10-Q

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 September 30, 2016

OR

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 or a smaller

reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company”

in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

 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 September 30, 2016, there were 429,701,812 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	3
Consolidated Statements of Comprehensive Loss	4
Consolidated Balance Sheets	5
Consolidated Statements of Cash Flows	6
Consolidated Statements of Equity	7
Notes to Consolidated Financial Statements	8
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.  Controls and Procedures	51
Part II. Other Information	53
Item 1.  Legal Proceedings	53
Item 1A.  Risk Factors	53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3. Defaults Upon Senior Securities	54
Item 4. Mine Safety Disclosures	54
Item 5.  Other Information	54
Item 6.  Exhibits	54
Signatures	55
Index to Exhibits	56

2

Part I. Financial Information

Item 1. Financial Statements

Noble Energy, Inc.

Consolidated Statements of Operations

(millions, except per share amounts)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues
Oil, Gas and NGL Sales	$	882		$	783		$	2,411		$	2,264
Income from Equity Method Investees	28			36			70			60
Total	910			819			2,481			2,324
Costs and Expenses
Production Expense	274			247			820			715
Exploration Expense	125			203			376			308
Depreciation, Depletion and Amortization	621			539			1,859			1,444
General and Administrative	95			109			293			308
Other Operating Expense, Net	45			188			66			310
Total	1,160			1,286			3,414			3,085
Operating Loss	(250		)	(467		)	(933		)	(761		)
Other Expense (Income)
(Gain) Loss on Commodity Derivative Instruments	(55		)	(267		)	53			(331		)
Interest, Net of Amount Capitalized	86			71			242			183
Other Non-Operating (Income) Expense, Net	(1		)	(12		)	3			(20		)
Total	30			(208		)	298			(168		)
Loss Before Income Taxes	(280		)	(259		)	(1,231		)	(593		)
Income Tax (Benefit) Provision	(137		)	24			(486		)	(180		)
Net Loss Including Noncontrolling Interests	(143		)	(283		)	(745		)	(413		)
Less: Net Income Attributable to Noncontrolling Interests	1			—			1			—
Net Loss Attributable to Noble Energy	$	(144	)	$	(283	)	$	(746	)	$	(413	)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Loss Per Share, Basic	$	(0.33	)	$	(0.67	)	$	(1.73	)	$	(1.05	)
Loss Per Share, Diluted	$	(0.33	)	$	(0.67	)	$	(1.73	)	$	(1.05	)
Weighted Average Number of Shares Outstanding
Basic	430			420			430			392
Diluted	430			420			430			392

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

3

Noble Energy, Inc.

Consolidated Statements of Comprehensive Loss

(millions)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Net Loss Including Noncontrolling Interests	$	(143	)	$	(283	)	$	(745	)	$	(413	)
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment	—			—			—			(11		)
Less Tax Expense	—			—			—			3
Net Change in Pension and Other	1			69			2			94
Less Tax Benefit	(1		)	(23		)	(1		)	(33		)
Other Comprehensive Income	—			46			1			53
Comprehensive Loss Including Noncontrolling Interests	(143		)	(237		)	(744		)	(360		)
Less: Comprehensive Income Attributable to Noncontrolling Interests	1			—			1			—
Comprehensive Loss Attributable to Noble Energy	$	(144	)	$	(237	)	$	(745	)	$	(360	)

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

4

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

	September 30, 2016				December 31, 2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,819			$	1,028
Accounts Receivable, Net	486				450
Commodity Derivative Assets	120				582
Other Current Assets	352				216
Total Current Assets	2,777				2,276
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,372				31,220
Property, Plant and Equipment, Other	919				858
Total Property, Plant and Equipment, Gross	31,291				32,078
Accumulated Depreciation, Depletion and Amortization	(12,186		)		(10,778		)
Total Property, Plant and Equipment, Net	19,105				21,300
Other Noncurrent Assets	587				620
Total Assets	$	22,469			$	24,196
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	786			$	1,128
Other Current Liabilities	742				677
Total Current Liabilities	1,528				1,805
Long-Term Debt	7,854				7,976
Deferred Income Taxes	2,103				2,826
Other Noncurrent Liabilities	1,139				1,219
Total Liabilities	12,624				13,826
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; 471 Million and 470 Million Shares Issued, respectively	5				5
Additional Paid in Capital	6,417				6,360
Accumulated Other Comprehensive Loss	(32		)		(33		)
Treasury Stock, at Cost; 38 Million Shares	(696		)		(688		)
Retained Earnings	3,851				4,726
Noble Energy Share of Equity	9,545				10,370
Noncontrolling Interests	300			—	—
Total Equity	9,845				10,370
Total Liabilities and Equity	$	22,469			$	24,196

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

5

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Nine Months Ended September 30,
	2016			2015
Cash Flows From Operating Activities
Net Loss Including Noncontrolling Interests	$	(745	)	$	(413	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	1,859			1,444
Asset Impairments	—			43
Dry Hole Cost	105			154
Undeveloped Leasehold Impairment	81			—
Gain on Extinguishment of Debt	(80		)	—
Loss on Asset Due to Terminated Contract	44			—
Deferred Income Tax Benefit	(699		)	(244		)
Loss (Gain) on Commodity Derivative Instruments	53			(331		)
Net Cash Received in Settlement of Commodity Derivative Instruments	454			683
Stock Based Compensation	61			69
Non-cash Pension Termination Expense	—			81
Other Adjustments for Noncash Items Included in Income	92			74
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable	6			370
Decrease in Accounts Payable	(124		)	(248		)
Increase (Decrease) in Current Income Taxes Payable	82			(118		)
Other Current Assets and Liabilities, Net	(72		)	(28		)
Other Operating Assets and Liabilities, Net	(63		)	(50		)
Net Cash Provided by Operating Activities	1,054			1,486
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,164		)	(2,519		)
Cash Acquired in Rosetta Merger	—			61
Additions to Equity Method Investments	(8		)	(86		)
Proceeds from Divestitures and Other	786			151
Net Cash Used in Investing Activities	(386		)	(2,393		)
Cash Flows From Financing Activities
Dividends Paid, Common Stock	(129		)	(214		)
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs	—			1,112
Proceeds from Issuance of Noble Midstream Common Units, Net of Offering Costs	299			—
Proceeds from Term Loan Facility	1,400			—
Repayment of Credit Facility	—			(74		)
Repayment of Senior Notes	(1,383		)	(12		)
Repayment of Capital Lease Obligation	(39		)	(49		)
Other	(25		)	(11		)
Net Cash Provided by Financing Activities	123			752
Increase (Decrease) in Cash and Cash Equivalents	791			(155		)
Cash and Cash Equivalents at Beginning of Period	1,028			1,183
Cash and Cash Equivalents at End of Period	$	1,819		$	1,028

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

6

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, 2015	$	5	$	6,360	$	(33	)	$	(688	)		$	4,726		$	—	$	10,370
Net (Loss) Income	—		—		—			—				(746		)	1		(745		)
Stock-based Compensation	—		57		—			—				—			—		57
Dividends (30 cents per share)	—		—		—			—				(129		)	—		(129		)
Issuance of Noble Midstream Common Units, Net of Offering Costs	—		—		—			—				—			299		299
Other	—		—		1			(8		)		—			—		(7		)
September 30, 2016	$	5	$	6,417	$	(32	)	$	(696	)		$	3,851		$	300	$	9,845
December 31, 2014	$	4	$	3,624	$	(90	)	$	(671	)		$	7,458		$	—	$	10,325
Net Loss	—		—		—			—				(413		)	—		(413		)
Rosetta Merger	1		1,528		—			—				—			—		1,529
Stock-based Compensation	—		69		—			—				—			—		69
Dividends (54 cents per share)	—		—		—			—				(214		)	—		(214		)
Issuance of Noble Energy Common Stock, Net of Offering Costs	—		1,112		—			—			—	—			—		1,112
Other	—		9		53			(20		)		—			—		42
September 30, 2015	$	5	$	6,342	$	(37	)	$	(691	)		$	6,831		$	—	$	12,450

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

7

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 core operating areas are onshore US (DJ Basin, Marcellus Shale, Eagle Ford Shale, and Permian Basin), and offshore in deepwater 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 September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 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. Certain prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

In third quarter 2016, Noble Midstream Partners LP (Noble Midstream), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we will be presenting our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream. Noble Midstream and the initial public offering of common units are further discussed in Note3.Noble Midstream Partners LP.

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, 2015.

Consolidation   Our consolidated accounts include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream, 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 lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream's economic performance; therefore, Noble Midstream is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream), 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. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream.

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.

Issuance of Phantom Units On February 1, 2016, we issued cash-settled awards to certain employees under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the achievement of specific performance goals. These phantom units, once vested, are settled in cash. The phantom units represent a hypothetical interest in the Company. The phantom unit value is the lesser of the fair market value of a share of common stock of the Company as of the vesting date or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.

The Company recognizes the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. As of September 30, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 8. Fair Value Measurements and Disclosures.

8

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Recently Issued Accounting Standards 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. We are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. We are currently evaluating the effect that the guidance will have on our consolidated financial statements and related disclosures.

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. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

In July 2015,the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost or net realizable value. We follow the average cost method and do not believe adoption of ASU 2015-11 will have a material impact on our financial position and results of operations.

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, the core principle of Topic 606 is that an entity recognizes revenue to depict 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. We are continuing to evaluate the provisions of ASU 2014-09 and have not yet determined the full impact it may have on our financial position and results of operations. At a minimum, we expect we will be required to change from the entitlements method, used for certain domestic natural gas sales, to the sales method of accounting. We believe the impact of utilizing the sales method of accounting for our current domestic natural gas sales agreements will be de minimis.

In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures, to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. We do not believe adoption of this guidance will have a material impact on our consolidated financial statements and related disclosures as all material investments are accounted for under the equity method of accounting.

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 certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. 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

9

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, which changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. During third quarter 2016, Noble Midstream closed on its initial public offering of common units. In accordance with ASU 2015-02, Noble Midstream is considered a VIE as Noble Energy is considered the primary beneficiary. We have adopted the provisions of ASU 2015-02, which did not have a material effect on our financial statements or related disclosures.

10

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Production Expense
Lease Operating Expense	$	131		$	133		$	412		$	419
Production and Ad Valorem Taxes	30			28			73			89
Transportation and Gathering Expense (1)	113			86			335			207
Total	$	274		$	247		$	820		$	715
Other Operating (Income) Expense, Net
(Gain) Loss on Asset Due to Terminated Contract (2)	$	(3	)	$	—		$	44		$	—
Marketing and Processing Expense, Net (3)	20			10			58			25
Loss on Divestitures	—			—			23			—
Corporate Restructuring Expense	—			21			—			39
Purchase Price Allocation Adjustment (4)	—			—			(25		)	—
Gain on Extinguishment of Debt (5)	—			—			(80		)	—
Asset Impairments	—			—			—			43
Inventory Adjustment (6)	14			—			14			—
Building Exit Cost	4			18			8			18
Rosetta Merger Expenses	—			71			—			73
Pension Plan Expense	—			67			—			88
Stacked Drilling Rig Expense	3			13			8			20
Other, Net	7			(12		)	16			4
Total	$	45		$	188		$	66		$	310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense (Income) (7)	$	2		$	(13	)	$	7		$	(19	)
Other (Income) Expense, Net	(3		)	1			(4		)	(1		)
Total	$	(1	)	$	(12	)	$	3		$	(20	)

⁽¹⁾  Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.

⁽²⁾  Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold CostsandItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update.

⁽³⁾  For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.

⁽⁴⁾  Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

⁽⁵⁾  Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

⁽⁶⁾  Amount relates to an adjustment of inventory to its net realizable value.

⁽⁷⁾  Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.

11

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2016			December 31, 2015
Accounts Receivable, Net
Commodity Sales	$	317		$	298
Joint Interest Billings	66			20
Proceeds Receivable (1)	40			—
Other	86			151
Allowance for Doubtful Accounts	(23		)	(19		)
Total	$	486		$	450
Other Current Assets
Inventories, Materials and Supplies	$	75		$	92
Inventories, Crude Oil	25			23
Assets Held for Sale (2)	214			67
Prepaid Expenses and Other Current Assets	38			34
Total	$	352		$	216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries	$	460		$	453
Mutual Fund Investments	83			90
Commodity Derivative Assets	—			10
Other Assets	44			67
Total	$	587		$	620
Other Current Liabilities
Production and Ad Valorem Taxes	$	121		$	166
Commodity Derivative Liabilities	27			—
Income Taxes Payable	168			86
Asset Retirement Obligations	128			128
Interest Payable	93			83
Current Portion of Capital Lease Obligations	61			53
Other	144			161
Total	$	742		$	677
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	232		$	217
Asset Retirement Obligations	820			861
Production and Ad Valorem Taxes	35			68
Commodity Derivative Liabilities	8			—
Other	44			73
Total	$	1,139		$	1,219

⁽¹⁾  Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.

⁽²⁾  Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures.

12

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 3. Noble Midstream Partners LP

Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream's current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas.

Initial Public Offering of Noble Midstream Partners LP On September 15, 2016, Noble Midstream common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016, Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts). 

In exchange for the contributed assets, Noble Energy received:

• 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream;

• 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream;

• incentive distribution rights in Noble Midstream; and

• the right to receive a cash distribution from Noble Midstream.

In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream, which is not entitled to receive cash distributions.

Noble Midstream generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million. In third quarter 2016, Noble Midstream made a distribution of $297 million to Noble Energy.

Note 4.Divestitures

Onshore US Properties During the first nine months of 2016, we entered into certain onshore transactions for which we:

• entered into a purchase and sale agreement for the divestiture of certain producing and non-producing crude oil and natural gas interests covering approximately 33,100 net acres in the DJ Basin for $505 million, subject to customary closing adjustments. We have received proceeds of $486 million and expect to receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss;

• closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43 million, and recognized a $23 million loss on sale of assets;

• closed a cashless acreage exchange within the DJ Basin to receive approximately 11,700 net acres within our Wells Ranch development area of the field in exchange for approximately 13,500 net acres primarily from our Bronco area of the field. No gain or loss was recognized for the transaction; and

• sold certain other non-producing interests within the DJ Basin, generating net proceeds of $20 million, and other certain smaller onshore US property packages, resulting in net proceeds of $19 million, during the first nine months of 2016. Proceeds received were applied to the respective field's basis with no recognition of gain or loss.

Subsequent to third quarter 2016, we closed the divestiture of certain Eagle Ford assets that were classified as assets held for sale of $68 million as of September 30, 2016. Total proceeds received will be applied to the field's basis with no recognition of gain or loss.

During the first nine months of 2015, we sold certain onshore US crude oil and natural gas interests in the DJ Basin, generating net proceeds of $151 million. Proceeds were applied to the field's basis with no recognition of gain or loss.

Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized.

13

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Offshore Israel Assets On July 4, 2016, we signed a definitive agreement to divest a 3% working interest in the Tamar field, offshore Israel, for $369 million, subject to customary closing adjustments. Under the terms of the agreement, the purchaser has the option to elect, before closing, to purchase an additional 1% working interest at the same valuation. The divestiture has an effective date of January 1, 2016 and is expected to close in fourth quarter 2016.

In November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, for a total transaction value of $73 million. These assets were held for sale as of December 31, 2015, and the transaction closed in January 2016.

Note 5.Rosetta Merger

On July 20, 2015, Noble Energy completed the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statements of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta common stock using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs in 2015 of approximately $81 million, including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and were included in Other Operating (Income) Expense, Net.

Allocation of Purchase Price The merger has been accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.

The following table sets forth our final purchase price allocation:

	(in millions, except stock price)
Shares of Noble Energy common stock issued to Rosetta shareholders	41
Noble Energy common stock price on July 20, 2015	$	36.97
Fair value of common stock issued	$	1,518
Plus: Fair value of Rosetta's restricted stock awards and performance awards assumed	10
Plus: Rosetta stock options assumed	1
Total purchase price	1,529
Plus: Liabilities assumed by Noble Energy
Accounts Payable	100
Current Liabilities	37
Long-Term Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	$	3,708
Fair Value of Rosetta Assets
Cash and Equivalents	$	61
Other Current Assets	76
Derivative Instruments	209
Oil and Gas Properties
Proved Reserves	1,613
Undeveloped Leaseholds	1,355
Gathering & Processing Assets	207
Asset Retirement Obligation	27
Other Property Plant and Equipment	5
Long Term Deferred Tax Asset	17
Goodwill (1)	138
Total Asset Value	$	3,708

14

Noble Energy, Inc.

Notes to Consolidated Financial Statements

⁽¹⁾  As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. 

The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. 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. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.

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

The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $119 million and $333 million and pre-tax net loss of $4 million and $17 million were generated from Rosetta assets during the three and nine months ended September 30, 2016, respectively.

Proforma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) adjustments to conform Rosetta's historical policy of accounting for its crude oil and natural gas properties from the full cost method to the successful efforts method of accounting, (ii) depletion of Rosetta's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share amounts)	2016 (1)			2015			2016 (1)			2015
Revenues	$	910		$	846		$	2,481		$	2,619
Net Loss Attributable to Noble Energy	$	(144	)	$	(202	)	$	(746	)	$	(338	)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Basic	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)
Diluted	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)

⁽¹⁾  No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

Note 6.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 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.

15

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Unsettled Commodity Derivative Instruments   As of September 30, 2016, 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
2016	Call Option (1)	NYMEX WTI	5,000	$	—	$	—	$	—	$	54.16
2016	Swaps	NYMEX WTI	16,000	67.69		—		—		—
2016	Swaps (2)	(3)	6,000	90.28		—		—		—
2016	Two-Way Collars	NYMEX WTI	10,000	—		—		40.50		53.42
2016	Three-Way Collars	NYMEX WTI	8,000	—		54.50		65.63		79.03
2016	Swaps	Dated Brent	9,000	97.96		—		—		—
2016	Three-Way Collars	Dated Brent	8,000	—		72.50		86.25		101.79
1H17 (4)	Swaps	NYMEX WTI	6,000	55.08		—		—		—
1H17 (4)	Two-Way Collars	NYMEX WTI	2,000	—		—		40.00		50.44
1H17 (4)	Swaps	Dated Brent	3,000	62.80		—		—		—
2H17 (4)	Call Option (1)	NYMEX WTI	3,000	—		—		—		60.12
2H17 (4)	Swaptions (5)	Dated Brent	3,000	—		—		—		62.80
2H17 (4)	Swaptions (5)	NYMEX WTI	3,000	—		—		—		50.05
2017	Two-Way Collars	NYMEX WTI	7,000	—		—		40.00		53.29
2017	Call Option (1)	NYMEX WTI	3,000	—		—		—		57.00
2017	Swaptions (5)	NYMEX WTI	4,000	—		—		—		47.34
2017	Three-Way Collars	NYMEX WTI	15,000	—		36.33		46.33		60.68
2017	Three-Way Collars	Dated Brent	2,000	—		35.00		45.00		66.33
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⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽³⁾  The indices for these derivative instruments are NYMEX WTI and Argus LLS.

⁽⁴⁾  We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year.

⁽⁵⁾  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.

16

Noble Energy, Inc.

Notes to Consolidated Financial Statements

As of September 30, 2016, 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
2016	Swaps	NYMEX HH	70,000	3.24	—	—	—
2016	Two-Way Collars	NYMEX HH	30,000	—	—	3.00	3.50
2016	Three-Way Collars	NYMEX HH	90,000	—	2.83	3.42	3.90
2016	Swaps (1)	(2)	30,000	4.04	—	—	—
2016	Two-Way Collars (1)	(2)	30,000	—	—	3.50	5.60
1H17	Swaps	NYMEX HH	30,000	2.92	—	—	—
2H17	Swaptions (3)	NYMEX HH	30,000	—	—	—	2.92
2017	Swaps	NYMEX HH	30,000	3.15	—	—	—
2017	Swaptions (3)	NYMEX HH	60,000	—	—	—	3.14
2017	Three-Way Collars	NYMEX HH	180,000	—	2.50	2.93	3.58
2017	Two-Way Collars	NYMEX HH	70,000	—	—	2.93	3.32
2018	Three-Way Collars	NYMEX HH	70,000	—	2.50	2.80	3.76

⁽¹⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽²⁾  The index for these derivative instruments is Houston Ship Channel.

⁽³⁾  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 Loss (Gain) 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
	September 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity DerivativeInstruments	Current Assets	$	120	Current Assets	$	582	Current Liabilities	$	27	Current Liabilities	$	—
	Noncurrent Assets	—		Noncurrent Assets	10		Noncurrent Liabilities	8		Noncurrent Liabilities	—
Total		$	120		$	592		$	35		$	—

17

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Cash Received in Settlement of Commodity Derivative Instruments
Crude Oil	$	(119	)	$	(235	)	$	(395	)	$	(578	)
Natural Gas	(13		)	(42		)	(59		)	(98		)
NGLs	—			(7		)	—			(7		)
Total Cash Received in Settlement of Commodity Derivative Instruments	(132		)	(284		)	(454		)	(683		)
Non-cash Portion of Loss on Commodity Derivative Instruments
Crude Oil	80			4			441			301
Natural Gas	(3		)	3			66			41
NGLs	—			10			—			10
Total Non-cash Portion of Loss on Commodity Derivative Instruments	77			17			507			352
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(39		)	(231		)	46			(277		)
Natural Gas	(16		)	(39		)	7			(57		)
NGLs	—			3			—			3
Total Loss (Gain) on Commodity Derivative Instruments	$	(55	)	$	(267	)	$	53		$	(331	)

18

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 7.Debt

Debt consists of the following:

	September 30, 2016					December 31, 2015
(millions, except percentages)	Debt			Interest Rate		Debt				Interest Rate
Revolving Credit Facility, due August 27, 2020	$	—		—	%	$	—			—	%
Noble Midstream Revolving Credit Facility, due September 20, 2021	—			—	%	—			—	—	%
Capital Lease and Other Obligations	368			—	%	403				—	%
Term Loan Facility, due January 6, 2019	1,400			1.70	%	—				—	%
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	%	693				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	%	597				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	%	499				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	%
Total	7,957					7,976
Unamortized Discount	(23		)			(24		)
Unamortized Premium	17					113
Unamortized Debt Issuance Costs	(36		)			(36		)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	7,915					8,029
Less Amounts Due Within One Year
Capital Lease Obligations	(61		)			(53		)
Long-Term Debt Due After One Year	$	7,854				$	7,976

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, and (iii) includes a sub-limit for letters of credit up to an aggregate amount of $500 million ($450 million of this capacity is committed as of September 30, 2016).

Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services, a subsidiary of Noble Midstream, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Revolving Credit Facility). The Noble Midstream Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Revolving Credit Facility may be increased by an additional $350 million subject to certain conditions and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream.

Borrowings by Noble Midstream under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream's option, either:

• 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

• in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

The Noble Midstream Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated EBITDA and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower

19

Noble Energy, Inc.

Notes to Consolidated Financial Statements

under the Noble Midstream Revolving Credit Facility, are guaranteed by Noble Midstream and all wholly-owned material subsidiaries of Noble Midstream.

Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility will accrue 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) a London interbank offered rate plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a London interbank offered rate, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 1.70% as of September 30, 2016.

In connection with the Term Loan Facility, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.38 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations.

Subsequent Event On November 1, 2016, we prepaid $850 million of borrowings under our Term Loan Facility from cash on hand.

See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

Note 8.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 6. 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.

Phantom Units The fair value of phantom unit awards is measured based on the fair market value of our common stock on the date of grant. We recognize the value of these awards utilizing the liability method whereby these liability awards are remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 2. Basis of Presentation.

20

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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)
September 30, 2016
Financial Assets
Mutual Fund Investments	$	83		$	—		$	—	$	—		$	83
Commodity Derivative Instruments	—			133			—		(13		)	120
Financial Liabilities
Commodity Derivative Instruments	—			(48		)	—		13			(35		)
Portion of Deferred Compensation Liability Measured at Fair Value	(105		)	—			—		—			(105		)
Portion of Stock Based Compensation Liability Measured at Fair Value	(6		)	—			—		—			(6		)
December 31, 2015
Financial Assets
Mutual Fund Investments	$	90		$	—		$	—	$	—		$	90
Commodity Derivative Instruments	—			600			—		(8		)	592
Financial Liabilities
Commodity Derivative Instruments	—			(8		)	—		8			—
Portion of Deferred Compensation Liability Measured at Fair Value	(98		)	—			—		—			(98		)

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

Inventory Adjustment Materials and supplies inventories are stated at the lower of cost or net realizable value. For the nine months ended September 30, 2016, we recorded a downward adjustment of $14 million to reduce inventory to its estimated net realizable value.

Asset Impairments  We periodically evaluate our oil and gas properties for impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. In line with accounting standards, we use an undiscounted cash flow model as an indicator of possible impairment. Where circumstances warrant, we use a discounted cash flow model based on management’s expectations of future production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent futures price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate. For the nine months ended September 30, 2016, no impairment was indicated. Impairments for the nine months ended September 30, 2015 were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs.

Assets Held for Sale In cases where assets meet the criteria to be classified as assets held for sale and a loss is expected, the underlying assets are written down to fair value less costs to sell. For the nine months ended September 30, 2016, we recorded a downward adjustment of $23 million to reflect the loss on divestiture of our Bowdoin property in northern Montana. See Note 4. Divestitures.

21

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Information about impaired assets is as follows:

	Fair Value Measurements Using
	Quoted Prices in  Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Book Value (1)		Total Pre-tax (Non-cash) Impairment Loss
(millions)
Nine Months Ended September 30, 2016
Material and Supplies Inventory Adjustment	$	—	$	—	$	91	$	105	$	14
Loss on Divestitures	—		—		42		65		23
Impaired Oil and Gas Properties	—		—		—		—		—
Nine Months Ended September 30, 2015
Impaired Oil and Gas Properties	—		—		—		43		43

⁽¹⁾  Amount represents net book value at the date of assessment.

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 7. Debt.

Fair value information regarding our debt is as follows:

	September 30, 2016				December 31, 2015
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt, Net (1)	$	7,547	$	7,976	$	7,626	$	7,105

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

Note 9.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)	Nine Months Ended September 30, 2016
Capitalized Exploratory Well Costs, Beginning of Period	$	1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	83
Divestitures and Other (1)	(143		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(1		)
Capitalized Exploratory Well Costs Charged to Expense (2)	(83		)
Capitalized Exploratory Well Costs, End of Period	$	1,209

22

Noble Energy, Inc.

Notes to Consolidated Financial Statements

⁽¹⁾  Includes $143 million relating to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.

⁽²⁾  Includes amounts related to contract termination offshore Falkland Islands, Dolphin 1 exploratory well offshore Israel, and Silvergate exploratory well deepwater Gulf of Mexico.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: 

(millions)	September 30, 2016		December 31, 2015
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	91	$	95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	1,118		1,258
Balance at End of Period	$	1,209	$	1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	13		14

23

Noble Energy, Inc.

Notes to Consolidated Financial Statements

The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of September 30, 2016:

(millions)	Total by Project		Progress
Country/Project:
Deepwater Gulf of Mexico
Troubadour	$	52	Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
Katmai	97		Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options.
Offshore Equatorial Guinea Blocks I and O
Diega (Block I) and Carmen (Block O)	240		Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Carla (Block O)	184		Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Yolanda (Block I)	22		A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries.
Felicita (Block O)	45		Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Offshore Cameroon
YoYo (YoYo Block)	53		A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries.
Offshore Israel
Leviathan	196		Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands.
Leviathan-1 Deep	84		The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
Dalit	31		Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar.
Offshore Cyprus

24

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Cyprus	88		During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision.
Other
Individual Projects Less than $20 million	26		Continuing to assess and evaluate wells.
Total	$	1,118

Undeveloped Leasehold Costs

Undeveloped leasehold costs as of September 30, 2016 totaled $2.0 billion, comprising $1.9 billion related to core onshore US unproved properties, $116 million related to Gulf of Mexico unproved properties, and $32 million related to international unproved properties.

As part of our quarterly impairment review, we evaluate our exploration opportunities. 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 either (1) impairment expense related to individually significant leases or (2) a decrease in the valuation of our pool of individually insignificant leases.

During third quarter 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico and offshore Falkland Islands leases and licenses and determined that several, representing $105 million of undeveloped leasehold cost, should be relinquished or exited. As a result, we recognized $81 million of leasehold impairment expense and recorded a $24 million decrease in our valuation pool of individually insignificant leases.

Note 10.Asset Retirement Obligations

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

	Nine Months Ended September 30,
(millions)	2016			2015
Asset Retirement Obligations, Beginning Balance	$	989		$	751
Liabilities Incurred	5			54
Liabilities Settled	(87		)	(29		)
Revision of Estimate	4			79
Accretion Expense (1)	37			32
Asset Retirement Obligations, Ending Balance	$	948		$	887

⁽¹⁾  Accretion expense is included in Depreciation, Depletion and Amortization (DD&A)expense in the consolidated statements ofoperations.

For the nine months ended September 30, 2016Liabilities incurred were due to new wells and facilities placed into service for onshore US and deepwater Gulf of Mexico. Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful life and primarily included activities for Gulf of Mexico of $42 million and onshore US of $40 million.

For thenine months ended September 30, 2015 Liabilities incurred were due to new wells and facilities for onshore US and deepwater Gulf of Mexico as well as liabilities assumed in the Rosetta Merger. Liabilities settled primarily related to non-core, onshore US properties sold.

Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing of abandonment and included $43 million for Eastern Mediterranean and $28 million for DJ Basin.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 11.Loss Per Share

Noble Energy's basic loss per share of common stock is computed by using net 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 loss per share:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except per share amounts)	2016			2015			2016			2015
Net Loss Attributable to Noble Energy	$	(144	)	$	(283	)	$	(746	)	$	(413	)
Weighted Average Number of Shares Outstanding, Basic (1)	430			420			430			392
Weighted Average Number of Shares Outstanding, Diluted(2)	430			420			430			392
Loss Per Share, Basic	$	(0.33	)	$	(0.67	)	$	(1.73	)	$	(1.05	)
Loss Per Share, Diluted	(0.33		)	(0.67		)	(1.73		)	(1.05		)
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14			14			15			11

⁽¹⁾  The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

⁽²⁾  For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy 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.

Note 12.Income Taxes

The income tax benefit consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Current	$	148		$	(45	)	$	213		$	64
Deferred	(285		)	69			(699		)	(244		)
Total Income Tax (Benefit) Provision	$	(137	)	$	24		$	(486	)	$	(180	)
Effective Tax Rate	48.9		%	(9.3		)%	39.5		%	30.4		%

Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2015, we no longer consider our foreign subsidiaries’ undistributed earnings to be indefinitely reinvested outside the US and, accordingly, we now record additional deferred income taxes, net of estimated foreign tax credits.

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 and nine months ended September 30, 2016, varied as compared with the three and nine months ended September 30, 2015, resulting in a higher income tax benefit and ETR primarily due to:

• a higher loss before income taxes for the first nine months of 2016 as compared with the first nine months of 2015;

• a period to period shift of the individual components of net income (loss) among tax jurisdictions with different rates, which is also impacted by the timing and magnitude of divestiture activities. See Note 4. Divestituresand Note 13. Segment Information; and

• the change in our permanent reinvestment assumption, noted above, which resulted in additional deferred income tax expense (net of estimated foreign tax credits) being recorded on certain income items, including income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, which reduced the income tax benefit.

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

26

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 13.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); West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we exited in second quarter 2015)); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, Falkland Islands, Suriname, Nicaragua (which we exited in first quarter 2015) and new ventures.

(millions)	Consolidated			United States			West Africa			Eastern Mediterranean		Other Int'l & Corporate
Three Months Ended September 30, 2016
Revenues from Third Parties	$	882		$	639		$	93		$	150	$	—
Income from Equity Method Investees	28			8			20			—		—
Total Revenues	910			647			113			150		—
DD&A	621			539			46			23		13
Gain on Commodity Derivative Instruments	(55		)	(48		)	(7		)	—		—
(Loss) Income Before Income Taxes	(280		)	(407		)	47			135		(55		)
Three Months Ended September 30, 2015
Revenues from Third Parties	$	783		$	510		$	120		$	152	$	1
Income from Equity Method Investees	36			16			20			—		—
Total Revenues	819			526			140			152		1
DD&A	539			437			67			22		13
Gain on Commodity Derivative Instruments	(267		)	(187		)	(80		)	—		—
(Loss) Income Before Income Taxes	(259		)	(189		)	98			107		(275		)
Nine Months Ended September 30, 2016
Revenues from Third Parties	$	2,411		$	1,705		$	299		$	407	$	—
Income from Equity Method Investees	70			39			31			—		—
Total Revenues	2,481			1,744			330			407		—
DD&A	1,859			1,612			150			62		35
Loss on Divestitures	23			23			—			—		—
Loss on Commodity Derivative Instruments	53			44			9			—		—
(Loss) Income Before Income Taxes	(1,231		)	(882		)	74			290		(713		)
Nine Months Ended September 30, 2015
Revenues from Third Parties	$	2,264		$	1,448		$	432		$	378	$	6
Income from Equity Method Investees	60			35			25			—		—
Total Revenues	2,324			1,483			457			378		6
DD&A	1,444			1,138			223			52		31
Gain on Commodity Derivative Instruments	(331		)	(231		)	(100		)	—		—
(Loss) Income Before Income Taxes	(593		)	(353		)	195			227		(662		)
September 30, 2016
Total Assets	$	22,469		$	17,752		$	1,975		$	2,515	$	227
December 31, 2015
Total Assets	24,196			18,831			2,299			2,677		389

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 14.Commitments and Contingencies

CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at September 30, 2016.

The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. The funding has been suspended since November 2014 due to lower natural gas prices. Based on the September 30, 2016 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months.

On October 29, 2016, we entered into an agreement with CONSOL to separate ownership of our jointly owned Marcellus Shale acreage, satisfy and extinguish the remaining balance of our carried cost obligation and terminate the joint development agreement. See Part II. Other Information, Item 5. Other Information.

Delivery and Firm Transportation Commitments We have commitments to deliver approximately 493 Bcf of natural gas produced onshore US (primarily in the Marcellus Shale) under long-term sales contracts and have also entered into various long-term gathering, processing and transportation contracts for approximately 271 MMBbls of crude oil and nearly 6 Tcf of natural gas for certain of our onshore US production (primarily in the Marcellus Shale, DJ Basin and Eagle Ford Shale).

We enter into long-term contracts to provide production flow assurance in over-supplied basins and/or areas with limited infrastructure. This strategy provides for optimization of transportation and processing costs. As properties are undergoing development activities, we may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. For the three and nine months ended September 30, 2016, we incurredexpense of approximately $12 million and $39 million, respectively, related to deficiencies and/or unutilized commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. Should commodity prices continue to 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.

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 not yet precisely quantifiable as they will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.

Compliance with the Consent Decree could result in the temporary shut in or 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. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.  Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.     

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 Air Compliance Order on Consent  In December 2015, 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 certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions that applied to assets currently owned and operated by both Noble Energy and Noble Midstream Services, LLC.  In May, 2016, Noble Energy on behalf of itself and its wholly owned subsidiary Noble Midstream Services, LLC, on behalf of itself and its wholly owned subsidiary Colorado River DevCo LP, reached a final resolution with the APCD, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695, and an expenditure of no less than $178,780 on an approved SEP. This resolution is not believed to 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 our 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 aim to achieve sustainable growth in value and cash flow through the development of a high-quality portfolio of assets with investment flexibility. Our core operating areas include: onshore US, primarily the DJ Basin, Marcellus Shale, Eagle Ford Shale and Permian Basin; offshore US Gulf of Mexico; West Africa; and Eastern Mediterranean. In these areas, we believe we have a strategic competitive advantage and will generate attractive returns throughout oil and gas business cycles.

Our portfolio is further complemented through the pursuit of certain exploration opportunities as we seek to establish potential new core areas, such as Suriname and Gabon. We may conclude that an exploration area is not commercially viable and, therefore, may exit locations, such as we did in 2015 with Nevada, Sierra Leone and Nicaragua.

The following discussion highlights significant operating and financial results for third quarter 2016. This discussion includes operating results associated with our Rosetta Merger, which closed in third quarter of 2015, and should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Third Quarter 2016 Significant Operating Highlights Included:

• maintained cost reduction efforts in capital, lease operating expense and general and administrative areas, with sustained efforts to further optimize operational performance in the current commodity price environment (see Cost Reduction Efforts, below);

• averaged quarterly total sales volumes of 425 MBoe/d, net, including 270 MBoe/d, net, from onshore US assets;

• completed the initial public offering of Noble Midstream common units and generated net proceeds of $299 million;

• completed an acreage exchange which further enhances our Wells Ranch position in Colorado;

• continued to enhance well completion designs across our onshore US assets leading to capital efficiencies;

• initiated production on our fourth operated well in the Permian Basin;

• set a quarterly sales volume record of 313 MMcfe/d, net, in Israel, primarily reflecting seasonal demand and increased use of natural gas over coal to fuel power generation;

• reached a cumulative gross production milestone of one trillion cubic feet from our Tamar field since initial production in first quarter 2013;

• continued to work towards a final investment decision of our Leviathan field, including the execution of a natural gas sales agreement with NEPCO (defined below) of up to approximately 120 MMcf/d, net to Noble;

• entered into an agreement for the divestiture of 3% working interest in the Tamar field for $369 million;

commenced production in July 2016 from our Gunflint field, deepwater Gulf of Mexico, which contributed 6 MBoe/d, net, during the quarter;

• assumed operatorship of the Thunder Hawk Production Facility which processes production from our Big Bend and Dantzler fields in the Gulf of Mexico; and

• completed hook-up and commissioning activities at the Alba B3 compression project, offshore Equatorial Guinea, which commenced production in July 2016.

Third Quarter 2016 Financial Results Included:

• net loss of $144 million, as compared with net loss of $283 million for third quarter 2015;

• net gain on commodity derivative instruments of $55 million, as compared with net gain on commodity derivative instruments of $267 million for third quarter 2015;

29

• reduced lease operating expense unit costs by 12% as compared to third quarter 2015, driven by increased sales volumes and cost efficiencies;

• reduced general and administrative expense unit costs by 22% as compared to third quarter 2015, driven by a decline in total costs as a result of continued cost reduction initiatives and increased sales volumes;

• recorded $81 million of exploration expense due to the write-off of certain leases and licenses in the Gulf of Mexico and offshore Falkland Islands;

• diluted loss per share of $0.33, as compared with diluted loss per share of $0.67 for third quarter 2015;

• cash flow provided by operating activities of $614 million, as compared with $520 million for third quarter 2015;

• cash proceeds from divestitures of $19 million, as compared with none for third quarter 2015; and

• capital expenditures of $297 million, as compared with $664 million for third quarter 2015.

Quarter-End Key Financial Metrics Included:

• ending cash balance of $1.8 billion, as compared with $1.0 billion at December 31, 2015;

• total liquidity of approximately $5.8 billion at September 30, 2016, as compared with $5.0 billion at December 31, 2015; and

• ratio of debt-to-book capital of 45% at September 30, 2016, as compared with 43% at December 31, 2015. 

Initial Public Offering of Noble Midstream Partners LP

On September 20, 2016, Noble Midstream completed its initial public offering of common units. Noble Midstream owns, operates and will develop certain of our DJ Basin crude oil, natural gas and water-related midstream infrastructure and will also develop crude oil and produced water midstream infrastructure in our Delaware position of the Permian Basin. Noble Energy owns the general partner interest in Noble Midstream and retains a majority of limited partnership interests in the master limited partnership.

Impact of Current Commodity Prices on our Business

In early 2016, we saw crude oil trading below $30 per barrel and natural gas trading for less than $2 per MMBtu. By mid-year 2016, commodity prices slowly began to increase, with crude oil prices trading between $40 to $50 per barrel and natural gas trading between $2 to above $3 per MMBtu. While both crude oil and natural gas prices have shown signs of modest improvement since March 2016, the global economy, related supply and demand and inventory levels for such commodities indicate a continued range-bound but volatile price environment.

In response to the commodity price environment, we have taken a disciplined approach to our 2016 capital program by focusing on long-term value creation, optimizing allocation of capital and driving operational and cost efficiencies across our asset portfolio. Our current 2016 capital spending program accommodates an investment level of less than $1.5 billion, approximately 50% lower than 2015 and approximately 70% lower than 2014. See Operating Outlook – 2016 Capital InvestmentProgram, below.

Positioning for the Future 

We have taken steps to sustain our business in the current volatile commodity price environment. We have undertaken a comprehensive effort to maintain strong liquidity and balance sheet, manage our capital investment and asset portfolio and maximize operational returns, particularly through use of existing infrastructure; to this end, we have:

• allocated capital towards areas with the most favorable returns at current prices, including focusing resources towards onshore US and Eastern Mediterranean activities, while complementing our capital program through proceeds from asset divestitures;

• hedged a portion of our future revenues for 2016 to 2018 in order to mitigate the effects of commodity price volatility;

• adjusted the quarterly dividend to 10 cents per common share beginning in first quarter 2016, representing a reduction of 8 cents, or 44%, from 2015 quarterly dividend levels;

• engaged in debt refinancing activities in first quarter 2016 by tendering for certain outstanding notes and refinanced with a lower cost three year loan (1.70% as of September 30, 2016). In late 2015, we also extended our Revolving Credit Facility maturity date from 2018 to 2020;

• completed our initial public offering of Noble Midstream common units which provided access to capital markets to support funding of our onshore US midstream investment program; and

• prepaid $850 million of borrowings under our Term Loan Facility from cash on hand in November 2016.

We believe we are well positioned to address a volatile commodity price environment, and have positioned the Company for sustainable value creation, financial strength and flexibility, improved capital and operational efficiency, and long-term success throughout the oil and gas business cycle. However, if industry conditions were to persist in the range below $40 per barrel, or becomes more severe, we could experience additional material negative impacts on our production revenues, asset values,

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profitability, cash flows, liquidity and proved reserves. In response, we may consider further reductions in our capital program or dividends, and additional asset sales and/or more organizational changes. Our production and our stock price could decline further as a result of these potential developments.

Cost Reduction Efforts

We continue to focus on maintaining a strong safety culture, driving operational efficiencies, increasing productivity and leveraging the current commodity price environment to reduce our cost structure. Cost reduction initiatives, including operational enhancements, reduction of overhead costs and new pricing arrangements with suppliers, have resulted in total lease operating expense and general and administrative expense decreases as compared to third quarter 2015 and first nine months of 2015 while sales volumes increased nearly 50 MBoe/d, or 12%, and 90 MBoe/d, or 27%, respectively, compared to the same periods in prior year. Our initiatives and focused efforts overall have lead to declining unit costs for the respective comparable periods. In addition, we have applied integrated development plan learnings from other onshore US assets to realize cost efficiencies, enhance completion designs and to optimize well placement, thereby positively impacting costs and performance associated with our Texas assets, which were acquired in mid-2015.

In addition, our onshore and global portfolio provides significant optionality, which has allowed us to reduce our capital program by approximately 50% in 2016, as compared to 2015. As the majority of our onshore US assets are held by production, our portfolio flexibility allows us to invest at levels appropriate to the current commodity price environment.

Sales Volumes

On a barrel of oil equivalent basis, or BOE, total sales volumes were 12%higher for third quarter 2016 as compared with third quarter 2015, and our mix of sales volumes was 44% global liquids, 34% US natural gas and 22% international natural gas. On a BOE basis and excluding the impact of the Rosetta Merger, total sales volumes were 8%higher for third quarter 2016 ascompared with third quarter 2015, and our mix of sales volumes was 40% global liquids, 34% US natural gas and 26%international natural gas. See Results of Operations – Revenues, below.

Commodity Price Changes

Crude oil prices are driven by global crude oil supply and demand factors. Since 2014, crude oil has become oversupplied as production from both OPEC and non-OPEC producers has increased, while global crude oil demand growth was curtailed by lower global economic growth, especially in Europe and developing countries, coupled with slower growth in China driven by the country's continuing economic reform. The outlook for crude oil prices for the remainder of 2016 and beyond depends primarily on supply and demand dynamics and geopolitical and security concerns in crude oil-producing nations. With OPEC production output reaching new peaks, the group announced in September 2016 its intention to limit future production in an attempt to re-balance the market. OPEC's commitment and ability to enforce this initiative, as well as Russia and other international emerging crude oil producers agreeing to freeze or curtail production, is not yet evident and may not materialize. On the demand side, recent projections reflect an increase in anticipated global crude oil demand growth as consumption increases in both India and China.

Longer term, we expect supply and demand to re-balance as global economies expand. With commodity prices experienced in early 2016, many producers reduced capital investments which will, over time, reduce production and stored inventory levels, helping to balance supply and demand in the crude oil market.

We plan for commodity price cyclicality in our business and believe we are well positioned to withstand current and future commodity price volatility due to the following:

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• we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;

• we have hedged a portion of our domestic natural gas and global liquids sales volumes through 2018;

• we have significantly reduced our capital investment program which has allowed us to respond to the low commodity price conditions in 2016;

• we have achieved substantial cost reductions impacting both operating expenses and capital expenditures;

• we have adjusted our quarterly dividend to 10 cents per common share; and

• we have robust liquidity of approximately $5.8 billion at September 30, 2016 and ability to access capital markets.

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.

DJ Basin (Onshore US)   During the quarter, we operated two drilling rigs, drilled 23 wells and commenced production on 43 wells. In third quarter 2016, we closed an acreage exchange agreement to receive approximately 11,700 net acres within our Wells Ranch development area of the field in exchange for approximately 13,500 net acres primarily from our Bronco area of the field, located southwest of Wells Ranch. The exchange enhances our ability to develop the field by improving our contiguous acreage position, increasing our lateral length potential and optimizing our access to central gathering facilities.

During second quarter 2016, we entered into an agreement to divest approximately 33,100 producing and undeveloped net acres in the Greeley Crescent area of Weld County, Colorado for $505 million, representing approximately 8% of our total DJ Basin acreage. We received partial proceeds of $486 million in second quarter 2016 and expect to receive the remaining proceeds in mid-2017.

Both of these transactions facilitate our asset monetization and allow for the acceleration of asset development. We continue to improve and enhance our completion designs, and as a result, we were able to deliver production at lower capital and lease operating expense costs than third quarter of 2015.

Marcellus Shale (Onshore US)   Currently, we have no operated or non-operated rigs running in the Marcellus Shale. For 2016, we and CONSOL have agreed to operate within cash flow and have agreed to a plan which will focus on well completions. As such, our allocated capital to be invested in the Marcellus Shale is limited to the completion of certain previously-drilled wells primarily located in non-operated dry gas areas. In third quarter 2016, our joint venture partner completed six wells and no wells commenced production during the quarter.

Eagle Ford Shale and Permian Basin (Onshore US) During third quarter 2016, our Eagle Ford Shale activity was focused within Gates Ranch where we operated one drilling rig, drilled five horizontal wells and commenced production on five wells. In the Permian Basin, we operated one drilling rig, drilled one horizontal well, and commenced production from one well which targeted the Upper Wolf Camp A bench. We have continued improving our completion designs and are applying best practices from our other onshore US operations, including utilizing slickwater and hybrid gel as completion fluids and testing varying cluster spacing, lateral lengths and proppant quantities. For the remainder of 2016, we are adding one rig each in the Eagle Ford Shale and the Permian Basin for a total of two rigs in each basin, as we plan to increase activity in these plays heading into 2017.

Gunflint (Deepwater Gulf of Mexico) Gunflint (31% operated working interest) was a 2008 crude oil discovery, utilizing a two-well subsea tieback to the third-party owned Gulfstar One Production Facility. Production commenced in July 2016 and contributed 6 MBoe/d, net, during third quarter 2016.

Alba Field (Offshore Equatorial Guinea) The Alba B3 compression platform was successfully installed in first quarter 2016. In July 2016, hook-up and commissioning activities were completed and first production commenced. The successful completion of this project extends the resource recovery life and slows the natural decline of this field.

Tamar Southwest We continue to work with the Government of Israel to obtain regulatory approval of our development plan, which is intended to utilize current Tamar infrastructure. The Government of Israel agreed, following a recommendation of the Israeli Supreme Court, to enter into mediation discussions that may resolve the dispute relating to the possible unitization of the Eran license, which is adjacent to the Tamar Southwest field. Timely development of Tamar Southwest will help reinforce the reliability for our Tamar project and support increased demand.

Unsanctioned Development Projects

Leviathan Project (Offshore Israel)   Our Plan of Development was approved by the Government of Israel during second quarter 2016 and we and our partners are performing front-end engineering design (FEED) studies necessary to progress the

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project to final investment decision (project sanction). Timing of project sanction depends on numerous factors, including completion of necessary marketing activities, engineering and construction planning and availability of funds from us and our partners to invest in the project.

The marketing and development of natural gas from this asset is intended to serve both domestic demand and regional export. We are actively engaged in natural gas marketing activities and executed our third natural gas sales and purchase agreement in third quarter 2016. This agreement would supply up to 350 MMcf/d, gross, or approximately 120 MMcf/d, net to Noble, of natural gas from the Leviathan field to the National Electric Power Company Ltd. (NEPCO) of Jordan for consumption in power production facilities over a 15-year period.  The execution of this agreement is subject to regulatory approvals from both Israel and Jordan. Sales to NEPCO are anticipated to commence at field startup. We expect to complete construction and field development to deliver first gas from Leviathan in as little as three years following sanction. The initial Leviathan field development will be a subsea tie-back to a shallow-water platform with a connection to the Israel Natural Gas Lines (INGL) pipeline network. See Update on Israel Natural Gas Regulatory Framework and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Tamar Expansion Project (Offshore Israel) We have begun the planning phase for an expansion project which would expand Tamar field deliverability 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. See Update on Israel Natural Gas Regulatory Framework, below.

Cyprus Project (Offshore Cyprus)  During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized. We will continue to operate with a 35% interest. As part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.

During 2015, we submitted a Declaration of Commerciality and in second quarter 2016, we submitted an updated Development Plan to the Government of Cyprus. We continue to work with the Government of Cyprus to obtain approval of the development plan and the issuance of an Exploitation License for the Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite gas, will allow us and our partners to perform the necessary FEED studies and progress the project to final investment decision. In preparation for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential development of Aphrodite field that, as currently planned, would deliver natural gas to potential customers in Cyprus and Egypt.

See Item 1. Financial Statements – Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Exploration Program Update

Our 2016 exploration budget has been substantially reduced compared to prior years as we adapt to the current pricing environment. While we are conducting limited exploratory activities in 2016, our core areas provide for exploration opportunities where we can apply new technologies and innovative drilling and completion designs to enhance field economics.

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 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Updates on significant exploration activities are as follows:

Deepwater Gulf of Mexico In first quarter 2016, drilling operations were completed at our Silvergate exploration well (50% operated working interest). The well did not encounter commercial hydrocarbons and was plugged and abandoned, resulting in dry hole expense of $79 million. In second quarter 2016, we spud our Katmai 2 appraisal well (38% operated working interest), located in Green Canyon Block 39, and encountered high pressure in the untested fault block. In response, we temporarily abandoned the well and are assessing plans to progress appraisal. As of September 30, 2016, we have capitalized approximately $43 million of costs associated with our Katmai 2 appraisal well.

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Offshore West Africa We are interpreting and evaluating recently acquired 3D seismic data across Equatorial Guinea Blocks I and O which will aid in advancing exploration and development opportunities, including the Diega/Carmen and Carla discoveries.

Offshore Cameroon  We have an interest in approximately 167,800 undeveloped acres offshore Cameroon in our YoYo mining concession (100% operated working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options and are negotiating with the Cameroon government to convert the YoYo mining concession to a production sharing contract.

In July 2016, we relinquished our acreage position in the Tilapia block (46.67% operated working interest) to the Cameroon government which covered an area of approximately 900,000 gross acres. We continue to work with the Cameroon government to finalize our exit from this block.

Offshore Eastern Mediterranean In July 2016, the Petroleum Commissioner of Israel deemed our Dolphin 1 (39.66% operated working interest) 2011 natural gas discovery to be non-commercial. As a result, we recorded exploration expense of $26 million in second quarter 2016 due to the expiration of our exploration license. For other offshore Eastern Mediterranean updates, see Update on Israel Natural Gas Regulatory Framework, below.

Offshore Falkland Islands In 2015, we experienced material operational issues with a drilling rig while drilling the Humpback well. The same drilling rig was scheduled to drill another prospect but due to significant safety and operational concerns, the drilling contract was terminated in first quarter 2016. As a result, we expensed $44 million of capitalized rig costs relating to pre-drill activities which are reflected in other operating expense, net in the consolidated statements of operations in 2016. We have been working closely with our partners and the Falkland Islands Government to evaluate a path forward for our Rhea prospect, located in the North Falkland Basin adjacent to a third party's 2010 Sea Lion discovery, and in third quarter 2016, we received a three year extension for this license. We also held certain other licenses located in both the South and North Falkland Basins. Following completion of our geological assessment in third quarter 2016, we began the process of exiting all licenses outside of the Rhea prospect which resulted in a $25 million leasehold impairment charge in third quarter 2016. See Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Offshore Suriname  The initial phase of exploration on Block 54 (non-operated 20% working interest) requires acquisition of a 3D seismic survey, which has been completed and is currently being processed.  Following our evaluation of the seismic survey, we will determine if a commitment to a subsequent exploration phase to drill an exploration well is warranted.

Offshore Gabon We are the operator of Block F15 (60% working interest), an undeveloped, deep water area. Our exploration commitment includes a 3D seismic obligation which was acquired during second quarter 2016 and is currently being processed. Final product delivery is anticipated early 2017.

Update on Israel Natural Gas Regulatory Framework

The Natural Gas Framework (Framework), as adopted by the Government of Israel, provides clarity on numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters, which we will rely upon to support a final investment decision and proceed with the development of these resources while ensuring economic benefits to the state of Israel and its citizens. The Framework provides for the reduction of our ownership interest in Tamar to 25% within six years, while enabling the marketing of Leviathan natural gas to Israeli customers. The development of Leviathan will substantially expand our capacity to deliver natural gas to Israel and the region, as well as provide a second source of domestic natural gas supply and redundancy of infrastructure.

In second quarter 2016, the Government of Israel adopted a new economic stability clause which does not prevent possible adverse legislation but instead provides for project economic stability in the event of certain future adverse actions. While it is possible that adoption of the new stability clause could be challenged in the Israeli Supreme Court, we believe this new clause addresses concerns raised by the Court in its March 2016 ruling and is consistent with that ruling.

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 enhances our balance sheet strength. We will continue to evaluate divestment opportunities of other assets within our portfolio.

See Item 1. Financial Statements – Note 4. Divestitures and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below.

Update on Regulations

US Offshore Regulatory Developments On April 14, 2016, the Bureau of Safety and Environmental Enforcement (BSEE) adopted a final rule updating requirements for blowout prevention systems and other well controls for offshore oil and gas activities conducted on the Outer Continental Shelf, including the Gulf of Mexico. Although the final rule incorporates some of

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the changes recommended by the oil and gas industry, it imposes a number of new requirements relating to well design, well control, casing, cementing, real-time well monitoring and subsea containment. For example, the new rule requires double sets of shear rams on all deepwater blowout preventers (BOPs), periodic inspections of BOPs and outside audits of equipment, and real-time well monitoring requirements. The new rule will likely increase the costs associated with well design, drilling and completion operations, and monitoring of rig based operations in the Gulf of Mexico. The final rule went into effect on July 28, 2016.

On March 17, 2016, the Bureau of Ocean Energy Management (BOEM) proposed a new air quality rule that would significantly broaden the scope of air emission sources for operations on the Outer Continental Shelf, including the Gulf of Mexico, that be must assessed, reported and when appropriate controlled. Among other items, the proposed rule would expand the types of emissions that must be measured, change the boundary for evaluating air emissions, and increase the scope of sources that must be addressed. If adopted as proposed, the new rule would likely increase the cost associated with our activities in the Gulf of Mexico. The comment period for the proposed rule expired June 20, 2016.

On July 14, 2016, the BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures the agency will be using to determine a lessee’s ability to carry out decommissioning obligations for activities on the Outer Continental Shelf, including the Gulf of Mexico. This revised policy became effective September 12, 2016 and institutes new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active on the Outer Continental Shelf. If the BOEM determines under the revised policy that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. We estimated the impact of the new financial criteria on our operations in the Gulf of Mexico and do not believe that the revised policy will have a material impact on our operations in the Gulf of Mexico.

The National Oceanic and Atmospheric Administration (NOAA) is proposing to expand the boundaries of the Flower Garden Banks National Marine Sanctuary in the Gulf of Mexico. NOAA released its draft environmental impact statement (DEIS) on the proposed expansion in June 2016, in which it proposed five alternatives for expanding existing sanctuary regulations to new geographic areas. Two of these alternatives for sanctuary expansion have the potential to impact certain leases which could increase drilling, operating and decommissioning costs. The comment period for the expansion alternatives outlined in the DEIS expired on August 19, 2016. We are currently evaluating the expansion alternatives and assessing any potential impact on our operations in the Gulf of Mexico.

Colorado Crude Oil and Natural Gas Regulation The Colorado Oil and Gas Task Force (Task Force) was established by executive order and made up of representatives of local governments, civic entities, environmental organizations and industry for the purpose of making recommendations regarding oil and gas development in communities. The Task Force issued nine recommendations to the governor of Colorado, all of which were adopted by legislation or regulation. The Colorado Oil and Gas Conservation Commission issued new rules governing the siting of large oil and gas operations in urban areas and the coordination of drilling operations with local governments. These new rules took effect in March 2016.

Earlier in 2016, the State of Colorado approved for signature gathering, four ballot measures which, if adopted, would have significantly limited or, under certain circumstances, prevented the future development of crude oil and natural gas in areas where we conduct operations. The measures sought to grant local communities the opportunity to ban certain businesses from operating in their jurisdictions, establish a constitutional right to a healthy environment and oblige local governments to protect the environment, grant local governments control over oil and gas development and require that all new oil and gas facilities be located 2,500 feet from occupied structures.

Only two of the four ballot measures completed the signature gathering phase before the August 8, 2016 deadline. However, neither of those measures garnered the 98,492 valid signatures necessary to be included on the November 2016 ballot.

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

Pennsylvania Crude Oil and Natural Gas Regulation  On October 8, 2016, the Pennsylvania Department of Environmental Protection issued a final rule amending Pennsylvania Code Chapter 78a revising requirements for surface activities related to unconventional oil and gas operations. The final rule increases requirements for permitting, waste handling, water management and restoration, surface reclamation, and requirements related to abandoned and orphaned wells. These regulations may increase operating costs and cause delays. 

Impact of Dodd-Frank Act Section 1504  On June 27, 2016, the SEC adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that will require resource extraction companies, such as us, to publicly file with the SEC 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

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development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government. Reporting and disclosure will be required annually beginning with the 2018 fiscal year.

Recently Issued Accounting Standards

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

OPERATING OUTLOOK

2016 Production   Our expected crude oil, natural gas and NGL production for the remainder of 2016 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;

• 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 3% working interest in the Tamar field which will lower our sales volumes;

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

• natural field decline in the onshore US, 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 onshore US 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 onshore US delivery points;

• impact of enhanced completion efforts for onshore US assets;

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

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

• purchases of producing properties or divestments of operating assets.

2016 Capital Investment Program Given the current commodity price environment, we designed a substantially reduced but flexible capital investment program in order to manage our balance sheet while preserving and building value. Our 2016 capital investment program accommodates an investment level of less than $1.5 billion, or approximately 50% lower than our 2015 program, with approximately two-thirds of total investment to core onshore US assets and the remaining one-third to offshore development and exploration. With our successful completion of offshore developments in the Gulf of Mexico and Equatorial Guinea in mid-2016, our capital program for the remainder of 2016 will be focused in our onshore US areas, where we receive the best returns and are able to maximize use of existing infrastructure, and progressing the development of our assets offshore Israel. For the remainder of 2016, we intend to operate two rigs in the DJ Basin and are adding one rig each in the Eagle Ford Shale and the Permian Basin for a total of two rigs in each basin, as we plan to increase activity in these plays heading into 2017. Offshore Israel, we spud our Tamar 8 development well in late October 2016 which will increase supply reliability and accelerate our development of the Tamar field.

See Liquidity and Capital Resources – Financing Activities.

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

Exploration Activities Our exploratory drilling program seeks to provide long-term growth from existing and potential new core areas. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, in the first nine months of 2016, we recorded total dry hole expense of $105 million primarily associated with our Silvergate exploratory well in the Gulf of Mexico and our Dolphin 1 discovery offshore Israel. The Silvergate well did not encounter commercial hydrocarbons and was plugged and abandoned, and our Dolphin 1 discovery was ruled by the Petroleum Commissioner of Israel to be non-commercial. See Item 1. Financial Statements - Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Results of Operations - Oil and Gas Exploration Expense, below.

Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, we continue to mature our prospect portfolio. However, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. In addition, the current commodity price environment may render certain prospects economically less attractive and we may not conduct exploration activities before lease expiration. During third quarter 2016, we accelerated our geological evaluation of certain of these leases and determined that several of them should be relinquished. As a result, we recorded $56 million of leasehold impairment expense related to

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certain of our deepwater Gulf of Mexico leases. During third quarter 2016, we also completed our geological assessment of licenses located in the South and North Falkland Basins near the Falkland Islands. Following completion of our geological assessment in third quarter 2016, we began the process of exiting all licenses outside of the Rhea prospect which resulted in a $25 million leasehold impairment charge in third quarter 2016.

We currently have remaining capitalized undeveloped leasehold cost of approximately $116 million relating to deepwater Gulf of Mexico prospects that have not yet been drilled and are scheduled to expire over the years 2017 to 2026. Changes in exploration plans, availability of capital and suitable rig and drilling equipment, insufficient resource potential, changing regulations and/or other factors, could result in future impairment. Moreover, in the deepwater Gulf of Mexico, some leases may become impaired for other reasons such as production not being established, foregoing actions to extend the terms of the leases, and/or leases becoming uneconomic due to commodity prices or the rising costs of complying with new regulations.

As a result of our exploration activities, future exploration expense, including leasehold expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below. See also Item 1A. Risk Factors.

Development Concept Selection Costs For our Leviathan and Cyprus discoveries, full field development may require several phases, with various facilities serving both domestic and regional export demand. In order to determine an optimum development scenario for these discoveries, we and our partners engage in development planning, also known as pre-FEED and FEED studies. Furthermore, we may progress pre-FEED and FEED studies simultaneously for multiple development options, with the realization that only one option may ultimately be approved or be economically feasible. This simultaneous progression of multiple options enables us to advance a final investment decision and quality development of resources in a timely and efficient manner.

Conducting pre-FEED and FEED work to varying degrees for a range of phased development scenarios may result in our incurring significant charges, as compared with pre-FEED and FEED costs incurred for previous offshore projects where the resources were not as significant. Other factors that may increase our pre-FEED and FEED costs include location of a field in a remote and/or under-developed area, lack of availability of, or capacity at, third party production platforms or other infrastructure, technical complexity, market availability, and significant time and effort required for government approval.

Once the final development plan has been determined and our board of directors has sanctioned a final investment decision, we expect to identify certain development scenarios that must be eliminated from further consideration. As a result, final investment decision for our Leviathan project may result in the write-off of pre-FEED and FEED costs, estimated at approximately $100 million, pre-tax, as of September 30, 2016. Pre-FEED and FEED costs are included in our capitalized development well cost balances.

Producing Properties We did not recognize any material impairments during the nine months ended September 30, 2016. 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, alone could result in an impairment.

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, the operator of the MacCulloch North Sea field has notified working interest owners that the scope and magnitude of decommissioning activities has been revised downward, resulting in a potentially accelerated project timeline with lower field abandonment costs. As of September 30, 2016, we had a total asset retirement obligation of $84 million related to this 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 10. Asset Retirement Obligations.

Divestments We actively manage our asset portfolio. If properties are reclassified as assets held for sale in the future, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 4. Divestitures.

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RESULTS OF OPERATIONS

Revenues

Revenues were as follows:

					(Decrease) / Increase from Prior Year
(millions)	2016		2015
Three Months Ended September 30,
Oil, Gas and NGL Sales	$	882	$	783	13	%
Income from Equity Method Investees	28		36		(22	)%
Total	$	910	$	819	11	%
Nine Months Ended September 30,
Oil, Gas and NGL Sales	$	2,411	$	2,264	6	%
Income from Equity Method Investees	70		60		17	%
Total	$	2,481	$	2,324	7	%

Changes in revenues are discussed below.

Oil, Gas and NGL Sales

We generally sell crude oil, natural gas, and NGLs under two types of agreements common in our industry. Both types of agreements may include transportation charges. One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser. In the case of NGLs, we may receive a price from the purchaser, which is net of fractionation and processing costs. Historically, we have recorded revenue at the net price we had received from the purchaser, net of transportation, fractionation or processing costs. Beginning in 2016, we changed our presentation of revenue to no longer include expenses netted from revenue by the purchaser. Crude oil, natural gas and NGL sales are now shown without deductions relating to transportation, fractionation or processing. These deductions are now recorded as production expense. Prior year amounts, including revenues, expenses, average realized sales prices and average production costs per BOE, have been reclassified to conform to the current presentation. For NGL sales, amounts reclassified for the three and nine months ended September 30, 2015 totaled $18 million and $37 million, respectively. Amounts reclassified for crude oil and natural gas sales were de minimis.

In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant. For example, transportation bottlenecks and oversupply in the Marcellus Shale have reduced the amount of production reaching higher priced out-of-basin locations. As a result of location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.

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

	Sales Volumes				Average Realized Sales Prices
	Crude Oil & Condensate (MBbl/d)	Natural Gas (MMcf/d)	NGLs (MBbl/d)	Total (MBoe/d) (1)	Crude Oil & Condensate (Per Bbl)		Natural Gas (Per Mcf)		NGLs (Per Bbl)
Three Months Ended September 30, 2016
United States	99	874	55	299	$	41.23	$	2.38	$	14.70
Equatorial Guinea (2)	22	261	—	65	43.73		0.27		—
Israel	—	310	—	52	—		5.22		—
Total Consolidated Operations	121	1,445	55	416	41.67		2.61		14.70
Equity Investees (3)	2	—	7	9	45.72		—		23.65
Total	123	1,445	62	425	$	41.75	$	2.61	$	15.66
Three Months Ended September 30, 2015
United States	83	741	49	255	$	42.42	$	2.01	$	11.37
Equatorial Guinea (2)	27	231	—	65	45.99		0.27		—
Israel	—	303	—	51	—		5.39		—
Total Consolidated Operations	110	1,275	49	371	43.30		2.50		11.37
Equity Investees (3)	2	—	6	8	51.41		—		24.86
Total	112	1,275	55	379	$	43.44	$	2.50	$	12.73
Nine Months Ended September 30, 2016
United States	99	902	56	304	$	37.23	$	2.00	$	13.38
Equatorial Guinea (2)	25	230	—	64	40.74		0.27		—
Israel	—	284	—	48	—		5.19		—
Total Consolidated Operations	124	1,416	56	416	37.94		2.36		13.38
Equity Investees (3)	2	—	5	7	43.95		—		24.43
Total	126	1,416	61	423	$	38.02	$	2.36	$	14.32
Nine Months Ended September 30, 2015
United States	73	658	34	217	$	46.02	$	2.20	$	13.77
Equatorial Guinea (2)	29	221	—	66	52.15		0.27		—
Israel	—	254	—	43	—		5.39		—
Other International (4)	1	—	—	1	55.52		—		—
Total Consolidated Operations	103	1,133	34	327	47.79		2.54		13.77
Equity Investees (3)	2	—	5	6	51.67		—		28.77
Total	105	1,133	39	333	$	47.85	$	2.54	$	15.64

⁽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.

⁽⁴⁾  Other International includes de minimis North Sea sales volumes with last production in May 2015.

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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			Natural Gas			NGLs			Total
Three Months Ended September 30, 2015	$	438		$	293		$	52		$	783
Changes due to
Increase in Sales Volumes	34			29			10			73
(Decrease) Increase in Sales Prices	(11		)	25			12			26
Three Months Ended September 30, 2016	$	461		$	347		$	74		$	882
Nine Months Ended September 30, 2015	$	1,352		$	785		$	127		$	2,264
Changes due to
Increase in Sales Volumes	176			185			82			443
Decrease in Sales Prices	(237		)	(54		)	(5		)	(296		)
Nine Months Ended September 30, 2016	$	1,291		$	916		$	204		$	2,411

Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales increased for third quarter 2016 and decreased for first nine months of 2016 as compared with 2015 due to the following:

• decreases in average realized prices primarily due to the decline in global commodity prices that began in the second half of 2014; and

• natural field decline at Alen and Aseng in offshore Equatorial Guinea;

partially offset by:

• production from the Big Bend and Dantzler developments (deepwater Gulf of Mexico), which began producing fourth quarter 2015 and contributed 8 MBbl/d and 6 MBbl/d, net, respectively, during the first nine months of 2016;

• production from the Gunflint development (deepwater Gulf of Mexico), which began producing in July 2016 and contributed 4 MBbl/d, net, during the current quarter; and

• sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 11 MBbl/d and 6 MBbl/d, net, respectively, during the first nine months of 2016.

Natural Gas Sales – Revenues from natural gas sales increased during third quarter and first nine months of 2016 as compared with 2015 due to the following:

• 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;

• higher sales volumes in the Marcellus Shale due to commencement of production on 42 operated and non-operated wells, and the recognition of efficiencies in base production performance; and

• sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 135 MMcf/d and 9 MMcf/d, net, respectively, during the first nine months of 2016;

partially offset by:

• decreases in average realized prices primarily due to the decline in global commodity prices that began in the second half of 2014.

NGL Sales – Revenues from NGL sales increased during third quarter and first nine months of 2016 as compared with 2015 due to the following:

• higher sales volumes in the DJ Basin driven by higher NGL yields due to infrastructure operating efficiencies; and

• sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 23 MBbl/d and 1 MBbl/d, net, respectively, during the first nine months of 2016;

partially offset by:

• decreases in average realized prices primarily driven by oversupply.

Income from Equity Method Investees We have interests in equity method investees that operate midstream assets onshore US 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 nine months of 2016 as compared with 2015. The increase includes a $9 millionincrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee; a $3 million

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decrease from Alba Plant, our LPG investee, due to lower realized prices; and an increase of $4 million from our investments in CONE Gathering LLC and CONE Midstream Partners due primarily to higher throughput volumes.

Operating Costs and Expenses

Operating costs and expenses were as follows:

					Increase / (Decrease) from Prior Year
(millions)	2016		2015
Three Months Ended September 30,
Production Expense	$	274	$	247	11	%
Exploration Expense	125		203		(38	)%
Depreciation, Depletion and Amortization	621		539		15	%
General and Administrative	95		109		(13	)%
Other Operating Expense, Net	45		188		(76	)%
Total	$	1,160	$	1,286	(10	)%
Nine Months Ended September 30,
Production Expense	$	820	$	715	15	%
Exploration Expense	376		308		22	%
Depreciation, Depletion and Amortization	1,859		1,444		29	%
General and Administrative	293		308		(5	)%
Other Operating Expense, Net	66		310		(79	)%
Total	$	3,414	$	3,085	11	%

Changes in operating costs and expenses are discussed below.

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Production Expense   Components of production expense were as follows:

(millions, except unit rate)	Total per BOE (1)		Total		United States		Equatorial Guinea		Israel		Corporate
Three Months Ended September 30, 2016
Lease Operating Expense (2)	$	3.42	$	131	$	98	$	22	$	8	$	3
Production and Ad Valorem Taxes	0.78		30		30		—		—		—
Transportation and Gathering Expense  (3)	2.95		113		113		—		—		—
Total Production Expense	$	7.15	$	274	$	241	$	22	$	8	$	3
Total Production Expense per BOE			$	7.15	$	8.77	$	3.67	$	1.67	N/M
Three Months Ended September 30, 2015
Lease Operating Expense (2)	$	3.89	$	133	$	92	$	26	$	13	$	2
Production and Ad Valorem Taxes	0.83		28		28		—		—		—
Transportation and Gathering Expense  (3)	2.51		86		86		—		—		—
Total Production Expense	$	7.23	$	247	$	206	$	26	$	13	$	2
Total Production Expense per BOE			$	7.23	$	8.77	$	4.32	$	2.78	N/M
Nine Months Ended September 30, 2016
Lease Operating Expense (2)	$	3.62	$	413	$	305	$	75	$	25	$	8
Production and Ad Valorem Taxes	0.64		72		72		—		—		—
Transportation and Gathering Expense  (3)	2.94		335		335		—		—		—
Total Production Expense	$	7.20	$	820	$	712	$	75	$	25	$	8
Total Production Expense per BOE			$	7.20	$	8.53	$	4.30	$	1.91	N/M
Nine Months Ended September 30, 2015
Lease Operating Expense (2)	$	4.70	$	419	$	274	$	96	$	38	$	11
Production and Ad Valorem Taxes	1.00		89		89		—		—		—
Transportation and Gathering Expense (3)	2.32		207		207		—		—		—
Total Production Expense	$	8.02	$	715	$	570	$	96	$	38	$	11
Total Production Expense per BOE			$	8.02	$	9.61	$	5.32	$	3.27	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.

⁽³⁾  Certain of our revenue received from purchasers was historically presented with deduction for transportation, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation. See Results of Operations – Revenues, above.

For third quarter and first nine months of 2016, total production expense increased as compared with 2015 due to the following:     

• an increase in transportation and gathering expense due to higher production, including the addition of onshore US production from our Eagle Ford Shale and Permian Basin assets acquired in third quarter 2015, and from our Big Bend and Dantzler development projects in deepwater Gulf of Mexico, which began producing in fourth quarter 2015, and Gunflint in deepwater Gulf of Mexico, which began producing in July 2016;

partially offset by:

• a decrease in production and ad valorem taxes resulting from lower revenues and an onshore US severance tax refund, both driven by a decline in US commodity prices.

While total production expense has increased as a result of increased production for the respective periods compared to 2015, costs on a per BOE basis have declined. We are working to maintain lease operating expense cost reductions in areas such as equipment utilization and saltwater disposal which help to optimize cost and operational efficiencies.

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Exploration Expense   Components of exploration expense were as follows:

(millions)	Total			United States		West   Africa (1)		Eastern Mediter- ranean (2)		Other Int'l, Corporate (3)
Three Months Ended September 30, 2016
Leasehold Impairment and Amortization	$	96		$	71	$	—	$	—	$	25
Dry Hole Expense	5			—		—		—		5
Seismic, Geological and Geophysical	15			—		—		—		15
Staff Expense	15			1		—		—		14
Other (4)	(6		)	—		—		—		(6		)
Total Exploration Expense	$	125		$	72	$	—	$	—	$	53
Three Months Ended September 30, 2015
Leasehold Impairment and Amortization	$	41		$	41	$	—	$	—	$	—
Dry Hole Expense	135			—		27		—		108
Seismic, Geological and Geophysical	—			—		—		—		—
Staff Expense	27			3		—		2		22
Other (4)	—			—		—		—		—
Total Exploration Expense	$	203		$	44	$	27	$	2	$	130
Nine Months Ended September 30, 2016
Leasehold Impairment and Amortization	$	127		$	102	$	—	$	—	$	25
Dry Hole Expense	105			79		—		26		—
Seismic, Geological and Geophysical	47			—		10		—		37
Staff Expense	53			2		2		—		49
Other (4)	44			35		—		7		2
Total Exploration Expense	$	376		$	218	$	12	$	33	$	113
Nine Months Ended September 30, 2015
Leasehold Impairment and Amortization	$	78		$	73	$	—	$	5	$	—
Dry Hole Expense	154			18		27		—		109
Seismic, Geological and Geophysical	2			2		—		—		—
Staff Expense	72			2		2		4		64
Other (4)	2			—		—		2		—
Total Exploration Expense	$	308		$	95	$	29	$	11	$	173

⁽¹⁾  West Africa includes Equatorial Guinea, Cameroon, Sierra Leone (which we exited in second quarter 2015), and Gabon.

⁽²⁾  Eastern Mediterranean includes Israel and Cyprus.

⁽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 third quarter and first nine months of 2016 included:

• leasehold impairment expense primarily related to write-off of leases and licenses in the deepwater Gulf of Mexico of $56 million and Falkland Islands of $25 million;

• dry hole cost primarily related to the Silvergate exploratory well, deepwater Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel;

• seismic expense related to the acquisition of 3D seismic data in West Africa and other international areas;

• other cost for onshore US includes lease rentals primarily related to Permian Basin leases; and

• salaries and related expenses for corporate exploration and new ventures personnel.

Exploration expense for third quarter and first nine months of 2015 included the following:

• dry hole cost related to onshore US, offshore Cameroon (Cheetah), and Falkland Islands (Humpback) exploration wells;

• leasehold impairment, including a $41 million deepwater Gulf of Mexico lease; and

• salaries and related expenses for corporate exploration and new ventures personnel.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
DD&A Expense (millions) (1)	$	621	$	539	$	1,859	$	1,444
Unit Rate per BOE (2)	$	16.23	$	15.75	$	16.31	$	16.21

⁽¹⁾  For DD&A expense by geographical area, see Item 1. Financial Statements – Note 13. Segment Information.

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

Total DD&A expense for third quarter and first nine months of 2016increased as compared with 2015 due to the following:

• the addition of Eagle Ford Shale and Permian Basin production in third quarter 2015, resulting in $144 million and $31 million in DD&A expense, respectively, during the first nine months of 2016;

• an increase in sales volumes due to commencement of production from the Big Bend, Dantzler and Gunflint development projects in deepwater Gulf of Mexico, additional wells which came online in the Marcellus Shale and increased demand in Eastern Mediterranean; and

• a reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;

partially offset by:

• an overall lower segment rate for offshore Equatorial Guinea due to the swing in production between higher DD&A rate assets Aseng and Alen and lower DD&A rate asset Alba; and

• the impact of lower net book value as a result of a fourth quarter 2015 impairment for offshore Equatorial Guinea properties.

The increase in the unit rate per BOE for third quarter and first nine months of 2016 as compared with 2015 was due primarily to increased higher-cost production volumes from certain onshore US properties and recently commenced deepwater Gulf of Mexico assets, Big Bend, Dantzler and Gunflint. The increase in the unit rate per BOE was partially offset by an increase in lower-cost production volumes from the Tamar and Alba fields and reductions in net book values in fourth quarter 2015 mainly due to downward price revisions.

Significant changes to the proved reserves at December 31, 2015 include additions of 269 MMBoe resulting from the Rosetta Merger during the third quarter 2015, offset by downward revisions of 307 MMBoe that were commodity price driven. Estimates of proved reserves significantly affect our DD&A expense. Holding other factors constant, a decline in proved reserves estimates caused by decreases in the 12-month average commodity prices, will result in accelerating DD&A expense in future periods.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
G&A Expense (millions)	$	95	$	109	$	293	$	308
Unit Rate per BOE (1)	$	2.48	$	3.19	$	2.57	$	3.46

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

G&A expense for third quarter and first nine months of 2016 decreased as compared with 2015 primarily due to cost savings initiatives, including reduced use of contractors and consultants, decreased special projects and other discretionary expenses, and decreases in employee personnel costs, partially offset by the addition of Rosetta employees in the third quarter of 2015. The decrease in the unit rate per BOE for the third quarter and first nine months of 2016 as compared with 2015 was due primarily to the increase in production volumes in onshore US, deepwater Gulf of Mexico, and Eastern Mediterranean, and cost synergies achieved through the Rosetta Merger.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
(Gain) Loss on Asset Due to Terminated Contract	$	(3	)	$	—		$	44		$	—
Marketing and Processing Expense, Net	20			10			58			25
Loss on Divestitures	—			—			23			—
Corporate Restructuring Expense	—			21			—			39
Purchase Price Allocation Adjustment	—			—			(25		)	—
Gain on Extinguishment of Debt	—			—			(80		)	—
Asset Impairments	—			—			—			43
Inventory Adjustment	14			—			14			—
Building Exit Cost	4			18			8			18
Rosetta Merger Expenses	—			71			—			73
Pension Plan Expense	—			67			—			88
Stacked Drilling Rig Expense	3			13			8			20
Other, Net	7			(12		)	16			4
Total	$	45		$	188		$	66		$	310

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 September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016		2015
(Gain) Loss on Commodity Derivative Instruments	$	(55	)	$	(267	)	$	53	$	(331	)
Interest, Net of Amount Capitalized	86			71			242		183
Other Non-Operating Expense (Income), Net	(1		)	(12		)	3		(20		)
Total	$	30		$	(208	)	$	298	$	(168	)

(Gain) Loss on Commodity Derivative Instruments  (Gain) loss on commodity derivative instruments includes (i) cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts, respectively, and (ii) non-cash (increases) or decreases in the fair value of our crude oil and natural gas commodity derivative contracts, respectively.

Cash settlement gains for the third quarter and first nine months of 2016 were driven by crude oil and natural gas hedge contracts primarily executed in previous years when commodities were trading at higher prices. Our crude oil contracts contributed $95 million and $317 million of cash settlements and our natural gas contracts contributed $8 million and $34 million, respectively, of cash settlements received in the third quarter and first nine months of 2016. In addition, we acquired commodity derivative contracts as part of the Rosetta Merger. Acquired crude oil contracts contributed gains of $24 million and $78 million of cash settlements and acquired natural gas contracts contributed $5 million and $25 million, respectively, of cash settlements received in the third quarter and first nine months of 2016.

Non-cash decreases in the fair value of our crude oil and natural gas commodity derivative contracts of $77 million and $507 million for the third quarter and first nine months of 2016, respectively, were primarily driven by the evolving and diverse mix of derivative contracts (i.e. the type of derivative instrument, the commodity being hedged and related volumes), acquired commodity derivative contracts as part of the Rosetta Merger, and fluctuations of current period and future commodity prices.

 See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities andNote 8. Fair Value Measurements and Disclosures.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except unit rate)	2016			2015			2016			2015
Interest Expense, Gross	$	103		$	110		$	312		$	294
Capitalized Interest	(17		)	(39		)	(70		)	(111		)
Interest Expense, Net	$	86		$	71		$	242		$	183
Unit Rate per BOE (1)	$	2.25		$	2.08		$	2.12		$	2.05

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

Interest expense, gross, was flat for third quarter 2016 as compared with 2015. The increase in interest expense, gross, for the first nine months of 2016 as compared with 2015 is primarily due to the impact of senior notes assumed by us in the Rosetta Merger during third quarter 2015, a portion of which were subsequently tendered during first quarter 2016 through proceeds derived from our Term Loan Facility. See Item 1. Financial Statements - Note 7. Debt.

The decrease in capitalized interest for third quarter and first nine months of 2016 as compared with 2015 is primarily due to lower work in progress amounts related to major long-term projects including Big Bend and Dantzler, deepwater Gulf of Mexico, which were both completed in fourth quarter 2015 and Gunflint, deepwater Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were both completed in July 2016. Additional items that contributed to the decrease in capitalized interest include offshore Cyprus (due to the farm-out agreement with a partner for a 35% interest in Block 12 during fourth quarter 2015), offshore Falkland Islands (due to the Humpback prospect that began drilling operations in June 2015 and was determined to be a dry hole during fourth quarter 2015), and timing of onshore US activities. See Item 1. Financial Statements - Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

Income Taxes

See Item 1. Financial Statements – Note 12. Income Taxes for a discussion of the change in our effective tax rate for third quarter and first nine months of 2016 as compared with 2015.

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 volatile 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 capitalize on financially attractive periodic mergers and acquisitions activity.

We endeavor to maintain a strong balance sheet and investment grade debt rating in service of these objectives. We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.

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 sales of non-core properties. We occasionally access the capital markets and, in third quarter 2016, we monetized certain of our midstream assets through the initial public offering of Noble Midstream common units.

Initial Public Offering of Noble Midstream Partners LP

On September 20, 2016, Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts). In connection with the offering, Noble Midstream generated net proceeds of $299 million from the issuance of common units and distributed $297 million to us.

We own a 54.8% limited partner interest and a non-economic general partner interest in Noble Midstream, while the public owns a 45.2% limited partner interest. We consolidate Noble Midstream as a variable interest entity for financial reporting purposes; however, Noble Midstream's sources of liquidity are independent of Noble Energy. See Item 1. Financial Statements – Note 2. Basis of Presentation. The public's ownership interest in Noble Midstream is reflected as a noncontrolling interest in our financial statements as of September 30, 2016.

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Noble Midstream's partnership agreement provides for a minimum quarterly distribution to the holders of common units and subordinated units of $0.3750 per unit for each whole quarter, or $1.5000 per unit on an annualized basis, to the extent Noble Midstream has sufficient available cash after the establishment of cash reserves and the payment of certain costs and expenses. We own all of Noble Midstream's subordinated units and incentive distribution rights. Upon completion of certain events as outlined in Noble Midstream's partnership agreement, we will be entitled to receive additional distributions associated with these units.

Available Liquidity    Information regarding cash and debt balances as shown in the table below, does not include amounts held by Noble Midstream, which are not readily available to Noble Energy:

	September 30,			December 31,
(millions, except percentages)	2016			2015
Cash and Cash Equivalents	$	1,772		$	1,001
Amount Available to be Borrowed Under Revolving Credit Facility (1)	4,000			4,000
Total Liquidity	$	5,772		$	5,001
Total Debt (2)	$	7,957		$	7,976
Noble Energy Share of Equity	9,545			10,370
Ratio of Debt-to-Book Capital (3)	45		%	43		%

⁽¹⁾  Does not include $350 million available to be borrowed under Noble Midstream's Revolving Credit Facility, which is not available to Noble Energy. See Revolving Credit Facilities, below.

⁽²⁾  Total debt includes capital lease obligations and excludes unamortized debt discount/premium.

⁽³⁾  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 $1.8 billion in cash and cash equivalents at September 30, 2016, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $488 million of this cash is attributable to our foreign subsidiaries. We have recorded a related deferred tax liability on undistributed foreign earnings of $368 million for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credit. Our cash on hand at September 30, 2016 also included $47 million relating to Noble Midstream.

Revolving Credit Facilities Noble Energy's Revolving Credit Facility matures on August 27, 2020. The commitment is $4.0 billion through the maturity date of the Revolving Credit Facility. Noble Midstream's Revolving Credit Facility matures on September 20, 2021. The commitment is $350 million through the maturity date of Noble Midstream's Revolving Credit Facility. As of September 30, 2016, no amounts were outstanding under either of these facilities. Borrowings under these facilities subject us to interest rate risk. See Item 1. Financial Statements – Note 7. Debt andItem 3. Quantitative and Qualitative Disclosures About Market Risk.

Term Loan 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. On January 6, 2016, we entered into the Term Loan Facility which provides for a three-year term loan facility for a principal amount of $1.4 billion. In connection with the Term Loan Facility, we launched cash tender offers for certain senior notes assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Collectively, the result of these transactions provides for significant future interest expense savings with a shorter term debt maturity. While we have no near-term debt maturities, we may seek to access the capital markets to refinance a portion of our outstanding indebtedness. As of September 30, 2016, we had $7.5 billion of long-term debt outstanding, $2.4 billion of which is due first quarter 2019. On November 1, 2016, we prepaid $850 million of long-term debt outstanding under our Term Loan Facility from cash on hand. See Item 1. Financial Statements – Note 7. Debt.

Commodity Derivative Instruments   We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and enhanced swaps.

Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. We net settle by counterparty based on netting provisions within the master agreements. None of our counterparty agreements contain margin requirements. 

Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs.  As of September 30, 2016, the fair value of our commodity derivative assets was $120 million and the fair value of our commodity derivative liabilities was $35 million (after consideration of netting provisions within our master agreements).

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While we use commodity derivative instruments to mitigate our exposure to commodity price risk, thereby mitigating our exposure to price declines, these instruments may also limit our potential cash flows in periods of rising commodity prices or even place us in a liability position respective to our counterparties. For example, should commodity prices increase, certain of our swaptions are likely to be extended by our counterparties which could require us to pay monthly cash settlements if market prices exceed the contracted swap prices.

See Item 1. Financial Statements – Note8. Fair Value Measurements and Disclosures, for a description of the methods we use to estimate the fair values of commodity derivative instruments, and Credit Risk, below.

Asset Divestitures

In addition, we evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider non-core asset sales or other sources of funding. Furthermore, as required by the Framework, we are required to divest certain of our interests within a stipulated period of time. During the first nine months of 2016, we received cash proceeds of approximately $786 million primarily from our divestment of certain onshore US assets in the DJ Basin, our Cyprus farm-out and the sale of our Karish and Tanin discoveries, offshore Israel. On July 4, 2016, we signed a definitive agreement to divest a 3% interest in the Tamar field, offshore Israel, for $369 million, subject to customary closing adjustments. See Item 1. Financial Statements – Note 4. Divestitures.

Capital Program

Our 50% reduction in capital spending in 2016 as compared to 2015, coupled with operating efficiencies to increase production at lower costs, has allowed us to closely align capital spending with our operating cash flows. We will continue our effort to invest capital at a level supported by current operating cash flows. Our financial capacity and lack of near-term debt maturities, coupled with our diversified global portfolio, provides us with flexibility in our investment decisions including execution of major development projects and exploration activity.

Our investment program is primarily supported by production from our core onshore US development programs, combined with new production from our completed major offshore projects in the Gulf of Mexico (including the Big Bend and Dantzler development projects, which began producing in fourth quarter 2015, and from the Gunflint development, which began producing in July 2016), as well as completion of the Alba B3 compression project offshore Equatorial Guinea, which commenced production in July 2016. Presuming no significant further deterioration of commodity prices, cash flows from these assets will be available to meet a portion of our remaining 2016 capital commitments and will help to fund investments in subsequent years. See Results of Operations, above.

We are currently exploring potential financing scenarios, including use of external project financing arrangements as well as using local internal cash flows supplemented by asset divestiture proceeds, to develop our significant natural gas discoveries offshore Eastern Mediterranean. Each of our development options, including the development of Leviathan infrastructure to supply domestic and regional demands, would require a multi-billion dollar investment and require a number of years to complete. See Update on Israel Natural Gas Regulatory Framework, above.

Credit Risk   We monitor the creditworthiness of our trade creditors, joint venture partners, hedge counterparties, and financial institutions on an ongoing basis. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development projects. As operator of the joint ventures, we pay joint venture expenses and make cash calls on our non-operating partners for their respective shares of joint venture costs. Our projects are capital cost intensive and, in some cases, a non-operating partner may experience a delay in obtaining financing for its share of the joint venture costs or have liquidity problems resulting in slow payment of joint venture costs. In addition, in the event of bankruptcy or insolvency of a joint venture partner, we may be required to complete their share of remediation activities or fulfill their lease obligations which could result in significant financial losses.

We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses.

Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a trade creditor, joint venture partner, hedge counterparty or financial institution could result in significant financial losses.

Contractual Obligations

Marcellus Shale Joint Development Agreement  The joint development agreement for our jointly owned Marcellus Shale acreage provides for a multi-year drilling and development plan (default plan). We and CONSOL have agreed to an annual plan that provides for fewer wells to be drilled than the number of wells that was provided for in the default plan, and, for 2016, the amount of capital investment allocated to the Marcellus Shale core area will be less than the amount provided for in the default

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plan. Each of us has a non-consent right, which is the right to elect not to participate in all (but not less than all) of the operations provided for the following year. If one of us elects to exercise the non-consent right, then the other partner, in its sole discretion, may determine the number of wells, if any, it will drill in such year, which may be significantly less than the number of wells that was provided for in the default plan, or none at all. In the event we elect to exercise our non-consent right for a given year, we would still have to pay the carried costs that are contemplated by the development plan for that non-consent year. Under the joint development agreement, this non-consent right may be exercised by each partner twice (in non-consecutive years) prior to the termination of the default plan at the end of 2020. Neither of us has exercised the non-consent right, and thus, each of us may still elect to exercise the non-consent right twice (in non-consecutive years) prior to the end of 2020.

On October 29, 2016, we entered into an agreement with CONSOL to separate ownership of our jointly owned Marcellus Shale acreage, satisfy and extinguish the remaining balance of our carried cost obligation and terminate the joint development agreement. See Part II. Other Information, Item 5. Other Information.

CONSOL Carried Cost Obligation See Item 1. Financial Statements - Note 14. Commitments and Contingencies and Part II. Other Information, Item 5. Other Information

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

Continuous Development Obligations  Although the majority of our assets are held by production, certain of our onshore US 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 a lease. Our 2016 capital program allows for managing these obligations.

Delivery and Firm Transportation Agreements  We have entered into various long-term gathering, processing, transportation and delivery contracts for some of our onshore US crude oil and natural gas production. These contracts may commit us to deliver minimum volumes and require us to make payments for any shortfalls in delivering or transporting the minimum volumes under the commitments. We may use long-term contracts such as these, which may range in term from one to 40 years, to provide flow assurance for production and to enable our production to reach markets with best pricing.

Although we strive to schedule well completion activities to meet the minimum volumes under the commitments, we may experience temporary, and possibly prolonged, delivery or transportation shortfalls. During the first nine months of 2016, we incurred expense of approximately $39 million related to deficiencies and/or unutilized commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. For full year 2016, we estimate these costs could range from approximately $50 million to $60 million.

Should commodity prices continue to remain low or decline further, or 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 under these commitments. In the event that these commitments are not otherwise offset, we could be required to make future payments for any shortfalls. While 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.

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Cash Flows

Cash flow information is as follows:

	Nine Months Ended September 30,
(millions)	2016			2015
Total Cash Provided By (Used in)
Operating Activities	$	1,054		$	1,486
Investing Activities	(386		)	(2,393		)
Financing Activities	123			752
Increase (Decrease) in Cash and Cash Equivalents	$	791		$	(155	)

Operating Activities   Net cash provided by operating activities for the first nine months of 2016 decreased as compared with 2015. Decreases in average realized commodity prices and lower settlements of commodity derivative instruments were partially offset by increases in sales volumes. Working capital changes resulted in a $171 million operating cash flow reduction in the first nine months of 2016 as compared with a negative impact of $74 million in the first nine months of 2015.

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 decreased by $1.4 billion during the first nine months of 2016 as compared with 2015, primarily due to a reduced capital spending program. Investing activities included $8 million in CONE Gathering LLC during the first nine months of 2016 as compared with $86 million in the same period of 2015. We received $786 million in proceeds from asset divestitures during the first nine months of 2016, as compared with $151 million during the same period in 2015.

Financing Activities   Our financing activities include the issuance or repurchase of Noble Energy common stock and Noble Midstream common units, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first nine months of 2016, we received proceeds ($299 million) from our initial public offering of Noble Midstream common units and funds from the term loan acquisition ($1.4 billion). We used cash to pay dividends on our common stock ($129 million), fund the purchase of certain of our outstanding senior notes ($1.38 billion), and make principal payments related to capital lease obligations ($39 million).

In comparison, during the first nine months of 2015, funds were provided by cash proceeds from the issuance of Noble Energy common stock to the public ($1.1 billion). We used cash to pay dividends on our common stock ($214 million), repay outstanding borrowings under the Rosetta revolving credit facility and terminate the facility ($74 million) and make principal payments related to capital lease obligations ($49 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 September 30,				Nine Months Ended September 30,
(millions)	2016		2015		2016		2015
Acquisition, Capital and Exploration Expenditures
Property Acquisition (1)	$	21	$	21	$	60	$	86
Exploration	25		117		183		257
Development	202		458		597		1,695
Midstream (2)	9		26		29		123
Corporate and Other	38		21		58		78
Total	$	295	$	643	$	927	$	2,239
Other
Investment in Equity Method Investee (3)	$	2	$	21	$	8	$	86
Increase in Capital Lease Obligations	5		29		5		60

⁽¹⁾  Property acquisition cost for 2016 includes $28 million in the DJ Basin, $22 million in the Marcellus Shale, $5 million in the Permian Basin and $5 million in the Eagle Ford Shale. Proved property acquisition cost for 2015 includes $37 million in the DJ Basin and $43 million in the Marcellus Shale.

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⁽²⁾  Midstream cost for the three and nine months ended September 30, 2016 includes Noble Midstream capital expenditures of $8 million and $13 million, respectively. Midstream costs for the three and nine months ended 2015 includes Noble Midstream capital expenditures of $14 million and $49 million, respectively.

⁽³⁾  Investment in equity method investee represents primarily contributions to CONE Gathering LLC which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.

Total expenditures decreased during the first nine months of 2016 as compared with 2015 due to our reduced capital spending program. See Operating Outlook – 2016 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 September 30, 2016, there were no borrowings outstanding under the Revolving Credit Facility, leaving $4.0 billion available for use. We may rely on our Revolving Credit Facility to help fund our capital investment program, and may periodically borrow amounts for working capital purposes. On January 6, 2016, we entered into the Term Loan Facility with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three-year term loan facility for a principal amount of $1.4 billion. In connection with the Term Loan Facility, we launched cash tender offers for certain Senior Notes assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. On November 1, 2016, we prepaid $850 million of long-term debt outstanding under our Term Loan Facility from cash on hand. See Item 1. Financial Statements – Note 7. Debt.

Our outstanding fixed-rate debt (excluding capital lease obligations) totaled approximately $6.1 billion at September 30, 2016. 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 30 cents per share of common stock during the first nine months of 2016 as compared with 54 cents per share during the first nine months of 2015.

On October 25, 2016, our board of directors declared a quarterly cash dividend of 10 cents per common share, which will be paid on November 21, 2016 to shareholders of record on November 7, 2016. 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 $8 million during the first nine months of 2016 and $7 million during the first nine months of 2015.

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 235,157 shares with a value of $8 million during the first nine months of 2016 and 481,229 shares with a value of $20 million during the first nine months of 2015. 

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes   We areexposed 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. 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 September 30, 2016, 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 asset position with a fair value of $85 million. Based on the September 30, 2016 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately $70 million. A hypothetical price increase of 10% per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $33 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 6. Derivative Instruments and Hedging Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on borrowings under our Revolving Credit Facility, Noble Midstream Revolving Credit Facility and Term Loan Facility and the amount of interest we earn on our short-term investments.

At September 30, 2016, we had approximately $7.5 billion (excluding capital lease obligations) of long-term debt, net, outstanding. Of this amount, $6.1 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 September 30, 2016, our cash and cash equivalents totaled nearly $1.8 billion, approximately 65% 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 September 30, 2016, 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 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 and nine months ended September 30, 2016 and 2015.

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

Disclosure Regarding Forward-Looking Statements

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

• our growth strategies;

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

• anticipated trends in our business;

• our future results of operations;

• our liquidity and ability to finance our exploration and development activities;

• market conditions in the oil and gas industry;

• our ability to make and integrate acquisitions;

• the impact of governmental fiscal terms and/or regulation, such as those involving the protection of the environment or marketing of production, as well as other regulations; and

• access to resources.

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, 2015 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, 2015 is available on our website at www.nobleenergyinc.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

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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.

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Part II. Other Information

Item 1.    Legal Proceedings

See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements - Note 14. 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, 2015.

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, 2015, other than the following:

One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream, which may involve a greater exposure to legal liability than our historic business operations.

One of our subsidiaries acts as the general partner of Noble Midstream, a publicly traded master limited partnership. Our control of the general partner of Noble Midstream may increase the possibility that we could be subject to claims of breach of fiduciary duties, including claims of conflicts of interest, related to Noble Midstream. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.

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)
7/1/2016 - 7/31/2016	1,248	$	35.82	—	—
8/1/2016 - 8/31/2016	462	34.91		—	—
9/1/2016 - 9/30/2016	577	34.51		—	—
Total	2,287	$	35.31	—	—

⁽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

On October 29, 2016, we entered into an Exchange Agreement (the “Exchange Agreement”) with CNX Gas Company LLC, a subsidiary of CONSOL Energy Inc. (collectively, “CNX”), pursuant to which the parties will exchange interests in the oil and gas properties (including certain related assets, the “Co-Owned Properties”) that are jointly owned by us and CNX and subject to the Joint Development Agreement dated September 30, 2011, as amended (the “JDA”). The JDA provides for the joint development of the Co-Owned Properties and, in certain circumstances, requires us to fund one-third of CNX’s working interest share of certain drilling and completion costs incurred in connection with the Co-Owned Properties (the “Carried Costs”). As of October 1, 2016, the Carried Costs owed by Noble totaled $1.6 billion.

At the closing of the Exchange Agreement: (a) the remaining balance of our Carried Cost obligation will be satisfied and extinguished; (b) we will take all of CNX’s interest in a portion of the Co-Owned Properties; (c) CNX will take all of our interest in the remainder of the Co-Owned Properties; and (d) we will pay CNX $205 million in cash. The foregoing transactions are subject to certain adjustments provided for in the Exchange Agreement. The JDA will terminate effective upon the closing of the Exchange Agreement.

Following the closing of the Exchange Agreement, we will own and operate a 100% working interest in approximately 363,000 acres in the Marcellus Shale, predominantly in West Virginia, with associated average daily production of approximately 450 million cubic feet per day of natural gas equivalents for the month ended October 31, 2016.

The Exchange Agreement contains customary representations and warranties, covenants, indemnification obligations and the closing is subject to customary closing conditions. If either party terminates the Exchange Agreement because of a willful breach by the other party or the other party’s election not to close despite all of its closing conditions having been satisfied, the party terminating the Exchange Agreement is entitled to liquidated damages of $100 million from the other party.

The Exchange Agreement is expected to close on or about December 1, 2016, or if the conditions to closing identified in the Exchange Agreement have not yet been satisfied as of such date, as soon thereafter as such conditions have been satisfied or waived, but no later than January 31, 2017.

The Exchange Agreement is attached to this quarterly report on Form 10-Q as Exhibit 2.3 and is incorporated herein by reference. The foregoing summary has been included to provide information regarding the terms of the Exchange Agreement and is qualified in its entirety by the terms and conditions of the Exchange Agreement. It is not intended to provide any other factual information about us or our subsidiaries and affiliates. The Exchange Agreement contains representations and warranties, which were made by us only for purposes of the Exchange Agreement and as of specified dates. The representations, warranties and covenants in the Exchange Agreement were made solely for the benefit of the parties to the Exchange Agreement, may be subject to limitations agreed upon by the contracting parties, including being qualified by confidential disclosures made for the purposes of allocating contractual risk between the parties to the Exchange Agreement instead of establishing these matters as facts, and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors. The representations, warranties and covenants in the Exchange Agreement, or any descriptions thereof, should not be relied upon as characterizations of the actual state of facts or condition of us or any of our subsidiaries or affiliates.

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	November 2, 2016	/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	Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble Energy, Inc. including Appendix I (Definitions) thereto (filed as Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 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 herewith.
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 July 27, 2016) (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K (Date of Event: July 27, 2016) filed on July 29, 2016 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).
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

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EX-2.3

EXHIBIT 2.3

EXCHANGE AGREEMENT

BY AND BETWEEN

CNX GAS COMPANY LLC

as CONSOL

and

NOBLE ENERGY, INC.

as NOBLE

EXECUTED ON OCTOBER 29, 2016

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS AND INTERPRETATION    2

1.1Defined Terms    2

1.2References and Rules of Construction    3

ARTICLE II EXCHANGE    3

2.1CONSOL Transferred Assets    3

2.2Noble Transferred Assets    5

2.3Excluded Assets    7

2.4Revenues and Expenses    7

2.5Consideration    9

2.6Adjustments to Cash Consideration    9

2.7Adjustment Methodology    13

2.8Preliminary Settlement Statement    13

2.9Final Settlement Statement    14

2.10Disputes    15

2.11Allocated Values    15

ARTICLE III TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS; DISCLAIMERS    16

3.1General Disclaimer of Title Warranties and Representations    16

3.2Special Warranty    16

3.3Casualty or Condemnation Loss    16

3.4Preferential Purchase Rights and Consents to Assign    18

3.5Disclaimers    21

ARTICLE IV REPRESENTATIONS AND WARRANTIES OF CONSOL    23

4.1Organization, Existence    23

4.2Authorization    23

4.3No Conflicts    23

4.4Consents    23

4.5Bankruptcy    24

4.6Foreign Person    24

4.7Litigation    24

4.8No Violation of Laws    24

4.9CONSOL Preferential Purchase Rights    24

4.10Permits    24

4.11CONSOL Contracts    24

4.12Brokers’ Fees    25

4.13Environmental    25

4.14Notices of Claims    25

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4.15Bonds and Credit Support    26

4.16Independent Evaluation    26

4.17Taxes    26

ARTICLE V REPRESENTATIONS AND WARRANTIES OF NOBLE    26

5.1Organization, Existence    26

5.2Authorization    26

5.3No Conflicts    27

5.4Consents    27

5.5Bankruptcy    27

5.6Foreign Person    27

5.7Litigation    27

5.8No Violation of Laws    27

5.9Noble Preferential Purchase Rights    28

5.10Permits    28

5.11Noble Contracts    28

5.12Brokers’ Fees    28

5.13Environmental    28

5.14Notices of Claims    29

5.15Bonds and Credit Support    29

5.16Independent Evaluation    29

5.17Taxes    29

ARTICLE VI CERTAIN AGREEMENTS    30

6.1Conduct of Business by CONSOL    30

6.2Conduct of Business by Noble    32

6.3HSR Act    34

6.4Operatorship    34

6.5Governmental Bonds, etc.    35

6.6On-Going Leasing Activity    35

6.7Fill-In Acreage    35

6.8Target Net Acres    36

6.9Split of Certain FERC Regulated Downstream Contracts    38

6.10Easements    40

6.11Certain Other Contracts    40

6.12Amendment of Certain Schedules    41

6.13Water Assets    41

ARTICLE VII NOBLE’S CONDITIONS TO CLOSING    41

7.1Representations    41

7.2Performance    42

7.3No Legal Proceedings    42

7.4Certificate    42

7.5HSR Act    42

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7.6Closing Deliverables    42

ARTICLE VIII CONSOL’S CONDITIONS TO CLOSING    42

8.1Representations    42

8.2Performance    43

8.3No Legal Proceedings    43

8.4Certificate    43

8.5HSR Act    43

8.6Closing Deliverables    43

ARTICLE IX CLOSING    43

9.1Date of Closing    43

9.2Place of Closing    43

9.3Closing Obligations    43

9.4Records    45

ARTICLE X ASSUMPTION; INDEMNIFICATION; SURVIVAL    46

10.1Assumption by the Parties    46

10.2Indemnities of CONSOL    47

10.3Indemnities of Noble    49

10.4Limitation on Liability    50

10.5Express Negligence    51

10.6Exclusive Remedy    51

10.7Indemnification Procedures    52

10.8Survival    53

10.9Non-Compensatory Damages    54

10.10Cooperation by Concerning Litigation    55

10.11Waiver of Right to Rescission    55

10.12Insurance    55

10.13Materiality    55

ARTICLE XI TERMINATION, DEFAULT AND REMEDIES    55

11.1Right of Termination    55

11.2Effect of Termination    56

ARTICLE XII MISCELLANEOUS    57

12.1Appendices, Exhibits and Schedules    57

12.2Expenses and Taxes    57

12.3Tax Treatment    58

12.4Intentionally Omitted    59

12.5Dispute Resolution    59

12.6Assignment    59

12.7Preparation of Agreement    59

12.8Publicity    59

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12.9Notices    59

12.10Further Cooperation    61

12.11Filings, Notices and Certain Governmental Approvals    61

12.12Entire Agreement; Conflicts    62

12.13Successors and Permitted Assigns    62

12.14Parties in Interest    62

12.15Amendment    63

12.16Waiver; Rights Cumulative    63

12.17Governing Law; Jurisdiction; Venue; Jury Waiver    63

12.18Severability    63

12.19Counterparts    64

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LIST OF APPENDIXES, EXHIBITS AND SCHEDULES

Appendixes

Appendix I    ―    Definitions

Exhibits

Exhibit A-1 ―    CONSOL Transferred Leases - Part 1 (Limited to Marcellus Formation), Part 2 (Not Limited to Any Formation), Part 3 (Limited to Utica/Point Pleasant Formation) and Part 4 (Limited to Rhinestreet Formation); Allocated Values

Exhibit A-2 ―    CONSOL Transferred O/G Wells (WI/NRI), Allocated Values – Part 1, CONSOL Transferred NON-O/G Wells – Part 2

Exhibit A-3 ―    CONSOL Wholly Transferred Rights-Of-Way – Part 1, CONSOL Partially Transferred Rights-Of-Way – Part 2

Exhibit A-4 ―    CONSOL Contracts Wholly Assigned – Part 1; CONSOL Split-Up Contracts Assigned in– Part 2

Exhibit A-5    ―    CONSOL Excluded Assets

Exhibit A-6 ―    Permitted Encumbrances – Certain Assignments

Exhibit B-1 ―    Noble Transferred Leases – Part 1 (Limited to Marcellus Formation). Part 2 (Not Limited to Any Formation) and Part 3 (Limited to Rhinestreet Formation)

Exhibit B-2 ―    Noble Transferred O/G Wells (WI/NRI), Allocated Values – Part 1, Noble Transferred NON-O/G Wells – Part 2

Exhibit B-3 ―    Noble Wholly Transferred Rights-Of-Way – Part 1, Noble Partially Transferred Rights-Of-Way – Part 2

Exhibit B-4 ―    Noble Contracts Wholly Assigned – Part 1; Noble Split-Up Contracts Assigned – Part 2

Exhibit B-5    ―    Noble Excluded Assets

Exhibit B-6 ―    Permitted Encumbrances – Certain Assignments

Exhibit C-1    ―    Marcellus Formation Log

Exhibit C-2    ―    Utica/Point Pleasant Formation Log

Exhibit C-3    ―    Rhinestreet Formation Log

Exhibit D        Form of Termination and Release Agreement

Exhibit E-1    ―    Form of CONSOL Assignment

Exhibit E-2    ―    Form of CONSOL Deed

Exhibit E-3 ―    Form of Noble Assignment

Exhibit E-4    ―    Form of Noble Deed

Exhibit F    ―    Form of Memorandum of Termination and Release Agreement

Exhibit G-1    ―    Form of Shared Asset/Use Agreement

Exhibit G-2    ―    Form of Noble Water Facility Operating and Use Agreement

Exhibit G-3    ―    Form of CONSOL Water Facility Operating and Use Agreement

Exhibit H    ―    Quitclaim Properties

Exhibit I    ―    Form of Restriction Agreement

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Exhibit J-1    ―    Form of CONSOL Transition Services Agreement

Exhibit J-2    ―    Form of Noble Transition Services Agreement

Exhibit K-1     ―    Form of CONSOL’s Officer Certificate

Exhibit K-2     ―    Form of Noble’s Officer Certificate

Exhibit L ―    Petition for Temporary Waivers of Capacity Release Regulations and Related Pipeline Tariff Provisions

Exhibit M    ―    Intentionally Omitted

Exhibit N    ―    Master Netting Agreement

Exhibit O    ―    Target Net Acres Per Region

Schedules

Schedule 1.1    ―    CONSOL Areas and Noble Areas

Schedule 2.6    ―    Land Costs for Certain Offered AMI Properties

Schedule 4.3    ―    No Conflicts (CONSOL)

Schedule 4.4    ―    CONSOL Consents

Schedule 4.7    ―    Litigation (CONSOL) – Part 1 and Part 2

Schedule 4.8    ―    Violation of Laws (CONSOL)

Schedule 4.9    ―    CONSOL Preferential Purchase Rights

Schedule 4.11(b)    ―    Breaches of CONSOL Contracts

Schedule 4.13    ―    Environmental Matters (CONSOL)

Schedule 4.15    ―    Bonds and Credit Support

Schedule 5.3    ―    No Conflicts (Noble)

Schedule 5.4    ―    Noble Consents    

Schedule 5.7    ―    Litigation (Noble) – Part 1 and Part 2

Schedule 5.8    ―    Violation of Laws (Noble)

Schedule 5.9    ―    Noble Preferential Purchase Rights

Schedule 5.11(b)    ―    Breaches of Noble Contracts

Schedule 5.13    ―    Environmental Matters (Noble)

Schedule 5.15    ―    Bonds and Credit Support

Schedule 6.1    ―    CONSOL’s Conduct of Business

Schedule 6.2    ―    Noble’s Conduct of Business

Schedule 6.10(b)    ―    Noble’s Regions

Schedule 6.10(c)    ―    CONSOL’s Regions

EXCHANGE AGREEMENT

THIS EXCHANGE AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into on October 29, 2016

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(the “Execution Date”) between CNX GAS COMPANY LLC, a Virginia limited liability company (“CONSOL”), and NOBLE ENERGY, INC., a Delaware corporation (“Noble”). Noble and CONSOL may be referred to collectively as the “Parties” or individually as a “Party.”

RECITALS

WHEREAS, CONSOL transferred to Noble, and Noble acquired from CONSOL, a portion of CONSOL’s right, title and interest in and to certain properties in accordance with that certain Asset Acquisition Agreement, dated August 17, 2011 (as amended, the “Acquisition Agreement”), and as part of the same transaction CONSOL and Noble entered into that certain Joint Development Agreement, dated September 30, 2011 (as amended, the “Development Agreement”), and certain related agreements, which, collectively, provide for the joint exploration, development and operation of certain oil and gas properties located in the Commonwealth of Pennsylvania and the State of West Virginia as described therein.

WHEREAS, CONSOL and Noble now desire to effect an exchange of certain interests in the jointly owned oil and gas properties and related assets that are subject to the Development Agreement.

WHEREAS, the Acquisition Agreement provides that as partial consideration for the oil and gas properties acquired thereby, Noble, subject to the terms and conditions of the Development Agreement, agreed to pay, on behalf of CONSOL, one-third of all drilling and completion costs that CONSOL would otherwise be required to pay as its share of development costs under the Development Agreement (as more particularly described in the Development Agreement, the “Carried Costs”).

WHEREAS, in connection with such exchange and in partial consideration to CONSOL in connection therewith, CONSOL desires to cancel and forgive Noble’s Carried Costs obligations under the Development Agreement in accordance with this Agreement.

NOW, THEREFORE, for and in consideration of the mutual agreements herein contained, the benefits to be derived by each Party, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE IDEFINITIONS AND INTERPRETATION

1.1Defined Terms. Capitalized terms used herein and not otherwise defined shall have the meanings given such terms in Appendix I.

1.2References and Rules of Construction. All references in this Agreement to Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing

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the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited. The word “including” (in its various forms) means including without limitation. All references to “$” or “dollars” shall be deemed references to United States dollars. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Except as expressly provided otherwise in this Agreement, references to any Law or agreement means such Law or agreement as it may be amended from time to time.

ARTICLE IIEXCHANGE

2.1CONSOL Transferred Assets. Subject to the terms and conditions of this Agreement, CONSOL agrees to transfer, and Noble agrees to acquire, all of CONSOL’s right, title and interest in and to the following assets and properties (less and except for the CONSOL Excluded Assets, such right, title and interest in and to such assets and properties collectively, the “CONSOL Transferred Assets”):

(a)the oil, gas and/or mineral leases and oil and gas mineral fee interests more particularly described in (i) Exhibit A-1, Part 1, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Marcellus Formation, (ii) Exhibit A-1, Part 2, (iii) Exhibit A-1, Part 3, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Utica/Point Pleasant Formation and (iv) Exhibit A-1, Part 4, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Rhinestreet Formation (less and except the CONSOL Excluded Assets, CONSOL’s interest in such leases and oil and gas mineral fee interests as limited pursuant to the foregoing, collectively, the “CONSOL Transferred Leases”), including all working interests, net profits interests, carried interests or similar rights or interest in the CONSOL Transferred Leases, and together with all rights, privileges, benefits and powers conferred upon the holder of the CONSOL Transferred Leases with respect to the use and occupation of the surface of the lands covered thereby that are necessary to the possession and enjoyment of the CONSOL Transferred Leases;

(b)(i) all oil and gas wells drilled, or for which CONSOL has obtained a Permit to be drilled, on the CONSOL Transferred Leases or the CONSOL Transferred Units, including the entire wellbore of such wells (limited, however, to the right only to explore, develop and produce from (A) those depths within the Marcellus Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 1, (B) those depths within the Utica/Point Pleasant Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 3 and (C) those depths within the Rhinestreet Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 4) and including the oil and gas wells listed on Exhibit A-2, Part 1 (less and except the CONSOL Excluded

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Assets, CONSOL’s interest in such wells as limited pursuant to the foregoing, the“CONSOL Transferred O/G Wells”) and (ii) to the extent CONSOL owns a legal or beneficial interest therein as of the Execution Date, all fresh water wells located on the CONSOL Transferred Leases and/or the CONSOL Transferred Units only to the extent set forth on Exhibit A-2, Part2 (less and except the CONSOL Excluded Assets, CONSOL’s interest in such wells as so limited, together with the CONSOL Transferred O/G Wells, the “CONSOL Transferred Wells”);

(c)all interests in pools or units which include all or a part of any CONSOL Transferred Lease (limited, however, to insofar and only insofar as such pools or units cover depths within (i) the Marcellus Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 1, (ii) the Utica/Point Pleasant Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 3 and (iii) the Rhinestreet Formation with respect to those CONSOL Transferred Leases described in Exhibit A-1, Part 4) (less and except the CONSOL Excluded Assets, CONSOL’s interest in such pools or units as limited pursuant to the foregoing, the “CONSOL Transferred Units”);

(d)all servitudes, easements, rights-of-way, surface use agreements, and other similar surface use or rights (i) set forth in Exhibit A-3, Part 1, and (ii) in each case, to the extent primarily used in connection with the ownership or operation of the CONSOL Transferred Leases or CONSOL Transferred Wells, those set forth in Exhibit A-3, Part 2 (less and except the CONSOL Excluded Assets, CONSOL’s interest in the foregoing, collectively, the “CONSOL Transferred Rights-Of-Way” and, together with the CONSOL Transferred Leases, CONSOL Transferred Units and CONSOL Transferred Wells being collectively referred to hereinafter as the “CONSOL Transferred Properties”);

(e)to the extent that they may be assigned, all Permits of Governmental Authorities primarily used in connection with the ownership or operation of the CONSOL Transferred Properties, including those Permits associated with the API numbers for the CONSOL Transferred Wells listed on Exhibit A-2;

(f)all equipment, machinery and other personal property and fixtures, operational or nonoperational, in each case, to the extent located upon or primarily used in connection with the CONSOL Transferred Properties or the other CONSOL Transferred Assets, including well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, manifolds, structures, materials and other items (less and except the CONSOL Excluded Assets, CONSOL’s interest in such properties, the “CONSOL Transferred Personal Property”);

(g)all Hydrocarbons produced from or allocated to the CONSOL Transferred Leases, CONSOL Transferred Wells or CONSOL Transferred Units on and after the Effective Time;

(h)those Contracts (i) described in Exhibit A-4, Part 1 and (ii) subject to Section 6.11, described in Exhibit A-4, Part 2 (collectively, the “CONSOL Contracts”);

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(i)all Well Imbalances relating to the CONSOL Transferred Assets;

(j)to the extent assignable without consent or payment of fees or other penalties (unless such consent is obtained by Noble and, if applicable, Noble agrees to, and does, pay such fees and penalties), all geophysical data, and other seismic and related technical data and information (in each case) relating to the CONSOL Transferred Assets; and

(k)excluding those files, records and other information that are currently in Noble’s possession, originals, if available (unless relating to CONSOL Sole Depths) and/or copies (in digital form, if available) of the following, to the extent in CONSOL’s or its Affiliates’ possession or control (including those records and documents held by any of CONSOL’s title attorneys, brokers or contractors) and to the extent relating to the CONSOL Transferred Assets: (i) land and title records (including abstracts of title, title opinions (including title opinions that cover both (A) the Marcellus Formation, the Utica/Point Pleasant Formation and/or the Rhinestreet Formation and (B) other formations) and title curative documents and other title review materials), (ii) Contract files, (iii) correspondence, (iv) maps, operations, environmental, production and accounting records, (v) facility, engineering and well files, (vi) division order files (including division and interest statements), (vii) engineering and/or production files, (viii) environmental files, (ix) permitting files, (x) geological data and (xi) Asset Tax records, but excluding any of the foregoing items that are primarily used in connection with the ownership or operation of the CONSOL Excluded Assets (subject to such exclusion, the “CONSOL Transferred Records”).

2.2Noble Transferred Assets. Subject to the terms and conditions of this Agreement, Noble agrees to transfer, and CONSOL agrees to acquire, all of Noble’s right, title and interest in and to the following assets and properties (less and except for the Noble Excluded Assets, such right, title and interests in and to such assets and properties collectively, the “Noble Transferred Assets”):

(a)the oil, gas and/or mineral leases and oil and gas mineral fee interests more particularly described in (i) Exhibit B-1, Part 1, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Marcellus Formation, (ii) Exhibit B-1, Part 2 and (iii) Exhibit B-1, Part 3, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Rhinestreet Formation (less and except the Noble Excluded Assets, Noble’s interest in such leases and oil and gas mineral fee interests as limited pursuant to the foregoing, collectively, the “Noble Transferred Leases”), including all working interests, net profits interests, carried interests or similar rights or interest in the Noble Transferred Leases, and together with all rights, privileges, benefits and powers conferred upon the holder of the Noble Transferred Leases with respect to the use and occupation of the surface of the lands covered thereby that are necessary to the possession and enjoyment of the Noble Transferred Leases;

(b)(i) all oil and gas wells drilled, or for which Noble has obtained a Permit to be drilled, on the Noble Transferred Leases or the Noble Transferred Units, including the entire wellbore of such wells (limited, however, to the right only to explore, develop and produce from those depths (A) within the Marcellus Formation with respect to those Noble

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Transferred Leases described in Exhibit B-1, Part 1 and (B) within the Rhinestreet Formation with respect to those Noble Transferred Leases described in Exhibit B-1, Part 3) and including the oil and gas wells listed on Exhibit B-2, Part 1 (less and except the Noble Excluded Assets, Noble’s interest in such wells as limited pursuant to the foregoing, the“Noble Transferred O/G Wells”) and (ii) to the extent Noble owns a legal or beneficial interest therein as of the Execution Date, all fresh water wells located on the Noble Transferred Leases and/or the Noble Transferred Units, only to the extent set forth on Exhibit B-2, Part 2 (less and except the Noble Excluded Assets, Noble’s interest in such wells as so limited, together with the Noble Transferred O/G Wells, the “Noble Transferred Wells”);

(c)all interests in pools or units which include all or a part of any Noble Transferred Lease (limited, however, to insofar and only insofar as such pools or units cover depths (i) within the Marcellus Formation with respect to those Noble Transferred Leases described in Exhibit B-1, Part 1 and (ii) within the Rhinestreet Formation with respect to those Noble Transferred Leases described in Exhibit B-1, Part 3) (less and except the Noble Excluded Assets, Noble’s interest in such pools or units as limited pursuant to the foregoing, the “Noble Transferred Units”);

(d)all servitudes, easements, rights-of-way, surface use agreements, and other similar surface use or rights (i) set forth in Exhibit B-3, Part 1, and (ii) in each case, to the extent primarily used in connection with the ownership or operation of the Noble Transferred Leases or Noble Transferred Wells, those set forth in Exhibit B-3, Part 2 (less and except the Noble Excluded Assets, Noble’s interest in the foregoing, collectively, the “Noble Transferred Rights-Of-Way” and, together with the Noble Transferred Leases, Noble Transferred Units, and, Noble Transferred Wells being collectively referred to hereinafter as the “Noble Transferred Properties”);

(e)to the extent that they may be assigned, all Permits of Governmental Authorities primarily used in connection with the ownership or operation of the Noble Transferred Properties, including those Permits associated with the API numbers for the Noble Transferred Wells listed on Exhibit B-2;

(f)all equipment, machinery and other personal property and fixtures, operational or nonoperational, in each case, to the extent located upon or primarily used in connection with the Noble Transferred Properties or the other Noble Transferred Assets, including well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, manifolds, structures, materials and other items (less and except the Noble Excluded Assets, Noble’s interest in such properties, the “Noble Transferred Personal Property”);

(g)all Hydrocarbons produced from or allocated to the Noble Transferred Leases, Noble Transferred Wells or Noble Transferred Units on and after the Effective Time;

(h)those Contracts (i) described in Exhibit B-4, Part 1 and (ii) subject to Section 6.11, described in Exhibit B-4, Part 2 (collectively, the “Noble Contracts”);

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(i)all Well Imbalances relating to the Noble Transferred Assets;

(j)to the extent assignable without consent or payment of fees or other penalties (unless such consent is obtained by CONSOL and, if applicable, CONSOL agrees to, and does, pay such fees and penalties), all geophysical data, and other seismic and related technical data and information (in each case) relating to the Noble Transferred Assets; and

(k)excluding those files, records and other information that are currently in CONSOL’s possession, originals, if available (unless relating to Noble Sole Depths) and/or copies (in digital form, if available) of the following, to the extent in Noble’s or its Affiliates’ possession or control (including those records and documents held by any of Noble’s title attorneys’, brokers or contractors) and to the extent relating to the Noble Transferred Assets: (i) land and title records (including abstracts of title, title opinions (including title opinions that cover both (A) the Marcellus Formation and/or Rhinestreet Formation and (B) other formations) and title curative documents and other title review materials), (ii) Contract files, (iii) correspondence, (iv) maps, operations, environmental, production and accounting records, (v) facility, engineering and well files, (vi) division order files (including division and interest statements), (vii) engineering and/or production files, (viii) environmental files, (ix) permitting files, (x) geological data and (xi) Asset Tax records, but excluding any of the foregoing items that are primarily used in connection with the ownership or operation of the Noble Excluded Assets (subject to such exclusion, the “Noble Transferred Records”).

2.3Excluded Assets. CONSOL shall reserve and retain all of the CONSOL Excluded Assets and Noble shall reserve and retain all of the Noble Excluded Assets.

2.4Revenues and Expenses.  

(a)For purposes of determining the amount of the adjustment to the Cash Consideration provided for in Section 2.6, the principles set forth in this Section 2.4 shall apply except as expressly provided otherwise in this Agreement. Except as expressly provided herein, CONSOL shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible (by payment, through the adjustments to the Cash Consideration hereunder or otherwise) for all Property Expenses, in each case attributable to the CONSOL Transferred Assets for the period of time prior to the Effective Time. Except as expressly provided herein, Noble shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible (by payment, through the adjustments to the Cash Consideration hereunder or otherwise) for all Property Expenses, in each case attributable to the Noble Transferred Assets for the period of time prior to the Effective Time. Subject to the occurrence of the Closing, Noble shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds), and shall be responsible (by payment, through the adjustments to the Cash Consideration hereunder or otherwise) for all Property Expenses, in each case, attributable to the CONSOL Transferred Assets for the period of time from and after the Effective Time. Subject to the occurrence of the Closing, CONSOL shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds),

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and shall be responsible (by payment, through the adjustments to the Cash Consideration hereunder or otherwise) for all Property Expenses, in each case, attributable to the Noble Transferred Assets for the period of time from and after the Effective Time. All Property Expenses attributable to the CONSOL Transferred Assets, in each case that are: (i) incurred with respect to operations conducted or production produced prior to the Effective Time shall be paid by or allocated to CONSOL and (ii) incurred with respect to operations conducted or production produced from and after the Effective Time shall be paid by or allocated to Noble. All Property Expenses attributable to the Noble Transferred Assets, in each case that are: (i) incurred with respect to operations conducted or production produced prior to the Effective Time shall be paid by or allocated to Noble and (ii) incurred with respect to operations conducted or production produced from and after the Effective Time shall be paid by or allocated to CONSOL. Such amounts that are received or paid prior to Closing shall be accounted for in the Preliminary Settlement Statement or Final Settlement Statement as applicable. Such amounts that are received or paid after Closing but prior to the date of the Final Settlement Statement shall be accounted for in the Final Settlement Statement.

(b)From and after the Final Settlement Statement Date there shall be no adjustment for, or obligation to pay or account for, any proceeds or Property Expenses between the Parties; provided that, this limitation will not be applicable to (i) adjustments made pursuant to the Final Settlement Statement, including the resolution of any disputes relating to the Final Settlement Statement, or (ii) amounts owing by a Party or its Affiliates to the other Party or its Affiliates in connection with the exercise of any audit rights by a Party pursuant to Section 2.4(c).

(c)The Parties acknowledge and agree that currently there are ongoing joint interest billings by each of the Parties with respect to certain of the Combined Assets where certain Combined Asset Property Expenses have been incurred by the operator of such assets prior to the Effective Time, but may not have been billed to the non-operators (including a Party) with interest in such assets. Such joint interest billings shall continue and the amounts that are determined to be due and payable by any Party shall be taken into account in connection with the Preliminary Settlement Statement or the Final Settlement Statement or otherwise settled between the Parties;provided, however,from and after the Final Settlement Statement Date neither Party shall have the right to issue to the other Party or its Affiliates any further joint interest billings or invoices under the Development Agreement or any joint operating agreement related to the Combined Assets. In addition, notwithstanding anything herein to the contrary, the Parties’ audit rights under any applicable joint operating agreement or other Contract with respect to the any of the Combined Assets (even if a Terminated Agreement) shall remain in effect (including with respect to such joint interest billings), notwithstanding the transfer of any such joint operating agreement or Contract by a Party or any termination of the applicable joint operating agreement or Contract.

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2.5Consideration.

(a)The consideration for (x) the transfer to Noble of the CONSOL Transferred Assets by CONSOL and (y) the assumption by Noble of the Noble Assumed Obligations, shall be comprised of the following components:

(i)an amount equal to $205,000,000, as adjusted in accordance with Section 2.6, to be paid at Closing in cash by Noble to CONSOL Energy Inc., the indirect parent of CONSOL (the “CONSOL Parent”), to an account designated by CONSOL Parent (the “Designated Account”) by wire transfer in same day funds (such amount, prior to such adjustment, the “Cash Consideration”);

(ii)the assignment by Noble of the Noble Transferred Assets to CONSOL; and

(iii)the delivery at Closing to CONSOL of the documents and other items required to be delivered by Noble under Section 9.3.

(b)The consideration for (x) the transfer to CONSOL of the Noble Transferred Assets by Noble and (y) the assumption by CONSOL of the CONSOL Assumed Obligations, shall be comprised of the following components:

(i)the assignment by CONSOL of the CONSOL Transferred Assets to Noble;    

(ii)the cancellation and forgiveness of the Carried Costs Balance (as defined in the Development Agreement) to $0; and

(iii)the delivery at Closing to Noble of the documents and other items required to be delivered by CONSOL under Section 9.3.

2.6Adjustments to Cash Consideration. The Cash Consideration shall be adjusted as follows (without duplication of any kind), and the resulting amount shall be herein called the “Adjusted Cash Consideration”:

(a)The Cash Consideration shall be adjusted upward by the following amounts (without duplication) (excluding any such amounts with respect to a CONSOL Transferred Asset that is not transferred at the Closing, until such time as such CONSOL Transferred Asset is actually transferred to Noble pursuant to the terms of this Agreement):

(i)an amount equal to the value of all liquid Hydrocarbons attributable to the CONSOL Transferred Assets in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time (being agreed by the Parties to be 2,322.9 barrels), the value to be based upon a price of $35 per barrel;

(ii)an amount equal to all Property Expenses and other costs and expenses incurred and paid by or on behalf of CONSOL that are attributable to the

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CONSOL Transferred Assets during the Interim Period, whether paid before or after the Effective Time, including (A) Burdens, (B) rentals and other lease maintenance payments and (C) water storage, transportation and disposal costs and expenses (including any such costs and expenses attributable to water in tanks, impoundments, pools or frack pits, in each case, as of the Effective Time);

(iii)the amount of all prepaid expenses attributable to the CONSOL Transferred Assets that are paid or incurred by, or on behalf of, CONSOL that are attributable to the period of time from and after the Effective Time, including expenditures which are advanced pursuant to a joint operating agreement and prepaid utility charges;

(iv)the amount of all Asset Taxes prorated to Noble in accordance with Section 12.2(f) but paid or payable by CONSOL;

(v)to the extent of a Well Imbalance with respect to any of the CONSOL Transferred O/G Wells where CONSOL is underproduced with respect to any Hydrocarbons as of the Effective Time, the sum of an amount equal to the product of (A) the underproduced volumes times (B) $1.02/Dth for gaseous Hydrocarbons; plus an amount equal to the product of (X) the underproduced volumes times (Y) $13.44/Bbl for liquid Hydrocarbons;

(vi)to the extent not paid by Noble prior to Closing, the aggregate of the amounts set forth in Schedule 2.6 as being owed by Noble to CONSOL for Noble’s Pre-Closing Working Interest Share in the properties described in the Schedule (all of such properties on such Schedule, the “Offered AMI Properties”); and

(vii)any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by CONSOL and Noble.

(b)The Cash Consideration shall be adjusted downward by the following amounts (without duplication) (excluding any such amounts with respect to a CONSOL Transferred Asset that is not transferred at the Closing, until such time as such CONSOL Transferred Asset is actually transferred to Noble pursuant to the terms of this Agreement):

(i)an amount equal to all proceeds received by CONSOL attributable to the sale of Hydrocarbons (A) produced from or allocable to the CONSOL Transferred Assets during the Interim Period or (B) contained in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time for which an upward Cash Consideration adjustment was made pursuant to Section 2.6(a)(i), (in each case) net of expenses (other than Property Expenses) directly incurred in earning or receiving such proceeds, and any severance, sales, excise or similar Taxes or fees payable or incurred in connection therewith not reimbursed or reimbursable to CONSOL by a Third Party purchaser;

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(ii)any amount determined pursuant to Section 3.4(a)(ii) and/or Section 3.4(b)(ii) for any CONSOL Transferred Assets excluded from the transaction contemplated hereby pursuant to such Section;

(iii)the amount of all Asset Taxes prorated to CONSOL in accordance with Section 12.2(f) but payable by Noble;

(iv)any amounts determined pursuant to Section 3.3(b) with respect to theCONSOL Transferred Assets;

(v)to the extent of a Well Imbalance with respect to any of the CONSOL Transferred O/G Wells where CONSOL is overproduced with respect to any Hydrocarbons as of the Effective Time, the sum of an amount equal to the product of (A) the overproduced volumes times (B) $1.02/Dth for gaseous Hydrocarbons; plus an amount equal to the product of (X) the overproduced volumes times (Y) $13.44/Bbl for liquid Hydrocarbons; and

(vi)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by CONSOL and Noble.

(c)The Cash Consideration shall be adjusted downward by the following amounts (without duplication) (excluding any such amounts with respect to a Noble Transferred Asset that is not transferred at the Closing, until such time as such Noble Transferred Asset is actually transferred to CONSOL pursuant to the terms of this Agreement):

(i)an amount equal to the value of all liquid Hydrocarbons attributable to the Noble Transferred Assets in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time (being agreed by the Parties to be 3,124.2 barrels), the value to be based upon a price of $35 per barrel;

(ii)an amount equal to all Property Expenses and other costs and expenses incurred and paid by or on behalf of Noble that are attributable to the Noble Transferred Assets during the Interim Period, whether paid before or after the Effective Time, including (A) Burdens, (B) rentals and other lease maintenance payments and (C) water storage, transportation and disposal costs and expenses (including any such costs and expenses attributable to water in tanks, impoundments, pools or frack pits, in each case, as of the Effective Time);

(iii)the amount of all prepaid expenses attributable to the Noble Transferred Assets that are paid or incurred by, or on behalf of, Noble that are attributable to the period of time from and after the Effective Time, including expenditures which are advanced pursuant to a joint operating agreement and prepaid utility charges;

(iv)the amount of all Asset Taxes prorated to CONSOL in accordance with Section 12.2(f) but paid or payable by Noble.

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(v)to the extent of a Well Imbalance with respect to any of the Noble Transferred O/G Wells where Noble is underproduced with respect to any Hydrocarbons as of the Effective Time, the sum of an amount equal to the product of (A) the underproduced volumes times (B) $1.02/Dth for gaseous Hydrocarbons; plus an amount equal to the product of (X) the underproduced volumes times (Y) $13.44/Bbl for liquid Hydrocarbons;

(vi)to the extent not paid by CONSOL prior to Closing, the aggregate of the amounts set forth in Schedule 2.6 as being owed by CONSOL to Noble for CONSOL’s Pre-Closing Working Interest Share in the Offered AMI Properties; and

(vii) any other amount provided for elsewhere in this Agreement or otherwise agreed upon by CONSOL and Noble.

(d)The Cash Consideration shall be adjusted upward by the following amounts (without duplication) (excluding any such amounts with respect to a Noble Transferred Asset that is not transferred at the Closing, until such time as such Noble Transferred Asset is actually transferred to CONSOL pursuant to the terms of this Agreement):

(i)an amount equal to all proceeds received by Noble attributable to the sale of Hydrocarbons (A) produced from or allocable to the Noble Transferred Assets during the Interim Period or (B) contained in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time for which a downward Cash Consideration adjustment was made pursuant to Section 2.6(c)(i), (in each case) net of expenses (other than Property Expenses) directly incurred in earning or receiving such proceeds, and any severance, sales, excise or similar Taxes or fees payable or incurred in connection therewith not reimbursed or reimbursable to Noble by a Third Party purchaser;

(ii)any amount determined pursuant to Section 3.4(a)(ii), and/or Section 3.4(b)(ii) for any Noble Transferred Assets excluded from the transaction contemplated hereby pursuant to such Section;

(iii)the amount of all Asset Taxes prorated to Noble in accordance with Section 12.2(f) but payable by CONSOL;

(iv)any amounts determined pursuant to Section 3.3(b) with respect to the Noble Transferred Assets.

(v)to the extent of a Well Imbalance with respect to any of the Noble Transferred O/G Wells where Noble is overproduced with respect to any Hydrocarbons as of the Effective Time, the sum of an amount equal to the product of (A) the overproduced volumes times (B) $1.02/Dth for gaseous Hydrocarbons; plus an amount equal to the product of (X) the overproduced volumes times (Y) $13.44/Bbl for liquid Hydrocarbons; and

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(vi) any other amount provided for elsewhere in this Agreement or otherwise agreed upon by CONSOL and Noble.

Notwithstanding anything herein to the contrary, the adjustments to the Cash Consideration set forth in Section 2.6(a)(iv), Section 2.6(b)(ii), Section 2.6(b)(iii), Section 2.6(c)(iv), Section 2.6(d)(ii) and Section 2.6(d)(iii) shall not be taken into account when determining Adjusted Cash Consideration in the Preliminary Settlement Statement and will only be taken into account for purposes of determining the Adjusted Cash Consideration in the Final Settlement Statement.

2.7Adjustment Methodology. When available, actual figures will be used for the adjustments to the Cash Consideration at Closing. To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section 2.9 and Section 2.10.

2.8Preliminary Settlement Statement.

(a)Not less than five days prior to the Closing, each Transferring Party shall prepare and submit to the Non-Transferring Party for review, using and based on the best information available to such Party, a draft adjustment statement with respect to the CONSOL Transferred Assets, in the case of CONSOL and the Noble Transferred Assets, in the case of Noble, (each a, “Preliminary Adjustment Statement”), which Preliminary Adjustment Statement  shall set forth the adjustments to the Cash Consideration as set forth in Sections 2.6(a) and (b), in the case of CONSOL, and Sections 2.6(c) and (d), in the case of Noble,(including the calculation of such adjustments), as of the date of preparation of such Preliminary Adjustment Statement. Within three days of its receipt of its Preliminary Adjustment Statement, each Non-Transferring Party will deliver to its Transferring Party a written report containing all changes with the explanation therefore that such Non-Transferring Party proposes to be made to its Preliminary Adjustment Statement, if any. Each Preliminary Adjustment Statement, as agreed upon by the Parties, will be used by CONSOL to create a preliminary settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Cash Consideration reflecting each adjustment made in accordance with this Agreement as set forth in the Preliminary Adjustment Statements. Notwithstanding the foregoing, if the Parties cannot agree on any Preliminary Adjustment Statement prior to the Closing, the Preliminary Adjustment Statement as presented by CONSOL will be used with respect to the adjustments set forth in in Sections 2.6(a) and (b), and the Preliminary Adjustment Statement as presented by Noble will be used with respect to the adjustments set forth in in Sections 2.6(c) and (d). Noble shall pay to CONSOL Parent at Closing the amount of the Adjusted Cash Consideration stated in the Preliminary Settlement Statement as determined in accordance with this Section 2.8. Contemporaneously with the delivery by CONSOL of its Preliminary Adjustment Statement, CONSOL shall provide Noble with the designation of CONSOL’s Parent’s Designated Account for the wire transfers of funds as set forth in Section 9.3(g).

(b)In the event the Adjusted Cash Consideration determined under Section 2.8(a) is less than $0, CONSOL shall deliver at Closing, to an account designated by Noble, by direct bank or wire transfer in same day funds, the Adjusted Cash Consideration. For the avoidance of doubt, in such an event, (i) CONSOL’s obligation to make any payment of the

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Adjusted Cash Consideration under this Section 2.8(b) will be subject to Noble conditions to close in Article VII and CONSOL’s conditions to close in Article VIII; (ii) CONSOL’s closing deliverables under Section 7.6 will be deemed to include delivery of the Adjusted Cash Consideration, and Noble’s closing deliverables under Section 8.6 will be deemed not to include delivery of the Adjusted Cash Consideration; and (iii) the closing obligations in Section 9.3 will be deemed to include CONSOL’s obligation to deliver the Adjusted Cash Consideration in accordance with this Section 2.8(b), and Noble’s obligation to deliver the Adjusted Cash Consideration under Section 9.3(g) will be deemed not to be a closing obligation. Further, the Parties acknowledge that in the event the Adjusted Cash Consideration is less than $0, that such event is not a failure of the consideration under Section 2.5 to support the transactions contemplated by this Agreement.

2.9Final Settlement Statement. On or before the date that is 120days following the Closing Date, a final adjustment statement (each, a “Final Adjustment Statement”) will be prepared by each Transferring Party, based on actual revenues and expenses during the Interim Period and which takes into account all final adjustments made to the Cash Consideration as set forth in Sections 2.6(a) and (b), in the case of CONSOL, and Sections 2.6(c) and (d), in the case of Noble,including the calculation of such adjustments. Each Final Adjustment Statement shall set forth the actual proration of the amounts required by this Agreement with respect to the Transferred Properties of such Transferring Party. As soon as practicable, and in any event within 30 days after the date on which the last Non-Transferring Party to receive its Final Adjustment Statement receives its Final Adjustment Statement, each Non-Transferring Party will deliver to its Transferring Party a written report containing any proposed changes to the Final Adjustment Statement delivered by its Transferring Party and an explanation of any such changes and the reasons therefore (the “Dispute Notice”). Any changes not so specified in the Dispute Notice shall be deemed waived and the Transferring Party’s determinations with respect to all such elements of its Final Adjustment Statement that are not addressed specifically in the Dispute Notice shall prevail. If a Non-Transferring Party fails to timely deliver a Dispute Notice to its Transferring Party containing changes that such Non-Transferring Party proposes to be made to the Final Adjustment Statement delivered by its Transferring Party, the Final Adjustment Statement as delivered by such Transferring Party will be deemed to be mutually agreed upon by the Parties and will be final and binding on the Parties. If the Final Adjustment Statements are mutually agreed upon by CONSOL and Noble (or deemed agreed, as the case may be), such Final Adjustment Statements will be used by CONSOL to create a final settlement statement (the “Final Settlement Statement”) that shall set forth the final Adjusted Cash Consideration reflecting each adjustment made in accordance with this Agreement as set forth in such Final Adjustment Statements. The Final Settlement Statement and the final Adjusted Cash Consideration as so agreed or deemed agreed, shall be final and binding on the Parties, subject to the provisions of Section 2.4(b). Once the final Adjusted Cash Consideration has been agreed (or deemed agreed) upon by the Parties pursuant to this Section 2.9 or determined by the Accounting Arbitrator pursuant to Section 2.10, as applicable, then, if the final Adjusted Cash Consideration is (a) more than the Adjusted Cash Consideration used at Closing pursuant to Section 2.8, Noble shall pay to CONSOL Parent by delivery to the Designated Account the amount of such difference, or (b) less than the Adjusted Cash Consideration used at Closing pursuant to Section 2.8, CONSOL shall pay to Noble by delivery to an account designated by Noble the amount of such difference, in each case, by wire transfer in immediately available funds no later than five Business

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Days after the date such final Adjusted Cash Consideration is agreed, or deemed agreed, pursuant to this Section 2.9 or determined pursuant to Section 2.10, as applicable.

2.10Disputes. If CONSOL and Noble are unable to resolve the matters addressed in the Dispute Notice (if any), each of Noble and CONSOL shall within 15 Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to the Pittsburgh office of Deloitte, or if Deloitte is unable or unwilling to serve as arbitrator and absent agreement by the Parties, by the Pittsburgh, Pennsylvania office of the AAA (the “Accounting Arbitrator”), together with the Dispute Notice, the applicable Final Adjustment Statement and any other documentation such Party may desire to submit. Within 20 Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either CONSOL’s position or Noble’s position with respect to each matter addressed in any Dispute Notice, based on the materials described above and determine the Final Settlement Statement and the final Adjusted Cash Consideration. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on CONSOL and Noble and will be enforceable against any of the Parties in any court of competent jurisdiction. The costs of such Accounting Arbitrator shall be borne 50% by Noble and 50% by CONSOL. The Final Adjustment Statement(s), the Final Settlement Statement and the final Adjusted Cash Consideration determined by the Accounting Arbitrator pursuant to this Section 2.10 shall be final and binding on the Parties (other than with respect to amounts not accounted for therein or settled thereby, which amounts shall be subject to the provisions of Section 2.4(b)).

2.11Allocated Values. The “Allocated Value” for any CONSOL Transferred Asset equals (a) with respect to any CONSOL Transferred Lease (or portion thereof) included in the CONSOL Transferred Assets, the amount allocated to such CONSOL Transferred Lease on Exhibit A-1 and (b) with respect to the CONSOL Transferred Wells included in the CONSOL Transferred Assets, the amount allocated to such CONSOL Transferred Wells on Exhibit A-2, Part 1. The “Allocated Value” for any Noble Transferred Asset equals (a) with respect to any Noble Transferred Lease (or portion thereof) included in the Noble Transferred Assets, the amount allocated to such Noble Transferred Lease on Exhibit B-1 and (b) with respect to the Noble Transferred Wells included in the Noble Transferred Assets, the amount allocated to such Noble Transferred Wells on Exhibit B-2, Part 1.

ARTICLE IIITITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS; DISCLAIMERS

3.1General Disclaimer of Title Warranties and Representations. Except for the Special Warranty contained in the CONSOL Assignment, the CONSOL Deed, the Noble Assignment and the Noble Deed, no Transferring Party makes any warranty or representation, express, implied, statutory or otherwise, with respect to its title to any of its Transferred Properties and each Non-Transferring Party hereby acknowledges and agrees that, except for (a) CONSOL’s remedies under Section 10.3(a) (relating to any breach by Noble of Sections 5.3, 5.4, 5.7, 5.9, 5.11 or 5.14), Section 10.3(b) (relating to any breach by Noble of Section 6.2), Section 10.3(h) and Section 10.3(i) and (b) Noble’s remedies under Section 10.2(a) (relating to any breach by CONSOL of Sections 4.3, 4.4, 4.7, 4.9, 4.11 or 4.14), Section 10.2(b) (relating to any breach by CONSOL of Section 6.1),

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Section 10.2(h) and Section 10.2(i), such Non-Transferring Party’s sole and exclusive remedy for any defect of title or any other title matter shall be pursuant to the Special Warranty, to the extent applicable, contained in the CONSOL Assignment, the CONSOL Deed, the Noble Assignment or the Noble Deed, as applicable.

3.2Special Warranty.  The CONSOL Assignment and the CONSOL Deed delivered at the Closing will contain a Special Warranty by CONSOL to the CONSOL Transferred Wells and the CONSOL Transferred Leases pursuant to the terms of the CONSOL Assignment or the CONSOL Deed, as applicable. The Noble Assignment and the Noble Deed delivered at the Closing will contain a Special Warranty by Noble to the Noble Transferred Wells and the Noble Transferred Leases pursuant to the terms of the Noble Assignment or the Noble Deed, as applicable. The Special Warranty contained in the Assignments and the Deeds shall survive the Closing indefinitely.

3.3Casualty or Condemnation Loss.  

(a)Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the CONSOL Transferred Assets, Noble shall assume all risk of loss with respect to (i) production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and (ii) the depreciation of CONSOL Transferred Personal Property due to ordinary wear and tear and Noble shall not assert such matters as any casualty losses hereunder. Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the Noble Transferred Assets, CONSOL shall assume all risk of loss with respect to (i) production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and (ii) the depreciation of Noble Transferred Personal Property due to ordinary wear and tear and CONSOL shall not assert such matters as any casualty losses hereunder.

(b)If, after the Execution Date but prior to the Closing Date, any portion of the CONSOL Transferred Assets or the Noble Transferred Assets is destroyed or damaged by Casualty or is taken in condemnation or under right of eminent domain, then the Non-Transferring Party who is acquiring the affected Transferred Property shall nevertheless be required to close, and CONSOL, in the case of a Casualty or taking related to the CONSOL Transferred Assets, or Noble, in the case of a Casualty or taking related to the Noble Transferred Assets (as applicable, the “Affected Party”) shall cause such affected Transferred Property to be repaired or restored to at least its condition prior to such Casualty or taking, at the Affected Party’s sole cost, prior to Closing; provided that if such affected Transferred Properties are not so repaired or restored prior to Closing, the Cash Consideration will be adjusted in the Final Settlement Statement by an amount equal to the loss of value of such affected Transferred Properties on account of such Casualty or taking (such amount, as limited by this Section 3.3(b)), the “Casualty Amount”). In the event that at or prior to the Closing, the Parties have not mutually agreed as to any such Casualty Amount, then each Party at or prior to Closing shall deliver written notice to the other Party of its asserted Casualty Amount with respect to any such affected Transferred Property (each, a “Casualty Amount Notice”) and such dispute with respect to such Casualty Amount shall be submitted to arbitration and

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finally resolved pursuant to Section 3.3(c). In no event, will the amount of any adjustment to the Cash Consideration exceed the Allocated Value of the affected Transferred Properties. The Affected Party shall retain all rights to insurance and other claims against Third Parties with respect to such Casualty or taking except to the extent the Parties otherwise agree in writing.

(c)In the event of a dispute between the Parties as to any Casualty Amount with respect to any Transferred Property affected by Casualty or taking that has not been cured by Closing (a “Casualty Dispute”), then either Party shall have the right to elect, upon written notice to the other Party, to initiate arbitration to resolve such Casualty Dispute. All Casualty Disputes shall be exclusively and finally resolved pursuant to this Section 3.3(c). There shall be a single arbitrator, who shall be an oil and gas attorney with at least ten years’ experience in oil and gas matters involving properties in the regional area in which the Transferred Property affected by such Casualty or taking are located (the “Casualty Arbitrator”). The Casualty Arbitrator shall be selected by mutual agreement of the Parties within 15 days after the election by a Party to utilize the provisions of this Section 3.3(c) with respect to a Casualty Dispute. If the Parties are unable to mutually agree upon the Casualty Arbitrator, the Pittsburgh, Pennsylvania office of the AAA shall appoint the Casualty Arbitrator under such conditions as the AAA in its sole discretion deems necessary or advisable. The place of arbitration shall be Pittsburgh, Pennsylvania, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 3.3(c). The Casualty Arbitrator’s determination shall be made within 30 days after submission of any Casualty Dispute and shall be final and binding upon both Parties, without right of appeal. In making its determination, the Casualty Arbitrator shall be bound by the rules set forth in Section 3.3(b) and, subject to the foregoing, may consider such other matters as in the opinion of the Casualty Arbitrator are necessary to make a proper determination. The Casualty Arbitrator, however, may not award (i) the Non-Transferring Party a greater Casualty Amount than the Casualty Amount claimed by such Non-Transferring Party in its applicable Casualty Amount Notice or (ii) Transferring Party a lesser Casualty Amount than the Casualty Amount claimed by such Transferring Party in its applicable Casualty Amount Notice. The Casualty Arbitrator shall act for the limited purpose of determining the specific Casualty Disputes submitted by either Party, and the Casualty Arbitrator may not award damages, interest or penalties to either Party with respect to any Casualty Dispute. Each Party shall each bear its own legal fees and other costs of presenting its case to the Casualty Arbitrator. Each Party shall bear one-half of the costs and expenses of the Casualty Arbitrator. Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 3.3(c).

3.4Preferential Purchase Rights and Consents to Assign.  

(a)With respect to each Preferential Purchase Right set forth in Schedule 4.9, on or before the 3^rd Business Day after the Execution Date (and 2^nd Business Days after the discovery of any other Preferential Purchase Right applicable to the transfer of the CONSOL Transferred Assets), CONSOL shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential

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Purchase Right. With respect to each Preferential Purchase Right set forth in Schedule 5.9, on or before the 3^rd Business Day after the Execution Date (and 2^nd Business Days after the discovery of any other Preferential Purchase Right applicable to the transfer of the Noble Transferred Assets), Noble shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential Purchase Right.

(i)If, prior to Closing, any holder of a Preferential Purchase Right notifies the Transferring Party of the Transferred Properties burdened by such Preferential Purchase Right that it intends to consummate the acquisition of such Transferred Properties to which its Preferential Purchase Right applies or if the time for exercising such Preferential Purchase Right has not expired, then (A) the Transferred Properties subject to such Preferential Purchase Right shall be excluded from the Transferred Properties to be assigned by such Transferring Party to the Non-Transferring Party at Closing (but only to the extent of the portion of such Transferred Properties affected by such Preferential Purchase Right), and (B) no adjustments to the Cash Consideration shall be made at Closing with respect to such excluded Transferred Properties.

(ii)If, on or before 110 days following the Closing Date, such holder of such Preferential Purchase Right thereafter consummates the acquisition of such excluded Transferred Properties (or portion thereof) covered by such Preferential Purchase Right or the time for exercising such Preferential Purchase Right has not expired without exercise by the holder thereof, then (in either case) such Transferred Property shall become a either a Noble Excluded Asset or a CONSOL Excluded Asset, as applicable, under this Agreement and (A) if the Transferring Party is Noble, the Cash Consideration in the Final Settlement Statement shall be increased by an amount equal to the Allocated Values of such excluded Transferred Properties or (B) if the Transferring Party is CONSOL, the Cash Consideration shall be decreased by an amount equal to the Allocated Values of such excluded Transferred Properties. The Transferring Party (or CONSOL Parent, if CONSOL is the Transferring Party) shall be entitled to all consideration given by any Person exercising a Preferential Purchase Right prior to Closing and consummating the acquisition in accordance herewith.

(iii)If, on or before 110 days following the Closing Date, such holder of such Preferential Purchase Right thereafter fails to consummate the acquisition of such excluded Transferred Properties covered by such Preferential Purchase Right or the time for exercising such Preferential Purchase Right expires without exercise by the holder thereof, then (A) the Transferring Party shall so notify the Non-Transferring Party, (B) the Transferring Party shall assign, on the tenth Business Day following its delivery of such notice or termination of such right without exercise, such excluded Transferred Properties that were so excluded from the Transferred Properties transferred at Closing by the Transferring Party to the Non-Transferring Party, effective as of the Effective Time pursuant to an instrument in substantially

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the same form as the CONSOL Assignment or Noble Assignment (as applicable) and (C) the Cash Consideration in the Final Settlement Statement shall be adjusted by the adjustments set forth in Section 2.6 (other than adjustments in Section 2.6(b)(ii) or Section 2.6(d)(ii), as applicable) to the extent relating to such excluded Transferred Properties through the date of such assignment.

(iv)All Transferred Properties for which any applicable Preferential Purchase Right has been waived, or as to which the period to exercise the applicable Preferential Purchase Right has expired (and such Preferential Purchase Right has not been exercised), in each case, prior to Closing, shall be assigned to the Non-Transferring Party at Closing pursuant to the provisions of this Agreement.

(b)With respect to each CONSOL Consent set forth in Schedule 4.4, on or before the 3^rd Business Day after the Execution Date (and 2^nd Business Days after the discovery of any other Consent applicable to the transfer of the CONSOL Transferred Assets), CONSOL shall send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby. With respect to each Noble Consent set forth in Schedule 5.4, on or before the 3^rd Business Day after the Execution Date (and 2^nd Business Days after the discovery of any other Consent applicable to the transfer of the Noble Transferred Assets), Noble shall send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby. Prior to Closing, the applicable Transferring Party shall use its commercially reasonable efforts, with reasonable assistance from the Non-Transferring Party, to obtain all Consents sought by such Transferring Party in accordance with this Section 3.4(b); provided, however, that neither the Transferring Party nor the Non-Transferring Party shall be required to incur any Liability or pay any money (in each case) to any Third Party in order to obtain any such Consent.

(i)If (A) a Transferring Party fails to obtain a Consent sought by it in accordance with this Section 3.4(b) prior to Closing and the failure to obtain such Consent would cause (1) the assignment of any of such Transferring Party’s Transferred Properties affected thereby to the Non-Transferring Party to be void or (2) the termination of a Transferred Property of such Transferring Party under the express terms thereof, (B) a Consent sought by such Transferring Party is denied in writing and the Non-Transferring Party of such Transferred Property does not waive the requirement to obtain such Consent that was denied in writing, or (C) a Consent sought by such Transferring Party is from a Governmental Authority (other than a Customary Post Closing Consent) (each of such Consents of the types described in clauses (A), (B) and (C) above, a “Hard Consent”) then, in each case, (x) such Transferred Property (or portion thereof) affected by such un-obtained Hard Consent shall be excluded from the Transferred Properties to be assigned by such Transferring Party to the Non-Transferring Party at Closing, and (y) no adjustments to the Cash Consideration shall be made at Closing with respect to such excluded Transferred Property.

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(ii)In the event that any such Hard Consent with respect to a Transferred Property that was not obtained prior to Closing thereafter is not obtained by the Transferring Party within (A) 110 days following the Closing Date with respect to any Transferred Property that is not a Downstream Contract or (B) twelve months following the Closing Date with respect to any Transferred Property that is a Downstream Contract, then such Transferred Property shall become a either a Noble Excluded Asset or a CONSOL Excluded Asset, as applicable, under this Agreement and (1) if the Transferring Party with respect to such Transferred Property is Noble, the Cash Consideration in the Final Settlement Statement shall be increased by an amount equal to the Allocated Values (if any) of such excluded Transferred Property or (2) if the Transferring Party is CONSOL, the Cash Consideration shall be decreased by an amount equal to the Allocated Values (if any) of such excluded Transferred Property. In the event that any such Hard Consent that was not obtained prior to Closing thereafter is obtained within (A) 110 days following the Closing Date with respect to a Transferred Property that is not a Downstream Contract, or (B) twelve months following the Closing Date with respect to any Transferred Property that is a Downstream Contract, then (1) the Transferring Party shall so notify the Non-Transferring Party, (2) the Transferring Party shall assign, on the tenth Business Day following its delivery of such notice, such excluded Transferred Property that was so excluded from the Transferred Properties transferred at Closing by the Transferring Party to the Non-Transferring Party, effective as of the Effective Time pursuant to an instrument in substantially the same form as the CONSOL Assignment or Noble Assignment, as applicable (or with respect to any excluded Contract pursuant to a mutually agreeable form of assignment and assumption agreement consistent with the principles set forth in the Assignment) and (3) the Cash Consideration in the Final Settlement Statement shall be adjusted by the adjustments (if applicable) set forth in Section 2.6 (other than adjustments in Section 2.6(b)(ii) or Section 2.6(d)(ii), as applicable) to the extent relating to such excluded Transferred Properties through the date of such assignment.

(iii)If the Transferring Party fails to obtain a Consent sought by it pursuant to this Section 3.4(b) prior to Closing that is not a Hard Consent, then the Transferred Property (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by such Transferring Party to its Non-Transferring Party at Closing as part of such Transferring Party’s Transferred Properties. Any Liability that arises due to the failure to obtain such Consent that is not a Hard Consent shall be borne 50% by CONSOL and 50% by Noble; provided, however, in the event a Non-Transferring Party waives the requirement to obtain a Consent that was denied in writing, any Liability that arises due to failure to obtain such Consent shall be borne 100% by such Non-Transferring Party.

3.5Disclaimers.  

(a)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE IV OR ARTICLE V, AS APPLICABLE, AND WITH RESPECT TO THE

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SPECIAL WARRANTY SET FORTH IN THE APPLICABLE ASSIGNMENT, WITH RESPECT TO ITS TRANSFERRED PROPERTIES (I) THE TRANSFERRING PARTY MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) THE TRANSFERRING PARTY EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO THE NON-TRANSFERRING PARTY OR ANY OF THE NON-TRANSFERRING PARTY’S AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO THE NON-TRANSFERRING PARTY BY A MEMBER OF THE TRANSFERRING PARTY’S RELATED INDEMNIFIED PARTIES).

(b)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE IV OR ARTICLE V, AS APPLICABLE AND WITH RESPECT TO THE SPECIAL WARRANTY SET FORTH IN THE APPLICABLE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, WITH RESPECT TO ITS TRANSFERRED PROPERTIES, THE TRANSFERRING PARTY EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, BY ANY MEMBER OF THE TRANSFERRING PARTY’S RELATED INDEMNIFIED PARTIES, AS TO (I) TITLE TO ANY OF SUCH TRANSFERRED PROPERTIES, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE TRANSFERRED PROPERTIES, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM SUCH TRANSFERRED PROPERTIES, (IV) ANY ESTIMATES OF THE VALUE OF SUCH TRANSFERRED PROPERTIES OR FUTURE REVENUES GENERATED BY SUCH TRANSFERRED PROPERTIES, (V) THE PRODUCTION OF HYDROCARBONS FROM SUCH TRANSFERRED PROPERTIES, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF SUCH TRANSFERRED PROPERTIES, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY THE TRANSFERRING PARTY OR THIRD PARTIES WITH RESPECT SUCH TRANSFERRED PROPERTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO THE NON-TRANSFERRING PARTY OR THE NON-TRANSFERRING PARTY’S AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE IV OR ARTICLE V, AS APPLICABLE AND WITH RESPECT TO THE SPECIAL WARRANTY SET FORTH IN THE APPLICABLE ASSIGNMENT, WITH RESPECT TO

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ITS TRANSFERRED PROPERTIES, THE TRANSFERRING PARTY FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY SUCH TRANSFERRED PROPERTIES, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT THE NON-TRANSFERRING PARTY SHALL BE DEEMED TO BE OBTAINING THE TRANSFERRED PROPERTIES OF SUCH TRANSFERRING PARTY IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT SUCH NON-TRANSFERRING PARTY HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS IT DEEMS APPROPRIATE.

(c)EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN SECTION 4.13 OR SECTION 5.13, AS APPLICABLE,AND SUBJECT TO THE NON-TRANSFERRING PARTY’S RIGHTS UNDER SECTION 10.2(f), SECTION 10.3(f) SECTION 10.2(g), SECTION 10.3(g), SECTION 10.2(k) OR SECTION 10.3(k) LIMITING THE GENERALITY OF THE FOREGOING, WITH RESPECT TO ITS TRANSFERRED PROPERTIES, THE TRANSFERRING PARTY MAKES NO REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF SUCH TRANSFERRED PROPERTIES, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO THE NON-TRANSFERRING PARTY’S RIGHTS FOR A BREACH OF SECTION 4.13 OR SECTION 5.13, AS APPLICABLE, AND ITS RIGHTS UNDER SECTION 10.2(f), SECTION 10.3(f) SECTION 10.2(g), SECTION 10.3(g), SECTION 10.2(k), OR SECTION 10.3(k), AS APPLICABLE, THE NON-TRANSFERRING PARTY SHALL BE DEEMED TO BE TAKING SUCH TRANSFERRED PROPERTIES OF THE TRANSFERRING PARTY “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THE NON-TRANSFERRING PARTY HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS IT DEEMS APPROPRIATE.

(d)CONSOL AND NOBLE AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 3.5 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE IVREPRESENTATIONS AND WARRANTIES OF CONSOL

CONSOL represents and warrants to Noble the following:

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4.1Organization, Existence. CONSOL is a limited liability company duly formed and validly existing under the Laws of Virginia, the state of its formation. CONSOL has all requisite power and authority to own and operate its property (including the CONSOL Transferred Assets) and to carry on its business as now conducted. CONSOL is duly licensed or qualified to do business as a foreign limited liability company and is in good standing in the Commonwealth of Pennsylvania and the State of West Virginia.

4.2Authorization. CONSOL has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by CONSOL of this Agreement have been duly and validly authorized and approved by all necessary limited liability company action on the part of CONSOL. This Agreement is, and the Transaction Documents to which CONSOL is a party when executed and delivered by CONSOL will be, the valid and binding obligation of CONSOL and enforceable against CONSOL in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

4.3No Conflicts. Except as set forth on Schedule 4.3 and for any restrictions under any Terminated Agreement, and assuming the receipt of all consents (including any CONSOL Consent) and the waiver of, or compliance with, all CONSOL Preferential Purchase Rights, the execution, delivery and performance by CONSOL of this Agreement and the consummation of the transactions contemplated herein by CONSOL do not and will not (a) conflict with, violate or result in a breach of any provisions of the organizational documents or other governing documents of CONSOL, (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any CONSOL Transferred Lease or Transferred Contract that is a part of the CONSOL Transferred Assets or any note, bond, mortgage, indenture or Contract to which CONSOL is a party or by which CONSOL or the CONSOL Transferred Assets may be bound or (c) violate any Law applicable to CONSOL or any of the CONSOL Transferred Assets, except in the case of subsections (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

4.4Consents. Except (a) as set forth on Schedule 4.4 and for those Contracts covered by the provisions of Section 6.9, (b) for Customary Post Closing Consents, (c) under Contracts that are terminable upon not greater than 60 days’ notice without payment of any fee, (d) for any Preferential Purchase Rights, (e) any consents or approvals required under the HSR Act and (f) any consents under any Terminated Agreement, there are no prohibitions on assignment or requirements to obtain consents from Third Parties, in each case, that would be applicable in connection with the transfer of the CONSOL Transferred Assets or the consummation of the transactions contemplated by this Agreement by CONSOL (each such consent but including those set forth in Schedule 4.4, a “CONSOL Consent”).

4.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to CONSOL’s Knowledge, threatened against CONSOL.

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4.6Foreign Person. CONSOL is an entity disregarded as separate from CNX Gas for federal income Tax purposes and CNX Gas is neither a disregarded entity nor a “foreign person” within the meaning of the Code and the Treasury Regulations promulgated thereunder.

4.7Litigation. Except as set forth on Schedule 4.7, there is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person before any Governmental Authority or arbitrator (a) pending or, to CONSOL’s Knowledge, threatened in writing, against CONSOL with respect to any of the CONSOL Transferred Assets or (b) to CONSOL’s Knowledge, pending or threatened in writing against any Third Party operator of any of the CONSOL Transferred Assets.

4.8No Violation of Laws. Except as set forth on Schedule 4.8 and to CONSOL’s Knowledge, neither CONSOL nor any Third Party operator is in violation of any applicable Laws with respect to the ownership or operation of the CONSOL Transferred Assets. This Section 4.8 does not include any matters with respect to Environmental Laws or any environmental matter.

4.9CONSOL Preferential Purchase Rights. Except as set forth on Schedule 4.9 and under any Terminated Agreement, there are no (a) preferential purchase rights, rights of first refusal or similar rights and (b) rights of first offer, tag-along rights, drag-along rights or other similar rights, in each case of subsection (a) and (b) above, that are applicable to the transfer of the CONSOL Transferred Assets in connection with the transactions contemplated hereby (each such right, including those set forth in Schedule 4.9, a “CONSOL Preferential Purchase Right”).

4.10Permits. To CONSOL’s Knowledge, CONSOL possesses all material permits, licenses, orders, approvals, variances, waivers, franchise rights and other authorizations (the “Permits”) required to be obtained from any Governmental Authority for conducting its business with respect to the CONSOL Transferred Assets, except where the failure to possess any such Permit would not have a Material Adverse Effect.

4.11CONSOL Contracts.  

(a)Except for the CONSOL Contracts, there are no Contracts that burden the CONSOL Transferred Assets that will be binding on such CONSOL Transferred Assets or Noble from and after the Closing.

(b)With respect to the CONSOL Contracts, except as set forth on Schedule 4.11(b):

(i)there exists no default under any CONSOL Contract by CONSOL or, to CONSOL’s Knowledge, by any other Person that is a party to such CONSOL Contract, and, except as would not have a Material Adverse Effect, no event has occurred that upon receipt of notice or lapse of time or both would constitute any default under any such CONSOL Contract by CONSOL or, to CONSOL’s Knowledge, any other Person who is a party to such CONSOL Contract; and

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(ii)prior to the execution of this Agreement, CONSOL has made available to Noble true and complete copies of each CONSOL Contract.

4.12Brokers’ Fees. Neither CONSOL nor any of its Affiliates have incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which Noble or any Affiliate of Noble shall have any responsibility.

4.13Environmental.  

(a)Except as set forth on Schedule 4.13, with respect to the CONSOL Transferred Assets CONSOL has neither entered into nor is a party (directly or as successor in interest) to, any agreement with, plea, diversion agreement or consent, order, decree or judgment of any Governmental Authority that (i) is in existence as of the Execution Date, (ii) are based on any Environmental Law and (iii) requires any remediation or change in the present condition of any of the CONSOL Transferred Assets, provided that this Section 4.13(a) shall not cover any reclamation obligations arising in the ordinary course of business under any Permit for any CONSOL Transferred Property.

(b)Except as set forth on Schedule 4.13, CONSOL has not received written notice from any Person or given written notice to any Governmental Authority of any release, spill, disposal, environmental condition or environmental incident (in each case) relating to any Hazardous Substance and concerning any land, facility, asset or property included in the CONSOL Transferred Assets that: (i) violates any Environmental Law or the terms of any license or permit issued pursuant thereto (ii) gives rise to or results in any common Law or other liability of CONSOL to any Person, (iii) requires CONSOL to take any remedial actions or show cause why remedial action is not required, or (iv) subject CONSOL to any fine, penalty or assessment of any Governmental Authority; provided that subsections (ii) and (iii) of this Section 4.13(b) shall not cover any reclamation obligations arising in the ordinary course of business under any Permit for any CONSOL Transferred Property.

(c)To CONSOL’s Knowledge, as of the Execution Date, CONSOL has made available to Noble all material written environmental reports prepared by a Third Party on behalf of CONSOL with respect to any of the CONSOL Transferred Assets.

4.14Notices of Claims. To CONSOL’s Knowledge, as of the Execution Date, neither CONSOL nor any of its Affiliates have received any written notices from any Third Party (a) requiring that any CONSOL Transferred Well be plugged and abandoned, (b) alleging the termination of any CONSOL Transferred Lease or (c) alleging any tort, breach of contract, or violation of any Law (excluding Environmental Laws) with respect to CONSOL’s ownership or operation of any of the CONSOL Transferred Assets.

4.15Bonds and Credit Support. Schedule 4.15 lists all bonds, letters of credit, guaranties and other similar credit support instruments that (a) are maintained by CONSOL or any of its Affiliates with any Governmental Authority or other Third Party with respect to the CONSOL

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Transferred Assets and (b) will be required to be obtained and delivered by Noble pursuant to Section 6.5.

4.16Independent Evaluation. CONSOL is sophisticated in the evaluation, acquisition, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, CONSOL has relied solely (a) on the representations and warranties of Noble set forth in Article V (or in any certificate furnished to CONSOL in connection with this Agreement) and in the other Transaction Documents and (b) on its own independent investigation and evaluation of the Noble Transferred Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of Noble (other than Noble’s representations and warranties contained herein, in any certificate furnished to CONSOL in connection with this Agreement, or in the Transaction Documents).

4.17Taxes. With respect to the CONSOL Transferred Assets: (i) all Asset Taxes that have become due and payable have been paid, and all Tax Returns that are required to be filed with respect to Asset Taxes have been timely filed; (ii) there are no liens on any of the CONSOL Transferred Assets attributable to Taxes other than statutory liens for Taxes that are not yet due and payable; and (iii) none of the CONSOL Transferred Assets is subject to any tax partnership agreement or is otherwise treated as held in an arrangement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code other than, for the avoidance of doubt, the Tax Partnership.

ARTICLE VREPRESENTATIONS AND WARRANTIES OF NOBLE

Noble represents and warrants to CONSOL the following:

5.1Organization, Existence. Noble is a corporation duly formed and validly existing under the Laws of Delaware, the state of its incorporation. Noble has all requisite power and authority to own and operate its property (including the Noble Transferred Assets) and to carry on its business as now conducted. Noble is duly licensed or qualified to do business as a foreign corporation and is in good standing in the Commonwealth of Pennsylvania and the State of West Virginia.

5.2Authorization. Noble has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Noble of this Agreement have been duly and validly authorized and approved by all necessary corporate action on the part of Noble. This Agreement is, and the Transaction Documents to which Noble is a party when executed and delivered by Noble will be, the valid and binding obligation of Noble and enforceable against Noble in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

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5.3No Conflicts. Except as set forth on Schedule 5.3 and for any restrictions under any Terminated Agreement and assuming the receipt of all consents (including any Noble Consent) and the waiver of, or compliance with, all Noble Preferential Purchase Rights, the execution, delivery and performance by Noble of this Agreement and the consummation of the transactions contemplated herein by Noble do not and will not (a) conflict with, violate or result in a breach of any provisions of the organizational documents or other governing documents of Noble, (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any Noble Transferred Lease or Transferred Contract that is a part of the Noble Transferred Assets or any note, bond, mortgage, indenture or Contract to which Noble is a party or by which Noble or the Noble Transferred Assets may be bound or (c) violate any Law applicable to Noble or any of the Noble Transferred Assets, except in the case of subsections (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

5.4Consents. Except (a) as set forth on Schedule 5.4 and for those Contracts covered by the provisions of Section 6.9, (b) for Customary Post Closing Consents, (c) under Contracts that are terminable upon not greater than 60 days’ notice without payment of any fee, (d) for any Preferential Purchase Rights, (e) any consents or approvals required under the HSR Act and (f) any consents under any Terminated Agreement, there are no prohibitions on assignment or requirements to obtain consents from Third Parties, in each case, that would be applicable in connection with the transfer of the Noble Transferred Assets or the consummation of the transactions contemplated by this Agreement by Noble (each such consent but including those set forth in Schedule 5.4, a “Noble Consent”).

5.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Noble’s Knowledge, threatened against Noble.

5.6Foreign Person. Noble is neither a disregarded entity nor a “foreign person” within the meaning of the Code and the Treasury Regulations promulgated thereunder.

5.7Litigation. Except as set forth on Schedule 5.7, there is no lawsuit, action, administrative or arbitration proceeding or litigation by any Person before any Governmental Authority or arbitrator (a) pending or, to Noble’s Knowledge, threatened in writing, against Noble with respect to any of the Noble Transferred Assets or (b) to Noble’s Knowledge, pending or threatened in writing against any Third Party operator of any of the Noble Transferred Assets.

5.8No Violation of Laws. Except as set forth on Schedule 5.8 and to Noble’s Knowledge, neither Noble nor any Third Party operator is in violation of any applicable Laws with respect to the ownership or operation of the Noble Transferred Assets. This Section 5.8 does not include any matters with respect to Environmental Laws or any environmental matter.

5.9Noble Preferential Purchase Rights. Except as set forth on Schedule 5.9 and under any Terminated Agreement, there are no (a) preferential purchase rights, rights of first refusal or similar rights and (b) rights of first offer, tag-along rights, drag-along rights or other similar rights, in each case of subsection (a) and (b) above, that are applicable to the transfer of the Noble Transferred

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Assets in connection with the transactions contemplated hereby (each such right, including those set forth in Schedule 5.9, a “Noble Preferential Purchase Right”).

5.10Permits. To Noble’s Knowledge, Noble possesses all material Permits required to be obtained from any Governmental Authority for conducting its business with respect to the Noble Transferred Assets, except where the failure to possess any such Permit would not have a Material Adverse Effect.

5.11Noble Contracts.  

(a)Except for the Noble Contracts, there are no Contracts that burden the Noble Transferred Assets that will be binding on such Noble Transferred Assets or CONSOL from and after the Closing.

(b)With respect to the Noble Contracts, except as set forth on Schedule 5.11(b):

(i)there exists no default under any Noble Contract by Noble or, to Noble’s Knowledge, by any other Person that is a party to such Noble Contract, and, except as would not have a Material Adverse Effect, no event has occurred that upon receipt of notice or lapse of time or both would constitute any default under any such Noble Contract by Noble or, to Noble’s Knowledge, any other Person who is a party to such Noble Contract; and

(ii)prior to the execution of this Agreement, Noble has made available to CONSOL true and complete copies of each Noble Contract.

5.12Brokers’ Fees. Neither Noble nor any of its Affiliates have incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which CONSOL or any Affiliate of CONSOL shall have any responsibility.

5.13Environmental.  

(a)Except as set forth on Schedule 5.13, with respect to the Noble Transferred Assets, Noble has neither entered into nor is a party (directly or as successor in interest) to, any agreement with, plea, diversion agreement or consent, order, decree or judgment of any Governmental Authority that (i) is in existence as of the Execution Date, (ii) are based on any Environmental Law and (iii) requires any remediation or change in the present condition of any of the Noble Transferred Assets, provided that this Section 5.13(a) shall not cover any reclamation obligations arising in the ordinary course of business under any Permit for any Noble Transferred Property.

(b)Except as set forth on Schedule 5.13, Noble has not received written notice from any Person or given written notice to any Governmental Authority of any release, spill, disposal, environmental condition or environmental incident (in each case) relating to any Hazardous Substance and concerning any land, facility, asset or property included in the

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Noble Transferred Assets that: (i) violates any Environmental Law or the terms of any license or permit issued pursuant thereto (ii) gives rise to or results in any common Law or other liability of Noble to any Person, (iii) requires Noble to take any remedial actions or show cause why remedial action is not required, or (iv) subject Noble to any fine, penalty or assessment of any Governmental Authority; provided that subsections (ii) and (iii) of this Section 5.13(b) shall not cover any reclamation obligations arising in the ordinary course of business under any Permit for any Noble Transferred Property.

(c)To Noble’s Knowledge, as of the Execution Date, Noble has made available to CONSOL all material written environmental reports prepared by a Third Party on behalf of Noble with respect to any of the Noble Transferred Assets.

5.14Notices of Claims. To Noble’s Knowledge, as of the Execution Date, neither Noble nor any of its Affiliates have received any written notices from any Third Party (a) requiring that any Noble Transferred Well be plugged and abandoned, (b) alleging the termination of any Noble Transferred Lease or (c) alleging any tort, breach of contract, or violation of any Law (excluding Environmental Laws) with respect to Noble’s ownership or operation of any of the Noble Transferred Assets.

5.15Bonds and Credit Support. Schedule 5.15 lists all bonds, letters of credit, guaranties and other similar credit support instruments that (a) are maintained by Noble or any of its Affiliates with any Governmental Authority or other Third Party with respect to the Noble Transferred Assets and (b) will be required to be obtained and delivered by CONSOL pursuant to Section 6.5.

5.16Independent Evaluation. Noble is sophisticated in the evaluation, acquisition, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Noble has relied solely (a) on the representations and warranties of CONSOL set forth in Article IV (or in any certificate furnished to Noble in connection with this Agreement) and in the other Transaction Documents and (b) on its own independent investigation and evaluation of the CONSOL Transferred Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of CONSOL (other than CONSOL’s representations and warranties contained herein, in any certificate furnished to Noble in connection with this Agreement, or in the Transaction Documents).

5.17Taxes. With respect to the Noble Transferred Assets: (i) all Asset Taxes that have become due and payable have been paid, and all Tax Returns that are required to be filed with respect to Asset Taxes have been timely filed; (ii) there are no liens on any of the Noble Transferred Assets attributable to Taxes other than statutory liens for Taxes that are not yet due and payable; and (iii) none of the Noble Transferred Assets is subject to any tax partnership agreement or is otherwise treated as held in an arrangement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code other than, for the avoidance of doubt, the Tax Partnership.

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ARTICLE VICERTAIN AGREEMENTS

6.1Conduct of Business by CONSOL. Except as (x) set forth on Schedule 6.1, (y) for emergency operations and (z) expressly contemplated by this Agreement or expressly consented to in writing by Noble (which consent shall not be unreasonably delayed, withheld or conditioned):

(a)With respect to the CONSOL Transferred Assets, CONSOL agrees that from and after the Execution Date until Closing, CONSOL will:

(i)use its commercially reasonable efforts to cause the operation of the CONSOL Transferred Assets not operated by CONSOL to be operated, and to operate the CONSOL Transferred Assets operated by CONSOL, in each case, in the usual, regular and ordinary manner consistent with past practice;

(ii)pay, in all material respects, all expenses incurred with respect to the CONSOL Transferred Assets in the usual, regular and ordinary manner consistent with past practice;

(iii)maintain the books of account and records relating to the CONSOL Transferred Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of each such Person;

(iv)give written notice to Noble as soon as is practicable of any written notice received or given by CONSOL with respect to any alleged material breach by CONSOL or other Person of any CONSOL Contract;

(v)with respect to emergency operations, CONSOL shall notify Noble of such emergency and the related emergency operations as soon as reasonably practicable; and

(vi)give prompt notice to Noble of (A) any written notice of any material damage to or destruction of any of the CONSOL Transferred Assets of which CONSOL has Knowledge and (B) any written notice received by CONSOL of any material claim asserting any breach of Contract, tort or violation of Law or any investigation, suit, action or litigation by or before a Governmental Authority, that (in each case) relates to the CONSOL Transferred Assets.

(b)With respect to the CONSOL Transferred Assets, CONSOL agrees that from and after the Execution Date until Closing, CONSOL will not:

(i)subject to the provisions of this Section 6.1(b)(i), propose or agree to participate in any operation with respect to the CONSOL Transferred Assets anticipated to cost in excess of $50,000 (net to CONSOL’s interest in the CONSOL Transferred Assets) without the prior written consent of Noble; provided that, with respect to each AFEproposed by a Third Party in excess of $50,000 (net to CONSOL’s

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interest in the CONSOL Transferred Assets) and each AFE to be proposed by CONSOL, CONSOL shall forward the same to Noble as soon as reasonably practicable prior to CONSOL proposing or agreeing to participate in such operation, as applicable. With respect to any AFE for an operation to be conducted in connection with the CONSOL Transferred Assets that is anticipated to cost in excess of $50,000 per operation (net to CONSOL’s interest in the CONSOL Transferred Assets), upon receipt of such AFE from CONSOL, Noble shall review and respond, within seven days of its receipt thereof, to CONSOL in writing with respect to whether it desires to consent or non-consent the operation covered by such AFE; provided that if Noble does not timely respond with its election with respect to any such AFE within such seven day period, then Noble shall be deemed to have responded to such AFE in the same manner as CONSOL elects to vote with respect to such operation;

(ii)enter into a Contract that if entered into on or prior to the Execution Date, would cause CONSOL to be unable to make the representation and warranty set forth in Section 4.11(a) as of the Closing;

(iii)terminate (unless such CONSOL Contract terminates pursuant to its stated terms) or amend the terms of any CONSOL Contract;

(iv)(A) settle any suit or litigation or (B) waive any claims or rights with a value in excess of $50,000, in each case, attributable to the CONSOL Transferred Assets and affecting the period after the Effective Time;

(v)transfer, sell, mortgage, pledge or dispose of the CONSOL Transferred Assets other than the sale and/or disposal of Hydrocarbons in the ordinary course of business and sales of equipment that is no longer necessary in the operation of the CONSOL Transferred Assets or for which replacement equipment of equal or greater value has been obtained;

(vi)voluntarily relinquish its position as operator with respect to any CONSOL Transferred Asset that CONSOL operated as of (A) the Execution Date, or (B) the Closing Date;

(vii)make, change or revoke any Tax election; change an annual accounting period; adopt or change any accounting method with respect to Taxes; file any amended Tax Return; enter into any closing agreement; settle or compromise any Tax claim or assessment; or consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Asset Taxes; or

(viii)commit to do any of the foregoing.

(c)Noble acknowledges that CONSOL owns undivided interests in certain of the CONSOL Transferred Assets with respect to which it is not the operator, and Noble agrees that the acts or omissions of the other working interest owners (including the operators) who are not CONSOL or any Affiliates of CONSOL shall not constitute a breach of the provisions

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of this Section 6.1, nor shall any action required by a vote of working interest owners constitute such a breach so long as CONSOL has voted its interest in a manner that complies with the provisions of this Section 6.1.

6.2Conduct of Business by Noble. Except as (x) set forth on Schedule 6.2, (y) for emergency operations and (z) expressly contemplated by this Agreement or expressly consented to in writing by CONSOL (which consent shall not be unreasonably delayed, withheld or conditioned):

(a)With respect to the Noble Transferred Assets, Noble agrees that from and after the Execution Date until Closing, Noble will:

(i)use its commercially reasonable efforts to cause the operation of the Noble Transferred Assets not operated by Noble to be operated, and to operate the Noble Transferred Assets operated by Noble, in each case, in the usual, regular and ordinary manner consistent with past practice;

(ii)pay, in all material respects, all expenses incurred with respect to the Noble Transferred Assets in the usual, regular and ordinary manner consistent with past practice;

(iii)maintain the books of account and records relating to the Noble Transferred Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of each such Person;

(iv)give written notice to CONSOL as soon as is practicable of any written notice received or given by Noble with respect to any alleged material breach by Noble or other Person of any Noble Contract;

(v)with respect to emergency operations, Noble shall notify CONSOL of such emergency and the related emergency operations as soon as reasonably practicable; and

(vi)give prompt notice to CONSOL of (A) any written notice of any material damage to or destruction of any of the Noble Transferred Assets of which Noble has Knowledge and (B) any written notice received by Noble of any material claim asserting any breach of Contract, tort or violation of Law or any investigation, suit, action or litigation by or before a Governmental Authority, that (in each case) relates to the Noble Transferred Assets.

(b)With respect to the Noble Transferred Assets, Noble agrees that from and after the Execution Date until Closing, Noble will not:

(i)subject to the provisions of this Section 6.2(b)(i), propose or agree to participate in any operation with respect to the Noble Transferred Assets anticipated to cost in excess of $50,000 (net to Noble’s interest in the Noble Transferred Assets) without the prior written consent of CONSOL; provided that, with respect to each

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AFE proposed by a Third Party in excess of $50,000 (net to Noble’s interest in the Noble Transferred Assets) and each AFE to be proposed by Noble, Noble shall forward the same to CONSOL as soon as reasonably practicable prior to Noble proposing or agreeing to participate in such operation, as applicable. With respect to any AFE for an operation to be conducted in connection with the Noble Transferred Assets that is anticipated to cost in excess of $50,000 per operation (net to Noble’s interest in the Noble Transferred Assets), upon receipt of such AFE from Noble, CONSOL shall review and respond, within seven days of its receipt thereof, to Noble in writing with respect to whether it desires to consent or non-consent the operation covered by such AFE; provided that if CONSOL does not timely respond with its election with respect to any such AFE within such seven day period, then CONSOL shall be deemed to have responded to such AFE in the same manner as Noble elects to vote with respect to such operation;

(ii)enter into a Contract that if entered into on or prior to the Execution Date, would cause Noble to be unable to make the representation and warranty set forth in Section 5.11(a) as of the Closing;

(iii)terminate (unless such Noble Contract terminates pursuant to its stated terms) or amend the terms of any Noble Contract;

(iv)(A) settle any suit or litigation or (B) waive any claims or rights with a value in excess of $50,000, in each case, attributable to the Noble Transferred Assets and affecting the period after the Effective Time

(v)transfer, sell, mortgage, pledge or dispose of the Noble Transferred Assets other than the sale and/or disposal of Hydrocarbons in the ordinary course of business and sales of equipment that is no longer necessary in the operation of the Noble Transferred Assets or for which replacement equipment of equal or greater value has been obtained;

(vi)voluntarily relinquish its position as operator with respect to any Noble Transferred Asset that Noble operated as of (A) the Execution Date, or (B) the Closing Date;

(vii)make, change or revoke any Tax election; change an annual accounting period; adopt or change any accounting method with respect to Taxes; file any amended Tax Return; enter into any closing agreement; settle or compromise any Tax claim or assessment; or consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Asset Taxes; or

(viii)commit to do any of the foregoing.

(c)CONSOL acknowledges that Noble owns undivided interests in certain of the Noble Transferred Assets with respect to which it is not the operator, and CONSOL agrees that the acts or omissions of the other working interest owners (including the operators) who

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are not Noble or any Affiliates of Noble shall not constitute a breach of the provisions of this Section 6.2, nor shall any action required by a vote of working interest owners constitute such a breach so long as Noble has voted its interest in a manner that complies with the provisions of this Section 6.2.

6.3HSR Act. If applicable, within one Business Day following the execution by Noble and CONSOL of this Agreement, Noble and CONSOL will each prepare and simultaneously file with the DOJ and the FTC the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early termination of the waiting period thereunder. Noble and CONSOL agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act. Noble and CONSOL shall cooperate with each other and shall promptly furnish all information to the other Party that is necessary in connection with Noble’s and CONSOL’s compliance with the HSR Act. Noble and CONSOL shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto. Each of CONSOL and Noble shall use its reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby. Any fees or expenses related to filings required by this Section 6.3 shall be paid 50% by Noble and 50% by CONSOL.

6.4Operatorship. While each Non-Transferring Party acknowledges that it desires to succeed its Transferring Party as operator with respect to the Transferred Properties that such Transferring Party is presently operating, such Non-Transferring Party acknowledges and agrees that such Transferring Party cannot and does not covenant or warrant that such Non-Transferring Party shall become successor operator of same since such Transferred Properties or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Within five Business Days after Closing, each Transferring Party shall send notices to co-owners of the Transferred Properties being transferred by such Transferring Party that such Transferring Party currently operates (other than such Non-Transferring Party) indicating that such Transferring Party is resigning as operator, effective as of the Closing Date, and recommending that such Non-Transferring Party be elected successor operator. Such Transferring Party shall cooperate, without having to pay or incur any cost or expense (unless paid by such Non-Transferring Party), with such Non-Transferring Party in connection with such Non-Transferring Party’s efforts to have such Non-Transferring Party be elected successor operator. If requested by such Non-Transferring Party, such Transferring Party will cast its vote, and will execute mutually satisfactory letters prepared by such Non-Transferring Party requesting the votes of the other owners of working interests in the relevant Transferred Properties, in each case in favor of the designation of such Non-Transferring Party as successor operator of such Transferred Properties, effective as of the Closing Date.

6.5Governmental Bonds, etc.. Each Non-Transferring Party acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by its Transferring Party or such Transferring Party’s Affiliates with Governmental Authorities or other Third Parties and relating to the Transferred Properties being transferred by such Transferring Party, are transferable or are to be transferred to such Non-Transferring Party. On or prior to the expiration of the operational services provided by the Transferring Party under the CONSOL Transition Services Agreement or

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the Noble Transition Services Agreement, as applicable, the Non-Transferring Party shall deliver to such Transferring Party evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such authorities for such Non-Transferring Party to own and, where appropriate, for such Non-Transferring Party or its Affiliates to operate, such Transferred Properties.

6.6On-Going Leasing Activity. In the event that CONSOL acquires any oil and gas leases or fee mineral interest in the Noble Areas prior to Closing from a Third Party (where upon such acquisition CONSOL would be the operator thereof) and such leases and/or interest cover the formations conveyed by CONSOL in such section of the Noble Areas, then such oil and gas leases and/or fee mineral interests, insofar as the same cover such formation(s) shall be transferred as part of the CONSOL Transferred Assets hereunder and Noble shall reimburse CONSOL for the actual out-of-pocket costs paid to such Third Party to acquire such oil and gas leases and/or fee mineral interests. In the event that Noble acquires any oil and gas leases or fee mineral interest in the CONSOL Areas prior to Closing from a Third Party (where upon such acquisition Noble would be the operator thereof) and such leases and/or interest cover the formations conveyed by Noble in such section of the CONSOL Areas, then such oil and gas leases and/or fee mineral interests, insofar as the same cover such formation(s) shall be transferred as part of the Noble Transferred Assets hereunder and CONSOL shall reimburse Noble for the actual out-of-pocket costs paid to such Third Party to acquire such oil and gas leases and/or fee mineral interests. Prior to Closing (a) CONSOL shall have no obligation under the Development Agreement to offer any interest in any oil and gas lease, fee mineral interest or other similar interest acquired by CONSOL in the CONSOL Areas to Noble, and (b) Noble shall have no obligation under the Development Agreement to offer any interest in any oil and gas lease, fee mineral interest or other similar interest acquired by Noble in the Noble Areas to CONSOL.

6.7Fill-In Acreage. Notwithstanding anything else contained herein, from and after Closing up to the first anniversary date thereof, each Non-Transferring Party shall have the right to provide notice to its Transferring Party of any Fill-In Interest believed by the Non-Transferring Party to be held by such Transferring Party or any of its Affiliates that covers the same formations conveyed by such Transferring Party to such Non-Transferring Party in a Transferred Unit acquired by such Non-Transferring Party and which Fill-In Interest such Non-Transferring Party desires to acquire (“Fill-In Notice”). Within 10 Business Days of such Transferring Party receiving the Fill-In Notice, such Transferring Party will respond to such Non-Transferring Party by (i) providing such Non-Transferring Party with all records relating to such Fill-In Interest that are in the Transferring Party’s or its Affiliates’ possession or control and the Acquisition Cost relating thereto, if such Transferring Party or its Affiliates still hold such Fill-In Interest, or (ii) provide notice that such Transferring Party or its Affiliates no longer hold such Fill-In Interest (the “Fill-In Response”). If such Transferring Party or its Affiliates hold such Fill-In Interest, then, within 60 days after such Fill-In Response is received by such Non-Transferring Party, such Non-Transferring Party will have the option to notify Transferring Party of its election to acquire all, but not less than all, of such Fill-In Interest. If such Non-Transferring Party fails to respond to the Fill-In Response within such 60 day period, such Non-Transferring Party shall be deemed to have declined its option. In the event that such Non-Transferring Party elects to acquire such Fill-In Interest for the Acquisition Cost relating thereto, then, contemporaneously with the payment of such Acquisition Costs by the

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Non-Transferring Party to the Transferring Party, such Transferring Party shall convey such Fill-In Interest to the Non-Transferring Party pursuant to an assignment substantially similar to the CONSOL Assignment, the CONSOL Deed, the Noble Assignment or the Noble Deed, as applicable.

6.8Target Net Acres.

(a)Notwithstanding anything else contained herein, in the event that a Transferring Party conveys to its Non-Transferring Party less than the Target Net Acres designated for such Transferring Party with respect to any Region (if any) at Closing (assuming for the purposes of this Section 6.8 that all Net Acres subject to any Preferential Purchase Right or Hard Consent were included in the Transferred Properties conveyed by such Transferring Party to such Non-Transferring Party at Closing) as the direct result of a Specified Defect (and not otherwise), then the following shall apply with regards to any such deficiency of Target Net Acres:

(i)On or before the date that is one year following the Closing, such Non-Transferring Party may make a claim against such Transferring Party of such deficiency of Target Net Acres in such affected Region as a direct result of a Specified Defect (and not otherwise) (“Deficiency Net Acres Claim”). Such claim shall be based on the value per Undeveloped Net Acre set forth in Exhibit O with respect to such affected Region with the value of such deficiency in such Target Net Acres being equal to an amount obtained by multiplying such value by such deficiency.

(ii)As soon as practicable, and in any event within 45 days after the date such Transferring Party receives such Deficiency Net Acres Claim, such Transferring Party will deliver to such Non-Transferring Party a written report containing any proposed changes to the Deficiency Net Acres Claim with respect to the matters raised in such claim and an explanation of any such changes and the reasons therefor (the “Deficiency Net Acres Dispute Notice”). Any proposed changes not so specified in such Deficiency Net Acres Dispute Notice shall be deemed waived and such Non-Transferring Party’s determinations with respect to all such elements of its Deficiency Net Acres Claim that are not addressed specifically in the Deficiency Net Acres Dispute Notice shall prevail.

(iii)If such Transferring Party fails to timely deliver a Deficiency Net Acres Dispute Notice to such Non-Transferring Party containing the changes that such Transferring Party proposes to be made to such Deficiency Net Acres Claim, then such Deficiency Net Acres Claim as delivered by such Non-Transferring Party in compliance with this Section 6.8(a) will be deemed to be mutually agreed upon by the Parties and will be final and binding on the Parties.

(iv)If such Deficiency Net Acres Claim is mutually agreed upon by CONSOL and Noble (or deemed agreed, as the case may be), then the Parties shall mutually agree to settle such Deficiency Net Acres Claim by such Transferring Party providing such Non-Transferring Party (i) additional acreage, (ii) additional production, (iii) the cash amount agreed to in the Deficiency Net Acres Claim, or

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(iv) a combination of the compensation provided for in clauses (i) through (iii). If the Parties are not able to mutually agree on the type(s) of compensation for such Deficiency Net Acres Claim within 10 Business Days of such Deficiency Net Acres Claim being agreed upon (or deemed agreed upon), then (to the extent not accounted for in the Final Settlement Statement) such Transferring Party shall pay to an account designated by such Non-Transferring Party the amount set forth in such Deficiency Net Acres Claim as agreed to by the Parties (or deemed agreed, as the case may be) by wire transfer in immediately available funds no later than five Business Days following such 10 Business Day period.

(b)Notwithstanding anything else contained herein, in the event that a Transferring Party conveys to its Non-Transferring Party more than the Target Net Acres designated for such Transferring Party with respect to any Region (if any) at Closing (assuming for the purposes of this Section 6.8 that all Net Acres subject to any Preferential Purchase Right or Hard Consent were included in the Transferred Properties conveyed by such Transferring Party to such Non-Transferring Party at Closing) as the direct result of a Specified Benefit (and not otherwise), then the following shall apply with regards to any such increase in such Target Net Acres:

(i)On or before the date that is one year following the Closing, such Transferring Party may make a claim against such Non-Transferring Party of such increase in such Target Net Acres in such affected Region as a direct result of a Specified Benefit (and not otherwise) (“Benefit Net Acres Claim”). Such claim shall be based on the value per Undeveloped Net Acre set forth in Exhibit O with respect to such affected Region with the value of such increase in such Target Net Acres being equal to an amount obtained by multiplying such value by such increase.

(ii)As soon as practicable, and in any event within 45 days after the date such Non-Transferring Party receives such Benefit Net Acres Claim, such Non-Transferring Party will deliver to such Transferring Party a written report containing any proposed changes to the Benefit Net Acres Claim with respect to the matters raised in such claim and an explanation of any such changes and the reasons therefor (the “Benefit Net Acres Dispute Notice”). Any proposed changes not so specified in such Benefit Net Acres Dispute Notice shall be deemed waived and Transferring Party’s determinations with respect to all such elements of its Benefit Net Acres Claim that are not addressed specifically in the Benefit Net Acres Dispute Notice shall prevail.

(iii)If such Non-Transferring Party fails to timely deliver a Benefit Net Acres Dispute Notice to such Transferring Party containing the changes that such Non-Transferring Party proposes to be made to such Benefit Net Acres Claim, then such Benefit Net Acres Claim as delivered by such Transferring Party in compliance with this Section 6.8(b) will be deemed to be mutually agreed upon by the Parties and will be final and binding on the Parties.

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(iv)If such Benefit Net Acres Claim is mutually agreed upon by CONSOL and Noble (or deemed agreed, as the case may be), then (to the extent not accounted for in the Final Settlement Statement) such Non-Transferring Party shall pay to an account designated by such Transferring Party (or CONSOL Parent if CONSOL is the Transferring Party) the amount set forth in such Benefit Net Acres Claim as agreed to by the Parties (or deemed agreed, as the case may be) by wire transfer in immediately available funds no later than five Business Days following such agreement (or deemed agreement, as the case may be).

(c)The Parties agree that if a Party discovers that it holds a Discovered Lease, then contemporaneously with the payment of any compensation pursuant to Section 6.8(b) to such Party with respect to such Discovered Lease, such Party shall convey such Discovered Lease to the other Party pursuant to an assignment or deed in substantially the same form as the Assignment or Deed, as applicable.

6.9Split of Certain FERC Regulated Downstream Contracts.

(a)With respect to the Tariff Agreements, upon satisfaction of the conditions set forth in Section 6.9(b), and, if possible, not more than five (5) Business Days following the Execution Date of this Agreement, the Parties shall jointly submit to the United States Federal Regulatory Commission (“FERC”) a Petition for Temporary Waivers of Capacity Release Regulations and Related Pipeline Tariff Provisions substantially in the form attached hereto as Exhibit L (“Petition for Waiver”), pursuant to which the Parties will seek waivers of applicable (i) capacity release regulations, (ii) tariff provisions of the transporters’ FERC tariffs and (iii) related provisions contained in the Tariff Agreements. The Petition for Waiver shall seek a permanent release of that portion of each Party’s rights and obligations in and to the Tariff Agreements (“Capacity”), as described in the Petition for Waiver.

(b)Each Party permanently releasing Capacity hereunder (the “Relinquishing Party”) shall use its commercially reasonable efforts to obtain as soon as possible from each transporter with which it has a service agreement for such Capacity the transporter’s consent or agreement not to oppose the waivers requested in the Petition for Waiver and the permanent release of Capacity as provided herein.

(c)Promptly following the later of (i) the Closing and (ii) receipt of a final FERC order granting the Petition for Waiver (the “FERC Order”), each Relinquishing Party shall effect a permanent release of the Capacity to be released hereunder in accordance with the pertinent provisions of each applicable transporter’s FERC tariff (to the extent FERC has not granted waiver of such provisions in the FERC Order). At the same time that the Relinquishing Party is effecting such permanent release of Capacity, the Party assuming the released Capacity shall post such credit support, if any, as each applicable transporter shall require pursuant to its FERC tariff. Each party receiving Capacity permanently released hereunder shall execute a new firm transportation service agreement with each respective transporter for such Capacity on the same terms and conditions as are set forth in the firm transportation service agreement of the Relinquishing Party.

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(d)Each Party shall use its commercially reasonable efforts to obtain the agreement of each respective transporter to terminate the rights, obligations and liabilities of the Relinquishing Party upon execution of each new firm transportation service agreement by the Party accepting the released Capacity as set forth herein; provided, that any rights, obligations, and liabilities arising prior to the permanent release of such Capacity shall not be affected. If all of a Relinquishing Party’s Capacity under a firm transportation service agreement is permanently released hereunder, the Parties shall each use commercially reasonable efforts to obtain the agreement of the respective transporter that such transportation service agreement of the Relinquishing Party shall terminate without any further liability of the parties to the transportation service agreement when any and all obligations and liabilities arising prior to the permanent release of the Capacity under such transportation service agreement are satisfied or otherwise extinguished.

(e)In the event that the FERC Order has not yet been issued by Closing, or in the event that FERC issues a final order denying the Petition for Waiver, the Parties will cooperate with one another to effect a temporary resolution, which may include but is not limited to entering into a non-biddable, thirty-one day release of the Capacity to be permanently released hereunder or entering into a purchase and sale arrangement to buy the gas supply of the other Party until such time as FERC issues the FERC Order, or until the Parties in good faith negotiate additional or different arrangements for the disposition of gas produced from the CONSOL Transferred Assets and the Noble Transferred Assets, as defined in this Agreement. If a sale arrangement is effectuated, the following shall apply:

(i)Title to all gas produced from the CONSOL Transferred Assets shall transfer from CONSOL to Noble at the receipt points designated for released Capacity under the Noble Tariff Agreements and Noble shall sell all such gas to parties chosen in its sole discretion.

(ii)Title to all gas produced from the Noble Transferred Assets shall transfer from Noble to CONSOL at the receipt points designated for released Capacity under the CONSOL Tariff Agreements and CONSOL shall sell all such gas to parties chosen in its sole discretion.

(iii)The proceeds from sales made by Noble shall be passed through to CONSOL, and the proceeds from sales made by CONSOL shall be passed through to Noble pursuant to the terms of a master netting agreement substantially in the form attached as Exhibit N (the “Master Netting Agreement”). Both Parties shall use commercially reasonable efforts to sell gas at a price not lower than the price that the other Party would receive for sales of its own gas; provided, however, that neither Party shall have a fiduciary obligation to obtain the best terms available for the sale of such gas.

6.10Easements.

(a)Prior to the Closing, the Parties will cooperate with each other and use their respective reasonable efforts to (i) identity any Easements to which a Party is entitled and

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has requested pursuant to the terms of that certain Surface Use Agreement dated September 30, 2011 (as amended, the “Surface Use Agreement”) that has not yet been assigned to such Party and (ii) CONSOL shall use its reasonable efforts to cause the applicable CONSOL Affiliate to assign such Easements to the applicable Party in accordance with the terms of such Surface Use Agreement.

(b)For a period of six months following Closing, Noble can request an Easement from the CONSOL Affiliates (as defined in the Surface Use Agreement) to the extent that such Easement would be utilized in operations reflected in the regions described in Schedule 6.10(b) and CONSOL shall use its reasonable efforts to cause such CONSOL Affiliates to assign each such Easement to Noble in accordance with the terms of the Surface Use Agreement (as if such Surface Use Agreement had been in effect through the expiration of the two month period with respect to such Easements).

(c)For a period of six months following Closing, CONSOL can request an easement from Noble or any Affiliate of Noble to the extent that such easement would be utilized in operations reflected in the regions described in Schedule 6.10(c) and Noble shall use its reasonable efforts to, or cause such Affiliate of Noble to, assign each such easement to CONSOL, which easement shall be substantially in the form of the Easement.

6.11Certain Other Contracts.

(a)    With respect to the MarkWest Contract where, after the partial assignment thereof to the other Party by the Transferring Party at Closing (subject to Section 3.4(b)), each Party will have continuing obligations and rights thereunder with respect to the Combined Assets held by such Party after Closing and with respect to the volumes of Hydrocarbons for which a Party is responsible in accordance with the allocations on Exhibit A-4 with respect to such MarkWest Contract. Each Party shall use its commercially reasonable efforts (continuing past Closing, to the extent necessary, up to the first anniversary of the Closing Date), to negotiate a separate agreement with MarkWest with respect to the Hydrocarbon volumes for which such Party is responsible in accordance with the allocations on Exhibit A-4 with respect to such MarkWest Contract and that are attributable to the applicable Combined Assets to be acquired or retained by such Party pursuant to this Agreement, and such agreement shall supersede and replace the obligations and rights of such Party under the MarkWest Contract.

(b)    With respect to the Nexus Contract, each Party shall use its commercially reasonable efforts (continuing past Closing, to the extent necessary, up to the first anniversary of the Closing Date) to negotiate an assignment agreement with the Third Party counterparty thereto to have 35,000 dekatherms per day of CONSOL’s capacity at Clarington released under the Nexus Contract and assigned to Noble. With respect to the Leach XPress Contract, each Party shall use its commercially reasonable efforts (continuing past Closing, to the extent necessary, up to the first anniversary of the Closing Date) to negotiate an assignment agreement with the Third Party counterparty thereto to have 50,000 dekatherms per day of Noble’s capacity at Sherwood released under the Leach XPress Contract and assigned to CONSOL.

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(c)    With respect to any master service agreement or similar Contract where, after the partial assignment thereof to the other Party at Closing (subject to Section 3.4(b)), each Party will have continuing obligations and rights thereunder with respect only to the Combined Assets held by such Party after Closing. Each Party shall use its commercially reasonable efforts (continuing past Closing, to the extent necessary, up to the date that is the 110^th day following the Closing Date), to negotiate a separate agreement with the counterparty to such Contract with respect to the services provided thereunder relating only to the applicable Combined Assets acquired or retained by such Party, and such agreement shall supersede and replace the obligations and rights of such Party under such Contract.

6.12Amendment of Certain Schedules. Each Party agrees that, with respect to the representations and warranties of the other Party in Section 4.7, Section 4.13, Section 5.7 or Section 5.13, as applicable, such other Party shall have the continuing right until the Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising or discovered which, if existing or known at the Execution Date or thereafter, would have been required to be set forth or described in such Schedules. For purposes of determining whether the conditions set forth in Article VII or Article VIII have been fulfilled and for all other purposes, including for purposes of the Parties’ indemnity obligations under Article X, the Schedules to such other Party’s representations and warranties contained in this Agreement shall be deemed to include all information contained in such addition, supplement or amendment to such Schedules.

6.1Water Assets. It is the intent of the Parties that each of CONSOL and Noble will hold title to an undivided 50% interest in and to the Water Assets and all associated rights-of-way, easements, surface rights and other real property and related assets used in connection therewith. Prior to Closing, each Party shall use its reasonable efforts to assign to the other Party an undivided 50% interest in and to such Water Assets and associated rights-of-way, easements and surface rights and other real property and related assets used in connection therewith that are currently held solely by the assigning Party.

ARTICLE VIINOBLE’S CONDITIONS TO CLOSING

The obligations of Noble to consummate the exchange of the Noble Transferred Assets and the CONSOL Transferred Assets, make the payment of the Adjusted Cash Consideration as determined in accordance with Section 2.8 and consummate the other transactions provided for herein is subject, at the option of Noble, to the fulfillment by CONSOL or waiver by Noble, on or prior to the Closing of each of the following conditions precedent:

7.1Representations. The representations and warranties of CONSOL set forth in Article IV shall be true and correct in all respects on and as of the Closing Date, with the same force and without giving effect to any qualifiers as to materiality, Material Adverse Effect or material adverse effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except where the failure of such

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representations and warranties to be so true and correct in the aggregate would not have a Material Adverse Effect.

7.2Performance. CONSOL shall have performed, observed or complied with, in all material respects, all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by CONSOL is required prior to or at the Closing Date.

7.3No Legal Proceedings. No material suit, action or other proceeding instituted by a Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement. No order, award or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal, or awarding substantial damages in connection with, the transactions contemplated by this Agreement.

7.4Certificate. An authorized officer of CONSOL shall execute and deliver a certificate dated as of the Closing Date in the form attached hereto as Exhibit K-1 certifying on behalf of CONSOL that the conditions set forth in Section 7.1 and Section 7.2 have been fulfilled by CONSOL and, if applicable, any exceptions to such conditions that have been waived by Noble.

7.5HSR Act. If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions hereby shall have expired, notice of early termination shall have been received or a consent order issued (in form and substance satisfactory to Noble and CONSOL) by or from the applicable Governmental Authorities.

7.6Closing Deliverables. CONSOL shall have delivered (or be ready, willing and able to deliver at Closing) to Noble the documents and other items required to be delivered by CONSOL under Section 9.3.

ARTICLE VIIICONSOL’S CONDITIONS TO CLOSING

The obligations of CONSOL to consummate the exchange of the Noble Transferred Assets and the CONSOL Transferred Assets, cause the cancellation and forgiveness of the Carried Costs Balance, and consummate the other transactions provided for herein is subject, at the option of CONSOL, to the fulfillment by Noble or waiver by CONSOL, on or prior to the Closing of each of the following conditions precedent:

8.1Representations. The representations and warranties of Noble set forth in Article V shall be true and correct in all respects on and as of the Closing Date, with the same force and without giving effect to any qualifiers as to materiality, Material Adverse Effect or material adverse effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except where the failure of such representations and warranties to be so true and correct in the aggregate would not have a Material Adverse Effect.

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8.2Performance. Noble shall have performed, observed or complied with, in all material respects, all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Noble is required prior to or at the Closing Date.

8.3No Legal Proceedings. No material suit, action or other proceeding instituted by a Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement. No order, award or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal, or awarding substantial damages in connection with, the transactions contemplated by this Agreement.

8.4Certificate. An authorized officer of Noble shall execute and deliver a certificate dated as of the Closing Date in the form attached hereto as Exhibit K-2 certifying on behalf of Noble that the conditions set forth in Section 8.1 and Section 8.2 have been fulfilled by Noble and, if applicable, any exceptions to such conditions that have been waived by CONSOL.

8.5HSR Act. If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions hereby shall have expired, notice of early termination shall have been received or a consent order issued (in form and substance satisfactory to Noble and CONSOL) by or from the applicable Governmental Authorities.

8.6Closing Deliverables. Noble shall have delivered (or be ready, willing and able to deliver at Closing) to CONSOL the documents and other items, including the Adjusted Cash Consideration as determined in accordance with Section 2.8, required to be delivered by Noble under Section 9.3.

ARTICLE IXCLOSING

9.1Date of Closing. Subject to the conditions set forth in this Agreement, the exchange of the Transferred Properties by CONSOL and Noble and consummation of the other transactions contemplated hereby pursuant to this Agreement (the “Closing”) shall occur at 10:00 am (Central Time) on December 1, 2016 (the “Scheduled Closing Date”),or such other date as CONSOL and Noble may agree upon in writing; provided that if the conditions to Closing in Article VII and Article VIII have not yet been satisfied or waived by the Scheduled Closing Date, then Closing shall occur five Business Days after such conditions have been satisfied or waived. The date Closing actually occurs shall be the “ClosingDate.”

9.2Place of Closing. The Closing shall be held at the offices of Latham & Watkins LLP, located at 811 Main Street, Suite 3700, Houston, Texas 77002 or such other location as Noble and CONSOL may agree upon in writing.

9.3Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

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(a)CONSOL and Noble shall execute and deliver the CONSOL Assignment in sufficient counterparts to facilitate recording in the applicable counties covering the CONSOL Transferred Assets;

(b)CONSOL and Noble shall execute and deliver the Noble Assignment in sufficient counterparts to facilitate recording in the applicable counties covering the Noble Transferred Assets;

(c)CONSOL and Noble shall execute and deliver the CONSOL Deed in sufficient counterparts to facilitate recording in the applicable counties covering the CONSOL Transferred Assets;

(d)CONSOL and Noble shall execute and deliver the Noble Deed in sufficient counterparts to facilitate recording in the applicable counties covering the Noble Transferred Assets;

(e)CONSOL and Noble shall execute and deliver assignments, on appropriate forms, of state and of federal leases comprising portions of the Noble Transferred Assets and the CONSOL Transferred Assets, if any, in sufficient counterparts to facilitate filing with the applicable Governmental Authority;

(f)CONSOL and Noble shall execute and deliver the Preliminary Settlement Statement;

(g)Noble shall deliver, to the Designated Account as designated by CONSOL, by direct bank or wire transfer in same day funds, the Adjusted Cash Consideration;

(h)Noble shall deliver an executed statement described in Treasury Regulation § 1.1445-2(b)(2) certifying that Noble is neither a disregarded entity nor a foreign person within the meaning of the Code and the Treasury Regulations promulgated thereunder;

(i)CNX Gas shall deliver an executed statement described in Treasury Regulation § 1.1445-2(b)(2) certifying that (i) CONSOL is an entity disregarded as separate from CNX Gas for federal income tax purposes and (ii) CNX Gas is neither a disregarded entity nor a foreign person within the meaning of the Code and the Treasury Regulations promulgated thereunder;

(j)CONSOL and Noble shall execute and deliver the Noble Transition Services Agreement;

(k)CONSOL and Noble shall execute and deliver the CONSOL Transition Services Agreement;

(l)CONSOL shall provide copies of a recordable release with respect to any Encumbrances granted pursuant to the CONSOL Credit Facility with respect to the CONSOL Transferred Assets including any necessary UCC-3 Termination Statements;

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(m)CONSOL and Noble shall, and CONSOL shall cause its Affiliates that are a party thereto, to execute and deliver the Termination and Release Agreement;

(n)CONSOL and Noble shall execute and deliver the Memorandum of Termination and Release Agreement in sufficient counterparts to facilitate recording in the applicable counties;

(o)CONSOL and Noble shall each cause to be filed a UCC-3 Termination Statement with respect to any UCC-1 Financing Statements that were filed in connection with any joint operating agreement that is being terminated pursuant to the Termination and Release Agreement;

(p)To the extent that the applicable Permits have been obtained by CONSOL, CONSOL and Noble shall execute and deliver all forms and applications required or permitted by applicable Governmental Authorities designating CONSOL as owner and/or operator of record, as applicable, with respect to the Noble Transferred Assets;

(q)To the extent that the applicable Permits have been obtained by Noble, CONSOL and Noble shall execute and deliver all forms and applications required or permitted by applicable Governmental Authorities designating Noble as owner and/or operator of record, as applicable, with respect to the CONSOL Transferred Assets;

(r)CONSOL and Noble shall execute and deliver the Shared Asset/Use Agreement and each of the Water Facility Operating and Use Agreements;

(s)CONSOL and Noble shall execute and deliver the Restriction Agreement;

(t)CONSOL and Noble shall executed and deliver a quitclaim in a form mutually agreeable to the Parties and in sufficient counterparts to facilitate recording in the applicable counties covering the Quitclaim Properties, whereby Noble shall quitclaim and release to CONSOL the Quitclaim Properties (without any warranty whatsoever);

(u)If applicable, CONSOL and Noble shall execute the Master Netting Agreement; and

(v)CONSOL and Noble shall execute and deliver any other Transaction Documents that are required by other terms of this Agreement to be executed and/or delivered at the Closing.

9.4Records.  

(a)In addition to the obligations set forth under Section 9.3 above, no later than 30 days following the Closing Date, CONSOL shall deliver to Noble possession of the CONSOL Transferred Records to which Noble is entitled pursuant to the terms of this Agreement; provided, however, that CONSOL may retain a copy of such CONSOL Transferred Records as may be necessary for litigation, Tax, accounting or auditing purposes or as otherwise may be required by applicable Law.

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(b)In addition to the obligations set forth under Section 9.3 above, no later than 30 days following the Closing Date, Noble shall deliver to CONSOL possession of the Noble Transferred Records to which CONSOL is entitled pursuant to the terms of this Agreement; provided, however, that Noble may retain a copy of such Noble Transferred Records as may be necessary for litigation, Tax, accounting or auditing purposes or as otherwise may be required by applicable Law.

ARTICLE XASSUMPTION; INDEMNIFICATION; SURVIVAL

10.1Assumption by the Parties.  

(a)Without limiting Noble’s rights to indemnity under this Article X, from and after the Closing, Noble shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and Liabilities, known or unknown, arising from, based upon or associated with CONSOL Transferred Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including obligations and Liabilities relating in any manner to the use, ownership or operation of the CONSOL Transferred Assets including obligations to (a) furnish makeup gas or settle Well Imbalances according to the terms of applicable CONSOL Contracts, (b) pay owners of Working Interests, royalties, overriding royalties and other interests revenues or proceeds attributable to sales of Hydrocarbons, including those held in suspense to the extent attributable to the CONSOL Transferred Assets, (c) properly plug and abandon any and all wells and pipelines, including inactive wells or temporarily abandoned wells, drilled on the CONSOL Transferred Assets, (d) to re-plug any well, wellbore or previously plugged CONSOL Transferred Well on the CONSOL Transferred Assets to the extent required or necessary under applicable Laws or under CONSOL Contracts relating to the CONSOL Transferred Assets, (e) dismantle or decommission and remove any CONSOL Transferred Personal Property and other property of whatever kind located on the CONSOL Transferred Assets related to or associated with operations and activities conducted by whomever on the CONSOL Transferred Assets, (f) clean up and remediate the CONSOL Transferred Assets in accordance with any CONSOL Contracts included in the CONSOL Transferred Assets and applicable Laws, including all Environmental Laws, (g) perform all obligations applicable to or imposed on the lessee, owner, or operator under the CONSOL Transferred Leases and the CONSOL Contracts included in the CONSOL Transferred Assets, or as required by Laws and (h) subject to Section 2.4, pay all Property Expenses (all of said obligations and Liabilities, herein being referred to as the “Noble Assumed Obligations”).

(b)Without limiting CONSOL’s rights to indemnity under this Article X, from and after the Closing, CONSOL shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and Liabilities, known or unknown, arising from, based upon or associated with Noble Transferred Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including obligations and Liabilities relating in any manner to the use, ownership or operation of the Noble Transferred Assets including obligations to (a) furnish

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makeup gas or settle Well Imbalances according to the terms of applicable Noble Contracts, (b) pay owners of Working Interests, royalties, overriding royalties and other interests revenues or proceeds attributable to sales of Hydrocarbons, including those held in suspense to the extent attributable to the Noble Transferred Assets, (c) properly plug and abandon any and all wells and pipelines, including inactive wells or temporarily abandoned wells, drilled on the Noble Transferred Assets, (d) to re-plug any well, wellbore or previously plugged Noble Transferred Well on the Noble Transferred Assets to the extent required or necessary under applicable Laws or under Noble Contracts relating to the Noble Transferred Assets, (e) dismantle or decommission and remove any Noble Transferred Personal Property and other property of whatever kind located on the Noble Transferred Assets related to or associated with operations and activities conducted by whomever on the Noble Transferred Assets, (f) clean up and remediate the Noble Transferred Assets in accordance with any Noble Contracts included in the Noble Transferred Assets and applicable Laws, including all Environmental Laws, (g) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Noble Transferred Leases and the Noble Contracts included in the Noble Transferred Assets, or as required by Laws and (h) subject to Section 2.4, pay all Property Expenses (all of said obligations and Liabilities, herein being referred to as the “CONSOL Assumed Obligations”).

10.2Indemnities of CONSOL. Effective as of the Closing, subject to the limitations set forth in Section 10.4 and Section 10.8 and otherwise in this Article X, CONSOL shall be responsible for, shall pay on a current basis, and hereby agrees to Indemnify Noble and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, “Noble Indemnified Parties”) from and against any and all Liabilities (whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder) arising from, based upon, related to or associated with any of the following:

(a)any breach by CONSOL of its representations or warranties contained in Article IV or in the certificate delivered by CONSOL at Closing pursuant to Section 7.4;

(b)any breach by CONSOL of its covenants and agreements under this Agreement;

(c)the payment, underpayment or nonpayment of CONSOL Taxes;

(d)(i) except to the extent covering the Liabilities for which an indemnity is provided pursuant Sections 10.2(c), 10.2(f), 10.2(h), 10.2(i), 10.2(j), 10.3(c), 10.3(f), 10.3(h), 10.3(i) or 10.3(j), any actions, suits or proceedings set forth on Schedule 4.7, Part I or Schedule 5.7, Part I (in each case) relating to any of the Combined Assets, but limited to CONSOL’s Pre-Closing Working Interest Share (and not Noble’s Pre-Closing Working Interest Share) of such Liabilities, (ii) to the extent relating to the period of time from and after Closing any actions, suits or proceedings arising during, or relating to, the ownership or operation of the CONSOL Combined Assets, (iii) notwithstanding anything contained in Section 10.2(d)(i) or Section 10.3(d), CONSOL shall be solely liable for the actions, suits or proceedings, if any, set forth on Schedule 4.7, Part II or Schedule 5.7, Part II, and (iv) the

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Liabilities of CONSOL under any actions, suits or proceedings, if any, set forth on Schedule 4.7, Part IV or Schedule 5.7, Part IV shall be determined in accordance with Section10.2(i);

(e)(i) to the extent relating to the period of time prior to Closing, personal injury, illness or death (in each case) relating to ownership or operation of the Combined Assets, but limited to CONSOL’s Pre-Closing Working Interest Share (and not Noble’s Pre-Closing Working Interest Share) of such Liabilities and (ii) to the extent relating to the period of time from and after Closing, personal injury, illness or death (in each case) relating to the ownership or operation of the CONSOL Combined Assets;

(f)notwithstanding anything else contained in this Section 10.2 or Section 10.3, the gross negligence or willful misconduct of CONSOL in connection with its operations, prior to the Closing Date, of the Combined Assets if CONSOL is the operator thereof;

(g)(i) to the extent relating to the period of time prior to Closing, the disposal of Hazardous Substances related or attributable to ownership or operation of the Combined Assets that were disposed of off-site at Third Party commercial disposal facilities, but limited to CONSOL’s Pre-Closing Working Interest Share (and not Noble’s Pre-Closing Working Interest Share) of such Liabilities, and (ii) to the extent relating to the period of time from and after Closing, the disposal of Hazardous Substances related or attributable to ownership or operation of the CONSOL Combined Assets that were disposed of off-site at Third Party commercial disposal facilities;

(h)notwithstanding anything contained in Section 10.3, proceeds attributable to Burdens payable to Third Parties from the CONSOL Transferred Assets that are held in suspense by CONSOL as of the Closing Date (including any interest accrued on such suspended funds), but only to the extent such suspended funds are not credited towards Noble, or under Noble’s control, at Closing;

(i)notwithstanding anything contained in Section 10.3, to the extent relating to the period of time prior to the Closing, the payment, underpayment or nonpayment by CONSOL (not Noble) of any Burdens related to the Combined Assets with respect to production of Hydrocarbons prior to the Closing (including any interest payable as a result of any such payment, underpayment or nonpayment);

(j)notwithstanding anything contained in Section 10.3, obligations and losses owed to, or arising out of CONSOL’s or its Affiliate’s employment relationship with, any of their employees prior to the Closing or out of or with respect to any employee benefit plan or under any Law with respect thereto;

(k)(i) any matter set forth on Schedule 4.13 or Schedule 5.13 (in each case) relating to the Combined Assets, but limited to CONSOL’s Pre-Closing Working Interest Share (and not Noble’s Pre-Closing Working Interest Share) of such Liabilities, and (ii) to the extent relating to the period of time from and after Closing any Environmental Event to the extent attributable or relating to the ownership or operation of the CONSOL Combined Assets; or

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(l)except for matters for which Noble is then obligated to Indemnify CONSOL pursuant to Sections 10.3(a) through (k), the CONSOL Assumed Obligations.

10.3Indemnities of Noble.  Effective as of the Closing, subject to the limitations set forth in Section 10.4 and Section 10.8 and otherwise in this Article X, Noble shall be responsible for, shall pay on a current basis and hereby agrees to Indemnify CONSOL and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, “CONSOL Indemnified Parties”) from and against any and all Liabilities (whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder) arising from, based upon, related to or associated with any of the following:

(a)any breach by Noble of its representations or warranties contained in Article V or in the certificate delivered by Noble at Closing pursuant to Section 8.4;

(b)any breach by Noble of its covenants and agreements under this Agreement;

(c)the payment, underpayment or nonpayment of Noble Taxes;

(d)(i) except to the extent covering the Liabilities for which an indemnity is provided pursuant Sections 10.2(c), 10.2(f), 10.2(h), 10.2(i), 10.2(j), 10.3(c), 10.3(f), 10.3(h), 10.3(i) or 10.3(j), any actions, suits or proceedings set forth on Schedule 4.7, Part I or Schedule 5.7, Part I1 (in each case) relating to any of the Combined Assets, but limited to Noble’s Pre-Closing Working Interest Share (and not CONSOL’s Pre-Closing Working Interest Share) of such Liabilities, (ii) to the extent relating to the period of time from and after Closing any actions, suits or proceedings arising during, or relating to, the ownership or operation of the Noble Combined Assets, and (iii) notwithstanding anything contained in Section 10.3(d)(i) or Section 10.2(d), Noble shall be solely liable for the actions, suits or proceedings, if any, set forth on Schedule 4.7, Part III or Schedule 5.7, Part III, and (iv) the Liabilities of CONSOL under any actions, suits or proceedings, if any, set forth on Schedule 4.7, Part IV or Schedule 5.7, Part IV shall be determined in accordance with Section10.3(i);

(e)(i) to the extent relating to the period of time prior to Closing, personal injury, illness or death (in each case) relating to ownership or operation of the Combined Assets, but limited to Noble’s Pre-Closing Working Interest Share (and not CONSOL’s Pre-Closing Working Interest Share) of such Liabilities and (ii) to the extent relating to the period of time from and after Closing, personal injury, illness or death (in each case) relating to the ownership or operation of the Noble Combined Assets;

(f)notwithstanding anything else contained in this Section 10.3 or Section 10.2, the gross negligence or willful misconduct of Noble in connection with its operations, prior to the Closing Date, of the Combined Assets if Noble is the operator thereof;

(g)(i) to the extent relating to the period of time prior to Closing, the disposal of Hazardous Substances related or attributable to ownership or operation of the Combined

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Assets that were disposed of off-site at Third Party commercial disposal facilities, but limited to Noble’s Pre-Closing Working Interest Share (and not CONSOL’s Pre-Closing Working Interest Share) of such Liabilities, and (ii) to the extent relating to the period of time from and after Closing, the disposal of Hazardous Substances related or attributable to ownership or operation of the Noble Combined Assets that were disposed of off-site at Third Party commercial disposal facilities;

(h)notwithstanding anything contained in Section 10.2, proceeds attributable to Burdens payable to Third Parties from the Noble Transferred Assets that are held in suspense by Noble as of the Closing Date (including any interest accrued on such suspended funds), but only to the extent such suspended funds are not credited towards CONSOL, or under CONSOL’s control, at Closing;

(i)notwithstanding anything contained in Section 10.2, to the extent relating to the period of time prior to the Closing, the payment, underpayment or nonpayment by Noble (not CONSOL) of any Burdens related to the Combined Assets with respect to production of Hydrocarbons prior to the Closing Date (including any interest payable as a result of any such payment, underpayment or nonpayment);

(j)notwithstanding anything contained in Section 10.2, obligations and losses owed to, or arising out of Noble’s or its Affiliate’s employment relationship with, any of their employees prior to the Closing or out of or with respect to any employee benefit plan or under any Law with respect thereto;

(k)(i) any matter set forth on Schedule 4.13 or Schedule 5.13 (in each case) relating to the Combined Assets, but limited to Noble’s Pre-Closing Working Interest Share (and not CONSOL’s Pre-Closing Working Interest Share) of such Liabilities, and (ii) to the extent relating to the period of time from and after Closing any Environmental Event to the extent attributable or relating to the ownership or operation of the Noble Combined Assets; or

(l)except for matters for which CONSOL is then obligated to Indemnify Noble pursuant to Sections 10.2(a) through (k), the Noble Assumed Obligations.

10.4Limitation on Liability.  

(a)No Indemnifying Party shall have any liability for any indemnification under Section 10.2(a) or Section 10.3(a) (as applicable) unless (i) the individual amount of any Liability for which a Claim Notice is delivered by such Indemnified Party to such Indemnifying Party under Section 10.2(a) or Section 10.3(a) (as applicable) exceeds $100,000 and (ii) the aggregate amount of all Liabilities for which such Indemnifying Party is liable under Section 10.2(a) or Section 10.3(a) (as applicable) exceeds $5,000,000 (with respect to each such Indemnifying Party, the “Indemnity Deductible”) and then only to the extent such Liabilities exceed the Indemnity Deductible; provided, however, that the indemnities under Section 10.2(a) or Section 10.3(a) for a breach of any Fundamental Representationor a breach of the representations and warranties contained in Section 4.17 or Section 5.17 (as applicable)

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(such foregoing items in this proviso, the “Limitation of Liability Exclusions”), in each case, shall not be limited by the provisions of this Section 10.4(a).

(b)Notwithstanding anything to the contrary contained in this Agreement, except with respect to the Limitation of Liability Exclusions, no Indemnifying Party shall be required to Indemnify the Indemnified Party pursuant to Section 10.2(a) or Section 10.3(a), as applicable, for aggregate Liabilities in excess of $50,000,000.

10.5Express Negligence. THE INDEMNIFICATION, RELEASE, ASSUMED OBLIGATIONS, WAIVER AND LIMITATION OF LIABILITY PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, JOINT, ACTIVE, PASSIVE, CONCURRENT, CONTRIBUTORY OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, AND WHETHER ANY LIABILITY OR CLAIM IS IN TORT, UNDER CONTRACT OR OTHERWISE AT LAW. NOBLE AND CONSOL ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

10.6Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement, from and after Closing, Sections10.2 and 10.3 contain the Parties’ exclusive remedy against each other with respect to breaches of the representations, warranties, covenants and agreements of the Parties contained in Article IV, Article V, Article VI and this Article X and the affirmations of such representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Section 7.4 or Section 8.4, as applicable. Except for (a) the remedies contained in Sections 10.2 and 10.3, (b) subject to the terms hereof, any other remedies available to the Parties at Law or in equity for breaches of provisions of this Agreement other than Article IV, Article V, Article VI and Article X, and (c) the remedies available at Law or in equity in connection with any other document delivered by a Party in connection with the consummation of the transactions contemplated hereby (other than the certificates delivered by the Parties pursuant to Section 7.4 or Section 8.4, as applicable), from and after Closing, CONSOL and Noble each releases, remises and forever discharges the other and its Affiliates and all such Persons’ stockholders, members, partners, officers, directors, employees, agents, advisors and representatives from any and all Liabilities in Law or in equity, known or unknown, which such parties might now or subsequently may have, based on, relating to or arising out of this Agreement, the consummation of the transactions contemplated hereby, the ownership, use or operation of the CONSOL Transferred Assets and the Noble Transferred Assets prior to the Closing, or the condition, quality, status or nature of the CONSOL Transferred Assets or the Noble Transferred Assets prior to the Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common Law rights of contribution, and rights under insurance maintained by any Transferring Party or any of its Affiliates.

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10.7Indemnification Procedures. All claims for indemnification under Section 10.2 and Section 10.3 shall be asserted and resolved as follows:

(a)For purposes of this Article X, the term “Indemnifying Party” when used in connection with particular Liabilities shall mean the Party having an obligation to Indemnify another Party or Person(s) with respect to such Liabilities pursuant to this Article X, and the term “Indemnified Party” when used in connection with particular Liabilities shall mean the Party or Person(s) having the right to be indemnified with respect to such Liabilities by another Party pursuant to this Article X.

(b)To make a claim for indemnification under Sections10.2 or 10.3, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 10.7, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 10.7 shall not relieve the Indemnifying Party of its obligations under Sections10.2 or 10.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c)In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have 60 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30 day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d)If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 10.7(d). An Indemnifying Party shall not, without the written consent of the Indemnified Party,

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(i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)If the Indemnifying Party does not admit its liability or admits its liability to defend the Indemnified Party against the Third Party Claim, but fails to diligently prosecute or settle such Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for 10 days following receipt of such notice to (i) admit in writing its liability to Indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure to respond to such notice by the Indemnified Party shall be deemed to be an election under subsection (iii) above.

(f)In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 60 days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such 60 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the Indemnified Party shall be deemed to have denied its liability for such claim of such Liabilities.

10.8Survival.  

(a)The representations and warranties of CONSOL in Article IV (other than the Fundamental Representations and the representations and warranties contained Section 4.17) and the covenants and agreements of CONSOL in Sections 6.1 and 9.4 shall, in each case, survive the Closing for a period of 12 months after the Closing Date; provided, however, (i) the Fundamental Representations of CONSOL shall survive the Closing indefinitely, (ii) the Special Warranty contained in the CONSOL Assignment and the CONSOL Deed, in each case, shall survive the Closing indefinitely, and (iii) the representations and warranties contained in Section 4.17, and the covenants and agreements of CONSOL contained in Section 12.2 shall survive for the applicable statute of limitations, plus 30 days. The representations and warranties of Noble in Article V (other than the Fundamental Representations and the representations and warranties contained in Section 5.17) and the covenants and agreements of Noble in Sections 6.2 and 9.4 shall, in each case, survive the Closing for a period of 12 months after the Closing Date; provided, however, (i) the Fundamental Representations of

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Noble shall survive the Closing indefinitely, (ii) the Special Warranty contained in the Noble Assignment and the Noble Deed, in each case, shall survive the Closing indefinitely, and (iii) the representations and warranties contained in Section 5.17, and the covenants and agreements of Noble contained in Section 12.2 shall survive for the applicable statute of limitations, plus 30 days. Subject to the foregoing and as set forth in Section 10.8(b), the remainder of this Agreement shall survive the Closing without time limit. Any reference to a representation or warranty in this Section 10.8(a) shall also be deemed to include a reference to the corresponding representations and warranties given in any certificate delivered at Closing by either Party. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration, provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b)The indemnities in Sections 10.2(a), 10.2(b), 10.3(a) and 10.3(b) shall terminate upon expiration of the survival period (as provided in Section 10.8(a)) of each respective representation, warranty, covenant or agreement that is subject to indemnification. The indemnities set forth in Sections 10.2(c) and 10.3(c) shall survive the Closing until the date that is 30 days following the expiration of the applicable statute limitation. The indemnities set forth in Sections 10.2(d), 10.3(d), 10.2(k),10.3(k), 10.2(l) and 10.3(l) (in each case) shall survive without limitation. The indemnities set forth in Sections10.2(e), 10.3(e), 10.2(f),10.3(f), 10.2(g), 10.3(g), 10.2(h), 10.3(h), 10.2(i),10.3(i), 10.2(j) and 10.3(j) (in each case) shall survive the Closing for a period of ten years. The indemnities set forth in Sections10.2(i) and 10.3(i) (in each case) shall survive the Closing for a period of eleven years. Notwithstanding the foregoing, there shall be no termination of any bona fide claim asserted pursuant to the indemnities in Section 10.2 or Section 10.3, if such bona fide claim is assertedprior to the expiration of the survival period for the applicable indemnity.

10.9Non-Compensatory Damages. Each of Noble and CONSOL waive any right to recover punitive, special, indirect, exemplary, consequential damages, remote or speculative, including damages for lost profits of any kind, arising in connection with or with respect to this Agreement or the transactions contemplated hereby, (b) Noble hereby Indemnifies the CONSOL Indemnified Parties for all claims, suits actions or proceeding brought by any Noble Indemnified Party for any indirect, special, incidental, consequential, punitive, exemplary, remote or speculative damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, and (c) CONSOL hereby Indemnifies the Noble Indemnified Parties for all claims, suits actions or proceeding brought by any CONSOL Indemnified Party for any indirect, special, incidental, consequential, punitive, exemplary, remote or speculative damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated hereby.

10.10Cooperation by Concerning Litigation. With respect to the actions, suits or proceedings set forth in Schedule 4.7 and Schedule 5.7,the Parties agree that, following Closing, the Parties will continue to handle such actions, suits and proceeding in the same manner as such suits were being handled prior to Closing. Each Party agrees to reasonably cooperate with the other Party in pursuing the resolution of such disputes.

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10.11Waiver of Right to Rescission. CONSOL and Noble acknowledge that, following Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following Closing, Noble and CONSOL waive any right to rescind this Agreement or any of the transactions contemplated hereby.

10.12Insurance. Intentionally Omitted.

10.13Materiality. For purposes of determining whether there has been any breach or inaccuracy of the representations and warranties under this Agreement, or the corresponding representations and warranties given in the certificates to be delivered by a Party at Closing pursuant to Section 7.4 or Section 8.4, and for purposes of determining the amount of any Liability resulting therefrom, all qualifiers as to materiality, Material Adverse Effect or material adverse effect shall be disregarded.

ARTICLE XITERMINATION, DEFAULT AND REMEDIES

11.1Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time at or prior to Closing:

(a)by CONSOL, at CONSOL’s option, if any of the conditions set forth in Article VIII (other than the conditions set forth in Section 8.3 or Section 8.5) have not been satisfied (or waived by CONSOL) on or before the Outside Termination Date;

(b)by Noble, at Noble’s option, if any of the conditions set forth in Article VII (other than the conditions set forth in Section 7.3 or Section 7.5) have not been satisfied (or waived by Noble) on or before the Outside Termination Date;

(c)by either Party if any of the conditions set forth in Section 8.3, Section 8.5, Section 7.3 or Section 7.5 have not been satisfied (or waived by (i) CONSOL with respect to the conditions set forth in Section 8.3, and Section 8.5 or (ii) Noble with respect to the conditions set forth in Section 7.3 and Section 7.5) on or before the Outside Termination Date;

(d)by either Party, at such Party’s option, at any time following ten days after the Outside Termination Date; or

(e)by the mutual written agreement of CONSOL and Noble;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to subsections (a), (b), or (d) above if such Party or its Affiliates are at such time in material breach of any provision of this Agreement.

11.2Effect of Termination.  

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(a)If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 11.1 hereof, then, except for the provisions of Article I, Section 10.9, this Section 11.2, Article XII (other than Sections 12.2(b) through 12.2(e), 12.3, 12.4, 12.10 and 12.11) and such of the defined terms in Appendix I necessary to give context to the surviving provisions, this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder.

(b)If this Agreement is terminated by CONSOL pursuant to Section 11.1(a) because of (i) the Willful Breach by Noble of this Agreement, or (ii) the failure of Noble to close in the instance where, as of the Outside Termination Date, (A) all of the conditions in Article VII (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied (or waived by Noble), (B) CONSOL is ready, willing and able to perform its obligations under Section 9.3, and (C) Noble nevertheless elects not to close, then in either such event, the Parties agree and acknowledge that CONSOL will suffer damages that are not practicable to ascertain. Accordingly, after such termination of this Agreement by CONSOL, CONSOL shall be entitled to an amount equal to $100,000,000 as liquidated damages, which amount shall be immediately payable by wire transfer in immediately available funds by Noble to CONSOL. The Parties agree that the foregoing liquidated damages are not a penalty and are reasonable considering all of the circumstances existing as of the Execution Date and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from such termination of this Agreement by CONSOL. CONSOL agrees that, to the fullest extent permitted by Law, CONSOL’s right to payment of such liquidated damages as provided in this Section 11.2(b) shall be its sole and exclusive remedy if the Closing does not occur with respect to any Liabilities whatsoever that CONSOL may suffer or allege to suffer as a result of the termination of this Agreement pursuant to Section 11.1(a) as described in this Section 11.2(b).

(c)If this Agreement is terminated by Noble pursuant to Section 11.1(b) because of (i) the Willful Breach by CONSOL of this Agreement, or (ii) the failure of CONSOL to close in the instance where, as of the Outside Termination Date, (A) all of the conditions in Article VIII (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied (or waived by CONSOL), (B) Noble is ready, willing and able to perform its obligations under Section 9.3, and (C) CONSOL nevertheless elects not to close, then in either such event, the Parties agree and acknowledge that Noble will suffer damages that are not practicable to ascertain. Accordingly, after such termination of this Agreement by Noble, Noble shall be entitled to an amount equal to $100,000,000 as liquidated damages, which amount shall be immediately payable by wire transfer in immediately available funds by CONSOL to Noble. The Parties agree that the foregoing liquidated damages are not a penalty and are reasonable considering all of the circumstances existing as of the Execution Date and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from such termination of this Agreement by Noble. Noble agrees that, to the fullest extent permitted by Law, Noble’s right to payment of such liquidated damages as provided in this Section 11.2(c) shall be its sole and exclusive remedy if the Closing does not occur with respect to any Liabilities whatsoever that Noble may suffer or

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allege to suffer as a result of the termination of this Agreement pursuant to Section 11.1(b) as described in this Section 11.2(c).

(d)Subject to the foregoing, upon the termination of this Agreement neither Party has any other liability or obligation hereunder.

ARTICLE XIIMISCELLANEOUS

12.1Appendices, Exhibits and Schedules. All of the Appendices, Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Appendices, Exhibits and Schedules prior to and as of the execution of this Agreement.

12.2Expenses and Taxes.  

(a)Except as otherwise specifically provided, all fees, costs and expenses incurred by the Parties in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b)All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to (i) the CONSOL Transferred Assets to Noble and (ii) the Noble Transferred Assets to CONSOL (in each case) shall be borne 50% by CONSOL and 50% by Noble.

(c)CONSOL shall retain responsibility for, and shall bear and pay all CONSOL Taxes.

(d)Noble shall retain responsibility for, and shall bear and pay all Noble Taxes.

(e)The Parties will cooperate in establishing the applicability of any occasional sale or other exemption from Transfer Taxes that may be applicable to the transfer to the Non-Transferring Party of the Transferred Properties.

(f)All Asset Taxes that are based upon or measured by the production of Hydrocarbons, such as extraction, production, severance and other similar taxes, applicable to the Transferred Properties shall be deemed attributable to the period during which the production of the Hydrocarbons with respect to such Asset Taxes occurred, and liability therefor shall be allocated to the Transferring Party for pre-Effective Time Asset Taxes and to the Non-Transferring Party for post-Effective Time Asset Taxes. All Asset Taxes that are based upon or measured by the ownership of the Transferred Properties, such as ad valorem (including ad valorem taxes for which the assessed valuation is based, in whole or in part, on the value of production in prior years), real property, personal property and other similar taxes and all state imposed impact fees, shall be deemed attributable to the period of ownership

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of the applicable Transferred Property subject to such Asset Taxes, and liability for such Asset Taxes shall be allocated to the Transferring Party for all periods ending prior to the Effective Time and to the Non-Transferring Party for all periods beginning on or after the Effective Time. For the avoidance of doubt, any such Asset Taxes for 2016 shall be allocated ¾ to the Transferring Party and ¼ to the Non-Transferring Party. For the purpose of calculating the adjustment to the Cash Consideration for purposes of the Preliminary Settlement Statement under Section 2.8 and the Final Settlement Statement under Section 2.9, Asset Taxes for which the actual liability amount is not known as of such time shall be estimated based on the most recent information available, with the resulting Cash Consideration adjustment under Section 2.9 to be considered full and final settlement of all such Asset Taxes, without regard to the actual Tax assessments (the “Settled Asset Taxes”). After Closing, the Non-Transferring Party shall timely file or cause to be filed all tax returns for Asset Taxes required to be filed after Closing and shall timely pay or cause to be paid to the taxing authorities all Asset Taxes that become due and payable after Closing. Any penalty, addition to Tax, or interest levied or assessed with respect to any Asset Tax shall be allocated to, and shall be payable by, the Party to which the Asset Tax to which such penalty, addition to Tax, or interest relates is allocated, regardless of when such penalty, addition to Tax, or interest is levied or assessed.

(g)Within 30 days after the calendar month of the Effective Time both CONSOL and Noble agree to file “well transfer requests” with respect to each well included in the CONSOL Transferred Assets or the Noble Transferred Assets in the Pennsylvania Public Utility Commission (PUC) Act 13 online system and each Non-Transferring Party agrees to include the transferred wells on its “annual report” with the PUC and to pay any related impact fees, subject to such Party’s right of reimbursement under Section 12.2(f).

(h)The Non-Transferring Party shall be entitled to all rights to any refunds of (a) Asset Taxes allocable to the Non-Transferring Party pursuant to Section 12.2(f) regardless of when received, and (b) Settled Asset Taxes. The Transferring Party shall be entitled to all rights to any refunds of Asset Taxes allocated to the Transferring Party pursuant to Section 12.2(f) other than refunds of Settled Asset Taxes. If a Party or its Affiliate receives a refund to which the other Party is entitled pursuant to this Section 12.2(g), such receiving Party shall forward to the other Party the amount of such refund within thirty (30) days after such refund is received, net of any reasonable costs or expenses incurred by such receiving Party in procuring such refund.

12.3Tax Treatment. For U.S. federal and applicable state income Tax purposes, the Parties intend that: (i) in accordance with Article 7 of the Tax Partnership Agreement, the Tax Partnership shall specially allocate items of income, gain, loss and deduction (including items of unrealized income, gain, loss and deduction) in a manner to ensure that the FMV Capital Accounts (as that term is defined in the Tax Partnership Agreement) of CONSOL and Noble are “balanced”; (ii) the Tax Partnership will be treated as making a liquidating distribution of the CONSOL Transferred Assets and the Noble Excluded Assets to Noble in a transaction governed by Section 731(a) of the Code; (iii) the Tax Partnership will be treated as making a liquidating distribution of the Noble Transferred Assets and the CONSOL Excluded Assets to CONSOL in a transaction

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governed by Section 731(a) of the Code; and (iv) Noble will be treated as making a payment of the Adjusted Cash Consideration to CONSOL Energy, Inc. in cancellation and forgiveness of the Carried Costs Balance obligations under the Development Agreement.

12.4Intentionally Omitted.

12.5Dispute Resolution. The procedures of Section 2.10 shall be applied in the event of a dispute for any item under Section 12.2 or 12.3.

12.6Assignment. This Agreement may not be assigned by either Party without the prior written consent of the other Party. No assignment of any rights hereunder by either Party shall relieve such Party of any obligations (including indemnity obligations) and responsibilities hereunder.

12.7Preparation of Agreement. Both CONSOL and Noble and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

12.8Publicity. CONSOL and Noble shall consult with each other with regard to all press releases or other announcements to the general public issued or made at or prior to the Closing concerning this Agreement or the transactions contemplated herein, and, except as may be required by applicable Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Noble nor CONSOL shall issue any such press release or other announcement to the general public without the prior written consent of the other Party, which shall not be unreasonably withheld. The Parties shall be obligated to hold all specific terms and provisions of this Agreement strictly confidential until the expiration of two years after the Closing under this Agreement; provided, however, that the foregoing shall not (a) restrict disclosures by Noble or CONSOL that are required by applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates, (b) prevent Noble or CONSOL from recording any Assignment and any federal or state assignments delivered at Closing or from complying with any disclosure requirements of Governmental Authorities that are applicable to the transfer of the Transferred Properties from any Transferring Party to the Non-Transferring Party, (c) prevent Noble or CONSOL from making any disclosure of information relating to this Agreement as may be required by any Governmental Authority, and (d) prevent any Transferring Party from making disclosures in connection with complying with the Preferential Purchase Rights and other transfer restrictions applicable to the transfer of such Transferring Party’s Transferred Properties contemplated hereby.

12.9Notices. All notices and communications required or permitted to be given hereunder, shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation).

If to CONSOL:

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CNX Gas Company LLC

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA 15317

Attention:     Nicholas J. DeIuliis

Telephone:     724-485-4032

Fax:     724-485-4834

with copies to:

CNX Gas Company LLC

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA 15317

Attention:     General Counsel

Telephone:     724-485-4234

Fax:     724-485-4836

and:

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Attention:     Jeff Munoz

Telephone:     713-546-7423

Fax:         713-546-5401

If to Noble:

Noble Energy, Inc.

1001 Noble Energy Way

Houston, Texas 77070

Attention:     Donald G. Moore

Telephone:    (281) 872-3100

Fax:        (281) 872-3112

with copies to:

Noble Energy, Inc.

1001 Noble Energy Way

Houston, Texas 77070

Attention:     Legal Department

Telephone:    (281) 872-3100

Fax:        (281) 872-3112

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and:

Porter Hedges LLP

1000 Main, 36th Floor

Houston, Texas 77002

Attention:      C. Randall King

Telephone:     (713) 226-6603

Fax:         (713) 226-6203

Any notice given in accordance herewith shall be deemed to have been given when (a) delivered to the addressee in person or by courier, (b) transmitted by facsimile transmission during normal business hours, or if transmitted after normal business hours, on the next Business Day, or (c) upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail if received during normal business hours, or if not received during normal business hours, then on the next Business Day, as the case may be. The Parties may change the address and facsimile numbers to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 12.9.

12.10Further Cooperation. After the Closing, Noble and CONSOL shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any Party may reasonably request, to convey and deliver the Transferred Properties to the applicable Non-Transferring Parties, to perfect such Non-Transferring Party’s title thereto, and to accomplish the orderly transfer of the Transferred Properties to such Non-Transferring Parties in the manner contemplated by this Agreement. In addition, the Parties acknowledge and agree that it is their joint intent that (a) as of the Closing, there will not be any oil and gas leases or fee mineral interests located within the State of West Virginia or the Commonwealth of Pennsylvania where each Party owns an interest that is symmetrical with the other’s Party’s interest except for any such interest that is operated by a Third Party (whether existing as a beneficial interest or otherwise, subject to such exception, a “Jointly Owned Property”) and (b) no property or assets that are not Jointly Owned Properties be transferred by a Party to the other Party pursuant to the transactions contemplated hereby. For a period of 12 months following the Closing Date, to the extent that a Party inadvertently transfers any property that is not Jointly Owned Property, then the other Party will re-convey such property to the Transferring Party by an assignment similar to the CONSOL Assignment, the CONSOL Deed, the Noble Assignment or the Noble Deed, as applicable.

12.11Filings, Notices and Certain Governmental Approvals. Promptly after Closing each Non-Transferring Party shall (a) record the Assignments of the Transferred Properties assigned to it and all state/federal assignments relating to such Transferred Properties executed at the Closing in all applicable real property records and/or, if applicable, all state or federal agencies, (b) actively pursue the approval of all applicable Governmental Authorities of the assignment of such Transferred Properties and (c) actively pursue all other consents and approvals that may be required in connection with (i) the assignment of such Transferred Properties to it, and the Transferring Party of such Transferred Properties agrees to use its commercially reasonable efforts to cooperate with such

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pursuit, and (ii) the assumption of the Liabilities assumed by such Non-Transferring Party hereunder, in each case, that shall not have been obtained prior to Closing. Each Non-Transferring Party obligates itself to take any and all action required by any Governmental Authority in order to obtain such approval, including but not limited to, the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

12.12Entire Agreement; Conflicts. WITHOUT WAIVING ANY RIGHTS ANY PARTY HAS UNDER THE DEVELOPMENT AGREEMENT PRIOR TO THE TERMINATION THEREOF IN ACCORDANCE WITH THIS AGREEMENT, THIS AGREEMENT, THE APPENDICES, EXHIBITS AND SCHEDULES HERETO AND THE TRANSACTION DOCUMENTS COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT AMONG THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER OF THIS AGREEMENT. THERE ARE NO WARRANTIES, REPRESENTATIONS OR OTHER AGREEMENTS AMONG THE PARTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT, AND NO PARTY SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT OR STATEMENTS OF INTENTION NOT SO SET FORTH. IN THE EVENT OF A CONFLICT BETWEEN: (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO OR (B) THE TERMS AND PROVISION OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE SCHEDULES OR EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION 12.12.

12.13Successors and Permitted Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their successors and permitted assigns.

12.14Parties in Interest. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than CONSOL and Noble and their respective successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder, any rights, remedies, obligations or Liabilities under or by reason of this Agreement; provided that only a Party and its respective successors and permitted assigns will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of any of its related Indemnified Parties (but shall not be obligated to do so).

12.15Amendment. This Agreement may be amended only by an instrument in writing executed by all of the Parties and expressly identified as an amendment or modification.

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12.16Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of any Party, or its respective officers, employees, agents or representatives, and no failure by a Party to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of the Parties under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

12.17Governing Law; Jurisdiction; Venue; Jury Waiver. THIS AGREEMENT AND THE LEGAL RELATIONS AMONG THE PARTIES SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION. SUBJECT TO SECTION 2.10 AND SECTION 3.3(C), ALL OF THE PARTIES CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES DISTRICT COURT FOR THE WESTERN DISTRICT OF PENNSYLVANIA FOR ANY ACTION ARISING OUT OF THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO OR FROM THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY SHALL BE EXCLUSIVELY LITIGATED IN THE UNITED STATES DISTRICT COURT FOR THE WESTERN DISTRICT OF PENNSYLVANIA (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER). EACH PARTY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY.

12.18Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

12.19Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts

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shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission or other electronic transmission shall be deemed an original signature hereto.

[Remainder of page intentionally left blank. Signature page follows.]

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IN WITNESS WHEREOF, CONSOL and Noble have executed this Agreement on the Execution Date.

CONSOL:

CNX GAS COMPANY LLC

By:     /s/ Timothy C. Dugan                

Name:     Timothy C. Dugan

Title:     President and Chief Executive Officer

Noble:

NOBLE ENERGY, INC.

By:     /s/ Donald G. Moore                

Name:    Donald G. Moore

Title:     Vice President    

APPENDIX IDefinitions

“AAA” means the American Arbitration Association.

“AAA Rules” means the Commercial Arbitration Rules of the AAA.

“Accounting Arbitrator” has the meaning set forth in Section 2.10.

“Acquisition Agreement” has the meaning set forth in the recitals.

“Acquisition Costs” means the actual acquisition costs and Third Party expenses, including lease bonuses, broker fees, abstract costs, title opinion costs and all other Third Party costs of due diligence, including reasonable attorneys’ fees, incurred by the applicable Transferring Party, or its Affiliates, in acquiring any Fill-In Interests.

“Adjusted Cash Consideration” has the meaning set forth in Section 2.6.

“AFEs” means an authorization for expenditure.

“Affected Party” has the meaning set forth in Section 3.3(b).

“Affiliate” means, with respect to any Person, any other Person that directly, or indirectly through one or more intermediaries, Controls, or is Controlled by, or is under common Control with, such Person.

“Agreement” has the meaning set forth in the first paragraph herein, as the same may be amended in writing from time to time.

“Allocated Value” has the meaning set forth in Section 2.11.

“Asset Taxes” means ad valorem, property, excise, sales, use, severance, production or similar Taxes (including any interest, fine, penalty or additions to Tax imposed by Governmental Authorities in connection with such Taxes) based upon operation or ownership of the oil and gas assets or the production of Hydrocarbons therefrom, including any state imposed impact fees, but excluding, for the avoidance of doubt, income, capital gains and franchise Taxes.

“Assignment” means the CONSOL Assignment or the Noble Assignment, as the context requires.

“Benefit Net Acres Claim” has the meaning set forth in Section 6.8(b)(i).

“Benefit Net Acres Dispute Notice” has the meaning set forth in Section 6.8(b)(ii).

“Burden” means any and all royalties (including lessor’s royalties), overriding royalties, and other burdens upon, measured by or payable out of production of Hydrocarbons.

“Business Day” means any day other than Saturday or Sunday or a day on which banking institutions in Houston, Texas or Pittsburgh, Pennsylvania are authorized by Law to close.

“Capacity” has the meaning set forth in Section 6.9(a).

“Carried Costs” has the meaning set forth in the recitals.

“Carried Costs Balance” has the meaning set forth in Section 2.5(b)(ii).

“Cash Consideration” has the meaning set forth in Section 2.5(a)(i).

“Casualty” means any event or circumstance outside the ordinary course of business that occurs between the Execution Date and the Closing Date causing physical damage to or destruction of all or any part of the Transferred Properties for any reason, including as a result of fire, explosion, tornado, hurricane, earthquake, earth movement, flood, water damage or any similar reason.

“Casualty Amount” has the meaning set forth in Section 3.3(b).

“Casualty Amount Notice” has the meaning set forth in Section 3.3(b).

“Casualty Arbitrator” has the meaning set forth in Section 3.3(c).

“Casualty Dispute” has the meaning set forth in Section 3.3(c).

“Claim Notice” has the meaning set forth in Section 10.7(b).

“Closing” has the meaning set forth in Section 9.1.

“Closing Date” has the meaning set forth in Section 9.1.

“CNX Gas” means, CNX Gas Corporation, a Delaware Corporation.

“Code” means the Internal Revenue Code of 1986, as amended.

“Combined Assets” means the Noble Combined Assets and the CONSOL Combined Assets.

“Combined Asset Property Expenses” means, with respect to any Combined Asset, all property expenses (including costs of insurance but excluding all Asset Taxes) and capital expenditures (in each case) incurred in the ownership and operation of such Combined Asset in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to such Combined Asset under the relevant operating agreement or unit agreement, if any, but excluding Liabilities attributable to (a) personal injury or death, property damage or violation of any Law, (b) obligations to plug wells, dismantle or decommission facilities, close pits and restore the surface around such wells, facilities and pits, (c) environmental matters, including obligations to remediate any contamination of groundwater, surface water, soil, sediments or such Combined Assets under applicable Environmental Laws, (d) obligations with respect to Well Imbalances, and (e) obligations to pay royalties, overriding royalties or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to such Combined Assets, including those held in suspense. Notwithstanding anything to the contrary, Combined Asset Property Expenses do not include any costs incurred by a Transferring Party in connection with any obligation of such Transferring Party to pay, reimburse or Indemnify its Non-Transferring Party hereunder, which costs shall be the sole obligation of such Transferring Party.

“Consent” means a CONSOL Consent or a Noble Consent, as the context requires.

“CONSOL” has the meaning set forth in the first paragraph herein.

“CONSOL Affiliates” has the meaning given such term in the Surface Use Agreement.

“CONSOL Areas” means the geographical areas set forth in Schedule 1.1 for CONSOL.

“CONSOLAssignment” means the Assignment and Bill of Sale from CONSOL to Noble, pertaining to the CONSOL Transferred Assets (other than the CONSOL Transferred Assets assigned pursuant to the CONSOL Deed), substantially in the form attached to this Agreement as Exhibit E-1.

“CONSOLAssumed Obligations” has the meaning set forth in Section 10.1(b).

“CONSOL Combined Assets” means the Noble Transferred Assets being acquired by CONSOL, together with the interest of CONSOL in the underlying assets comprising such Noble Transferred Assets that was owned by CONSOL prior to its acquisition of such Noble Transferred Assets pursuant to this Agreement.

“CONSOL Consent” has the meaning set forth in Section 4.4.

“CONSOL Contracts” has the meaning set forth in Section 2.1(h).

“CONSOL Credit Facility” means that certain Amended and Restated Credit Agreement by and among CONSOL Energy Inc. and the Guarantors party thereto from time to time and the Lenders party thereto and PNC Bank, National Association, as the Administrative Agent and the other Agents party thereto, dated as of June 18, 2014, as heretofore and may hereafter be amended.

“CONSOLDeed” means the Mineral Deed from CONSOL to Noble, pertaining to the CONSOL Transferred Assets, substantially in the form attached to this Agreement as Exhibit E-2.

“CONSOL Excluded Assets” means (a) all of CONSOL’s corporate minute books and corporate financial records that relate to CONSOL’s business generally (including the ownership and operation of the CONSOL Transferred Assets); (b) except to the extent relating to a Noble Assumed Obligation, all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the CONSOL Transferred Assets with respect to any period of time prior to the Effective Time; (c) except to the extent relating to a Noble Assumed Obligation, all claims and causes of action of CONSOL arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (d) all rights and interests of CONSOL (i) under any policy or agreement of insurance, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property; (e) all Hydrocarbons produced and sold from the CONSOL Transferred Properties with respect to all periods prior to the Effective Time, other than those Hydrocarbons attributable to the CONSOL Transferred Properties that are in storage or existing in stock tanks, pipelines or plants (including inventory) as of the Effective Time; (f) all claims of CONSOL for refunds of or loss carry forwards with respect to (i) CONSOL Taxes; (g) all offices (including any owned or leased real or immovable property relating thereto) and personal computers and associated peripherals and all radio and telephone equipment and licenses relating thereto; (h) all of CONSOL’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (i) all servitudes, easements, rights-of-way, surface fee interests, surface leases and other surface use agreements not primarily used or held for use in connection with the ownership or operation of the CONSOL Transferred Properties or the CONSOL Transferred Personal Property (j) except to the extent relating to a Noble Assumed Obligation, all documents and instruments of CONSOL that may be protected by an attorney-client privilege;(k) except to the extent relating to a Noble Assumed Obligation, all audit rights arising under any of the CONSOL Contracts included in the CONSOL Transferred Assets or otherwise with respect to any period prior to the Effective Time or to any of the CONSOL Excluded Assets, except for any Well Imbalances assumed by Noble; (l) all geophysical and other seismic and related technical data and information relating to the CONSOL Transferred Properties or other CONSOL Transferred Assets, to the extent not assignable without consent or payment of fees or other penalties (unless such consent is obtained by Noble and, if applicable, Noble agrees to, and does, pay such fees and penalties);(m) documents prepared or received by CONSOL or its Affiliates with respect to (i) analyses by CONSOL or its Affiliates of any value with respect to the CONSOL Transferred Assets or the Noble Transferred Assets, and (ii) correspondence between or among CONSOL or its Affiliates and their respective representatives regarding the transactions contemplated hereby; (n) all trucks, cars and drilling/workover rigs utilized by CONSOL or its Affiliates in connection with the ownership or operation of the CONSOL Transferred Assets; (o) all Hedge Contracts to which CONSOL or its Affiliates are a party;(p) overhead costs payable to CONSOL or any Affiliate of CONSOL as operator of the CONSOL Transferred Assets attributable to the period between the Effective Time and the Closing Date; (q) any CONSOL Transferred Assets described in Section 2.1(e) that are not assignable; (r) except (in each case) to the extent constituting a CONSOL Contract and subject to the Parties’ obligations under Section 6.9, all Downstream Contracts, master service Contracts and similar Contracts, drilling or fracking Contracts and compressor and other equipment leases; (s) to the extent permitted pursuant to the terms thereof, concurrent rights under all of the CONSOL Transferred Rights-of-Way to the extent necessary or useful to the ownership or operation of assets or properties held by CONSOL or its Affiliates that are not Jointly Owned Properties; (t) all of CONSOL’s interest (including overriding royalty interests) in assets and properties that are Jointly Owned Properties but that are operated by a Third Party; including the rights under the instruments set forth in Exhibit A-5 and including reversionary rights; (u) all rights to coal and substances mined in connection therewith and all CONSOL Sole Depths; (v) the properties described in Exhibit A-5 and all associated assets and properties of CONSOL relating thereto; (w) any injection wells or saltwater disposal wells located on the CONSOL Transferred Leases and/or the CONSOL Transferred Units; (x) all water rights and all infrastructure, equipment, fixtures, rights-of-way, easements, and surface rights relating thereto; (y) an easement to drill through all depths being assigned to Noble for purposes of accessing, exploring, developing and producing Hydrocarbons from the any CONSOL Sole Depths lying below such formations being assigned to Noble (provided that such easement shall not permit the production of Hydrocarbons from the depths being assigned to Noble or perforations, open hole completions, fracture operations or other stimulation operations in the depths being assigned); and (z) those CONSOL Transferred Assets that are deemed to be “CONSOL Excluded Assets” in accordance with Section 3.4(a)(ii) or Section 3.4(b)(ii).

“CONSOL Indemnified Parties” has the meaning set forth in Section 10.3.

“CONSOL Parent” has the meaning set forth in Section 2.5(a)(i).

“CONSOLPreferential Purchase Right” has the meaning set forth in Section 4.9.

“CONSOL Sole Depths” means all of CONSOL’s rights in and to the oil, gas and/or mineral leases and oil and gas mineral fee interests described in (a) Exhibit A-1, Part 1 insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above or below the Marcellus Formation (b) Exhibit A-1, Part 3 insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above or below the Utica/Point Pleasant Formation, and (c) Exhibit A-1, Part 4 insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above or below the Rhinestreet Formation.

“CONSOLTariff Agreements” means the following firm natural gas transportation service agreements: (a) Firm Gas Transportation Service Agreement by and between CONSOL and Columbia Gas Transmission Corporation, Contract No. 3868, with a start date of September 18, 2008, (b) Firm Gas Transportation Service Agreement by and between CONSOL and Dominion Transmission, Inc., Contract No. 200689 dated as of September 28, 2015 and (c) Firm Gas Transportation Service Agreement by and between CONSOL and Dominion Transmission, Inc., Contract No. 200589 dated as of June 20, 2011.

“CONSOL Taxes” means any (i) federal income Taxes, state income Taxes and other similar Taxes (including any applicable interest or penalties) incurred or imposed on CONSOL, CONSOL’s Affiliates or any consolidated, combined or unitary group of which CONSOL is or was a member; (ii) any Asset Taxes (other than Settled Asset Taxes attributable to the CONSOL Transferred Assets) allocable to CONSOL pursuant to Section 12.2(f) (taking into account, and without duplication of, (i) such Asset Taxes effectively borne by CONSOL as a result of the adjustments to the Cash Consideration made pursuant to Section 2.8 and/or Section 2.9, as applicable, and (ii) any payments made from one Party to the other in respect of a refund of Asset Taxes pursuant to Section 12.2(f)); (iii) 50% of any Transfer Taxes imposed or incurred in connection with the transactions contemplated by this Agreement; and (iv) any Taxes attributable to the CONSOL Excluded Assets.

“CONSOL Transferred Assets” has the meaning set forth in Section 2.1.

“CONSOL Transferred Leases” has the meaning set forth in Section 2.1(a).

“CONSOL Transferred O/G Wells” has the meaning set forth in Section 2.1(b).

“CONSOL Transferred Personal Property” has the meaning set forth in Section 2.1(f).

“CONSOL Transferred Property” or “CONSOL Transferred Properties” has the meaning set forth in Section 2.1(d).

“CONSOL Transferred Records” has the meaning set forth in Section 2.1(k).

“CONSOL Transferred Rights-Of-Way” has the meaning set forth in Section 2.1(d).

“CONSOL Transferred Units” has the meaning set forth in Section 2.1(c).

“CONSOLTransferredWells” has the meaning set forth in Section 2.1(b).

“CONSOL Transition Services Agreement” means the Transition Services Agreement by and between CONSOL and Noble substantially in the form attached hereto as Exhibit J-1 covering, among other things, services provided by CONSOL with respect to the certain of the Noble Combined Assets.

“CONSOL Undeveloped Net Acres” means, with respect to the applicable Region, the Undeveloped Net Acres designated as “CONSOL Undeveloped Net Acres” on Exhibit O for such Region.

“CONSOL Water Facility Operating and Use Agreement” means the Water Facility Operating and Use Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit G-3 (where CONSOL is acting as operator thereunder).

“Contract” means any written or oral contract, agreement, lease, mortgage, franchise, license agreement, purchase order, binding bid, commitment, debt instrument or any other legally binding arrangement, including farmin and farmout agreements; participation, exploration and joint development agreements, crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements, acreage contribution agreements, operating agreements, balancing agreements, unitization agreements, processing agreements, hydrocarbon balancing agreements, hydrocarbon storage agreements, facilities or equipment leases, platform use and platform sharing agreements, production handling agreements and other similar Contracts, but excluding, however, any lease, deed, easement, right-of-way, permit or other instrument (other than acquisition or similar sales or purchase agreements) creating, evidencing or assigning an interest in a CONSOL Transferred Property or a Noble Transferred Property or any real or immovable property related to or used in connection with the operations of any Transferred Property.

“Control” (including the terms “Controlling,” “Controlled by” and “under common Control with”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting shares, by contract, or otherwise.

“Customary Post Closing Consents” means the consents and approvals from Governmental Authorities for the assignment by a Transferring Party of a Transferred Property included in the Transferred Properties of such Transferring Party to its Non-Transferring Party that are customarily obtained after the assignment of properties similar to the Transferred Properties.

“Deed” means the CONSOL Deed or the Noble Deed, as the context requires.

“Deficiency Net Acres Claim” has the meaning set forth in Section 6.8(a)(i).

“Deficiency Net Acres Dispute Notice” has the meaning set forth in Section 6.8(a)(ii).

“Defensible Title” means such title of a Transferring Party as of Closing with respect to the Transferred Leases and the Transferred Wells included in such Transferring Party’s Transferred Properties that, subject to the Permitted Encumbrances:

(a)    with respect to each Transferred Lease shown in Exhibit A-1 or Exhibit B-1 (as applicable), and each Transferred Well shown in Exhibit A-2, Part 1 or Exhibit B-2, Part 1, (as applicable),entitles such Transferring Party to receive not less than the Net Revenue Interest shown in such Exhibit for such Transferred Lease or Transferred Well (as applicable) throughout the productive life of such Transferred Lease or Transferred Well (as applicable), except for (i) subject to Section 6.1(b)(i) and Section 6.2(b)(ii), respectively, decreases in connection with those operations in which such Non-Transferring Party may from and after the Execution Date elect to be a non-consenting co-owner, (ii) decreases resulting from the establishment or amendment from and after the Execution Date of pools or units, (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, (iv) decreases resulting from actions by the Non-Transferring Party and (v) decreases resulting from any reversion of interest to a co-owner with respect to operations in which such co-owner, after the Execution Date, elects not to consent;

(b)    with respect to each Transferred Well shown in Exhibit A-2, Part 1 or Exhibit B-2, Part 1 (as applicable), obligates such Transferring Party to bear a percentage of the costs and expenses for the development and maintenance of, and operations relating to, such Transferred Well of not more than the Working Interest shown in Exhibit A-2, Part 1 or Exhibit B-2, Part 1 (as applicable) for such Transferred Well throughout the productive life of such Transferred Well, except (i) increases resulting from contribution requirements with respect to defaulting co-owners from and after the Execution Date under applicable operating agreements, (ii) increases to the extent that such increases are accompanied by a proportionate increase in such Transferring Party’s Net Revenue Interest and (iii) increases resulting from actions by the Non-Transferring Party;

(c)    with respect to each Transferred Lease shown in Exhibit A-1 or Exhibit B-1 (as applicable)entitles such Transferring Party to the Net Acres for such Transferred Lease; and

(d)    is free and clear of all Encumbrances.

“Designated Account” has the meaning set forth in Section 2.5(a)(i).

“Developed Net Acres” means, with respect to any Transferred Lease, that portion of such Transferred Lease included within a Transferred Unit that, as of the Effective Time, has a producing oil or gas well or an oil or gas well that has been drilled but not yet completed.

“Development Agreement” has the meaning set forth in the recitals.

“Discovered Leases” has the meaning given such term in the definition of Transferred Leases.

“Dispute Notice” has the meaning set forth in Section 2.9.

“DOJ” means the United States Department of Justice.

“Downstream Contracts” means all interstate transmission and transportation agreements and gathering, processing, treating and similar agreements.

“Easements” has the meaning given such term in the Surface Use Agreement.

“Effective Time” means 12:01 a.m. (Eastern Time) on October 1, 2016.

“Encumbrance” means any lien, mortgage, security interest, defect, irregularity, pledge, charge or encumbrance.

“Environmental Event” means any release, spill, disposal, environmental condition or environmental incident concerning any land, facility, asset, property or natural resources (including air, land, soil, surface and subsurface strata, surface water and ground water or sediments) that: violates any Environmental Law or the terms of any license or permit issued pursuant thereto (ii) gives rise to or results in any common Law or other liability to any Person, (iii) requires remedial actions or show cause why remedial action is not required, or (iv) results in a fine, penalty or assessment of any Governmental Authority.

“Environmental Laws” means all applicable federal, state and local Laws in effect as of the Execution Date, including common Law, relating to the protection of the public health, welfare and the environment, including those Laws relating to the storage, handling and use of chemicals and other Hazardous Substances and those relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority.

“Execution Date” has the meaning set forth in the first paragraph herein.

“FERC” is defined in Section 6.9(a).

“FERC Order” has the meaning set forth in Section 6.9(c).

“Fill-In Interest” means, excluding any Quitclaim Property, any interest in an oil and gas lease or fee mineral interest that (a) was acquired by a Transferring Party or any of its Affiliates (other than from another Affiliate) after September 30, 2011, (b) covers lands within any Transferred Unit that has a producing oil or gas well or an oil or gas well that has been drilled but not yet completed that was included in the Transferred Properties conveyed by such Transferring Party to its Non-Transferring Party pursuant to this Agreement, and (c) was not conveyed by such Transferring Party to such Non-Transferring Party pursuant to an Assignment at Closing (and that was not excluded pursuant to Section 3.4).

“Fill-In Notice” is defined in Section 6.7.

“Fill-In Response” is defined in Section 6.7.

“Final Adjustment Statement” has the meaning set forth in Section 2.9.

“Final Settlement Statement” has the meaning set forth in Section 2.9.

“Final Settlement Statement Date” means the date that is 120 days following the Closing Date.

“FTC” means the United States Federal Trade Commission.

“Fundamental Representations” means those representations and warranties of (a) CONSOL set forth in Sections 4.1, 4.2, 4.5, 4.6 and 4.12 and (b) of Noble set forth in Sections 5.1, 5.2, 5.5, 5.6 and 5.12.

“GAAP” means generally accepted accounting principles as used in the United States of America.

“Governmental Authority” means any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, belief, regulatory or taxing authority or power; and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

“Hard Consents” has the meaning set forth in Section 3.4(b)(i).

“Hazardous Substances” means any pollutants, contaminants, toxics or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of any liability under, any Environmental Laws, including, naturally occurring radioactive material, asbestos, and man-made material fibers.

“Hedge Contract” means any Contract to which a Transferring Party or any of its Affiliates is a party with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

“HSR Act” means the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations thereunder.

“Hydrocarbons” means oil and gas and other hydrocarbons (including condensate) produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination thereof, and any minerals produced in association therewith.

“incur” or “incurred” shall be interpreted as follows: expenditures which are cash-called or advanced pursuant to an operating agreement shall be deemed incurred when incurred by the operator thereunder and the determination as to whether expenditures were incurred prior to, or on and after, the Effective Time shall be based upon when the services were rendered or the goods delivered, as applicable

“Indemnify”means indemnify, defend (including the requirement to pay costs of litigation, dispute resolution and other legal costs and court fees), release and hold harmless.

“Indemnified Party” has the meaning set forth in Section 10.7(a).

“Indemnifying Party” has the meaning set forth in Section 10.7(a).

“Indemnity Deductible” has the meaning set forth in Section 10.4(a).

“Interim Period” means that period of time commencing with the Effective Time and ending immediately prior to Closing.

“Jointly Owned Property” has the meaning set forth in Section 12.10.

“Knowledge” means with respect to (a) CONSOL, the actual knowledge (without investigation) of the following Persons: Craig Neal, Jeremy Jones and Chad Griffith and (b) Noble, the actual knowledge (without investigation) of the following Persons: Donnie Moore, David Burger and Jay Smith.

“Law” means any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leach XPress Contract” means that certain FTS Service Agreement by and among Columbia Gas Transmission LLC and Noble dated as of June 1, 2016, as such agreement may have heretofore and may hereafter be amended.

“Liabilities” means any and all claims, causes of actions, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines or costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury or death or property damage.

“Limitation of Liability Exclusions” has the meaning set forth in Section 10.4(a).

“Marcellus Formation” means (a) in north central Pennsylvania (Indiana, Clearfield, Jefferson, Cameron, Elk, Forest and Cambria Counties in Pennsylvania), specifically from the stratigraphic equivalent of the top of the Burkett in the Marchand 3I (API 37-063-37480) at 6874' MD through to the stratigraphic equivalent of the top of the Onondaga at 7540' MD and illustrated in the log attached as Exhibit C-1; (b) in central Pennsylvania (Clarion, Armstrong, Westmoreland, Venango, Somerset and Fayette Counties in Pennsylvania), specifically from the stratigraphic equivalent of the top of the Burkett in the DeArmitt #1 (API 37-129-27246) at 7000' MD through to the stratigraphic equivalent of the top of the Onondaga at 7530' MD and illustrated in the log attached as Exhibit C-1; (c) in southwest Pennsylvania (Mercer, Lawrence, Butler, Beaver, Allegheny, Washington and Greene Counties in Pennsylvania, and Hancock, Brooke, Ohio, Marshall, Wetzel and Monongalia Counties in West Virginia), specifically from the stratigraphic equivalent of the top of the Burkett in the GH-10C-CV (API 37-059-25397) at 7580' MD through to the stratigraphic equivalent of the top of the Onondaga at 7892' MD and illustrated in the log attached as Exhibit C-1; (d) in north West Virginia (Marion, Preston, Taylor, Tucker, Grant and Barbour Counties in West Virginia), specifically from the stratigraphic equivalent of the top of the Burkett in the DEPI #14815 (API 47-001-02850) at 7350' MD through to the stratigraphic equivalent of the top of the Onondaga at 7710' MD and illustrated in the log attached as Exhibit C-1; (e) in north West Virginia (Upshur, Randolph, Webster, Lewis, Harrison and Doddridge Counties in West Virginia), specifically from the stratigraphic equivalent of the top of the Burkett in the CENT3A (47-097-03847) at 7272’ MD through to the stratigraphic equivalent of the top of the Onondaga at 7569’ MD and illustrated in the log attached as Exhibit C-1; and (f) in western West Virginia (Tyler, Pleasants, Wood, Wirt, Ritchie, Calhoun, Roane, Jackson, Gilmer, Braxton, Clay and Nicholas Counties in West Virginia), specifically from the equivalent of the top of the Burkett in the PENS1C (47-085-10011) at 6270’ MD through to the stratigraphic equivalent of the top of the Onondaga at 6380’ MD and illustrated in the log attached as Exhibit C-1.

“MarkWest Contract” means that certain Third Amended and Restated Gas Processing Agreement dated effective November 23, 2013, as such agreement has been heretofore and may hereafter be amended, modified and restated.

“Master Netting Agreement” has the meaning set forth in Section 6.9(e)(iii).

“Material Adverse Effect” means any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not and whether covered by insurance or not) that has had or would be reasonably likely to have, individually or in the aggregate with any other event or events, a material adverse effect on the ownership, operation or financial condition of the Noble Transferred Assets or the CONSOL Transferred Assets, as applicable, taken as a whole as currently operated as of the Execution Date; provided, however, that Material Adverse Effect shall not include such material adverse effects resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates) in the area in which the CONSOL Transferred Assets or the Noble Transferred Assets, as applicable, are located, the United States or worldwide; (c) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Noble Transferred Assets or the CONSOL Transferred Assets, as applicable, are located; (d) acts of God, including hurricanes, storms or other naturally occurring events; (e) acts or failures to act of Governmental Authorities; (f) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (g) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (h) a change in Laws from and after the Execution Date; (i) casualty losses; (j) any reclassification or recalculation of reserves in the ordinary course of business; (k) changes in the prices of Hydrocarbons; (l) a change in Laws and any interpretations thereof from and after the Execution Date; and (m) natural declines in well performance.

“Memorandum of Termination and Release Agreement” means the Memorandum of Termination and Release Agreement and Release of Liens by and between Noble and CONSOL in substantially the form of Exhibit F.

“Net Acre” means, as computed separately with respect to each Transferred Lease, (a) the number of gross acres in the lands covered by such Transferred Lease, multiplied by (b) the undivided percentage interest in oil, gas and other minerals covered by such Transferred Lease in such lands, multiplied by (c) the applicable Transferring Party’s Working Interest or undivided interest in such Transferred Lease; provided that if items (b) and/or (c) vary as to different areas of such lands (including depths) covered by such Transferred Lease, a separate calculation shall be done for each such area as if it were a separate Transferred Lease.

“Net Revenue Interest” means, with respect to any Transferred Well or Transferred Lease, the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Transferred Well or Transferred Lease, after giving effect to all Burdens.

“Nexus Contract” means that certain Precedent Agreement by and among DTE Pipeline Company, Spectra Energy Transmission, LLC and CONSOL dated as of September 19, 2014, as such agreement has been heretofore and may hereafter be amended, modified and restated.

“Noble” has the meaning set forth in the first paragraph herein.

“Noble Areas” means the geographical areas set forth in Schedule 1.1 for Noble.

“NobleAssignment” means the Assignment and Bill of Sale from Noble to CONSOL, pertaining to the Noble Transferred Assets (other than the Noble Transferred Assets assigned pursuant to the Noble Deed), substantially in the form attached to this Agreement as Exhibit E-3.

“NobleAssumed Obligations” has the meaning set forth in Section 10.1(a).

“Noble Combined Assets” means the CONSOL Transferred Assets being acquired by Noble, together with the interest of Noble in the underlying assets comprising such CONSOL Transferred Assets that was owned by Noble prior to its acquisition of such CONSOL Transferred Assets pursuant to this Agreement.

“Noble Consent” has the meaning set forth in Section 5.4.

“Noble Contracts” has the meaning set forth in Section 2.2(h).

“NobleDeed” means the Mineral Deed from Noble to CONSOL, pertaining to the Noble Transferred Assets, substantially in the form attached to this Agreement as Exhibit E-4.

“Noble Excluded Assets” means (a) all of Noble’s corporate minute books and corporate financial records that relate to Noble’s business generally (including the ownership and operation of the Noble Transferred Assets); (b) except to the extent relating to a CONSOL Assumed Obligation, all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Noble Transferred Assets with respect to any period of time prior to the Effective Time; (c) except to the extent relating to a CONSOL Assumed Obligation, all claims and causes of action of Noble arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (d) all rights and interests of Noble (i) under any policy or agreement of insurance, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property; (e) all Hydrocarbons produced and sold from the Noble Transferred Properties with respect to all periods prior to the Effective Time, other than those Hydrocarbons attributable to the Noble Transferred Properties that are in storage or existing in stock tanks, pipelines or plants (including inventory) as of the Effective Time; (f) all claims of Noble for refunds of or loss carry forwards with respect to Noble Taxes; (g) all offices (including any owned or leased real or immovable property relating thereto) and personal computers and associated peripherals and all radio and telephone equipment and licenses relating thereto; (h) all of Noble’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (i) all servitudes, easements, rights-of-way, surface fee interests, surface leases and other surface use agreements not primarily used or held for use in connection with the ownership or operation of the Noble Transferred Properties or the Noble Transferred Personal Property; (j) except to the extent relating to a CONSOL Assumed Obligation, all documents and instruments of Noble that may be protected by an attorney-client privilege;(k) except to the extent relating to a CONSOL Assumed Obligation, all audit rights arising under any of the Noble Contracts included in the Noble Transferred Assets or otherwise with respect to any period prior to the Effective Time or to any of the Noble Excluded Assets, except for any Well Imbalances assumed by CONSOL; (l) all geophysical and other seismic and related technical data and information relating to the Noble Transferred Properties or other Noble Transferred Assets, to the extent not assignable without consent or payment of fees or other penalties (unless such consent is obtained by CONSOL and, if applicable, CONSOL agrees to, and does, pay such fees and penalties);(m) documents prepared or received by Noble or its Affiliates with respect to (i) analyses by Noble or its Affiliates of any value with respect to the Noble Transferred Assets or the CONSOL Transferred Assets, and (ii) correspondence between or among Noble or its Affiliates and their respective representatives regarding the transactions contemplated hereby;(n) all trucks, cars and drilling/workover rigs utilized by Noble or its Affiliates in connection with the ownership or operation of the Noble Transferred Assets; (o) all Hedge Contracts to which Noble or its Affiliates are a party;(p) overhead costs payable to Noble or any Affiliate of Noble as operator of the Noble Transferred Assets attributable to the period between the Effective Time and the Closing Date; (q) any Noble Transferred Assets described in Section 2.1(e) that are not assignable; (r) except (in each case) to the extent constituting a Noble Contract and subject to the Parties’ obligations under Section 6.9, all Downstream Contracts, master service Contracts and similar Contracts, drilling or fracking Contracts and compressor and other equipment leases; (s) to the extent permitted pursuant to the terms thereof, concurrent rights under all of the Noble Transferred Rights-of-Way to the extent necessary or useful to the ownership or operation of assets or properties held by Noble or its Affiliates that are not Jointly Owned Properties; (t) all of Noble’s interest (including overriding royalty interests) in assets and properties that are Jointly Owned Properties but that are operated by a Third Party; including the rights under the instruments set forth in Exhibit B-5 and including reversionary rights; (u) all Noble Sole Depths; (v) the properties described in Exhibit B-5 and all associated assets and properties of Noble relating thereto; (w) any injection wells or saltwater disposal wells located on the Noble Transferred Leases and/or the Noble Transferred Units; (x) all water rights and all infrastructure, equipment, fixtures, rights-of-way, easements, and surface rights relating thereto; (y) an easement to drill through all depths being assigned to CONSOL for purposes of accessing, exploring, developing and producing Hydrocarbons from the any Noble Sole Depths lying below such formations being assigned to CONSOL (provided that such easement shall not permit the production of Hydrocarbons from the depths being assigned to CONSOL or perforations, open hole completions, fracture operations or other stimulation operations in the depths being assigned); and (z) those Noble Transferred Assets that are deemed to be “Noble Excluded Assets” in accordance with Section 3.4(a)(ii) or Section 3.4(b)(ii).

“Noble Indemnified Parties” has the meaning set forth in Section 10.2.

“NoblePreferential Purchase Right” has the meaning set forth in Section 5.9.

“Noble Sole Depths” means all of Noble’s rights in and to the oil, gas and/or mineral leases and oil and gas mineral fee interests described in in (a) Exhibit B-1, Part 1 insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above or below the Marcellus Formation and (b) Exhibit B-1, Part 3 insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above or below the Rhinestreet Formation.

“Noble Tariff Agreements” means the following firm natural gas transportation service agreements: (a) Firm Gas Transportation Service Agreement by and between Noble and Columbia Gas Transmission, LLC, Contract No. 134784, dated September 28, 2012, (b) Firm Gas Transportation Service Agreement by and between Noble and Columbia Gas Transmission, LLC,, Contract No. 134785 dated September 28, 2012, (c) Firm Gas Transportation Service Agreement by and between Noble and Dominion Transmission, Inc., Contract No. 200620 dated February 6, 2014, and (d) Firm Gas Transportation Service Agreement by and between Noble and Dominion Transmission, Inc., Contract No. 200617 dated August 24, 2011.

“Noble Taxes” means any (i) federal income Taxes, state income Taxes and other similar Taxes (including any applicable interest or penalties) incurred or imposed on Noble, Noble’s Affiliates or any consolidated, combined or unitary group of which Noble is or was a member; (ii) any Asset Taxes (other than Settled Asset Taxes attributable to the Noble Transferred Assets) allocable to Noble pursuant to Section 12.2(f) (taking into account, and without duplication of, (i) such Asset Taxes effectively borne by Noble as a result of the adjustments to the Cash Consideration made pursuant to Section 2.8 and/or Section 2.9, as applicable, and (ii) any payments made from one Party to the other in respect of a refund of Asset Taxes pursuant to Section 12.2(f)); (iii) 50% of any Transfer Taxes imposed or incurred in connection with the transactions contemplated by this Agreement; and (iv) any Taxes attributable to the Noble Excluded Assets.

“Noble Transferred Assets” has the meaning set forth in Section 2.2.

“Noble Transferred Leases” has the meaning set forth in Section 2.2(a).

“Noble Transferred O/G Wells” has the meaning set forth in Section 2.2(b).

“Noble Transferred Personal Property” has the meaning set forth in Section 2.2(f).

“Noble Transferred Property” or “Noble Transferred Properties” has the meaning set forth in Section 2.2(d).

“Noble Transferred Records” has the meaning set forth in Section 2.2(k).

“Noble Transferred Rights-Of-Way” has the meaning set forth in Section 2.2(d).

“Noble Transferred Units” has the meaning set forth in Section 2.2(c).

“NobleTransferredWells” has the meaning set forth in Section 2.2(b).

“Noble Transition Services Agreement” means the Transition Services Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit J-2 covering, among other things, services provided by Noble with respect to the certain of the Noble Combined Assets.

“Noble Undeveloped Net Acres” means, with respect to the applicable Region, the amount of Undeveloped Net Acres designated as “Noble Undeveloped Net Acres” on Exhibit O for such Region.

“Noble Water Facility Operating and Use Agreement” means the Water Facility Operating and Use Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit G-2 (where Noble is acting as operator thereunder).

“Non-Transferring Party” means the Party that is not the Transferring Party

“Offered AMI Properties” ” has the meaning set forth in Section 2.6(a)(iv).

“Outside Termination Date” means January 31, 2017.

“Party” and “Parties” has the meaning set forth in the first paragraph herein.

“Permits” ” has the meaning set forth in Section 4.10.

“Permitted Encumbrances” means, with respect to any Transferred Properties (including any Transferred Lease or Transferred Well) of any Transferring Party:

(a)    the terms and conditions of such Transferred Leases and all Burdens on such Transferred Properties if the net cumulative effect of such terms and conditions and Burdens does not (i) operate to reduce the Net Revenue Interest of such Transferring Party with respect to any such Transferred Lease or Transferred Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1, Exhibit A-2, Part 1, Exhibit B-1 or Exhibit B-2, Part 1 (as applicable) for such Transferred Lease or Transferred Well, (ii) obligate such Transferring Party to bear a Working Interest with respect to any such Transferred Well in any amount greater than the Working Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1 for such Transferred Well (unless such Transferring Party’s Net Revenue Interest for such Transferred Well is greater than such Transferring Party’s Net Revenue Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1, as applicable, for such Transferred Well in the same proportion as any increase in such Working Interest), or (iii) reduce the Net Acres of such Transferring Party in any such Transferred Lease to less than the Net Acres for such Transferred Lease set forth in Exhibit A-1 or Exhibit B-1, as applicable;

(b)    preferential purchase rights, rights of first refusal and similar rights and required Third Party consents to assignment and similar requirements;

(c)    liens for Taxes or assessments not yet due or delinquent;

(d)    Customary Post Closing Consents;

(e)    to the extent not yet triggered, conventional rights of reassignment;

(f)    all applicable Laws and all rights reserved to or vested in any Governmental Authority (i) to control or regulate any such Transferred Lease or Transferred Well in any manner or to assess Taxes with respect to any such Transferred Lease or Transferred Well; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any such Transferred Lease or Transferred Well; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting such Transferred Leases or Transferred Wells to any Governmental Authority with respect to any franchise, grant, license or permit;

(g)    rights of a common owner of any interest in rights-of-way, Permits or easements held by such Transferred Party and such common owner as tenants in common or through common ownership;

(h)    easements, conditions, covenants, restrictions, servitudes, Permits, rights-of-way, surface leases and other similar rights for the purpose of surface or other operations, facilities, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines and other like purposes, or for the joint or common use of the lands, rights-of-way, facilities and equipment, which, in each case, do not (i) materially impair the operation or use of such Transferred Leases or Transferred Wells as currently operated and used, (ii) operate to reduce the Net Revenue Interest of such Transferring Party with respect to any such Transferred Lease or Transferred Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1, Exhibit A-2, Part 1, Exhibit B-1 or Exhibit B-2, Part 1 (as applicable) for such Transferred Lease or Transferred Well, (iii) obligate such Transferring Party to bear a Working Interest with respect to any such Transferred Well in any amount greater than the Working Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1 for such Transferred Well (unless such Transferring Party’s Net Revenue Interest for such Transferred Well is greater than such Transferring Party’s Net Revenue Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1, as applicable, for such Transferred Well in the same proportion as any increase in such Working Interest), or (iv) reduce the Net Acres of such Transferring Party in any such Transferred Lease to less than the Net Acres for such Transferred Lease set forth in Exhibit A-1 or Exhibit B-1, as applicable;

(i)    zoning and planning ordinances and municipal regulations;

(j)    vendors, carriers, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due;

(k)    liens created under such Transferred Leases or Contracts included in the Transferred Properties or by operation of Law in respect of obligations that are not yet due;

(l)    any Encumbrance affecting such Transferred Leases or Transferred Wells that is discharged by such Transferring Party at or prior to Closing;

(m)    any matters expressly identified as a Permitted Encumbrance to such Transferred Properties on Exhibit A or Exhibit B (as applicable) and all litigation set forth in Schedule 4.7 or Schedule5.7 (as applicable);

(n)    calls on production under existing Contracts;

(o)    any lien, charge or other Encumbrance on or affecting such Transferred Properties which is expressly bonded or paid by the Non-Transferring Party acquiring such Transferred Properties at or prior to Closing;

(p)    limitations (including drilling and operating limitations) imposed on such Transferred Properties by reason of the rights of subsurface owners or operators in a common property (including the rights of coal, utility and timber owners);

(q)    all Contracts and all other Encumbrances, instruments, obligations, defects and irregularities affecting the Transferred Leases or the Transferred Wells that individually or in the aggregate do not: do not (i) materially impair the operation or use of such Transferred Leases or Transferred Wells as currently operated and used, (ii) operate to reduce the Net Revenue Interest of such Transferring Party with respect to any such Transferred Lease or Transferred Well to an amount less than the Net Revenue Interest set forth in Exhibit A-1, Exhibit A-2, Part 1, Exhibit B-1 or Exhibit B-2, Part 1 (as applicable) for such Transferred Lease or Transferred Well, (iii) obligate such Transferring Party to bear a Working Interest with respect to any such Transferred Well in any amount greater than the Working Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1 for such Transferred Well (unless such Transferring Party’s Net Revenue Interest for such Transferred Well is greater than such Transferring Party’s Net Revenue Interest set forth in Exhibit A-2, Part 1 or Exhibit B-2, Part 1, as applicable, for such Transferred Well in the same proportion as any increase in such Working Interest), or (iv) reduce the Net Acres of such Transferring Party in any such Transferred Lease to less than the Net Acres for such Transferred Lease set forth in Exhibit A-1 or Exhibit B-1, as applicable;

(r)    any assignments by the Transferring Party of any Transferred Properties to the non-Transferring Party prior to the date hereof; and

(s)    the assignments set forth on Exhibit A-6 or Exhibit B-6, as applicable.

“Person” means any individual, corporation, company, partnership, limited partnership, limited liability company, trust, estate, Governmental Authority or any other entity.

“Petition for Waiver” has the meaning set forth in Section 6.9(a).

“Pre-Closing Working Interest Share” means (a) with respect to Noble, Noble’s Working Interest share of Liabilities attributable to the Combined Assets and (b) with respect to CONSOL, CONSOL’s Working Interest share of Liabilities attributable to the Combined Assets.

“Preferential Purchase Right” means a CONSOL Preferential Purchase Right or a Noble Preferential Purchase Right, as the context requires.

“Preliminary Adjustment Statement” has the meaning set forth in Section 2.8(a).

“Preliminary Settlement Statement” has the meaning set forth in Section 2.8(a).

“Property Expenses” means, with respect to any Transferred Properties of any Transferring Party, all property expenses (including costs of insurance but excluding all Asset Taxes) and capital expenditures (in each case) incurred in the ownership and operation of such Transferred Properties in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to such Transferred Properties under the relevant operating agreement or unit agreement, if any, but excluding Liabilities attributable to (a) personal injury or death, property damage or violation of any Law, (b) obligations to plug wells, dismantle or decommission facilities, close pits and restore the surface around such wells, facilities and pits, (c) environmental matters, including obligations to remediate any contamination of groundwater, surface water, soil, sediments or such Transferred Properties under applicable Environmental Laws, (d) obligations with respect to Well Imbalances, and (e) obligations to pay royalties, overriding royalties or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to such Transferred Properties, including those held in suspense. Notwithstanding anything to the contrary, Property Expenses do not include any costs incurred by a Transferring Party in connection with any obligation of such Transferring Party to pay, reimburse or Indemnify the Non-Transferring Party hereunder, which costs shall be the sole obligation of such Transferring Party.

“Quitclaim Properties” means the properties described in Exhibit H.

“Region” means each region set forth in Exhibit O.

“Relinquishing Party” has the meaning set forth in Section 6.9(b).

“Restriction Agreement” means the Restriction Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit I.

“Rhinestreet Formation” means specifically from the stratigraphic equivalent of the top of the Rhinestreet in the NV 39F (API 37-125-24701) at 6628’MD through to the stratigraphic equivalent of the top of the Burkett, which top is at 7102’MD, and illustrated in the log attached as Exhibit C-3.

“Scheduled Closing Date” has the meaning set forth in Section 9.1.

“Settled Asset Taxes” has the meaning set forth in Section 12.2(f).

“Shared Asset/Use Agreement” means the Shared Asset/Use Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit G-1.

“Special Warranty” means with respect to (a) the CONSOL Assignment and the CONSOL Deed, a warranty of Defensible Title to the CONSOL Transferred Leases and the CONSOL Transferred Wells against any claim arising by, through or under CONSOL with respect to CONSOL’s period of ownership of the CONSOL Transferred Leases and the CONSOL Transferred Wells after September 30, 2011 but not otherwise, and (b) the Noble Assignment and the Noble Deed, a warranty of Defensible Title to the Noble Transferred Leases and the Noble Transferred Wells against any claim arising by, through or under Noble but not otherwise.

“Specified Benefit” means, with respect to a Transferring Party, an increase in the Net Acres in any Transferred Lease assigned by such Transferring Party to its Non-Transferring Party to the extent and only to the extent such increase of Net Acres arises as a result of (i) it being mutually agreed by the Parties that the Transferred Lease was Jointly Owned Property not identified on Exhibit A-1 or Exhibit B-1, as applicable (other than any Quitclaim Property), (ii) such Transferred Lease or portion thereof being mutually agreed by the Parties as having more Undeveloped Net Acres and less Developed Net Acres than what was accounted for in determining the Target Net Acres in the Region where such Transferred Lease is located, or (iii) such Transferred Lease being mutually agreed by the Parties to be in a Region other than the Region specified on Exhibit A-1 or Exhibit B-1, as applicable, for such Transferred Lease.

“Specified Defect” means, with respect to a Transferring Party, a shortage of Net Acres in any Transferred Lease assigned by such Transferring Party to its Non-Transferring Party to the extent and only to the extent such shortage of Net Acres arises as a result of (i) the expiration of the primary term of such Transferred Lease after September 30, 2011 but prior to the Closing Date as mutually agreed by the Parties, (ii) it being mutually agreed by the Parties that the Transferred Lease was not a Jointly Owned Property (the Parties acknowledging, for the avoidance of doubt, that the properties on Exhibit A-5 and/or Exhibit B-5 will not be considered Jointly Owned Properties),(iii) such Transferred Lease or portion thereof was transferred by such Transferring Party to a Third Party after September 30, 2011 but prior to Closing, (iv) such Transferred Lease or portion thereof being mutually agreed by the Parties as having less Undeveloped Net Acres and more Developed Net Acres than what was accounted for in determining the Target Net Acres in the Region where such Transferred Lease is located, (v) such Transferred Lease being mutually agreed by the Parties to be in a Region other than the Region specified on Exhibit A-1 or Exhibit B-1, as applicable, for such Transferred Lease, (vi) such Transferred Lease was supposed to have been on Exhibit H but was inadvertently on Exhibit A-1 or Exhibit B-1, as applicable, or (vii) such Transferred Party having filed, after September 30, 2011 but prior to Closing, a recorded release of such Transferred Lease.

“Surface Use Agreement” has the meaning set forth in Section 6.10(a).

“Target Net Acres” means, with respect to each Region, the CONSOL Undeveloped Net Acres or the Noble Undeveloped Net Acres, as the context requires.

“Tariff Agreements” means the CONSOL Tariff Agreements and the Noble Tariff Agreements.

“Tax” or “Taxes” means any federal, state, local or non-U.S. income, gross receipts, license, payroll, employment, excise, severance, stamp, occupation, premium, windfall profits, environmental (including taxes under section 59A of the Code), customs duties, capital stock, franchise, profits, withholding, social security (or similar), unemployment, disability, real property, personal property, sales, use, severance, natural resources, production, ad valorem, transfer, registration, stamp, value added, alternative or add-on minimum, estimated or other tax of any kind whatsoever, whether computed on a separate or consolidated, unitary or combined basis or in any other manner, including any interest, penalty or addition thereto, whether disputed or not.

“Tax Partnership” means the partnership between Noble and CONSOL created solely for U.S. federal and applicable state income tax purposes by the Acquisition Agreement and the Development Agreement and governed by the Tax Partnership Agreement.

“Tax Partnership Agreement” means the agreement between Noble and CONSOL attached as Exhibit G to the Development Agreement that governs the Tax Partnership.

“Tax Return” means any return, declaration, report or information return (including any related or supporting estimates, elections, schedules, statements, or information) filed or required to be filed in connection with the determination, assessment, or collection of any Tax.

“Terminated Agreements” means those Contracts and other instruments to be terminated pursuant to the Termination and Release Agreement.

“Termination and Release Agreement” means the Termination and Release Agreement by and between CONSOL and Noble and/or their respective Affiliates substantially in the form attached hereto as Exhibit D.

“Third Party” means any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

“Third Party Claim” has the meaning set forth in Section 10.7(b).

“Transaction Documents” means those documents executed and/or delivered on or prior to Closing pursuant to or in connection with this Agreement.

“Transferred Contracts” means the CONSOL Contracts or the Noble Contracts, as the context requires.

“Transferred Leases” means the CONSOL Transferred Leases or the Noble Transferred Leases, as the context requires. For the avoidance of doubt, the term “Transferred Lease” is limited to the depths in such Transferred Lease assigned or to be assigned by a Transferring Party to its Non-Transferring Party hereunder. Any Jointly Owned Property that is not included on Exhibit A-1 or Exhibit B-1 as applicable, shall be deemed to be a Transferred Lease for purposes of Section 6.8 and the defined terms used therein (“Discovered Leases”).

“Transferred Properties” means the CONSOL Transferred Assets or the Noble Transferred Assets, as the context requires.

“Transferred Units” means the CONSOL Transferred Units or the Noble Transferred Units, as the context requires.

“Transferred Wells” means the CONSOL Transferred Wells or the Noble Transferred Wells, as the context requires.

“Transferring Party” means, in connection with or relating to (a) any of the CONSOL Transferred Assets (including any of the CONSOL Transferred Leases and/or the CONSOL Transferred Wells), CONSOL and (b) any of the Noble Transferred Assets (including any of the Noble Transferred Leases and/or the Noble Transferred Wells), Noble.

“Transfer Taxes” means sales, use, excise, real property transfer, registration, documentary, stamp, filing or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed on, or with respect to, the transactions contemplated by this Agreement, as well as any interest, penalty or addition thereto whether disputed or not.

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed or final Treasury Regulations.

“Undeveloped Net Acres” means, with respect to each Transferred Lease, the Net Acres of a Transferring Party in such Transferred Lease that are not located within a Transferred Unit for a producing oil or gas well or an oil or gas well drilled but not yet completed.

“Utica/Point Pleasant Formation” means specifically from the stratigraphic equivalent of the top of the Onondaga in the Protégé Dangel #1 (API 34-111-24305) at 6282'MD through to one hundred (100) feet below the stratigraphic equivalent of the base of the Utica/Point Pleasant (otherwise known as the top of the Trenton Limestone), which base is at 10,797’, and illustrated in the log attached as Exhibit C-2.

“Water Assets” means the water assets and facilities cover by the Water Facility Operating and Use Agreements.

“Water Facility Operating and Use Agreements” means the Noble Water Facility Operating and Use Agreement and the CONSOL Water Facility Operating and Use Agreement.

“Well Imbalance” means, with respect to any Transferred Wells of any Transferring Party, any imbalance at the wellhead between the amount of Hydrocarbons produced from such Transferred Well and allocable to the interests of such Transferring Party therein and the shares of production from such Transferred Well to which such Transferring Party is entitled.

“Willful Breach” means, with respect to any Party, that such Party does one or more of the following: (a) such Party willfully and intentionally breaches in any material respect (by refusing to perform or taking an action prohibited by) any material pre-Closing covenant applicable to such Party, (b) such Party intentionally misrepresents any of the matters covered by its representations or warranties under this Agreement as of the Execution Date, or (c) such Party willfully and intentionally causes any of its representations or warranties under this Agreement to not be true and correct in all material respects as of the Closing Date. For clarity, if a Party is obligated hereunder to use its commercially reasonable efforts to perform an action or to achieve a result, the failure to use such commercially reasonable efforts would constitute a willful and intentional breach of this Agreement.

“Working Interest” with respect to any Transferred Lease or Transferred Well, means the interest in and to such Transferred Lease or Transferred Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Transferred Lease or Transferred Well, but without regard to the effect of any Burdens.

[SIGNATURE PAGE TO EXCHANGE AGREEMENT]

S-1

EX-12.1

EXHIBIT 12.1

Noble Energy, Inc.
Calculation of Ratio of Earnings to Fixed Charges
	Nine Months Ended September 30,			Year Ended December 31,
	2016			2015			2014			2013			2012
(millions)
(Loss) Income From Continuing Operations Before Income Tax and Income From Equity Investees	$	(1,301	)	$	(2,309	)	$	1,540		$	1,138		$	1,170
Add (Deduct)
Fixed Charges	331			435			349			296			288
Capitalized Interest	(70		)	(144		)	(116		)	(121		)	(151		)
Distributed Income From Equity Investees	58			77			382			204			204
Earnings as Defined	$	(982	)	$	(1,941	)	$	2,155		$	1,517		$	1,511
Net Interest Expense	242			263			210			158			125
Capitalized Interest	70			144			116			121			151
Interest Portion of Rental Expense	19			28			23			17			12
Fixed Charges as Defined	$	331		$	435		$	349		$	296		$	288
Ratio of Earnings to Fixed Charges	—			—			6.2			5.1			5.2
Amount by Which Earnings Were Insufficient to Cover Fixed Charges	$	1,313		$	2,376		$	—		$	—		$	—

EX-31.1

Exhibit 31.1

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 7241)

I, David L. Stover, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2016
/s/ David L. Stover
David L. Stover
Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 7241)

I, Kenneth M. Fisher, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 2, 2016
/s/ Kenneth M. Fisher
Kenneth M. Fisher
Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2016 (the “Report”), I, David L. Stover, Chief Executive Officer of the Company, hereby certify that to my knowledge:

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

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

Date:	November 2, 2016	/s/ David L. Stover
		David L. Stover
		Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C. Section 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2016 (the “Report”), I, Kenneth M. Fisher, Chief Financial Officer of the Company, hereby certify that to my knowledge:

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

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

Date:	November 2, 2016	/s/ Kenneth M. Fisher
		Kenneth M. Fisher
		Chief Financial Officer

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Document And Entity Information	9 Months Ended
	Sep. 30, 2016 shares
Document And Entity Information [Abstract]
Entity Registrant Name	NOBLE ENERGY INC
Entity Central Index Key	0000072207
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	429,701,812
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016

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Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016		Sep. 30, 2015
Income Statement [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		$ (143)	$ (283)	$ (745)		$ (413)
Revenues
Oil, Gas and NGL Sales		882	783	2,411		2,264
Income from Equity Method Investees		28	36	70		60
Total		910	819	2,481		2,324
Costs and Expenses
Production Expense		274	247	820		715
Exploration Expense		125	203	376		308
Depreciation, Depletion and Amortization		621	539	1,859		1,444
General and Administrative		95	109	293		308
Other Operating Expense, Net		45	188	66		310
Total		1,160	1,286	3,414		3,085
Operating Loss		(250)	(467)	(933)		(761)
Other Expense (Income)
(Gain) Loss on Commodity Derivative Instruments		(55)	(267)	53		(331)
Interest, Net of Amount Capitalized		86	71	242		183
Other Non-Operating (Income) Expense, Net		(1)	(12)	3		(20)
Total		30	(208)	298		(168)
Loss Before Income Taxes		(280)	(259)	(1,231)		(593)
Income Tax (Benefit) Provision		(137)	24	(486)		(180)
Net Income (Loss) Attributable to Noncontrolling Interest		1	0	1		0
Net Loss Including Noncontrolling Interests		$ (144)	$ (283)	$ (746)		$ (413)
Loss per share, basic (in dollars per share)		$ (0.33)	$ (0.67)	$ (1.73)	[1]	$ (1.05)
Loss per share, diluted (in dollars per share)		$ (0.33)	$ (0.67)	$ (1.73)	[1]	$ (1.05)
Weighted Average Number of Shares Outstanding
Basic (in shares)	[2]	430	420	430		392
Diluted (in shares)	[3]	430	420	430		392

[1] No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

[2] The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

[3] For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy 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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Consolidated Statements of Comprehensive Loss - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (143)	$ (283)	$ (745)	$ (413)
Net Loss Including Noncontrolling Interests	(144)	(283)	(746)	(413)
Other Items of Comprehensive Loss
Net Change in Mutual Fund Investment	0	0	0	(11)
Less Tax Expense	0	0	0	3
Net Change in Pension and Other	1	69	2	94
Less Tax Benefit	(1)	(23)	(1)	(33)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	0	46	1	53
Comprehensive Loss Including Noncontrolling Interests	(143)	(237)	(744)	(360)
Comprehensive Loss Including Noncontrolling Interests	(144)	(237)	(745)	(360)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 1	$ 0	$ 1	$ 0

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 1,819	$ 1,028
Accounts Receivable, Net	486	450
Commodity Derivative Assets	120	582
Other Current Assets	352	216
Total Current Assets	2,777	2,276
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	30,372	31,220
Property, Plant and Equipment, Other	919	858
Total Property, Plant and Equipment, Gross	31,291	32,078
Accumulated Depreciation, Depletion and Amortization	(12,186)	(10,778)
Total Property, Plant and Equipment, Net	19,105	21,300
Other Noncurrent Assets	587	620
Total Assets	22,469	24,196
Current Liabilities
Accounts Payable - Trade	786	1,128
Other Current Liabilities	742	677
Total Current Liabilities	1,528	1,805
Long-Term Debt	7,854	7,976
Deferred Income Taxes	2,103	2,826
Other Noncurrent Liabilities	1,139	1,219
Total Liabilities	12,624	13,826
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued	0	0
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 471 Million and 470 Million Shares Issued, respectively	5	5
Additional Paid in Capital	6,417	6,360
Accumulated Other Comprehensive Loss	(32)	(33)
Treasury Stock, at Cost; 38 Million Shares	(696)	(688)
Retained Earnings	3,851	4,726
Noble Energy Share of Equity	9,545	10,370
Stockholders' Equity Attributable to Noncontrolling Interest	300	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	9,845	10,370
Total Liabilities and Equity	$ 22,469	$ 24,196

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred stock, par value per share (in dollars per share)	$ 1.00	$ 1.00
Preferred stock, shares authorized (in shares)	4,000,000	4,000,000
Preferred stock, shares issued (in shares)	0	0
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000,000,000	1,000,000,000
Common stock, shares issued (in shares)	471,000,000	470,000,000
Treasury stock, shares (in shares)	38,000,000	38,000,000

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Repayments of Long-term Lines of Credit		$ 0	$ 74
Cash Flows From Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		(745)	(413)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		1,859	1,444
Asset Impairments		0	43
Results of Operations, Dry Hole Costs		105	154
Impairment of Leasehold		81	0
Gain on Extinguishment of Debt	[1]	(80)	0
Finalization of Purchase Price Allocation for Rosetta Merger		(25)	0	[2]
Loss on Asset Due to Terminated Contract	[3]	44	0
Deferred Income Tax Benefit		(699)	(244)
Loss (Gain) on Commodity Derivative Instruments		53	(331)
Net Cash Received in Settlement of Commodity Derivative Instruments		454	683
Stock Based Compensation		61	69
Non-cash Pension Termination Expense		0	81
Other Adjustments for Noncash Items Included in Income		92	74
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable		6	370
Decrease in Accounts Payable		(124)	(248)
Increase (Decrease) in Current Income Taxes Payable		82	(118)
Other Current Assets and Liabilities, Net		(72)	(28)
Other Operating Assets and Liabilities, Net		(63)	(50)
Net Cash Provided by Operating Activities		1,054	1,486
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,164)	(2,519)
Cash Acquired in Rosetta Merger		0	61
Additions to Equity Method Investments		(8)	(86)
Proceeds from Divestitures and Other		786	151
Net Cash Used in Investing Activities		(386)	(2,393)
Cash Flows From Financing Activities
Dividends Paid, Common Stock		(129)	(214)
Proceeds from Term Loan Facility		1,400	0
Repayment of Senior Notes		(1,383)
Repayment of Capital Lease Obligation		(39)	(49)
Other		(25)	(11)
Net Cash Provided by Financing Activities		123	752
Increase (Decrease) in Cash and Cash Equivalents		791	(155)
Cash and Cash Equivalents at Beginning of Period		1,028	1,183
Cash and Cash Equivalents at End of Period		1,819	1,028
Noble Energy, Inc. [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs		0	1,112
Noble Midstream Partners LP [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs			$ 0
Noble Midstream | Noble Midstream Partners LP [Member]
Cash Flows From Financing Activities
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs		$ 299

[1] Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

[2] Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

[3] Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update

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Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid in Capital	Accumulated Other Comprehensive Loss	Treasury Stock at Cost	Retained Earnings	Noncontrolling Interest [Member]
Balance at Beginning of Period at Dec. 31, 2014	$ 10,325	$ 4	$ 3,624	$ (90)	$ (671)	$ 7,458	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(413)	0	0	0	0	(413)	0
Rosetta Merger	(1,529)	(1)	(1,528)	0	0	0	0
Stock-based Compensation	69	0	69	0	0	0	0
Dividends	(214)	0	0	0	0	(214)	0
Issuance of Noble Energy Common Stock, Net of Offering Costs	1,112	0	1,112	0	0	0	0
Other	42	0	9	53	(20)	0	0
Balance at End of Period at Sep. 30, 2015	12,450	5	6,342	(37)	(691)	6,831
Balance at Beginning of Period at Dec. 31, 2015	10,370	5	6,360	(33)	(688)	4,726	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(745)	0	0	0	0	(746)	1
Stock-based Compensation	57	0		0	0	0	0
Dividends	(129)	0	0	0	0	(129)	0
Issuance of Noble Energy Common Stock, Net of Offering Costs	299	0	0	0	0	0	299
Other	(7)	0	0	1	(8)	0	0
Balance at End of Period at Sep. 30, 2016	$ 9,845	$ 5	$ 6,417	$ (32)	$ (696)	$ 3,851	$ 300

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Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Statement of Stockholders' Equity [Abstract]
Cash Dividends per share (in dollars per share)	$ 0.30	$ 0.54

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Organization and Nature of Operations

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

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 core operating areas are onshore US (DJ Basin, Marcellus Shale, Eagle Ford Shale, and Permian Basin), and offshore in deepwater Gulf of Mexico, Eastern Mediterranean and West Africa.

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Basis of Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

Presentation   The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 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. Certain prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

In third quarter 2016, Noble Midstream Partners LP (Noble Midstream), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we will be presenting our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream. Noble Midstream and the initial public offering of common units are further discussed in Note3.Noble Midstream Partners LP.

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, 2015.

Consolidation   Our consolidated accounts include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream, 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 lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream's economic performance; therefore, Noble Midstream is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream), 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. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream.

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.

Issuance of Phantom Units On February 1, 2016, we issued cash-settled awards to certain employees under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the achievement of specific performance goals. These phantom units, once vested, are settled in cash. The phantom units represent a hypothetical interest in the Company. The phantom unit value is the lesser of the fair market value of a share of common stock of the Company as of the vesting date or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.

The Company recognizes the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. As of September 30, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 8. Fair Value Measurements and Disclosures.

Recently Issued Accounting Standards 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. We are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. We are currently evaluating the effect that the guidance will have on our consolidated financial statements and related disclosures.

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. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

In July 2015,the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost or net realizable value. We follow the average cost method and do not believe adoption of ASU 2015-11 will have a material impact on our financial position and results of operations.

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, the core principle of Topic 606 is that an entity recognizes revenue to depict 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. We are continuing to evaluate the provisions of ASU 2014-09 and have not yet determined the full impact it may have on our financial position and results of operations. At a minimum, we expect we will be required to change from the entitlements method, used for certain domestic natural gas sales, to the sales method of accounting. We believe the impact of utilizing the sales method of accounting for our current domestic natural gas sales agreements will be de minimis.

In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures, to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. We do not believe adoption of this guidance will have a material impact on our consolidated financial statements and related disclosures as all material investments are accounted for under the equity method of accounting.

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 certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. 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.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, which changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. During third quarter 2016, Noble Midstream closed on its initial public offering of common units. In accordance with ASU 2015-02, Noble Midstream is considered a VIE as Noble Energy is considered the primary beneficiary. We have adopted the provisions of ASU 2015-02, which did not have a material effect on our financial statements or related disclosures.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Production Expense
Lease Operating Expense	$	131		$	133		$	412		$	419
Production and Ad Valorem Taxes	30			28			73			89
Transportation and Gathering Expense (1)	113			86			335			207
Total	$	274		$	247		$	820		$	715
Other Operating (Income) Expense, Net
(Gain) Loss on Asset Due to Terminated Contract (2)	$	(3	)	$	—		$	44		$	—
Marketing and Processing Expense, Net (3)	20			10			58			25
Loss on Divestitures	—			—			23			—
Corporate Restructuring Expense	—			21			—			39
Purchase Price Allocation Adjustment (4)	—			—			(25		)	—
Gain on Extinguishment of Debt (5)	—			—			(80		)	—
Asset Impairments	—			—			—			43
Inventory Adjustment (6)	14			—			14			—
Building Exit Cost	4			18			8			18
Rosetta Merger Expenses	—			71			—			73
Pension Plan Expense	—			67			—			88
Stacked Drilling Rig Expense	3			13			8			20
Other, Net	7			(12		)	16			4
Total	$	45		$	188		$	66		$	310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense (Income) (7)	$	2		$	(13	)	$	7		$	(19	)
Other (Income) Expense, Net	(3		)	1			(4		)	(1		)
Total	$	(1	)	$	(12	)	$	3		$	(20	)

⁽¹⁾  Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.

⁽²⁾  Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold CostsandItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update.

⁽³⁾  For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.

⁽⁴⁾  Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

⁽⁵⁾  Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

⁽⁶⁾  Amount relates to an adjustment of inventory to its net realizable value.

⁽⁷⁾  Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2016			December 31, 2015
Accounts Receivable, Net
Commodity Sales	$	317		$	298
Joint Interest Billings	66			20
Proceeds Receivable (1)	40			—
Other	86			151
Allowance for Doubtful Accounts	(23		)	(19		)
Total	$	486		$	450
Other Current Assets
Inventories, Materials and Supplies	$	75		$	92
Inventories, Crude Oil	25			23
Assets Held for Sale (2)	214			67
Prepaid Expenses and Other Current Assets	38			34
Total	$	352		$	216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries	$	460		$	453
Mutual Fund Investments	83			90
Commodity Derivative Assets	—			10
Other Assets	44			67
Total	$	587		$	620
Other Current Liabilities
Production and Ad Valorem Taxes	$	121		$	166
Commodity Derivative Liabilities	27			—
Income Taxes Payable	168			86
Asset Retirement Obligations	128			128
Interest Payable	93			83
Current Portion of Capital Lease Obligations	61			53
Other	144			161
Total	$	742		$	677
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	232		$	217
Asset Retirement Obligations	820			861
Production and Ad Valorem Taxes	35			68
Commodity Derivative Liabilities	8			—
Other	44			73
Total	$	1,139		$	1,219

⁽¹⁾  Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.

⁽²⁾  Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures.

Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream's current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas.

Initial Public Offering of Noble Midstream Partners LP On September 15, 2016, Noble Midstream common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016, Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts). 

In exchange for the contributed assets, Noble Energy received:

• 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream;

• 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream;

• incentive distribution rights in Noble Midstream; and

• the right to receive a cash distribution from Noble Midstream.

In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream, which is not entitled to receive cash distributions.

Noble Midstream generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million. In third quarter 2016, Noble Midstream made a distribution of $297 million to Noble Energy.

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Noble Midstream Partners LP

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Noble Midstream Partners LP

Basis of Presentation

Presentation   The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 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. Certain prior-period amounts have been reclassified to conform to the current period presentation. Operating results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

In third quarter 2016, Noble Midstream Partners LP (Noble Midstream), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we will be presenting our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream. Noble Midstream and the initial public offering of common units are further discussed in Note3.Noble Midstream Partners LP.

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, 2015.

Consolidation   Our consolidated accounts include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream, 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 lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream's economic performance; therefore, Noble Midstream is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream), 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. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream.

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.

Issuance of Phantom Units On February 1, 2016, we issued cash-settled awards to certain employees under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the achievement of specific performance goals. These phantom units, once vested, are settled in cash. The phantom units represent a hypothetical interest in the Company. The phantom unit value is the lesser of the fair market value of a share of common stock of the Company as of the vesting date or up to four times the fair market value of a share of common stock of the Company, which was $31.65, as of the grant date.

The Company recognizes the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation. The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. As of September 30, 2016, the fair value remeasurement had a de minimis impact on our consolidated statement of operations and balance sheet. See Note 8. Fair Value Measurements and Disclosures.

Recently Issued Accounting Standards 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. We are currently evaluating the provisions of this guidance to determine the effects it will have on our consolidated financial statements and related disclosures. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.

In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. We are currently evaluating the effect that the guidance will have on our consolidated financial statements and related disclosures.

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. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

In July 2015,the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost or net realizable value. We follow the average cost method and do not believe adoption of ASU 2015-11 will have a material impact on our financial position and results of operations.

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, the core principle of Topic 606 is that an entity recognizes revenue to depict 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. We are continuing to evaluate the provisions of ASU 2014-09 and have not yet determined the full impact it may have on our financial position and results of operations. At a minimum, we expect we will be required to change from the entitlements method, used for certain domestic natural gas sales, to the sales method of accounting. We believe the impact of utilizing the sales method of accounting for our current domestic natural gas sales agreements will be de minimis.

In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures, to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. We do not believe adoption of this guidance will have a material impact on our consolidated financial statements and related disclosures as all material investments are accounted for under the equity method of accounting.

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 certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. 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.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, which changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. During third quarter 2016, Noble Midstream closed on its initial public offering of common units. In accordance with ASU 2015-02, Noble Midstream is considered a VIE as Noble Energy is considered the primary beneficiary. We have adopted the provisions of ASU 2015-02, which did not have a material effect on our financial statements or related disclosures.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Production Expense
Lease Operating Expense	$	131		$	133		$	412		$	419
Production and Ad Valorem Taxes	30			28			73			89
Transportation and Gathering Expense (1)	113			86			335			207
Total	$	274		$	247		$	820		$	715
Other Operating (Income) Expense, Net
(Gain) Loss on Asset Due to Terminated Contract (2)	$	(3	)	$	—		$	44		$	—
Marketing and Processing Expense, Net (3)	20			10			58			25
Loss on Divestitures	—			—			23			—
Corporate Restructuring Expense	—			21			—			39
Purchase Price Allocation Adjustment (4)	—			—			(25		)	—
Gain on Extinguishment of Debt (5)	—			—			(80		)	—
Asset Impairments	—			—			—			43
Inventory Adjustment (6)	14			—			14			—
Building Exit Cost	4			18			8			18
Rosetta Merger Expenses	—			71			—			73
Pension Plan Expense	—			67			—			88
Stacked Drilling Rig Expense	3			13			8			20
Other, Net	7			(12		)	16			4
Total	$	45		$	188		$	66		$	310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense (Income) (7)	$	2		$	(13	)	$	7		$	(19	)
Other (Income) Expense, Net	(3		)	1			(4		)	(1		)
Total	$	(1	)	$	(12	)	$	3		$	(20	)

⁽¹⁾  Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.

⁽²⁾  Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold CostsandItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update.

⁽³⁾  For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.

⁽⁴⁾  Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

⁽⁵⁾  Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

⁽⁶⁾  Amount relates to an adjustment of inventory to its net realizable value.

⁽⁷⁾  Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2016			December 31, 2015
Accounts Receivable, Net
Commodity Sales	$	317		$	298
Joint Interest Billings	66			20
Proceeds Receivable (1)	40			—
Other	86			151
Allowance for Doubtful Accounts	(23		)	(19		)
Total	$	486		$	450
Other Current Assets
Inventories, Materials and Supplies	$	75		$	92
Inventories, Crude Oil	25			23
Assets Held for Sale (2)	214			67
Prepaid Expenses and Other Current Assets	38			34
Total	$	352		$	216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries	$	460		$	453
Mutual Fund Investments	83			90
Commodity Derivative Assets	—			10
Other Assets	44			67
Total	$	587		$	620
Other Current Liabilities
Production and Ad Valorem Taxes	$	121		$	166
Commodity Derivative Liabilities	27			—
Income Taxes Payable	168			86
Asset Retirement Obligations	128			128
Interest Payable	93			83
Current Portion of Capital Lease Obligations	61			53
Other	144			161
Total	$	742		$	677
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	232		$	217
Asset Retirement Obligations	820			861
Production and Ad Valorem Taxes	35			68
Commodity Derivative Liabilities	8			—
Other	44			73
Total	$	1,139		$	1,219

⁽¹⁾  Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.

⁽²⁾  Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures.

Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream's current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas.

Initial Public Offering of Noble Midstream Partners LP On September 15, 2016, Noble Midstream common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016, Noble Midstream completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts). 

In exchange for the contributed assets, Noble Energy received:

• 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream;

• 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream;

• incentive distribution rights in Noble Midstream; and

• the right to receive a cash distribution from Noble Midstream.

In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream, which is not entitled to receive cash distributions.

Noble Midstream generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million. In third quarter 2016, Noble Midstream made a distribution of $297 million to Noble Energy.

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Rosetta Merger Rosetta Merger

9 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Rosetta Merger

Rosetta Merger

On July 20, 2015, Noble Energy completed the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statements of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta common stock using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs in 2015 of approximately $81 million, including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and were included in Other Operating (Income) Expense, Net.

Allocation of Purchase Price The merger has been accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair value at the merger date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.

The following table sets forth our final purchase price allocation:

	(in millions, except stock price)
Shares of Noble Energy common stock issued to Rosetta shareholders	41
Noble Energy common stock price on July 20, 2015	$	36.97
Fair value of common stock issued	$	1,518
Plus: Fair value of Rosetta's restricted stock awards and performance awards assumed	10
Plus: Rosetta stock options assumed	1
Total purchase price	1,529
Plus: Liabilities assumed by Noble Energy
Accounts Payable	100
Current Liabilities	37
Long-Term Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	$	3,708
Fair Value of Rosetta Assets
Cash and Equivalents	$	61
Other Current Assets	76
Derivative Instruments	209
Oil and Gas Properties
Proved Reserves	1,613
Undeveloped Leaseholds	1,355
Gathering & Processing Assets	207
Asset Retirement Obligation	27
Other Property Plant and Equipment	5
Long Term Deferred Tax Asset	17
Goodwill (1)	138
Total Asset Value	$	3,708

⁽¹⁾  As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. 

The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. 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. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.

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

The results of operations attributable to Rosetta are included in our consolidated statements of operations beginning on July 21, 2015. Revenues of $119 million and $333 million and pre-tax net loss of $4 million and $17 million were generated from Rosetta assets during the three and nine months ended September 30, 2016, respectively.

Proforma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) adjustments to conform Rosetta's historical policy of accounting for its crude oil and natural gas properties from the full cost method to the successful efforts method of accounting, (ii) depletion of Rosetta's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share amounts)	2016 (1)			2015			2016 (1)			2015
Revenues	$	910		$	846		$	2,481		$	2,619
Net Loss Attributable to Noble Energy	$	(144	)	$	(202	)	$	(746	)	$	(338	)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Basic	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)
Diluted	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)

⁽¹⁾  No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

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Divestitures

9 Months Ended

Sep. 30, 2016

Divestitures [Abstract]

Divestitures

Divestitures

Onshore US Properties During the first nine months of 2016, we entered into certain onshore transactions for which we:

• entered into a purchase and sale agreement for the divestiture of certain producing and non-producing crude oil and natural gas interests covering approximately 33,100 net acres in the DJ Basin for $505 million, subject to customary closing adjustments. We have received proceeds of $486 million and expect to receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss;

• closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43 million, and recognized a $23 million loss on sale of assets;

• closed a cashless acreage exchange within the DJ Basin to receive approximately 11,700 net acres within our Wells Ranch development area of the field in exchange for approximately 13,500 net acres primarily from our Bronco area of the field. No gain or loss was recognized for the transaction; and

• sold certain other non-producing interests within the DJ Basin, generating net proceeds of $20 million, and other certain smaller onshore US property packages, resulting in net proceeds of $19 million, during the first nine months of 2016. Proceeds received were applied to the respective field's basis with no recognition of gain or loss.

Subsequent to third quarter 2016, we closed the divestiture of certain Eagle Ford assets that were classified as assets held for sale of $68 million as of September 30, 2016. Total proceeds received will be applied to the field's basis with no recognition of gain or loss.

During the first nine months of 2015, we sold certain onshore US crude oil and natural gas interests in the DJ Basin, generating net proceeds of $151 million. Proceeds were applied to the field's basis with no recognition of gain or loss.

Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. In first quarter 2016, we received proceeds of $131 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. The proceeds were applied to the Cyprus project asset with no gain or loss recognized.

Offshore Israel Assets On July 4, 2016, we signed a definitive agreement to divest a 3% working interest in the Tamar field, offshore Israel, for $369 million, subject to customary closing adjustments. Under the terms of the agreement, the purchaser has the option to elect, before closing, to purchase an additional 1% working interest at the same valuation. The divestiture has an effective date of January 1, 2016 and is expected to close in fourth quarter 2016.

In November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, for a total transaction value of $73 million. These assets were held for sale as of December 31, 2015, and the transaction closed in January 2016.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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

Unsettled Commodity Derivative Instruments   As of September 30, 2016, 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
2016	Call Option (1)	NYMEX WTI	5,000	$	—	$	—	$	—	$	54.16
2016	Swaps	NYMEX WTI	16,000	67.69		—		—		—
2016	Swaps (2)	(3)	6,000	90.28		—		—		—
2016	Two-Way Collars	NYMEX WTI	10,000	—		—		40.50		53.42
2016	Three-Way Collars	NYMEX WTI	8,000	—		54.50		65.63		79.03
2016	Swaps	Dated Brent	9,000	97.96		—		—		—
2016	Three-Way Collars	Dated Brent	8,000	—		72.50		86.25		101.79
1H17 (4)	Swaps	NYMEX WTI	6,000	55.08		—		—		—
1H17 (4)	Two-Way Collars	NYMEX WTI	2,000	—		—		40.00		50.44
1H17 (4)	Swaps	Dated Brent	3,000	62.80		—		—		—
2H17 (4)	Call Option (1)	NYMEX WTI	3,000	—		—		—		60.12
2H17 (4)	Swaptions (5)	Dated Brent	3,000	—		—		—		62.80
2H17 (4)	Swaptions (5)	NYMEX WTI	3,000	—		—		—		50.05
2017	Two-Way Collars	NYMEX WTI	7,000	—		—		40.00		53.29
2017	Call Option (1)	NYMEX WTI	3,000	—		—		—		57.00
2017	Swaptions (5)	NYMEX WTI	4,000	—		—		—		47.34
2017	Three-Way Collars	NYMEX WTI	15,000	—		36.33		46.33		60.68
2017	Three-Way Collars	Dated Brent	2,000	—		35.00		45.00		66.33
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⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽³⁾  The indices for these derivative instruments are NYMEX WTI and Argus LLS.

⁽⁴⁾  We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year.

⁽⁵⁾  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.

As of September 30, 2016, 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
2016	Swaps	NYMEX HH	70,000	3.24	—	—	—
2016	Two-Way Collars	NYMEX HH	30,000	—	—	3.00	3.50
2016	Three-Way Collars	NYMEX HH	90,000	—	2.83	3.42	3.90
2016	Swaps (1)	(2)	30,000	4.04	—	—	—
2016	Two-Way Collars (1)	(2)	30,000	—	—	3.50	5.60
1H17	Swaps	NYMEX HH	30,000	2.92	—	—	—
2H17	Swaptions (3)	NYMEX HH	30,000	—	—	—	2.92
2017	Swaps	NYMEX HH	30,000	3.15	—	—	—
2017	Swaptions (3)	NYMEX HH	60,000	—	—	—	3.14
2017	Three-Way Collars	NYMEX HH	180,000	—	2.50	2.93	3.58
2017	Two-Way Collars	NYMEX HH	70,000	—	—	2.93	3.32
2018	Three-Way Collars	NYMEX HH	70,000	—	2.50	2.80	3.76

⁽¹⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽²⁾  The index for these derivative instruments is Houston Ship Channel.

⁽³⁾  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 Loss (Gain) 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
	September 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity DerivativeInstruments	Current Assets	$	120	Current Assets	$	582	Current Liabilities	$	27	Current Liabilities	$	—
	Noncurrent Assets	—		Noncurrent Assets	10		Noncurrent Liabilities	8		Noncurrent Liabilities	—
Total		$	120		$	592		$	35		$	—

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Cash Received in Settlement of Commodity Derivative Instruments
Crude Oil	$	(119	)	$	(235	)	$	(395	)	$	(578	)
Natural Gas	(13		)	(42		)	(59		)	(98		)
NGLs	—			(7		)	—			(7		)
Total Cash Received in Settlement of Commodity Derivative Instruments	(132		)	(284		)	(454		)	(683		)
Non-cash Portion of Loss on Commodity Derivative Instruments
Crude Oil	80			4			441			301
Natural Gas	(3		)	3			66			41
NGLs	—			10			—			10
Total Non-cash Portion of Loss on Commodity Derivative Instruments	77			17			507			352
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(39		)	(231		)	46			(277		)
Natural Gas	(16		)	(39		)	7			(57		)
NGLs	—			3			—			3
Total Loss (Gain) on Commodity Derivative Instruments	$	(55	)	$	(267	)	$	53		$	(331	)

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Debt

9 Months Ended

Sep. 30, 2016

Debt [Abstract]

Debt

Debt

Debt consists of the following:

	September 30, 2016					December 31, 2015
(millions, except percentages)	Debt			Interest Rate		Debt				Interest Rate
Revolving Credit Facility, due August 27, 2020	$	—		—	%	$	—			—	%
Noble Midstream Revolving Credit Facility, due September 20, 2021	—			—	%	—			—	—	%
Capital Lease and Other Obligations	368			—	%	403				—	%
Term Loan Facility, due January 6, 2019	1,400			1.70	%	—				—	%
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	%	693				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	%	597				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	%	499				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	%
Total	7,957					7,976
Unamortized Discount	(23		)			(24		)
Unamortized Premium	17					113
Unamortized Debt Issuance Costs	(36		)			(36		)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	7,915					8,029
Less Amounts Due Within One Year
Capital Lease Obligations	(61		)			(53		)
Long-Term Debt Due After One Year	$	7,854				$	7,976

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, and (iii) includes a sub-limit for letters of credit up to an aggregate amount of $500 million ($450 million of this capacity is committed as of September 30, 2016).

Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services, a subsidiary of Noble Midstream, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Revolving Credit Facility). The Noble Midstream Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Revolving Credit Facility may be increased by an additional $350 million subject to certain conditions and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream.

Borrowings by Noble Midstream under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream's option, either:

• 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

• in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

The Noble Midstream Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated EBITDA and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Revolving Credit Facility, are guaranteed by Noble Midstream and all wholly-owned material subsidiaries of Noble Midstream.

Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three-year term loan facility for a principal amount of $1.4 billion. Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility will accrue 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) a London interbank offered rate plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a London interbank offered rate, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 1.70% as of September 30, 2016.

In connection with the Term Loan Facility, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.38 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations.

Subsequent Event On November 1, 2016, we prepaid $850 million of borrowings under our Term Loan Facility from cash on hand.

See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.

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Fair Value Measurements and Disclosures

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements and Disclosures

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 6. 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.

Phantom Units The fair value of phantom unit awards is measured based on the fair market value of our common stock on the date of grant. We recognize the value of these awards utilizing the liability method whereby these liability awards are remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 2. Basis of Presentation.

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)
September 30, 2016
Financial Assets
Mutual Fund Investments	$	83		$	—		$	—	$	—		$	83
Commodity Derivative Instruments	—			133			—		(13		)	120
Financial Liabilities
Commodity Derivative Instruments	—			(48		)	—		13			(35		)
Portion of Deferred Compensation Liability Measured at Fair Value	(105		)	—			—		—			(105		)
Portion of Stock Based Compensation Liability Measured at Fair Value	(6		)	—			—		—			(6		)
December 31, 2015
Financial Assets
Mutual Fund Investments	$	90		$	—		$	—	$	—		$	90
Commodity Derivative Instruments	—			600			—		(8		)	592
Financial Liabilities
Commodity Derivative Instruments	—			(8		)	—		8			—
Portion of Deferred Compensation Liability Measured at Fair Value	(98		)	—			—		—			(98		)

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

Inventory Adjustment Materials and supplies inventories are stated at the lower of cost or net realizable value. For the nine months ended September 30, 2016, we recorded a downward adjustment of $14 million to reduce inventory to its estimated net realizable value.

Asset Impairments  We periodically evaluate our oil and gas properties for impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. In line with accounting standards, we use an undiscounted cash flow model as an indicator of possible impairment. Where circumstances warrant, we use a discounted cash flow model based on management’s expectations of future production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent futures price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate. For the nine months ended September 30, 2016, no impairment was indicated. Impairments for the nine months ended September 30, 2015 were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs.

Assets Held for Sale In cases where assets meet the criteria to be classified as assets held for sale and a loss is expected, the underlying assets are written down to fair value less costs to sell. For the nine months ended September 30, 2016, we recorded a downward adjustment of $23 million to reflect the loss on divestiture of our Bowdoin property in northern Montana. See Note 4. Divestitures.

Information about impaired assets is as follows:

	Fair Value Measurements Using
	Quoted Prices in  Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Book Value (1)		Total Pre-tax (Non-cash) Impairment Loss
(millions)
Nine Months Ended September 30, 2016
Material and Supplies Inventory Adjustment	$	—	$	—	$	91	$	105	$	14
Loss on Divestitures	—		—		42		65		23
Impaired Oil and Gas Properties	—		—		—		—		—
Nine Months Ended September 30, 2015
Impaired Oil and Gas Properties	—		—		—		43		43

⁽¹⁾  Amount represents net book value at the date of assessment.

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 7. Debt.

Fair value information regarding our debt is as follows:

	September 30, 2016				December 31, 2015
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt, Net (1)	$	7,547	$	7,976	$	7,626	$	7,105

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

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

9 Months Ended

Sep. 30, 2016

Capitalized Exploratory Well Costs [Abstract]

Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

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)	Nine Months Ended September 30, 2016
Capitalized Exploratory Well Costs, Beginning of Period	$	1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	83
Divestitures and Other (1)	(143		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(1		)
Capitalized Exploratory Well Costs Charged to Expense (2)	(83		)
Capitalized Exploratory Well Costs, End of Period	$	1,209

⁽¹⁾  Includes $143 million relating to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.

⁽²⁾  Includes amounts related to contract termination offshore Falkland Islands, Dolphin 1 exploratory well offshore Israel, and Silvergate exploratory well deepwater Gulf of Mexico.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: 

(millions)	September 30, 2016		December 31, 2015
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	91	$	95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	1,118		1,258
Balance at End of Period	$	1,209	$	1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	13		14

The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of September 30, 2016:

(millions)	Total by Project		Progress
Country/Project:
Deepwater Gulf of Mexico
Troubadour	$	52	Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
Katmai	97		Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options.
Offshore Equatorial Guinea Blocks I and O
Diega (Block I) and Carmen (Block O)	240		Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Carla (Block O)	184		Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Yolanda (Block I)	22		A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries.
Felicita (Block O)	45		Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Offshore Cameroon
YoYo (YoYo Block)	53		A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries.
Offshore Israel
Leviathan	196		Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands.
Leviathan-1 Deep	84		The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
Dalit	31		Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar.
Offshore Cyprus

Cyprus	88		During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision.
Other
Individual Projects Less than $20 million	26		Continuing to assess and evaluate wells.
Total	$	1,118

Undeveloped Leasehold Costs

Undeveloped leasehold costs as of September 30, 2016 totaled $2.0 billion, comprising $1.9 billion related to core onshore US unproved properties, $116 million related to Gulf of Mexico unproved properties, and $32 million related to international unproved properties.

As part of our quarterly impairment review, we evaluate our exploration opportunities. 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 either (1) impairment expense related to individually significant leases or (2) a decrease in the valuation of our pool of individually insignificant leases.

During third quarter 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico and offshore Falkland Islands leases and licenses and determined that several, representing $105 million of undeveloped leasehold cost, should be relinquished or exited. As a result, we recognized $81 million of leasehold impairment expense and recorded a $24 million decrease in our valuation pool of individually insignificant leases.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

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

	Nine Months Ended September 30,
(millions)	2016			2015
Asset Retirement Obligations, Beginning Balance	$	989		$	751
Liabilities Incurred	5			54
Liabilities Settled	(87		)	(29		)
Revision of Estimate	4			79
Accretion Expense (1)	37			32
Asset Retirement Obligations, Ending Balance	$	948		$	887

⁽¹⁾  Accretion expense is included in Depreciation, Depletion and Amortization (DD&A)expense in the consolidated statements ofoperations.

For the nine months ended September 30, 2016Liabilities incurred were due to new wells and facilities placed into service for onshore US and deepwater Gulf of Mexico. Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful life and primarily included activities for Gulf of Mexico of $42 million and onshore US of $40 million.

For thenine months ended September 30, 2015 Liabilities incurred were due to new wells and facilities for onshore US and deepwater Gulf of Mexico as well as liabilities assumed in the Rosetta Merger. Liabilities settled primarily related to non-core, onshore US properties sold.

Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing of abandonment and included $43 million for Eastern Mediterranean and $28 million for DJ Basin.

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Loss Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Loss Per Share

Loss Per Share

Noble Energy's basic loss per share of common stock is computed by using net 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 loss per share:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except per share amounts)	2016			2015			2016			2015
Net Loss Attributable to Noble Energy	$	(144	)	$	(283	)	$	(746	)	$	(413	)
Weighted Average Number of Shares Outstanding, Basic (1)	430			420			430			392
Weighted Average Number of Shares Outstanding, Diluted(2)	430			420			430			392
Loss Per Share, Basic	$	(0.33	)	$	(0.67	)	$	(1.73	)	$	(1.05	)
Loss Per Share, Diluted	(0.33		)	(0.67		)	(1.73		)	(1.05		)
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14			14			15			11

⁽¹⁾  The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

⁽²⁾  For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy 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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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The income tax benefit consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Current	$	148		$	(45	)	$	213		$	64
Deferred	(285		)	69			(699		)	(244		)
Total Income Tax (Benefit) Provision	$	(137	)	$	24		$	(486	)	$	(180	)
Effective Tax Rate	48.9		%	(9.3		)%	39.5		%	30.4		%

Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2015, we no longer consider our foreign subsidiaries’ undistributed earnings to be indefinitely reinvested outside the US and, accordingly, we now record additional deferred income taxes, net of estimated foreign tax credits.

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 and nine months ended September 30, 2016, varied as compared with the three and nine months ended September 30, 2015, resulting in a higher income tax benefit and ETR primarily due to:

• a higher loss before income taxes for the first nine months of 2016 as compared with the first nine months of 2015;

• a period to period shift of the individual components of net income (loss) among tax jurisdictions with different rates, which is also impacted by the timing and magnitude of divestiture activities. See Note 4. Divestituresand Note 13. Segment Information; and

• the change in our permanent reinvestment assumption, noted above, which resulted in additional deferred income tax expense (net of estimated foreign tax credits) being recorded on certain income items, including income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, which reduced the income tax benefit.

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

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Segment Information

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Information

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); West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we exited in second quarter 2015)); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, Falkland Islands, Suriname, Nicaragua (which we exited in first quarter 2015) and new ventures.

(millions)	Consolidated			United States			West Africa			Eastern Mediterranean		Other Int'l & Corporate
Three Months Ended September 30, 2016
Revenues from Third Parties	$	882		$	639		$	93		$	150	$	—
Income from Equity Method Investees	28			8			20			—		—
Total Revenues	910			647			113			150		—
DD&A	621			539			46			23		13
Gain on Commodity Derivative Instruments	(55		)	(48		)	(7		)	—		—
(Loss) Income Before Income Taxes	(280		)	(407		)	47			135		(55		)
Three Months Ended September 30, 2015
Revenues from Third Parties	$	783		$	510		$	120		$	152	$	1
Income from Equity Method Investees	36			16			20			—		—
Total Revenues	819			526			140			152		1
DD&A	539			437			67			22		13
Gain on Commodity Derivative Instruments	(267		)	(187		)	(80		)	—		—
(Loss) Income Before Income Taxes	(259		)	(189		)	98			107		(275		)
Nine Months Ended September 30, 2016
Revenues from Third Parties	$	2,411		$	1,705		$	299		$	407	$	—
Income from Equity Method Investees	70			39			31			—		—
Total Revenues	2,481			1,744			330			407		—
DD&A	1,859			1,612			150			62		35
Loss on Divestitures	23			23			—			—		—
Loss on Commodity Derivative Instruments	53			44			9			—		—
(Loss) Income Before Income Taxes	(1,231		)	(882		)	74			290		(713		)
Nine Months Ended September 30, 2015
Revenues from Third Parties	$	2,264		$	1,448		$	432		$	378	$	6
Income from Equity Method Investees	60			35			25			—		—
Total Revenues	2,324			1,483			457			378		6
DD&A	1,444			1,138			223			52		31
Gain on Commodity Derivative Instruments	(331		)	(231		)	(100		)	—		—
(Loss) Income Before Income Taxes	(593		)	(353		)	195			227		(662		)
September 30, 2016
Total Assets	$	22,469		$	17,752		$	1,975		$	2,515	$	227
December 31, 2015
Total Assets	24,196			18,831			2,299			2,677		389

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at September 30, 2016.

The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. The funding has been suspended since November 2014 due to lower natural gas prices. Based on the September 30, 2016 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months.

On October 29, 2016, we entered into an agreement with CONSOL to separate ownership of our jointly owned Marcellus Shale acreage, satisfy and extinguish the remaining balance of our carried cost obligation and terminate the joint development agreement. See Part II. Other Information, Item 5. Other Information.

Delivery and Firm Transportation Commitments We have commitments to deliver approximately 493 Bcf of natural gas produced onshore US (primarily in the Marcellus Shale) under long-term sales contracts and have also entered into various long-term gathering, processing and transportation contracts for approximately 271 MMBbls of crude oil and nearly 6 Tcf of natural gas for certain of our onshore US production (primarily in the Marcellus Shale, DJ Basin and Eagle Ford Shale).

We enter into long-term contracts to provide production flow assurance in over-supplied basins and/or areas with limited infrastructure. This strategy provides for optimization of transportation and processing costs. As properties are undergoing development activities, we may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. For the three and nine months ended September 30, 2016, we incurredexpense of approximately $12 million and $39 million, respectively, related to deficiencies and/or unutilized commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. Should commodity prices continue to 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.

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 not yet precisely quantifiable as they will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.

Compliance with the Consent Decree could result in the temporary shut in or 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. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.  Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.     

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 Air Compliance Order on Consent  In December 2015, 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 certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions that applied to assets currently owned and operated by both Noble Energy and Noble Midstream Services, LLC.  In May, 2016, Noble Energy on behalf of itself and its wholly owned subsidiary Noble Midstream Services, LLC, on behalf of itself and its wholly owned subsidiary Colorado River DevCo LP, reached a final resolution with the APCD, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695, and an expenditure of no less than $178,780 on an approved SEP. This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows.

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Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Statement of Operations Information

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Production Expense
Lease Operating Expense	$	131		$	133		$	412		$	419
Production and Ad Valorem Taxes	30			28			73			89
Transportation and Gathering Expense (1)	113			86			335			207
Total	$	274		$	247		$	820		$	715
Other Operating (Income) Expense, Net
(Gain) Loss on Asset Due to Terminated Contract (2)	$	(3	)	$	—		$	44		$	—
Marketing and Processing Expense, Net (3)	20			10			58			25
Loss on Divestitures	—			—			23			—
Corporate Restructuring Expense	—			21			—			39
Purchase Price Allocation Adjustment (4)	—			—			(25		)	—
Gain on Extinguishment of Debt (5)	—			—			(80		)	—
Asset Impairments	—			—			—			43
Inventory Adjustment (6)	14			—			14			—
Building Exit Cost	4			18			8			18
Rosetta Merger Expenses	—			71			—			73
Pension Plan Expense	—			67			—			88
Stacked Drilling Rig Expense	3			13			8			20
Other, Net	7			(12		)	16			4
Total	$	45		$	188		$	66		$	310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense (Income) (7)	$	2		$	(13	)	$	7		$	(19	)
Other (Income) Expense, Net	(3		)	1			(4		)	(1		)
Total	$	(1	)	$	(12	)	$	3		$	(20	)

⁽¹⁾  Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.

⁽²⁾  Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold CostsandItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update.

⁽³⁾  For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.

⁽⁴⁾  Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

⁽⁵⁾  Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

⁽⁶⁾  Amount relates to an adjustment of inventory to its net realizable value.

⁽⁷⁾  Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.

Balance Sheet Information Table

Balance Sheet Information   Other balance sheet information is as follows:

(millions)	September 30, 2016			December 31, 2015
Accounts Receivable, Net
Commodity Sales	$	317		$	298
Joint Interest Billings	66			20
Proceeds Receivable (1)	40			—
Other	86			151
Allowance for Doubtful Accounts	(23		)	(19		)
Total	$	486		$	450
Other Current Assets
Inventories, Materials and Supplies	$	75		$	92
Inventories, Crude Oil	25			23
Assets Held for Sale (2)	214			67
Prepaid Expenses and Other Current Assets	38			34
Total	$	352		$	216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries	$	460		$	453
Mutual Fund Investments	83			90
Commodity Derivative Assets	—			10
Other Assets	44			67
Total	$	587		$	620
Other Current Liabilities
Production and Ad Valorem Taxes	$	121		$	166
Commodity Derivative Liabilities	27			—
Income Taxes Payable	168			86
Asset Retirement Obligations	128			128
Interest Payable	93			83
Current Portion of Capital Lease Obligations	61			53
Other	144			161
Total	$	742		$	677
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	232		$	217
Asset Retirement Obligations	820			861
Production and Ad Valorem Taxes	35			68
Commodity Derivative Liabilities	8			—
Other	44			73
Total	$	1,139		$	1,219

⁽¹⁾  Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.

⁽²⁾  Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures

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Rosetta Merger Rosetta Merger (Tables)

9 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Schedule of purchase price allocations

The following table sets forth our final purchase price allocation:

	(in millions, except stock price)
Shares of Noble Energy common stock issued to Rosetta shareholders	41
Noble Energy common stock price on July 20, 2015	$	36.97
Fair value of common stock issued	$	1,518
Plus: Fair value of Rosetta's restricted stock awards and performance awards assumed	10
Plus: Rosetta stock options assumed	1
Total purchase price	1,529
Plus: Liabilities assumed by Noble Energy
Accounts Payable	100
Current Liabilities	37
Long-Term Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	$	3,708
Fair Value of Rosetta Assets
Cash and Equivalents	$	61
Other Current Assets	76
Derivative Instruments	209
Oil and Gas Properties
Proved Reserves	1,613
Undeveloped Leaseholds	1,355
Gathering & Processing Assets	207
Asset Retirement Obligation	27
Other Property Plant and Equipment	5
Long Term Deferred Tax Asset	17
Goodwill (1)	138
Total Asset Value	$	3,708

⁽¹⁾  As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. 

Schedule of pro forma information

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share amounts)	2016 (1)			2015			2016 (1)			2015
Revenues	$	910		$	846		$	2,481		$	2,619
Net Loss Attributable to Noble Energy	$	(144	)	$	(202	)	$	(746	)	$	(338	)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Basic	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)
Diluted	$	(0.33	)	$	(0.44	)	$	(1.73	)	$	(0.79	)

⁽¹⁾  No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Unsettled Derivative Instruments

Unsettled Commodity Derivative Instruments   As of September 30, 2016, 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
2016	Call Option (1)	NYMEX WTI	5,000	$	—	$	—	$	—	$	54.16
2016	Swaps	NYMEX WTI	16,000	67.69		—		—		—
2016	Swaps (2)	(3)	6,000	90.28		—		—		—
2016	Two-Way Collars	NYMEX WTI	10,000	—		—		40.50		53.42
2016	Three-Way Collars	NYMEX WTI	8,000	—		54.50		65.63		79.03
2016	Swaps	Dated Brent	9,000	97.96		—		—		—
2016	Three-Way Collars	Dated Brent	8,000	—		72.50		86.25		101.79
1H17 (4)	Swaps	NYMEX WTI	6,000	55.08		—		—		—
1H17 (4)	Two-Way Collars	NYMEX WTI	2,000	—		—		40.00		50.44
1H17 (4)	Swaps	Dated Brent	3,000	62.80		—		—		—
2H17 (4)	Call Option (1)	NYMEX WTI	3,000	—		—		—		60.12
2H17 (4)	Swaptions (5)	Dated Brent	3,000	—		—		—		62.80
2H17 (4)	Swaptions (5)	NYMEX WTI	3,000	—		—		—		50.05
2017	Two-Way Collars	NYMEX WTI	7,000	—		—		40.00		53.29
2017	Call Option (1)	NYMEX WTI	3,000	—		—		—		57.00
2017	Swaptions (5)	NYMEX WTI	4,000	—		—		—		47.34
2017	Three-Way Collars	NYMEX WTI	15,000	—		36.33		46.33		60.68
2017	Three-Way Collars	Dated Brent	2,000	—		35.00		45.00		66.33
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⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽³⁾  The indices for these derivative instruments are NYMEX WTI and Argus LLS.

⁽⁴⁾  We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year.

⁽⁵⁾  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.

As of September 30, 2016, 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
2016	Swaps	NYMEX HH	70,000	3.24	—	—	—
2016	Two-Way Collars	NYMEX HH	30,000	—	—	3.00	3.50
2016	Three-Way Collars	NYMEX HH	90,000	—	2.83	3.42	3.90
2016	Swaps (1)	(2)	30,000	4.04	—	—	—
2016	Two-Way Collars (1)	(2)	30,000	—	—	3.50	5.60
1H17	Swaps	NYMEX HH	30,000	2.92	—	—	—
2H17	Swaptions (3)	NYMEX HH	30,000	—	—	—	2.92
2017	Swaps	NYMEX HH	30,000	3.15	—	—	—
2017	Swaptions (3)	NYMEX HH	60,000	—	—	—	3.14
2017	Three-Way Collars	NYMEX HH	180,000	—	2.50	2.93	3.58
2017	Two-Way Collars	NYMEX HH	70,000	—	—	2.93	3.32
2018	Three-Way Collars	NYMEX HH	70,000	—	2.50	2.80	3.76

⁽¹⁾  Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

⁽²⁾  The index for these derivative instruments is Houston Ship Channel.

⁽³⁾  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 of Derivative Instruments

Fair Value Amounts and Loss (Gain) 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
	September 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
(millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity DerivativeInstruments	Current Assets	$	120	Current Assets	$	582	Current Liabilities	$	27	Current Liabilities	$	—
	Noncurrent Assets	—		Noncurrent Assets	10		Noncurrent Liabilities	8		Noncurrent Liabilities	—
Total		$	120		$	592		$	35		$	—

Derivative Instruments, (Gain) Loss

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Cash Received in Settlement of Commodity Derivative Instruments
Crude Oil	$	(119	)	$	(235	)	$	(395	)	$	(578	)
Natural Gas	(13		)	(42		)	(59		)	(98		)
NGLs	—			(7		)	—			(7		)
Total Cash Received in Settlement of Commodity Derivative Instruments	(132		)	(284		)	(454		)	(683		)
Non-cash Portion of Loss on Commodity Derivative Instruments
Crude Oil	80			4			441			301
Natural Gas	(3		)	3			66			41
NGLs	—			10			—			10
Total Non-cash Portion of Loss on Commodity Derivative Instruments	77			17			507			352
(Gain) Loss on Commodity Derivative Instruments
Crude Oil	(39		)	(231		)	46			(277		)
Natural Gas	(16		)	(39		)	7			(57		)
NGLs	—			3			—			3
Total Loss (Gain) on Commodity Derivative Instruments	$	(55	)	$	(267	)	$	53		$	(331	)

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Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt [Abstract]

Schedule of debt

Debt consists of the following:

	September 30, 2016					December 31, 2015
(millions, except percentages)	Debt			Interest Rate		Debt				Interest Rate
Revolving Credit Facility, due August 27, 2020	$	—		—	%	$	—			—	%
Noble Midstream Revolving Credit Facility, due September 20, 2021	—			—	%	—			—	—	%
Capital Lease and Other Obligations	368			—	%	403				—	%
Term Loan Facility, due January 6, 2019	1,400			1.70	%	—				—	%
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	%	693				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	%	597				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	%	499				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	%
Total	7,957					7,976
Unamortized Discount	(23		)			(24		)
Unamortized Premium	17					113
Unamortized Debt Issuance Costs	(36		)			(36		)
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs	7,915					8,029
Less Amounts Due Within One Year
Capital Lease Obligations	(61		)			(53		)
Long-Term Debt Due After One Year	$	7,854				$	7,976

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Fair Value Measurements and Disclosures (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

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

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)
September 30, 2016
Financial Assets
Mutual Fund Investments	$	83		$	—		$	—	$	—		$	83
Commodity Derivative Instruments	—			133			—		(13		)	120
Financial Liabilities
Commodity Derivative Instruments	—			(48		)	—		13			(35		)
Portion of Deferred Compensation Liability Measured at Fair Value	(105		)	—			—		—			(105		)
Portion of Stock Based Compensation Liability Measured at Fair Value	(6		)	—			—		—			(6		)
December 31, 2015
Financial Assets
Mutual Fund Investments	$	90		$	—		$	—	$	—		$	90
Commodity Derivative Instruments	—			600			—		(8		)	592
Financial Liabilities
Commodity Derivative Instruments	—			(8		)	—		8			—
Portion of Deferred Compensation Liability Measured at Fair Value	(98		)	—			—		—			(98		)

⁽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.

Fair Value Measurements, Nonrecurring

Information about impaired assets is as follows:

	Fair Value Measurements Using
	Quoted Prices in  Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Book Value (1)		Total Pre-tax (Non-cash) Impairment Loss
(millions)
Nine Months Ended September 30, 2016
Material and Supplies Inventory Adjustment	$	—	$	—	$	91	$	105	$	14
Loss on Divestitures	—		—		42		65		23
Impaired Oil and Gas Properties	—		—		—		—		—
Nine Months Ended September 30, 2015
Impaired Oil and Gas Properties	—		—		—		43		43

⁽¹⁾  Amount represents net book value at the date of assessment.

Additional fair value disclosures

Fair value information regarding our debt is as follows:

	September 30, 2016				December 31, 2015
(millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt, Net (1)	$	7,547	$	7,976	$	7,626	$	7,105

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

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables)

9 Months Ended

Sep. 30, 2016

Capitalized Exploratory Well Costs [Abstract]

Changes in Capitalized Exploratory Well Costs

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

(millions)	Nine Months Ended September 30, 2016
Capitalized Exploratory Well Costs, Beginning of Period	$	1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	83
Divestitures and Other (1)	(143		)
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(1		)
Capitalized Exploratory Well Costs Charged to Expense (2)	(83		)
Capitalized Exploratory Well Costs, End of Period	$	1,209

⁽¹⁾  Includes $143 million relating to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner.

⁽²⁾ 

Aging of Capitalized Well Costs

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: 

(millions)	September 30, 2016		December 31, 2015
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	91	$	95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	1,118		1,258
Balance at End of Period	$	1,209	$	1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	13		14

Aging of Exploratory Well Costs

The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of September 30, 2016:

(millions)	Total by Project		Progress
Country/Project:
Deepwater Gulf of Mexico
Troubadour	$	52	Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
Katmai	97		Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options.
Offshore Equatorial Guinea Blocks I and O
Diega (Block I) and Carmen (Block O)	240		Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Carla (Block O)	184		Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Yolanda (Block I)	22		A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries.
Felicita (Block O)	45		Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
Offshore Cameroon
YoYo (YoYo Block)	53		A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries.
Offshore Israel
Leviathan	196		Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands.
Leviathan-1 Deep	84		The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
Dalit	31		Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar.
Offshore Cyprus

Cyprus	88		During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision.
Other
Individual Projects Less than $20 million	26		Continuing to assess and evaluate wells.
Total	$	1,118

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Changes in Asset Retirement Obligations

Changes in ARO are as follows:

	Nine Months Ended September 30,
(millions)	2016			2015
Asset Retirement Obligations, Beginning Balance	$	989		$	751
Liabilities Incurred	5			54
Liabilities Settled	(87		)	(29		)
Revision of Estimate	4			79
Accretion Expense (1)	37			32
Asset Retirement Obligations, Ending Balance	$	948		$	887

⁽¹⁾  Accretion expense is included in Depreciation, Depletion and Amortization (DD&A)expense in the consolidated statements ofoperations.

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Loss Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Schedule of earnings per share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions, except per share amounts)	2016			2015			2016			2015
Net Loss Attributable to Noble Energy	$	(144	)	$	(283	)	$	(746	)	$	(413	)
Weighted Average Number of Shares Outstanding, Basic (1)	430			420			430			392
Weighted Average Number of Shares Outstanding, Diluted(2)	430			420			430			392
Loss Per Share, Basic	$	(0.33	)	$	(0.67	)	$	(1.73	)	$	(1.05	)
Loss Per Share, Diluted	(0.33		)	(0.67		)	(1.73		)	(1.05		)
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above	14			14			15			11

⁽¹⁾  The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

⁽²⁾  For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy 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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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax Provision (Benefit)

The income tax benefit consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(millions)	2016			2015			2016			2015
Current	$	148		$	(45	)	$	213		$	64
Deferred	(285		)	69			(699		)	(244		)
Total Income Tax (Benefit) Provision	$	(137	)	$	24		$	(486	)	$	(180	)
Effective Tax Rate	48.9		%	(9.3		)%	39.5		%	30.4		%

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Information

(millions)	Consolidated			United States			West Africa			Eastern Mediterranean		Other Int'l & Corporate
Three Months Ended September 30, 2016
Revenues from Third Parties	$	882		$	639		$	93		$	150	$	—
Income from Equity Method Investees	28			8			20			—		—
Total Revenues	910			647			113			150		—
DD&A	621			539			46			23		13
Gain on Commodity Derivative Instruments	(55		)	(48		)	(7		)	—		—
(Loss) Income Before Income Taxes	(280		)	(407		)	47			135		(55		)
Three Months Ended September 30, 2015
Revenues from Third Parties	$	783		$	510		$	120		$	152	$	1
Income from Equity Method Investees	36			16			20			—		—
Total Revenues	819			526			140			152		1
DD&A	539			437			67			22		13
Gain on Commodity Derivative Instruments	(267		)	(187		)	(80		)	—		—
(Loss) Income Before Income Taxes	(259		)	(189		)	98			107		(275		)
Nine Months Ended September 30, 2016
Revenues from Third Parties	$	2,411		$	1,705		$	299		$	407	$	—
Income from Equity Method Investees	70			39			31			—		—
Total Revenues	2,481			1,744			330			407		—
DD&A	1,859			1,612			150			62		35
Loss on Divestitures	23			23			—			—		—
Loss on Commodity Derivative Instruments	53			44			9			—		—
(Loss) Income Before Income Taxes	(1,231		)	(882		)	74			290		(713		)
Nine Months Ended September 30, 2015
Revenues from Third Parties	$	2,264		$	1,448		$	432		$	378	$	6
Income from Equity Method Investees	60			35			25			—		—
Total Revenues	2,324			1,483			457			378		6
DD&A	1,444			1,138			223			52		31
Gain on Commodity Derivative Instruments	(331		)	(231		)	(100		)	—		—
(Loss) Income Before Income Taxes	(593		)	(353		)	195			227		(662		)
September 30, 2016
Total Assets	$	22,469		$	17,752		$	1,975		$	2,515	$	227
December 31, 2015
Total Assets	24,196			18,831			2,299			2,677		389

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Basis of Presentation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015		Jul. 04, 2016	Feb. 01, 2016	Dec. 31, 2015
Oil, Gas and NGL Sales		$ 882		$ 783		$ 2,411		$ 2,264
Share Price											$ 31.65
Production Expense
Lease Operating Expense		131		133		412		419
Production and Ad Valorem Taxes		30		28		73		89
Transportation and Gathering Expense (1)	[1]	113		86		335		207
Total		274		247		820		715
Other Operating (Income) Expense, Net
Loss on Asset Due to Terminated Contract	[2]	(3)		0		44		0
Midstream Gathering and Processing (Income) Expense, Net	[3]	20		10		58		25
Asset Impairments		0		0		0		43
Inventory Write-down		14		0		14		0
Business Exit Costs		4		18		8		18
Business combination costs		0		71		0	[4]	73	[4]
Pension And Other Postretirement Plans, Termination Expense		0		67		0		88
Facility Costs		3		13		8		20
Gain on Extinguishment of Debt	[5]	0		0		(80)		0
Other, Net		7		(12)		16		4
Total		45		188		66		310
Other Non-Operating Expense (Income), Net
Deferred Compensation Expense	[6]	2		(13)		7		(19)
Other (Income) Expense, Net		(3)		1		(4)		(1)
Total		(1)		(12)		3		(20)
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		12		6		39		15
Accounts Receivable, Net
Commodity Sales		317				317						$ 298
Joint Interest Billings		66				66						20
Proceeds Receivable	[7]	40				40						0
Other		86				86						151
Allowance for Doubtful Accounts		(23)				(23)						(19)
Total		486				486						450
Other Current Assets
Inventories, Materials and Supplies		75				75						92
Inventories, Crude Oil		25				25						23
Assets Held-for-Sale	[8]	214				214						67
Prepaid Expenses and Other Current Assets		38				38						34
Total		352				352						216
Other Noncurrent Assets
Investments in Unconsolidated Subsidiaries		460				460						453
Mutual Fund Investments		83				83						90
Commodity Derivative Assets		0				0						10
Other Assets		44				44						67
Total		587				587						620
Other Current Liabilities
Production and Ad Valorem Taxes		121				121						166
Derivative Liability, Current		27				27						0
Income Taxes Payable		168				168						86
Asset Retirement Obligations		128				128						128
Interest Payable		93				93						83
Current Portion of Capital Lease Obligations		61				61						53
Other		144				144						161
Total		742				742						677
Other Noncurrent Liabilities
Deferred Compensation Liabilities		232				232						217
Asset Retirement Obligations		820				820						861
Accrual for Taxes Other than Income Taxes		35				35						68
Derivative Liability, Noncurrent		8				8						0
Other		44				44						73
Total		$ 1,139				$ 1,139						$ 1,219
Percentage of divestiture farmed out		35.00%				35.00%						35.00%
Gain (Loss) on Disposition of Oil and Gas Property		$ 0		0		$ (23)		0
Restructuring Charges		0		21		0		39
Finalization of Purchase Price Allocation for Rosetta Merger		0	[4]	$ 0	[4]	(25)		$ 0	[4]
Phantom Units [Member]
Shares issued											1
NGL Revenue Previously Netted with Expense [Member]
Oil, Gas and NGL Sales		18				37
Tamar Field, Offshore Israel [Member]
Other Current Assets
Assets Held-for-Sale	[8]	$ 127				$ 127
Other Noncurrent Liabilities
Percentage of divestiture farmed out										3.00%
Working interest		3.00%				3.00%

[1] Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $18 million and $37 million for the three and nine months ended September 30, 2015 have been reclassified to conform to the current presentation.

[2] Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. See Note 9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update

[3] For the three and nine months ended September 30, 2016, amount includes $12 million and $39 million, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.Prior year amounts of $6 million and $15 million for the three and nine months ended September 30, 2015, were previously presented within production expense. These amounts have been reclassified to conform to the current presentation.

[4] Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

[5] Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

[6] Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.

[7] Amount relates to proceeds to be received from our farm-out of 35% interest in Block 12 offshore Cyprus. See Note 4. Divestitures.

[8] Assets held for sale at September 30, 2016 primarily include $127 million relating to our 3% working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel. See Note 4. Divestitures

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Noble Midstream Partners LP (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended	9 Months Ended
	Sep. 20, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Noble Midstream Partners LP [Member]
Subsidiary, Sale of Stock [Line Items]
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs				$ 0
Noble Midstream | IPO [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Partners' Offering Costs	$ 24
Payments of Capital Distribution		$ 297
Noble Midstream | IPO [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	14,375,000
Shares Issued, Price Per Share	$ 22.50
Shares Issued, Price Per Share, Net	$ 21.21
Noble Midstream | Over-Allotment Option [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	1,875,000
Noble Midstream | Noble Energy [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	1,527,584
Noble Midstream | Noble Energy [Member] | Subordinated Units [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Units, Sale of Units	15,902,584
Noble Midstream | Affiliated Entity [Member] | Noble Energy [Member] | Common Units [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	4.80%
Noble Midstream | Affiliated Entity [Member] | Noble Energy [Member] | Subordinated Units [Member]
Subsidiary, Sale of Stock [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	50.00%
Noble Midstream | Noble Midstream Partners LP [Member]
Subsidiary, Sale of Stock [Line Items]
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs			$ 299

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Rosetta Merger - Narrative (Details) $ / shares in Units, a in Thousands, shares in Millions, $ in Millions			3 Months Ended				9 Months Ended				12 Months Ended
		Jul. 20, 2015 USD ($) a business $ / shares shares	Sep. 30, 2016 USD ($)		Sep. 30, 2015 USD ($)		Sep. 30, 2016 USD ($)		Sep. 30, 2015 USD ($)	[1]	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Other Noncash Income			$ 0	[1]	$ 0	[1]	$ 25		$ 0
Shares exchange in acquisition | shares		41
Rosetta Merger Expenses			0		$ 71		0	[1]	$ 73
Pro forma revenue			119				333
Pro forma pre-tax net income			$ 4				$ 17
Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Shares exchange in acquisition | shares		41
Number of onshore plays added in acquisition | business		2
Merger related costs including noncash share-based compensation expense											$ 81
Rosetta Merger Expenses											66
Merger related costs related to noncash share-based compensation											$ 15
Share price | $ / shares		$ 36.97
Eagle Ford Shale [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		50
Permian [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		54
Delaware Basin [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Liquid rich asset based acquired | a		45
Midland Basin [Member] | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Long-term Debt, Fair Value	[2]	$ 2,000
Liquid rich asset based acquired | a		9
Common Stock | Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Exchange ratio of common shares for acquired company		0.542

[1] Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

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

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Rosetta Merger - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended				9 Months Ended
	Jul. 20, 2015		Sep. 30, 2016	[1]	Sep. 30, 2015	[1]	Sep. 30, 2016	Sep. 30, 2015	[1]	Dec. 31, 2015
Business Acquisition [Line Items]
Other Noncash Income			$ 0		$ 0		$ 25	$ 0
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares)	41
Rosetta Resources, Inc [Member]
Business Acquisition [Line Items]
Shares of Noble Energy common stock issued to Rosetta shareholders (in shares)	41
Noble Energy common stock price on July 20, 2015	$ 36.97
Fair value of common stock issued	$ 1,518
Plus: Fair value of Rosetta's restricted stock awards and performance awards assumed	10
Plus: Rosetta stock options assumed	1
Total purchase price	1,529
Plus: Liabilities assumed by Noble Energy
Accounts Payable	100
Current Liabilities	37
Long-Term Debt	1,992
Other Long Term Liabilities	23
Asset Retirement Obligation	27
Total purchase price plus liabilities assumed	3,708
Fair Value of Rosetta Assets
Cash and Equivalents	61
Other Current Assets	76
Derivative Instruments	209
Oil and Gas Properties
Proved Reserves	1,613
Undeveloped Leaseholds	1,355
Gathering & Processing Assets	207
Asset Retirement Obligation	27
Other Property Plant and Equipment	5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Assets Noncurrent	17
Goodwill	138	[2]								$ 163
Total Asset Value	$ 3,708

[1] Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger. See Note 5. Rosetta Merger.

[2] As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date.

XML

Rosetta Merger - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Business Combinations [Abstract]
Revenues	$ 846	$ 2,619
Net Loss Attributable to Noble Energy	$ (202)	$ (338)
Net Loss Attributable to Noble Energy Per Share of Common Stock
Basic (in dollars per share)	$ (0.44)	$ (0.79)
Diluted (in dollars per share)	$ (0.44)	$ (0.79)

XML

Divestitures (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Nov. 02, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) a	Sep. 30, 2015 USD ($)	Jul. 04, 2016	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Nov. 20, 2015 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of divestiture farmed out		35.00%		35.00%				35.00%
Sales Proceeds				$ 786	$ 151
Gain (Loss) on Disposition of Oil and Gas Property		$ 0	$ 0	(23)	$ 0
MONTANA
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				43
Bowdoin property, Northern Montana [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				19
Gain (Loss) on Disposition of Oil and Gas Property				(23)
Alon A And Alon C [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value									$ 73
Percentage of divestiture farmed out								47.00%
Cyprus Block 12 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total transaction value		143		143				$ 171
Proceeds received from farm-out agreement							$ 131
Consideration subject to post-close adjustments							$ 40
Certain US Crude Oil And Natural Gas Properties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				20
Weld County, Colorado [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sales agreement, consideration		$ 505		505
Producing and Undeveloped Net Acres in the DJ Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales Proceeds				$ 486
Purchase and sales agreement, area | a				33,100
Wells Ranch Development Area [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Purchase And Sales Agreement, Land Exchanged | a				11,700
Bronco Development Area [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sales agreement, area | a				13,500
Tamar Field, Offshore Israel [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of divestiture farmed out						3.00%
Sales Proceeds				$ 369
Option to purchase additional interest						1.00%
Subsequent Event [Member] | Eagle Ford [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash Provided by (Used in) Investing Activities, Discontinued Operations	$ 68

XML

Derivative Instruments and Hedging Activities (Details)	9 Months Ended
	Sep. 30, 2016 bbl / d MMBTU / d $ / bbl $ / MMBTU
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX WTI
Bbls Per Day | bbl / d	16,000
Weighted Average Fixed Price	67.69
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2016 [Member]
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX WTI
Bbls Per Day | bbl / d	10,000
Weighted Average Floor Price	40.50
Weighted Average Ceiling Price	53.42
Crude Oil Commodity Contract | Swaps - Dated Brent 2016
Derivative [Line Items]
Settlement Period	2016
Index	Dated Brent
Bbls Per Day | bbl / d	9,000
Weighted Average Fixed Price	97.96
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX WTI
Bbls Per Day | bbl / d	8,000
Weighted Average Short Put Price	54.50
Weighted Average Floor Price	65.63
Weighted Average Ceiling Price	79.03
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2016
Derivative [Line Items]
Settlement Period	2016
Index	Dated Brent
Bbls Per Day | bbl / d	8,000
Weighted Average Short Put Price	72.50
Weighted Average Floor Price	86.25
Weighted Average Ceiling Price	101.79
Crude Oil Commodity Contract | Call - NYMEX WTI 2016 [Member]
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX WTI
Bbls Per Day | bbl / d	5,000
Weighted Average Ceiling Price	54.16
Crude Oil Commodity Contract | Call - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	57.00
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX WTI
Bbls Per Day | bbl / d	4,000
Weighted Average Ceiling Price	47.34
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX WTI
Bbls Per Day | bbl / d	7,000
Weighted Average Floor Price	40.00
Weighted Average Ceiling Price	53.29
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX WTI
Bbls Per Day | bbl / d	15,000
Weighted Average Short Put Price	36.33
Weighted Average Floor Price	46.33
Weighted Average Ceiling Price	60.68
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	Dated Brent
Bbls Per Day | bbl / d	2,000
Weighted Average Short Put Price	35.00
Weighted Average Floor Price	45.00
Weighted Average Ceiling Price	66.33
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2018 [Member]
Derivative [Line Items]
Settlement Period	2018
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Short Put Price	40.00
Weighted Average Floor Price	50.00
Weighted Average Ceiling Price	70.41
Natural Gas Commodity Contract | Swaps - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Fixed Price | $ / MMBTU	3.24
Natural Gas Commodity Contract | Two Way Collars - NYMEX HH 2016
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Floor Price | $ / MMBTU	3.00
Weighted Average Ceiling Price | $ / MMBTU	3.50
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2016 [Member]
Derivative [Line Items]
Settlement Period	2016
Index	NYMEX HH
Bbls Per Day | MMBTU / d	90,000
Weighted Average Short Put Price | $ / MMBTU	2.83
Weighted Average Floor Price | $ / MMBTU	3.42
Weighted Average Ceiling Price | $ / MMBTU	3.90
Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	3.15
Natural Gas Commodity Contract | Swaptions - NYMEX HH 2017 [Member] [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	60,000
Weighted Average Ceiling Price | $ / MMBTU	3.14
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	180,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.93
Weighted Average Ceiling Price | $ / MMBTU	3.58
Natural Gas Commodity Contract | Two Way Collars - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2017
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Floor Price | $ / MMBTU	2.93
Weighted Average Ceiling Price | $ / MMBTU	3.32
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2018 [Member]
Derivative [Line Items]
Settlement Period	2018
Index	NYMEX HH
Bbls Per Day | MMBTU / d	70,000
Weighted Average Short Put Price | $ / MMBTU	2.50
Weighted Average Floor Price | $ / MMBTU	2.80
Weighted Average Ceiling Price | $ / MMBTU	3.76
Rosetta Resources, Inc [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2016
Derivative [Line Items]
Settlement Period	2016
Index	(3)
Bbls Per Day | bbl / d	6,000
Weighted Average Fixed Price	90.28
Rosetta Resources, Inc [Member] | Natural Gas Commodity Contract | Swaps - Houston Ship Channel and Tennessee Zone 0 2016 [Member] [Member]
Derivative [Line Items]
Settlement Period	2016
Index	(2)
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	4.04
Rosetta Resources, Inc [Member] | Natural Gas Commodity Contract | Two Way Collars - Houston Ship Channel and Tennessee Zone 0 2016 [Member]
Derivative [Line Items]
Settlement Period	2016
Index	(2)
Bbls Per Day | MMBTU / d	30,000
Weighted Average Floor Price | $ / MMBTU	3.50
Weighted Average Ceiling Price | $ / MMBTU	5.60
Second half 2017 [Member] | Crude Oil Commodity Contract | Call - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	60.12
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	50.05
Second half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17 (4)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Ceiling Price	62.80
Second half 2017 [Member] | Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	2H17
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Ceiling Price | $ / MMBTU	2.92
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	6,000
Weighted Average Fixed Price	55.08
First half 2017 [Member] | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (4)
Index	Dated Brent
Bbls Per Day | bbl / d	3,000
Weighted Average Fixed Price	62.80
First half 2017 [Member] | Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17 (4)
Index	NYMEX WTI
Bbls Per Day | bbl / d	2,000
Weighted Average Floor Price	40.00
Weighted Average Ceiling Price	50.44
First half 2017 [Member] | Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member]
Derivative [Line Items]
Settlement Period	1H17
Index	NYMEX HH
Bbls Per Day | MMBTU / d	30,000
Weighted Average Fixed Price | $ / MMBTU	2.92

XML

Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 120		$ 120		$ 592
Derivative Liability, Fair Value	35		35		0
(Gain) Loss on Commodity Derivative Instruments	(55)	$ (267)	53	$ (331)
Non-cash Portion of Loss on Commodity Derivative Instruments	(132)	(284)	(454)	(683)
(Gain) Loss on Commodity Derivative Instruments	77	17	507	352
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	120		120		582
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value					0
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0		0		10
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	8		8		$ 0
Crude Oil [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	(39)	(231)	46	(277)
Non-cash Portion of Loss on Commodity Derivative Instruments	(119)	(235)	(395)	(578)
(Gain) Loss on Commodity Derivative Instruments	80	4	441	301
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	(16)	(39)	7	(57)
Non-cash Portion of Loss on Commodity Derivative Instruments	(13)	(42)	(59)	(98)
(Gain) Loss on Commodity Derivative Instruments	(3)	3	66	41
Natural Gas Liquids [Member]
Derivatives, Fair Value [Line Items]
(Gain) Loss on Commodity Derivative Instruments	0	3	0	3
Non-cash Portion of Loss on Commodity Derivative Instruments	0	(7)		(7)
(Gain) Loss on Commodity Derivative Instruments	$ 0	$ 10	$ 0	$ 10

XML

Debt (Details) - USD ($)				3 Months Ended		9 Months Ended		12 Months Ended
		Nov. 01, 2016	Jan. 06, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Sep. 20, 2016	Aug. 27, 2015
Debt Instrument [Line Items]
Debt				$ 7,957,000,000		$ 7,957,000,000		$ 7,976,000,000
Unamortized Discount				(23,000,000)		(23,000,000)		(24,000,000)
Debt Instrument, Unamortized Premium				17,000,000		17,000,000		113,000,000
Total Debt, Net of Discount				7,915,000,000		7,915,000,000		8,029,000,000
Capital Lease Obligations, Current				(61,000,000)		(61,000,000)		(53,000,000)
Long-term Debt Due After One Year				7,854,000,000		7,854,000,000		7,976,000,000
Gain on tendered offers	[1]			0	$ 0	80,000,000	$ 0
Repayments of Long-term Lines of Credit						0	$ 74,000,000
Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt				$ 1,400,000,000		$ 1,400,000,000		$ 0
Debt stated rate				1.698%		1.698%		0.00%
Debt instrument, maturity date						Jan. 06, 2019
Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Debt				$ 0		$ 0		$ 0
Debt stated rate				0.00%		0.00%		0.00%
Debt instrument, maturity date						Aug. 27, 2020		Aug. 27, 2020
Maximum borrowing capacity				$ 4,000,000,000		$ 4,000,000,000
Credit facility fee rate basis points, minimum										0.10%
Credit facility fee rate basis points, maximum										0.25%
Credit facility aggregate short-term loans and letters of credit, maximum										$ 500,000,000
Credit facility aggregate short-term loans and letters of credit, committed				450,000,000		450,000,000
Credit facility interest rate, Eurodollar rate plus, minimum										0.90%
Credit facility interest rate, Eurodollar rate plus, maximum										1.50%
Noble Midstream Revolving Credit Facility, due September 20, 2021
Debt Instrument [Line Items]
Debt				$ 0		$ 0		$ 0
Debt stated rate				0.00%		0.00%		0.00%
Capital Lease and Other Obligations
Debt Instrument [Line Items]
Debt				$ 368,000,000		$ 368,000,000		$ 403,000,000
Debt stated rate				0.00%		0.00%		0.00%
Capital Lease Obligations, Current				$ (61,000,000)		$ (61,000,000)		$ (53,000,000)
8.25% Senior Notes, due March 1, 2019
Debt Instrument [Line Items]
Debt				$ 1,000,000,000		$ 1,000,000,000		$ 1,000,000,000
Debt stated rate				8.25%		8.25%		8.25%
Debt instrument, maturity date						Mar. 01, 2019		Mar. 01, 2019
5.625% Senior Notes, due May 1, 2021
Debt Instrument [Line Items]
Debt				$ 379,000,000		$ 379,000,000		$ 693,000,000
Debt stated rate				5.625%		5.625%		5.625%
Debt instrument, maturity date						May 01, 2021		May 01, 2021
4.15% Senior Notes, due December 15, 2021
Debt Instrument [Line Items]
Debt				$ 1,000,000,000		$ 1,000,000,000		$ 1,000,000,000
Debt stated rate				4.15%		4.15%		4.15%
Debt instrument, maturity date						Dec. 15, 2021		Dec. 15, 2021
5.875% Senior Notes, due June 1, 2022
Debt Instrument [Line Items]
Debt				$ 18,000,000		$ 18,000,000		$ 597,000,000
Debt stated rate				5.875%		5.875%		5.875%
Debt instrument, maturity date						Jun. 01, 2022		Jun. 01, 2022
7.25% Senior Notes, due October 15, 2023
Debt Instrument [Line Items]
Debt				$ 100,000,000		$ 100,000,000		$ 100,000,000
Debt stated rate				7.25%		7.25%		7.25%
Debt instrument, maturity date						Oct. 15, 2023		Oct. 15, 2023
Unamortized Debt Issuance Expense				$ (36,000,000)		$ (36,000,000)		$ (36,000,000)
5.875% Senior Notes, due June 1, 2024
Debt Instrument [Line Items]
Debt				$ 8,000,000		$ 8,000,000		$ 499,000,000
Debt stated rate				5.875%		5.875%		5.875%
Debt instrument, maturity date						Jun. 01, 2024		Jun. 01, 2024
3.90% Senior Notes, due November 15, 2024
Debt Instrument [Line Items]
Debt				$ 650,000,000		$ 650,000,000		$ 650,000,000
Debt stated rate				3.90%		3.90%		3.90%
Debt instrument, maturity date						Nov. 15, 2024		Nov. 15, 2024
8.00% Senior Notes, due April 1, 2027
Debt Instrument [Line Items]
Debt				$ 250,000,000		$ 250,000,000		$ 250,000,000
Debt stated rate				8.00%		8.00%		8.00%
Debt instrument, maturity date						Apr. 01, 2027		Apr. 01, 2027
6.00% Senior Notes, due March 1, 2041
Debt Instrument [Line Items]
Debt				$ 850,000,000		$ 850,000,000		$ 850,000,000
Debt stated rate				6.00%		6.00%		6.00%
Debt instrument, maturity date						Mar. 01, 2041		Mar. 01, 2041
5.25% Senior Notes, due November 15, 2043
Debt Instrument [Line Items]
Debt				$ 1,000,000,000		$ 1,000,000,000		$ 1,000,000,000
Debt stated rate				5.25%		5.25%		5.25%
Debt instrument, maturity date						Nov. 15, 2043		Nov. 15, 2043
5.05% Senior Notes, due November 15, 2044
Debt Instrument [Line Items]
Debt				$ 850,000,000		$ 850,000,000		$ 850,000,000
Debt stated rate				5.05%		5.05%		5.05%
Debt instrument, maturity date						Nov. 15, 2044		Nov. 15, 2044
7.25% Senior Debentures, due August 1, 2097
Debt Instrument [Line Items]
Debt				$ 84,000,000		$ 84,000,000		$ 84,000,000
Debt stated rate				7.25%		7.25%		7.25%
Debt instrument, maturity date						Aug. 01, 2097		Aug. 01, 2097
Revolving Credit Facility, due August 27, 2020 | Term Loan Facility [Member]
Debt Instrument [Line Items]
Proceeds from Lines of Credit						$ 1,380,000,000
Debt Instrument, Term			3 years
Revolving Credit Facility, due August 27, 2020 | Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility fee rate basis points, minimum			0.10%
Credit facility fee rate basis points, maximum			0.75%
Revolving Credit Facility, due August 27, 2020 | Federal Funds Effective Swap Rate [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate			0.50%
Revolving Credit Facility, due August 27, 2020 | London Interbank Offered Rate (LIBOR) [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate			1.00%
Revolving Credit Facility, due August 27, 2020 | London Interbank Offered Rate (LIBOR) [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility interest rate, Eurodollar rate plus, minimum			1.00%
Credit facility interest rate, Eurodollar rate plus, maximum			1.75%
Other Operating Income (Expense) [Member] | Revolving Credit Facility, due August 27, 2020 | Credit Facility [Member]
Debt Instrument [Line Items]
Gain on tendered offers						$ 80,000,000
Noble Midstream | Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 350,000,000
Available increase in capacity									350,000,000
Debt Instrument, Term						5 years
Noble Midstream | Revolving Credit Facility, due August 27, 2020 | Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						0.50%
Noble Midstream | Revolving Credit Facility, due August 27, 2020 | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, variable rate						1.00%
Letter of Credit | Noble Midstream | Revolving Credit Facility, due August 27, 2020
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 100,000,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Lines of Credit		$ 850,000,000

[1] Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 7. Debt.

XML

Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Financial Assets [Abstract]
Mutual Fund Investments		$ 83	$ 90
Commodity Derivative Instruments		120	592
Financial Liabilities [Abstract]
Commodity Derivative Instruments		(35)	0
Portion of Deferred Compensation Liability Measured at Fair Value		(105)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability		(6)
Quoted Prices in Active Markets (Level 1)
Financial Assets [Abstract]
Mutual Fund Investments	[1]	83	90
Commodity Derivative Instruments	[1]	0	0
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[1]	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	[1]	(105)	(98)
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[1]	(6)
Significant Unobservable Inputs (Level 3)
Financial Assets [Abstract]
Mutual Fund Investments	[2]	0	0
Commodity Derivative Instruments	[2]	0	0
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[2]	0	0
Portion of Deferred Compensation Liability Measured at Fair Value	[2]	0	0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[2]	0
Significant Other Observable Inputs (Level 2)
Financial Assets [Abstract]
Mutual Fund Investments	[3]	0	0
Commodity Derivative Instruments	[3]	133	600
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[3]	(48)	(8)
Portion of Deferred Compensation Liability Measured at Fair Value	[3]	0	0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[3]	0
Scenario, Adjustment [Member]
Financial Assets [Abstract]
Mutual Fund Investments	[4]	0	0
Commodity Derivative Instruments	[4]	(13)	(8)
Financial Liabilities [Abstract]
Commodity Derivative Instruments	[4]	13	8
Portion of Deferred Compensation Liability Measured at Fair Value	[4]	0	$ 0
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability	[4]	$ 0

[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 3 measurements are fair value measurements which use unobservable inputs.

[3] 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.

[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.

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Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Nonrecurring Basis (Details 2) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Inventory Write-down		$ 14,000,000	$ 0	$ 14,000,000	$ 0
Asset Impairment Charges				0
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties		0	0	0	43,000,000
Impairment Of Materials And Supply Inventory				14,000,000
Assets Held For Sale, Net Book Value		65,000,000		65,000,000
Impairments On Assets Held For Sale				23,000,000
Material and Supply Inventory, Net Book Value				105,000,000
Oil and Gas Property, Full Cost Method, Net	[1]			0	43,000,000
Gain (Loss) on Disposition of Oil and Gas Property		0	$ 0	(23,000,000)	0
Quoted Prices in Active Markets (Level 1)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	0
Impairment Of Materials And Supply Inventory				0
Loss On Assets Held For Sale		0		0
Significant Other Observable Inputs (Level 2)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	0
Impairment Of Materials And Supply Inventory				0
Loss On Assets Held For Sale		0		0
Significant Unobservable Inputs (Level 3)
Asset Impairment Charges [Abstract]
Impaired of Oil and Gas Properties				0	$ 0
Impairment Of Materials And Supply Inventory				91,000,000
Loss On Assets Held For Sale		$ 42,000,000		$ 42,000,000

[1] Amount represents net book value at the date of assessment.

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Fair Value Measurements and Disclosures (Details 3) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	[1]	$ 7,547	$ 7,626
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	[1]	$ 7,976	$ 7,105

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

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Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended
		Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized Exploratory Well Costs, Beginning of Period			$ 1,353
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves			83
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves			(1)
Capitalized Exploratory Well Cost, Charged to Expense	[1]		(83)
Capitalized Exploratory Well Costs, End of Period		$ 1,209	1,209
Exploratory Well Costs Capitalized for a Period of One Year or Less					$ 91		$ 95
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					1,118		1,258
Capitalized Exploratory Well Costs, End of Period		1,209	1,353		$ 1,209		$ 1,353
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling					13		14
Percentage of divestiture farmed out					35.00%		35.00%
Capitalized undeveloped leasehold cost		105	2,000
Leasehold impairment		81	81	$ 0
Valuation allowance increase		$ 24
Onshore US [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			1,900
International [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			32
Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Capitalized undeveloped leasehold cost			$ 116
Katmai Deepwater Gulf Of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					$ 97
Troubadour Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					52
Diega (including Carmen) Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					240
Carla Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					184
YoYo Offshore Cameron [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					53
Leviathan Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					196
Leviathan-1 Deep Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					84
Dalit Offshore Israel [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					31
Cyprus [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					88
Other - Projects of $20 million or less each [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling					26
Cyprus Block 12 [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Farmdown					$ (143)		$ (171)
Aging of Capitalized Exploratory Well Costs, Period One [Member] | Felicita/Yolanda Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling						$ 45
Aging of Capitalized Exploratory Well Costs, Period One [Member] | Yolanda Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Roll Forward]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling						$ 22

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Asset Retirement Obligations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligations, Beginning Balance		$ 989	$ 751
Liabilities Incurred		5	54
Liabilities Settled		(87)	(29)
Revision of Estimate		4	79
Accretion Expense	[1]	37	32
Asset Retirement Obligations, Ending Balance		948	887
Eastern Mediterranean [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate			43
DJ Basin (Onshore US) [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Revision of Estimate			$ 28
Deepwater Gulf of Mexico [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred		42
Onshore US [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities Incurred		$ 40

[1] Accretion expense is included in Depreciation, Depletion and Amortization (DD&A) expense in the consolidated statements of operations.

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Loss Per Share (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended			9 Months Ended
		Jul. 20, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net Income (Loss) Attributable to Parent			$ (144)	$ (283)		$ (746)	$ (413)
Weighted Average, Number of Shares Outstanding, Basic (in shares)	[1]		430,000,000	420,000,000		430,000,000	392,000,000
Weighted Average, Number of Shares Outstanding, Diluted (in shares)	[2]		430,000,000	420,000,000		430,000,000	392,000,000
Earnings (Loss) from Continuing Operations Per Share, Basic (in dollars per share)			$ (0.33)	$ (0.67)		$ (1.73)	$ (1.05)
Earnings (Loss) from Continuing Operations Per Share, Diluted (in dollars per share)			$ (0.33)	$ (0.67)		$ (1.73)	$ (1.05)
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above (in shares)			14,000,000	14,000,000		15,000,000	11,000,000
Underwritten public offering (in shares)					24,150,000
Shares exchange in acquisition		41,000,000

[1] The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

[2] For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy 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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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Examination [Line Items]
Current	$ 148	$ (45)	$ 213	$ 64
Deferred	(285)	69		(244)
Total Income Tax (Benefit) Provision	$ (137)	$ 24	$ (486)	$ (180)
Effective Tax Rate	48.90%	(9.30%)	39.50%	30.40%
US
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination			2013
Equatorial Guinea
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination			2011
Israel
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination			2011

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Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues from Third Parties	$ 882	$ 783	$ 2,411	$ 2,264
Income from Equity Method Investees	28	36	70	60
Total Revenues	910	819	2,481	2,324
DD&A	621	539	1,859	1,444
Loss on Divestitures	0	0	23	0
Asset Impairments	0	0	0	43
(Gain) Loss on Commodity Derivative Instruments	(55)	(267)	53	(331)
(Loss) Income Before Income Taxes	(280)	(259)	(1,231)	(593)
Total Assets	22,469		22,469		$ 24,196
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	639	510	1,705	1,448
Income from Equity Method Investees	8	16	39	35
Total Revenues	647	526	1,744	1,483
DD&A	539	437	1,612	1,138
Loss on Divestitures			23
(Gain) Loss on Commodity Derivative Instruments	(48)	(187)	44	(231)
(Loss) Income Before Income Taxes	(407)	(189)	(882)	(353)
Total Assets	17,752		17,752		18,831
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	93	120	299	432
Income from Equity Method Investees	20	20	31	25
Total Revenues	113	140	330	457
DD&A	46	67	150	223
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	(7)	(80)	9	(100)
(Loss) Income Before Income Taxes	47	98	74	195
Total Assets	1,975		1,975		2,299
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	150	152	407	378
Income from Equity Method Investees	0	0	0	0
Total Revenues	150	152	407	378
DD&A	23	22	62	52
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
(Loss) Income Before Income Taxes	135	107	290	227
Total Assets	2,515		2,515		2,677
Other Int'l & Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	0	1	0	6
Income from Equity Method Investees	0	0	0	0
Total Revenues	0	1	0	6
DD&A	13	13	35	31
Loss on Divestitures			0
(Gain) Loss on Commodity Derivative Instruments	0	0	0	0
(Loss) Income Before Income Taxes	(55)	$ (275)	(713)	$ (662)
Total Assets	$ 227		$ 227		$ 389

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Commitments and Contingencies Commitments and Contingencies (Details)	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2016 USD ($)	Sep. 30, 2016 USD ($) Tcf Bcf MMBbls	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) $ / MMBTU Tcf Bcf MMBbls	Sep. 30, 2015 USD ($)
Other Commitments [Line Items]
Additional expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments		$ 12,000,000	$ 6,000,000	$ 39,000,000	$ 15,000,000
Supplemental environmental projects	$ 178,780
Reduced penalty	$ 44,695
CONSOL Carried Cost Obligation [Member]
Other Commitments [Line Items]
Equity method investment, ownership percentage		50.00%		50.00%
Maximum amount to be paid each calendar year for funding of future drilling and completion costs				$ 400,000,000
Funding of joint venture's future drilling and completion costs				$ 1,600,000,000
Natural gas price agreed upon benchmark, average				4.00
Consent Decree [Member]
Other Commitments [Line Items]
Civil penalty				$ 4,950,000
Mitigation projects				4,500,000
Supplemental environmental projects				$ 4,000,000
Natural Gas [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | Tcf		6		6
Crude Oil [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | MMBbls		271		271
Marcellus Shale [Member] | Natural Gas [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Available Amounts to be Received | Bcf		493		493

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Label	Element	Value
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	$ 12,000,000