weighted Average Number of Shares Outstanding, Diluted	434		429
Income (Loss) Per Share, Basic	$	0.08	$	(0.67	)
Income (Loss) Per Share, Diluted	0.08		(0.67		)
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14		15


⁽¹⁾	For first quarter 2016, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as the Company incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 11. Income Taxes

The income tax provision (benefit) consists of the following:



	Three Months Ended March 31,
(millions)	2017			2016
Current	$	12		$	20
Deferred	—			(186		)
Total Income Tax Provision (Benefit)	$	12		$	(166	)
Effective Tax Rate	20.3		%	36.6		%

Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR) to current year earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the three months ended March 31, 2017, varied as compared with the three months ended March 31, 2016, primarily due to:


•	income before income taxes for first quarter 2017 as compared with a loss before income taxes for first quarter 2016; and


•	discrete items with a disproportionate impact to the rate due to lower earnings during first quarter 2017.

Our deferred income tax provision for first quarter 2017 had a de minimis impact which was attributable to the deferred tax expense created by non-cash increases in the fair value of our commodity derivative instruments, offset by the expected deferred tax benefit.

In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2013, Equatorial Guinea – 2011 and Israel – 2015.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 12. Segment Information

We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States (which includes consolidated accounts of Noble Midstream Partners); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); and Other International and Corporate. Other International includes Falkland Islands, Suriname, Newfoundland and new ventures.



(millions)	Consolidated			United States			Eastern Mediterranean		West Africa			Other Int'l & Corporate
Three Months Ended March 31, 2017
Revenues from Third Parties	$	994		$	770		$	131	$	93		$	—
Income from Equity Method Investees	42			14			—		28			—
Total Revenues	1,036			784			131		121			—
DD&A	528			463			19		34			12
Gain on Commodity Derivative Instruments	(110		)	(102		)	—		(8		)	—
Income (Loss) Before Income Taxes	59			96			101		66			(204		)

Three Months Ended March 31, 2016
Revenues from Third Parties	$	705		$	489		$	126	$	90		$	—
Income from Equity Method Investees	19			16			—		3			—
Total Revenues	724			505			126		93			—
DD&A	617			530			20		55			12
Gain on Commodity Derivative Instruments	(44		)	(37		)	—		(7		)	—
Income (Loss) Before Income Taxes	(453		)	(292		)	84		9			(254		)

March 31, 2017
Total Assets	$	21,008		$	16,997		$	2,391	$	1,401		$	219
December 31, 2016
Total Assets	21,011			17,029			2,233		1,479			270

Note 13. 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, 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 was entered by the court on June 2, 2015.

The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities and to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief 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.

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

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

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

Colorado Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. The COC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. At present, the COC seeks payment of a reduced penalty of $123,500, of which up to 80% may be mitigated by pursuing a supplemental environment project or projects. Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.

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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; 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

We are a globally diversified explorer and producer of crude oil, natural gas and natural gas liquids (NGLs). We endeavor to maintain a high-quality portfolio of assets that are well-positioned on the global industry cost supply curve and offer growth at attractive financial returns. Our operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale; offshore US Gulf of Mexico; Eastern Mediterranean; and West Africa.

Our portfolio is further complemented through the pursuit of certain exploration opportunities as we seek to establish potential new areas, such as Suriname, Gabon and Newfoundland. For 2017, we anticipate engaging in seismic acquisition and processing and potentially drilling an exploratory well offshore Suriname.

The following discussion highlights significant operating and financial results for first quarter 2017. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

First Quarter 2017 Significant Operating Highlights Included:


•	total average daily sales volumes of 382 MBoe/d, net;


•	first quarter average daily sales volume record of 274 MMcfe/d, net, in Israel, primarily reflecting increased use of natural gas over coal to fuel power generation;


•	executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc., which adds highly contiguous acreage in the core of the Southern Delaware Basin (and which closed on April 24, 2017);


•	closed a bolt-on acquisition of certain Delaware Basin properties for $301 million in cash;


•	sanctioned and commenced the first phase of development activities at Leviathan, our third major natural gas project offshore Israel;


•	completed drilling activities at the Tamar 8 development well, offshore Israel; and


•	exported natural gas from the Tamar field to Jordan, marking a significant milestone in Israel's natural gas development.

First Quarter 2017 Financial Results Included:


•	net income of $36 million, as compared with net loss of $287 million for first quarter 2016;


•	net gain on commodity derivative instruments of $110 million, as compared with net gain on commodity derivative instruments of $44 million for first quarter 2016;


•	diluted net income per share of $0.08, as compared with diluted net loss per share of $0.67 for first quarter 2016;


•	cash flow provided by operating activities of $536 million, as compared with $251 million for first quarter 2016; and


•	capital expenditures of $999 million, including $323 million related to acquisition capital, as compared with $374 million for first quarter 2016.

Quarter-End Key Financial Metrics Included:


•	ending cash balance of $787 million, as compared with $1.2 billion at December 31, 2016;


•	total liquidity of approximately $4.8 billion at March 31, 2017, as compared with $5.2 billion at December 31, 2016; and


•	ratio of debt-to-book capital of 43% at March 31, 2017, unchanged from 43% at December 31, 2016.

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Clayton Williams Energy Acquisition

On April 24, 2017, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) which increases our Southern Delaware position to approximately 118,000 net acres. The integration of the Clayton Williams Energy assets into our portfolio expands our opportunity set in core, high-oil content area of the Delaware Basin and significantly increases our growth outlook through 2020 and beyond. See Item 1. Financial Statements – Note 3. Clayton Williams Energy Acquisition.

Upstream Marcellus Shale Divestiture

On May 1, 2017, we entered into a purchase and sale agreement for the divestiture of all of our upstream assets in the Marcellus Shale for approximately $1.2 billion. We expect to receive approximately $1.1 billion of cash proceeds at closing. With an effective date of January 1, 2017, the transaction includes contingent consideration of up to $100 million based on future commodity price thresholds and is subject to customary sales price adjustments.

Impact of Current Commodity Prices on our Business

Although we expect supply and demand to re-balance as global economies expand over the longer term, commodity prices continued to trade in a narrow range during first quarter 2017. A future decision by OPEC regarding extension of production cuts, changes in levels of crude oil storage and US shale oil production trends, could have significant impacts on crude oil prices in the remainder of 2017. We expect natural gas prices to remain range bound near current or recent trading levels.

Because the global economic outlook and commodity price environment are uncertain, we have planned a 2017 capital investment program that will be responsive to positive or negative commodity conditions that may develop. Excluding acquisition capital, our current 2017 capital spending program targets an investment level of $2.3 to $2.6 billion, or approximately 50% higher than 2016. See Operating Outlook – 2017 Capital Investment Program, below.

Positioning for the Future

We believe the following factors will contribute to the sustainability of our business throughout the commodity price cycle, including extended periods of lower prices:


•	we have a high-quality, globally diversified portfolio of assets focused on top-tier basins, and the majority of our assets are held by production, which provides investment optionality and flexibility;


•	we have achieved substantial cost reductions (and are well-positioned on the global cost supply curve) impacting both operating expenses and capital expenditures;


•	we have designed a capital investment program with flexibility allowing us to respond to changing commodity price conditions in 2017;


•	we have a capital structure and financing strategy which provide sufficient liquidity throughout the commodity price cycle, and recently entered into a term loan facility agreement to fund a portion of our share of Leviathan development costs;


•	we have the ability to access capital markets;


•	we have operational and technical expertise which has led to our delivery of major development projects on schedule and within budget providing a competitive and financial advantage in our industry; and


•	we have exploration expertise which has led to numerous discoveries, in the deepwater Gulf of Mexico, Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in major development project opportunities, including Leviathan phase one, which we recently sanctioned.

As we progress through 2017, we believe we are positioned for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. Although the industry has begun to recover from the recent downturn, if commodity prices decline or operating costs begin to rise, we could experience material negative impacts on our revenues, profitability,

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cash flows, liquidity and proved reserves, and in response, we may consider reductions in our capital program or dividends, asset sales or cost structure. Our production and our stock price could decline as a result of these potential developments.

Sales Volumes

On a barrel of oil equivalent basis, or BOE, total sales volumes were 382 MBoe/d, or 8% lower for first quarter 2017 as compared with first quarter 2016, and our mix of sales volumes was 46% global liquids, 32% US natural gas and 22% international natural gas. See Results of Operations – Revenues, below.

Major Development Project Updates

We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows:

Sanctioned Ongoing Development Projects

A "sanctioned" development project is one for which a final investment decision has been reached. First quarter 2017 activities included the following:

DJ Basin (US onshore) Our activities in first quarter 2017 were primarily focused in Wells Ranch and East Pony where we operated two drilling rigs, drilled 27 wells and commenced production on 14 wells.

Delaware Basin (US onshore) We operated three drilling rigs, drilled ten horizontal wells, and commenced production from three wells which targeted the Upper Wolf Camp A bench. We also closed a bolt-on acquisition in the Southern Delaware Basin which included seven producing wells, of which four are operated by us.

Eagle Ford Shale (US onshore) During first quarter 2017, our activity was focused in Webb and Dimmit counties where we operated two drilling rigs, drilled 13 horizontal wells and commenced production on six wells.

Marcellus Shale (US onshore) In first quarter 2017, we focused on completion activities for previously drilled wells. As such, we had no rigs running in the Marcellus Shale but we expect to commence production from several newly completed wells by mid-year 2017.

Deepwater Gulf of Mexico (Offshore US) Reservoir performance and our development activities in late 2015 and mid-2016 continued to provide strong production during first quarter 2017. In addition, we continue to see positive impacts since our recent assumption of operatorship of the Thunder Hawk Production Facility, which supports production from our Rio Grande development properties.

Leviathan Natural Gas Project (Offshore Israel) We sanctioned the first phase of development of the Leviathan natural gas project and are targeting first production by the end of 2019. Leviathan will provide a second source of natural gas for Israel and the region through a separate tie-in location to the natural gas grid in northern Israel. In April 2017, we recommenced drilling activities and expect completion activities to commence in 2018. Initial Leviathan field proved reserves are expected to be recorded in 2017. We have also executed major equipment and installation contracts in support of our development activities in the field.

Tamar Natural Gas Project (Offshore Israel) In late March 2017, we completed the Tamar 8 development well and commenced production in early April 2017. The Tamar 8 well increases supply reliability as domestic demand for natural gas continues to grow. We continue to market a portion of our working interest in Tamar, in accordance with the Israel Natural Gas Framework (Framework), which provides for reduction in our ownership interest to 25% by year-end 2021.

Alba Field Unitization (Offshore West Africa) In early April 2017, subsequent to quarter end, we executed a unitization agreement on the Alba Field with our partner and the government of Equatorial Guinea. The agreement was between Alba Block and Block D partners. As a result of the unitization, our revenue interest going forward will change from 34% to 32%. The impact on our proved reserves and allocated future production volumes is de minimis.

Unsanctioned Development Projects

Tamar Expansion Project (Offshore Israel) We are also engaged in the planning phase for the Tamar expansion project. The project would expand field deliverability from the current level of approximately 1.2 Bcf/d to approximately 2.1 Bcf/d, a quantity that would allow for regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction is dependent upon progress relating to marketing efforts of these resources.

Cyprus Natural Gas Project (Offshore Cyprus) We and our partners are currently performing preliminary engineering and design for the potential development of the Aphrodite field that, as currently planned, would deliver natural gas to potential customers in Cyprus and Egypt. In addition, we are focused on 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.

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West Africa Natural Gas Monetization We continue our efforts to monetize our significant natural gas discoveries offshore West Africa. A natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial returns. Given the monetization plan, to develop the Alen resource through existing infrastructure, we have changed the units-of-production depletion rate, based on risked resources. As a result, we have proportionally allocated existing book value associated with the existing infrastructure assets to the natural gas resources that will be developed in the future, resulting in approximately $153 million of net asset value being reclassified as development costs not subject to depletion. See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs, Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below, and Results of Operations - Operating Costs and Expenses, below.

Exploration Program Update

Our 2017 exploration budget has been substantially reduced compared to prior years due to the current commodity price environment. In 2017, we anticipate engaging in seismic acquisition and processing and participating in drilling an exploratory well in offshore Suriname in which we own a 20% non-operating working interest.

Through our drilling activities, we do not always encounter hydrocarbons. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs will be recorded as dry hole expense.

Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Divestiture and Acreage Exchange Activities

We actively manage our asset portfolio and periodically divest assets. Proceeds from divestitures allow us to allocate capital and other resources to potentially higher-value and higher-growth areas and enhance our balance sheet strength. We will continue to evaluate divestment opportunities of other assets within our portfolio. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Update on Regulations

US Regulatory Developments In early 2017, President Trump issued two executive orders directing the US Environmental Protection Agency (EPA) and other executive agencies to review their rules and policies that unduly burden domestic energy development. Specifically, on February 28, 2017, President Trump signed an executive order directing the EPA and the US Army Corps of Engineers to review the Clean Water Rule and to initiate rulemaking to rescind or revise it, as appropriate under the stated policies of protecting navigable waters from pollution while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On March 28, 2017, President Trump signed an executive order directing the EPA and other executive agencies to review all regulations, orders, guidance documents and policies and take actions to suspend, revise or rescind them, as appropriate and consistent with the law, to the extent that they unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest. It remains unclear how and to what extent this broad review could impact environmental regulations at the federal level.

Impact of Dodd-Frank Act Section 1504 In June 2016, the Securities and Exchange Commission (SEC) adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount of payments made to a foreign government, including subnational governments (such as states and/or counties), or the U.S. federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).

However, on February 14, 2017, President Trump signed a joint resolution passed by the United States Congress under the Congressional Review Act and eliminated the Resource Extraction Issuer Payment Rules. It should be noted that Section 1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. We cannot predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated pursuant to the Congressional Review Act.

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We will continue to monitor proposed and new regulations and legislation in all of our operating jurisdictions to assess the potential impact on our company. We continue to engage in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.

Recently Issued Accounting Standards

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

OPERATING OUTLOOK

2017 Production Our expected crude oil, natural gas and NGL production for the remainder of 2017 may be impacted by several factors including:


•	commodity prices which, if subject to further decline, could result in certain current production becoming uneconomic;


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


•	with increased drilling activity, onshore cost inflation pressure may result in certain current production becoming less profitable or uneconomic;


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


•	timing of the divestiture of a portion of our working interest in the Tamar field, in accordance with the Framework, which will lower our sales volumes;


•	timing of crude oil and condensate liftings impacting sales volumes in West Africa as well as the unitization of the Alba Field;


•	integration and timing of producing wells acquired as a result of the Clayton Williams Energy Acquisition;


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


•	natural field decline in the US onshore, deepwater Gulf of Mexico and offshore Equatorial Guinea;


•	potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting US onshore operations;


•	reliability of support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;


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


•	impact of enhanced completion efforts for US onshore assets;


•	shut-in of US producing properties if storage capacity becomes unavailable; and


•	drilling and/or completion permit delays due to future regulatory changes.

2017 Capital Investment Program Given the current commodity price environment, we have designed a flexible capital investment program as part of our comprehensive effort to spend within cash flows and manage the Company's balance sheet. Excluding acquisition capital, our current 2017 capital program targets an investment level of approximately $2.3 to $2.6 billion, with more than 75% of the total capital program allocated to US onshore development primarily in liquids-rich opportunities in the DJ Basin, Delaware Basin, and Eagle Ford Shale. The remaining 25% capital program will be predominately allocated to the Eastern Mediterranean, including initial development costs associated with the Leviathan project.

See Liquidity and Capital Resources – Financing Activities, below.

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

Exploration Activities Our exploration program seeks to provide growth through long-term and/or large-scale exploration opportunities. We continue to seek exploration opportunities in various geographical areas, such as our recent entry into Newfoundland, Canada. In other areas of the world, we have capitalized a significant amount of exploratory drilling costs. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Results of Operations – Oil and Gas Exploration Expense, below.

We may also impair and/or relinquish certain undeveloped leases prior to expiration, based upon geological evaluation or other factors. For example, in first quarter 2017, we impaired $18 million of cost related to deepwater Gulf of Mexico undeveloped leases. We have numerous leases for deepwater Gulf of Mexico prospects that have not yet been drilled. A significant portion of these leases are scheduled to expire over the years 2018 to 2020 and some leases may become impaired if production is not

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established, no action is taken to extend the terms of the leases, or the leases become uneconomic due to low commodity prices or other factors.

As of March 31, 2017, we have capitalized costs related to exploratory wells of $571 million. We also have capitalized undeveloped leasehold costs of $139 million, of which $86 million is related to the Gulf of Mexico and $53 million is related to our international exploration areas. As a result of our exploration activities, future exploration expense, including undeveloped leasehold impairment expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below.

Proved and Unproved Properties In first quarter 2017, no impairments were incurred related to proved properties. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward commodity prices, or widening of basis differentials, could result in an impairment.

Undeveloped leasehold costs as of March 31, 2017 totaled $2.3 billion, primarily comprised of $2.2 billion related to US onshore unproved properties. These costs were derived from allocated fair values as a result of a business combination or other purchase of unproved properties and, in that the properties are held by production, they are subject to impairment testing utilizing a future cash flows analysis.

In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may also be difficult to estimate costs of rigs and services in periods of fluctuating demand. In addition, we do not operate certain assets and we therefore work with respective operators to receive updated estimates of abandonment activities and costs. For example, as of March 31, 2017, we had a total asset retirement obligation of $89 million related to a North Sea remediation project. As the operator moves beyond the initial decommissioning phase, we will continue to monitor the status and costs of the project and will adjust our estimate accordingly. See Item 1. Financial Statements - Note 9. Asset Retirement Obligations.

Divestments We actively manage our asset portfolio to ensure our assets are well-positioned on the industry cost of supply curve and offer growth at financially attractive rates of return. Therefore, we may periodically divest certain assets to reposition our portfolio. Proceeds from asset sales are redeployed in our capital investment program, used to pay down debt, strengthen our balance sheet and/or support returns to shareholders through dividends or other mechanisms.

When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction related costs to sell.

We strive to obtain the most advantageous price for any asset divestment; however, various factors, such as current and future commodity prices, reserves, production profiles, operating costs, capital investment requirements and potential future liabilities, as well as legal and regulatory requirements, can make it difficult to predict an asset's selling price and whether a transaction will result in a gain or loss. Inability to achieve a desired sales price, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a possible loss on the sale, which could be material. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.

We are in the process of reviewing our portfolio to ensure alignment with the aforementioned strategic objectives. Further, 7.5% of our working interest in the Tamar field in Israel is required by the State of Israel to be divested by December 2021, reducing our working interest from 32.5% to 25%. Additional potential divestments are being considered, even though no commitments have been made by our management and our Board of Directors.

We have had recent third party interest in certain of our properties with aggregated estimated net book value of approximately $1.7 billion. We have recently engaged financial advisors to assess these interests and assist with the marketing of these assets. While preliminary marketing efforts have been initiated, our management and Board of Directors have not yet committed to any such divestments.

It is difficult to predict the outcome of these discussions, and while it is possible that the potential sale of certain of these assets may generate gains, it is also possible that these potential sales may generate losses. Several commercial factors impacting our short and long term strategy need to be evaluated prior to committing to a divestment action. Ultimately, these decisions will be made by our management and approved by our Board of Directors.

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RESULTS OF OPERATIONS

Revenues

Revenues were as follows:



					Increase from Prior Year
(millions)	2017		2016		Increase from Prior Year
Three Months Ended March 31,
Oil, NGL and Gas Sales	$	994	$	705	41	%
Income from Equity Method Investees	42		19		121	%
Total	$	1,036	$	724	43	%

Changes in revenues are discussed below.

Oil, NGL and Gas Sales

Average daily sales volumes and average realized sales prices were as follows:



	Sales Volumes				Average Realized Sales Prices
	Crude Oil & Condensate (MBbl/d)	NGLs (MBbl/d)	Natural Gas (MMcf/d)	Total (MBoe/d) ⁽¹⁾	Crude Oil & Condensate (Per Bbl)		NGLs (Per Bbl)		Natural Gas (Per Mcf)
Three Months Ended March 31, 2017
United States	99	49	730	270	$	49.03	$	23.97	$	3.44
Israel	—	—	271	46	—		—		5.32
Equatorial Guinea ⁽²⁾	18	—	244	58	53.42		—		0.27
Total Consolidated Operations	117	49	1,245	374	49.70		23.97		3.23
Equity Investees ⁽³⁾	2	6	—	8	52.59		36.04		—
Total	119	55	1,245	382	$	49.73	$	25.34	$	3.23
Three Months Ended March 31, 2016
United States	102	53	910	306	$	30.14	$	11.18	$	1.90
Israel	—	—	266	45	—		—		5.19
Equatorial Guinea ⁽²⁾	27	—	195	60	34.49		—		0.27
Total Consolidated Operations	129	—	1,371	411	31.04		11.18		2.30
Equity Investees ⁽³⁾	1	4	—	5	33.30		22.19		—
Total	130	57	1,371	416	$	31.06	$	12.01	$	2.30

⁽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 price 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 in Equatorial Guinea is 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 in part by affiliated entities accounted for under the equity method of accounting.


⁽³⁾	Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees, below.

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



	Sales Revenues
(millions)	Crude Oil & Condensate			NGLs			Natural Gas			Total
Three Months Ended March 31, 2016	$	365		$	53		$	287		$	705
Changes due to
Decrease in Sales Volumes	(28		)	(3		)	(26		)	(57		)
Increase in Sales Prices	190			55			101			346
Three Months Ended March 31, 2017	$	527		$	105		$	362		$	994

Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales increased for first quarter 2017 as compared with first quarter 2016 due to the following:


•	higher average realized prices due to the rebalancing of global supply and demand factors;


•	higher sales volumes of 3 MBbl/d, net, in the Delaware Basin primarily attributable to increased productivity due to enhanced well design and completion techniques; and


•	production from the Gunflint development, deepwater Gulf of Mexico, which began producing in July 2016 and contributed 5 MBbl/d, net, during the current quarter;

partially offset by:


•	lower sales volumes in the DJ Basin and Eagle Ford Shale due to decreased development activity during the period of lower commodity prices in 2016; and


•	lower sales volumes due to natural field decline at Aseng and Alen, offshore Equatorial Guinea.

NGL Sales Revenues Revenues from NGL sales increased for first quarter 2017 as compared with first quarter 2016 due to the following:


•	higher average realized prices due to the rebalancing of domestic supply and demand factors; and


•	higher sales volumes of 1 MBbl/d, net, in the Delaware Basin primarily attributable to increased productivity due to enhanced well design and completion techniques;

partially offset by:


•	lower sales volumes in the DJ Basin and Eagle Ford Shale due to decreased development activity during the period of lower commodity prices in 2016.

Natural Gas Sales Revenues Revenues from natural gas sales increased for first quarter 2017 as compared with first quarter 2016 due to the following:


•	higher average realized US prices due to the rebalancing of domestic supply and demand factors;


•	production from the Gunflint development, deepwater Gulf of Mexico, which began producing in July 2016 and contributed 9 MMcf/d, net, during the current quarter;


•	higher sales volumes from the Tamar field, offshore Israel, in response to the increased use of natural gas over coal to fuel power generation and higher seasonal demand; and


•	higher sales volumes of 48 MMcf/d, net, offshore Equatorial Guinea due to the completion of the Alba B3 compression project which commenced production in July 2016;

partially offset by:


•	lower sales volumes in the Marcellus Shale primarily due to natural well decline and the termination of our Joint Development Agreement with CONSOL in fourth quarter 2016;


•	lower sales volumes in the DJ Basin and Eagle Ford Shale due to decreased development activity during the period of lower commodity prices in 2016; and


•	lower sales volumes of 5 MMcf/d, net, as a result of the sale of 3.5% working interest in the Tamar field in December 2016.

Income from Equity Method Investees We have interests in equity method investees that operate midstream assets US onshore and West Africa. Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.

Income from equity method investees increased for the first quarter of 2017 as compared with the first quarter of 2016. The increase includes an $11 million increase from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee,

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and a $14 million increase from Alba Plant, our LPG investee, primarily due to rising commodity prices and 3 MBbl/d increase in sales volumes.

Operating Costs and Expenses

Operating costs and expenses were as follows:



						Increase / (Decrease) from Prior Year
(millions)	2017		2016			Increase / (Decrease) from Prior Year
Three Months Ended March 31,
Production Expense	$	303	$	276		10	%
Exploration Expense	42		163			(74	)%
Depreciation, Depletion and Amortization	528		617			(14	)%
General and Administrative	99		91			9	%
Other Operating Expense, Net	29		(1		)	N/M
Total	$	1,001	$	1,146		(13	)%

N/M amount is not meaningful.

Changes in operating costs and expenses are discussed below.

Production Expense Components of production expense were as follows:



(millions, except unit rate)	Total per BOE ⁽¹⁾		Total		United States		Israel		Equatorial Guinea		Corporate
Three Months Ended March 31, 2017
Lease Operating Expense ⁽²⁾	$	4.13	$	139	$	108	$	8	$	23	$	—
Production and Ad Valorem Taxes	1.34		45		45		—		—		—
Gathering, Transportation and Processing	3.54		119		119		—		—		—
Total Production Expense	$	9.01	$	303	$	272	$	8	$	23	$	—
Total Production Expense per BOE			$	9.01	$	11.20	$	1.96	$	4.36	—
Three Months Ended March 31, 2016
Lease Operating Expense ⁽²⁾	$	4.31	$	161	$	120	$	10	$	29	$	2
Production and Ad Valorem Taxes	0.11		4		4		—		—		—
Gathering, Transportation and Processing	2.97		111		111		—		—		—
Total Production Expense	$	7.39	$	276	$	235	$	10	$	29	$	2
Total Production Expense per BOE			$	7.39	$	8.43	$	2.46	$	5.34	N/M

N/M Amount is not meaningful.


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


⁽²⁾	Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

For first quarter 2017, total production expense increased as compared with 2016 due to the following:


•	an increase in production and ad valorem taxes due to an increase in realized commodity prices, as well as a $28 million US onshore severance tax refund recorded in first quarter 2016 and a $7 million US onshore severance tax charge recorded in first quarter 2017; and


•	an increase in gathering, transportation and processing expense due to higher production in the Delaware Basin, the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees in the DJ Basin, and from the startup of our Gunflint development, deepwater Gulf of Mexico, which began producing in July 2016;

partially offset by:


•	a decrease in lease operating expense due to lower production volumes in the DJ Basin and Eagle Ford Shale resulting from decreased development activity during the period of lower commodity prices in 2016.

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Production expense on a per BOE basis increased primarily due to the increase in production and ad valorem taxes discussed above. Transportation expense per BOE is also higher in first quarter 2017 as compared to first quarter 2016 due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees in the DJ Basin.

Exploration Expense Components of exploration expense were as follows:



(millions)	Total		United States		Eastern Mediter- ranean ⁽¹⁾		West Africa ⁽²⁾		Other Int'l, Corporate ⁽³⁾
Three Months Ended March 31, 2017
Leasehold Impairment	$	18	$	18	$	—	$	—	$	—
Dry Hole Expense	—		—		—		—		—
Seismic, Geological and Geophysical	5		—		—		—		5
Staff Expense	13		—		—		1		12
Other ⁽⁴⁾	6		5		—		1		—
Total Exploration Expense	$	42	$	23	$	—	$	2	$	17
Three Months Ended March 31, 2016
Leasehold Impairment	$	15	$	15	$	—	$	—	$	—
Dry Hole Expense	93		95		—		—		(2		)
Seismic, Geological and Geophysical	9		—		—		—		9
Staff Expense	18		1		1		1		15
Other ⁽⁴⁾	28		13		7		—		8
Total Exploration Expense	$	163	$	124	$	8	$	1	$	30


⁽¹⁾	Eastern Mediterranean includes Israel and Cyprus.


⁽²⁾	West Africa includes Equatorial Guinea, Cameroon and Gabon.


⁽³⁾	Other International, Corporate includes the Falkland Islands, other new ventures and corporate expenditures.


⁽⁴⁾	Includes lease rentals and other exploratory costs.

Exploration expense for first quarter 2017 included the following:


•	leasehold impairment expense related to the impairment of leases in deepwater Gulf of Mexico.

Exploration expense for first quarter 2016 included the following:


•	US dry hole expense related to the Silvergate exploratory well, deepwater Gulf of Mexico;


•	US other cost includes lease rentals of $12 million primarily related to Delaware Basin leases; and


•	leasehold impairment expense primarily related to undeveloped leasehold amortization.

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



	Three Months Ended March 31,
	2017		2016
DD&A Expense (millions) ⁽¹⁾	$	528	$	617
Unit Rate per BOE ⁽²⁾	$	15.70	$	16.52


⁽¹⁾	For DD&A expense by geographical area, see Item 1. Financial Statements – Note 12. Segment Information.


⁽²⁾	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

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Total DD&A expense for first quarter 2017 decreased as compared with first quarter 2016 due to the following:


•	lower sales volumes in the DJ Basin, Eagle Ford Shale and Marcellus Shale;


•	sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016; and


•	a reduction in depletable costs due to the reallocation of $153 million of common asset costs from Alen, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which lowered DD&A expense by $10 million;

partially offset by:


•	increased sales volumes in the Delaware Basin due to higher levels of development activity;


•	an increase in sales volumes from the Gunflint development, deepwater Gulf of Mexico, which commenced producing in July 2016; and


•	higher first quarter sales volumes from the Tamar field due to higher domestic demand.

The decrease in the unit rate per BOE for first quarter 2017 as compared with first quarter 2016, was due to increased lower-cost production volumes from the Tamar field and the reduction in Alen net book value, partially offset by decreases in proved reserves at year-end 2016 due to downward price revisions in the US and Equatorial Guinea.

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



	Three Months Ended March 31,
	2017		2016
G&A Expense (millions)	$	99	$	91
Unit Rate per BOE ⁽¹⁾	$	2.94	$	2.44


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

G&A expense for first quarter 2017 increased as compared with first quarter 2016 primarily due to higher full-time workforce costs and lower cost allocations to exploration expense due to decreased exploration activity. The increase in the unit rate per BOE for the first quarter 2017 as compared with 2016 was due to the increase in total G&A combined with the decrease in total sales volumes.

Other Operating (Income) Expense Other operating (income) expense was as follows:



	Three Months Ended March 31,
(millions)	2017		2016
Marketing Expense	$	19	$	18
Gain on Extinguishment of Debt	—		(80		)
Loss on Asset Due to Terminated Contract	4		42
Other, Net	6		19
Total	$	29	$	(1	)

See Item 1. Financial Statements – Note 2. Basis of Presentation for discussion of the above components of other operating (income) expense.

Other (Income) Expense

Other (income) expense was as follows:



	Three Months Ended March 31,
(millions)	2017			2016
Gain on Commodity Derivative Instruments	$	(110	)	$	(44	)
Interest, Net of Amount Capitalized	87			79
Other Non-Operating Expense (Income), Net	(1		)	(4		)
Total	$	(24	)	$	31

Gain on Commodity Derivative Instruments

Gain on commodity derivative instruments includes:

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•	cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts; and


•	non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.

For first quarter 2017, gain on commodity derivative instruments included:


•	net cash settlement receipts of $3 million; and


•	non-cash increases in the fair value of our derivative instruments of $107 million primarily driven by declines in the forward commodity price curves.

For first quarter 2016, gain on commodity derivative instruments included:


•	net cash settlement receipts of $178 million; and


•	non-cash decreases in the fair value of our derivative instruments of $134 million primarily driven by declines in the forward commodity price curves.

See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities and Note 7. Fair Value Measurements and Disclosures.

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



	Three Months Ended March 31,
(millions, except unit rate)	2017			2016
Interest Expense, Gross	$	99		$	106
Capitalized Interest	(12		)	(27		)
Interest Expense, Net	$	87		$	79
Unit Rate per BOE ⁽¹⁾	$	2.59		$	2.11


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

Interest expense, gross, for first quarter 2017 decreased as compared with first quarter 2016. The decrease was primarily due to a lower Term Loan Facility balance. See Item 1. Financial Statements - Note 6. Debt.

The decrease in capitalized interest for first quarter 2017 as compared with first quarter 2016 is primarily due to lower work in progress amounts related to major long-term projects including Gunflint, deepwater Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were both completed in July 2016. We also impaired certain of our discoveries offshore Equatorial Guinea after an additional review of 3D seismic data was completed in fourth quarter 2016, resulting in a lower capitalized exploratory well cost balance. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

The increase in the unit rate of interest expense, net, per BOE was due to the changes noted above, combined with the decrease in total sales volumes.

Income Taxes

See Item 1. Financial Statements – Note 11. Income Taxes for a discussion of the change in our effective tax rate for first quarter 2017 as compared with 2016.

LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the commodity price cycle, including the current commodity price environment. 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 periodically capitalize on financially attractive mergers and acquisitions opportunities. We endeavor to maintain a strong balance sheet and investment grade debt rating in service of these objectives.

We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Revolving Credit Facility and proceeds from property divestitures. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending.

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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 February 2017, we entered into a term loan facility agreement to fund a portion of our share of Leviathan development costs. Also during first quarter 2017, we received $175 million in payments from foreign operations on an outstanding note payable, leaving a balance of approximately $546 million that can be repaid without additional US tax impact.

As of March 31, 2017, our outstanding debt (excluding capital lease and other obligations) totaled $6.7 billion. While we have no near-term debt maturities, we may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness.

Available Liquidity

Information regarding cash and debt balances is shown in the table below:



	March 31,			December 31,
(millions, except percentages)	2017			2016
Total Cash ⁽¹⁾	$	787		$	1,209
Amount Available to be Borrowed Under Revolving Credit Facility ⁽²⁾	4,000			4,000
Total Liquidity	$	4,787		$	5,209
Total Debt ⁽³⁾	$	7,100		$	7,114
Noble Energy Share of Equity	9,292			9,288
Ratio of Debt-to-Book Capital ⁽⁴⁾	43		%	43		%


⁽¹⁾	As of March 31, 2017, total cash included cash and cash equivalents of $39 million related to Noble Midstream Partners. As of December 31, 2016, total cash included cash and cash equivalents of $57 million related to Noble Midstream Partners and restricted cash of $30 million related to a Delaware Basin property acquisition that closed in January 2017.


⁽²⁾	Excludes $350 million and $650 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, respectively, which are not available to Noble Energy for general corporate purposes. See discussion below.


⁽³⁾	Total debt includes capital lease obligations and excludes unamortized debt discount/premium. See Item 1. Financial Statements – Note 6. Debt.


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

Cash and Cash Equivalents We had approximately $787 million in cash and cash equivalents at March 31, 2017, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $466 million of this cash is attributable to our foreign subsidiaries. We have recorded a related deferred tax liability on undistributed foreign earnings of $314 million for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credits. Our cash and cash equivalents at March 31, 2017 included $39 million relating to Noble Midstream Partners.

Revolving Credit Facility Noble Energy's Revolving Credit Facility matures on August 27, 2020, and the commitment is $4.0 billion through the maturity date. No amounts were drawn as of March 31, 2017. However, on April 24, 2017, we borrowed $1.3 billion under our Revolving Credit Facility to fund activities in connection with the Clayton Williams Energy Acquisition, including the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. See Item 1. Financial Statements - Note 3. Clayton Williams Energy Acquisition.

Noble Midstream Services Revolving Credit Facility Noble Midstream Services Revolving Credit Facility matures on September 20, 2021, and the commitment is $350 million through the maturity date. No amounts were drawn as of March 31, 2017.

Leviathan Term Loan Facility On February 24, 2017, we entered into a facility agreement (Leviathan Term Loan Facility) providing for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million is initially committed. Any loans borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel. As of March 31, 2017, no amounts were drawn under this facility.

Interest Rate Risk Certain of our borrowings subject us to interest rate risk. See Item 1. Financial Statements – Note 6. Debt and Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Contractual Obligations

Exploration Commitments The terms of some of our production sharing contracts, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data,

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within specific time periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.

Leviathan Development Obligations The development of our Leviathan field will require substantial infrastructure and capital. We have executed major equipment and installation contracts in support of our development activities in the field. As of March 31, 2017, we had entered into approximately $566 million of contracts to support the development of this field and to bring first production online by the end of 2019.

Continuous Development Obligations Although the majority of our assets are held by production, certain of our US onshore assets are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas and failure to meet these obligations may result in the loss of one or more leases. Our 2017 capital program allows for managing these obligations.

Delivery and Firm Transportation Agreements We have entered into various long-term gathering, processing and transportation contracts for some of our US onshore production, with remaining terms of one to 31 years. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost.

Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments.

For first quarter 2017 and 2016, we incurred expense of approximately $19 million and $18 million, respectively, related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are recorded as marketing expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term.

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.

Cash Flows

Summary cash flow information is as follows:



	Three Months Ended March 31,
(millions)	2017			2016
Total Cash Provided By (Used in)
Operating Activities	$	536		$	251
Investing Activities	(863		)	(264		)
Financing Activities	(66		)	(62		)
Decrease in Cash and Cash Equivalents	$	(393	)	$	(75	)

Operating Activities Net cash provided by operating activities for the first quarter of 2017 increased as compared with 2016. Increases in average realized commodity prices were partially offset by decreases in sales volumes. Working capital changes resulted in a $48 million operating cash flow increase for the first quarter of 2017, as compared with a negative impact of $136 million for the first quarter of 2016, and was primarily driven by a decrease in accounts receivable as a result of cash received from the farm-out of our 35% interest in Block 12 (offshore Cyprus) and hedging activities along with an increase in accounts payable primarily due to increased development activity.

Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that occurred in prior periods. Capital spending for property, plant and equipment increased by $91 million during the first quarter

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of 2017 as compared with the first quarter of 2016, primarily due to increased US onshore development activity in response to the commodity price recovery. In addition, we acquired Delaware Basin assets for $301 million. During first quarter 2016, we received proceeds of $238 million from asset sales.

Financing Activities Our financing activities include the issuance or repurchase of Noble Energy common stock and Noble Midstream Partners common units, payment of cash dividends on our common stock, the borrowing of cash, the repayment of borrowings and distributions to noncontrolling interest owners in Noble Midstream Partners. During the first quarter of 2017, we used cash to pay dividends on our common stock of $44 million.

In comparison, during the first quarter of 2016, funds were provided by cash proceeds from the Term Loan Facility of $1.4 billion. We used cash to fund the purchase of certain of our outstanding senior notes of $1.38 billion and pay dividends on our common stock of $41 million.

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

Investing Activities

Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows:



	Three Months Ended March 31,
(millions)	2017		2016
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition ⁽¹⁾	$	246	$	19
Proved Property Acquisition ⁽²⁾	58		—
Exploration	10		98
Development	587		228
Midstream	93		15
Corporate and Other	5		8
Total	$	999	$	368
Other
Investment in Equity Method Investee	$	—	$	6

⁽¹⁾Unproved property acquisition cost for first quarter 2017 includes $246 million related to the Delaware Basin asset acquisition. Unproved property acquisition cost for 2016 includes $10 million in the DJ Basin and $6 million in the Marcellus Shale.

⁽²⁾ Proved property acquisition cost for first quarter 2017 is related to the Delaware Basin asset acquisition.

Total expenditures increased during the first quarter of 2017 as compared with 2016 as we have increased our US onshore acquisition and development activity in response to the current commodity price recovery. See Operating Outlook – 2017 Capital Investment Program, above.

Financing Activities

Long-Term Debt Our principal source of liquidity is our Revolving Credit Facility that matures August 27, 2020. At March 31, 2017, we had no amount outstanding under the Revolving Credit Facility, leaving $4.0 billion available for use. However, on April 24, 2017, we drew $1.3 billion under our Revolving Credit Facility to fund activities in connection with the Clayton Williams Energy Acquisition, including the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. We may rely on our Revolving Credit Facility to help fund our capital investment program, and may periodically borrow amounts for working capital purposes. See Item 1. Financial Statements – Note 6. Debt.

Our outstanding fixed-rate debt (excluding capital lease obligations) totaled approximately $6.2 billion at March 31, 2017. The weighted average interest rate on fixed-rate debt was 5.69%, with maturities ranging from March 2019 to August 2097.

Dividends We paid total cash dividends of 10 cents per share of common stock during the first quarter of 2017, consistent with 10 cents per share during the first quarter of 2016.

On April 24, 2017, our Board of Directors declared a quarterly cash dividend of 10 cents per common share, which will be paid on May 22, 2017 to shareholders of record on May 8, 2017. 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.

Exercise of Stock Options We received cash proceeds from the exercise of stock options of $9 million during the first quarter of 2017 and $5 million during the first quarter of 2016.

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Common Stock Repurchases We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 260,146 shares with a value of $11 million during the first quarter of 2017 and 228,917 shares with a value of $8 million during the first quarter of 2016.

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 Results of Operations - Revenues, above.

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

At March 31, 2017, we had various open commodity derivative instruments related to crude oil and natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $9 million. Based on the March 31, 2017 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil would increase the fair value of our net commodity derivative liability by approximately $47 million. A hypothetical price increase of 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $30 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on certain of our borrowings and the amount of interest we earn on our short-term investments.

At March 31, 2017, we had approximately $6.7 billion (excluding capital lease obligations) of long-term debt, net, outstanding. Of this amount, $6.2 billion was fixed-rate debt, net, with a weighted average interest rate of 5.69%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.

However, we are exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of March 31, 2017, our cash and cash equivalents totaled $787 million, approximately 52% of which was invested in money market funds and short-term investments with major financial institutions. In addition, borrowings under the Term Loan Facility are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost. While we currently have no interest rate derivative instruments as of March 31, 2017, we may invest in such instruments in the future in order to mitigate interest rate risk. A change in the interest rate applicable to our short-term investments or Term Loan Facility would have a de minimis impact.

Foreign Currency Risk

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

Net transaction gains and losses were de minimis for the three months ended March 31, 2017 and 2016.

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

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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, development and acquisitions activities;


•	our ability to make and integrate acquisitions;


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


•	anticipated trends in our business;


•	market conditions in the oil and gas industry;


•	the impact of governmental fiscal regulation, including federal, state, local, and foreign host regulations, and/or terms, such as those involving the protection of the environment or marketing of production, as well as other regulations; 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, 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, 2016 and in this quarterly report on Form 10-Q, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2016 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 13. 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, 2016.

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, 2016.

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	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(in thousands)
1/1/2017 - 1/31/2017	129,906	$	39.63	—	—
2/1/2017 - 2/28/2017	112,859	39.46		—	—
3/1/2017 - 3/31/2017	17,381	36.70		—	—
Total	260,146	$	39.36	—	—


⁽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.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The information required by this Part II. Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q and is incorporated by reference into this Part II. Item 6.

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Signatures

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



		NOBLE ENERGY, INC.
		(Registrant)

Date	May 2, 2017	/s/ Kenneth M. Fisher
		Kenneth M. Fisher Executive Vice President, Chief Financial Officer

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Index to Exhibits



Exhibit Number		Exhibit**

2.1		Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).

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

2.3		Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 and incorporated herein by reference).

3.1		Restated Certificate of Incorporation of Noble Energy Inc., (filed as Exhibit 3.3 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

3.2		By-Laws of Noble Energy, Inc. (as amended through January 24, 2017) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 23, 2017) filed on January 27, 2017 and incorporated herein by reference).

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

3.4		Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).

10.1		Support Agreement, dated as of January 13, 2017, by and among certain stockholders affiliated with Ares Management, LLC, Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).

10.2		Agreement Not to Dissent, dated as of January 13, 2017, by and among Clayton W. Williams, Jr., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).

10.3		Agreement Not to Dissent, dated as of January 13, 2017, by and among The Williams Children’s Partnership, Ltd., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).

10.4*		Noble Energy, Inc. 2017 Long-Term Incentive Plan. (incorporated by reference to Appendix C to the Company's Definitive Proxy Statement on Schedule 14A filed on March 2, 2017).

10.5*		Form of Restricted Stock Award Agreement (two-year vested) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan filed herewith.

10.6*		Form of Restricted Stock Award Agreement (three-year vested) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan filed herewith.

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

10.8*		Form of Performance Share Award Agreement under the Noble Energy, Inc. 2017 Long-Term Incentive Plan filed herewith.

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10.9†		Noble Energy Mediterranean Ltd. Facility Agreement, dated February 24, 2017 by and between NEML Leviathan Finance Company LTD as Borrower and BNP Paribas, Credit Agricole Corporate and Investment Bank, ING Bank N.V., Natixis and Societe Generale London Branch as Mandated Lead Arrangers, filed herewith.

12.1		Calculation of ratio of earnings to fixed charges, 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		XBRL Instance Document

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

101.DEF		XBRL Definition Linkbase Document



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



**	Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.



†	Material information has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities and Exchange Act of 1934, as amended.

NOBLE ENERGY INC - FORM 10-Q - May 2, 2017

Attached files

NOBLE ENERGY INC Reports