10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

     OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

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)
100 Glenborough Drive, Suite 100
Houston, Texas	77067
(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 x    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 x    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 x

As of October 6, 2011, there were 176,645,583 shares of the registrant’s common stock,

par value $3.33 1/3 per share, outstanding.

Table of Contents

Part I. Financial Information	3
Item 1. Financial Statements	3
Consolidated Statements of Operations	3
Consolidated Balance Sheets	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Shareholders' Equity	6
Notes to Consolidated Financial Statements	7
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.  Controls and Procedures	47
Part II. Other Information	47
Item 1.  Legal Proceedings	47
Item 1A.  Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3. Defaults Upon Senior Securities	48
Item 4. (Removed and Reserved)	49
Item 5.  Other Information	49
Item 6.  Exhibits	49
Signatures	49
Index to Exhibits	50

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,
	2011			2010			2011			2010
Revenues
Oil, Gas and NGL Sales	$	874		$	704		$	2,599		$	2,102
Income from Equity Method Investees		50			34			146			85
Other Revenues		-			17			33			52
Total		924			755			2,778			2,239
Costs and Expenses
Production Expense		153			141			449			430
Exploration Expense		57			35			195			167
Depreciation, Depletion and Amortization		225			231			681			662
General and Administrative		89			65			254			194
Gain on Divestitures		-			(114	)		(26	)		(114	)
Asset Impairments		-			100			139			100
Other Operating (Income) Expense, Net		2			4			45			59
Total		526			462			1,737			1,498
Operating Income		398			293			1,041			741
Other (Income) Expense
Gain on Commodity Derivative Instruments		(322	)		(38	)		(179	)		(280	)
Interest, Net of Amount Capitalized		14			21			51			60
Other Non-Operating (Income) Expense, Net		(16	)		12			(16	)		(1	)
Total		(324	)		(5	)		(144	)		(221	)
Income Before Income Taxes		722			298			1,185			962
Income Tax Provision		281			66			436			289
Net Income	$	441		$	232		$	749		$	673
Earnings Per Share, Basic	$	2.50		$	1.33		$	4.25		$	3.86
Earnings Per Share, Diluted		2.39			1.31			4.12			3.80
Weighted Average Number of Shares Outstanding, Basic		177			175			176			175
Weighted Average Number of Shares Outstanding, Diluted		180			177			179			178

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

3

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

	September 30,			December 31,
	2011			2010
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,252		$	1,081
Accounts Receivable, Net		546			556
Other Current Assets		279			201
Total Assets, Current		2,077			1,838
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)		17,180			14,393
Property, Plant and Equipment, Other		277			263
Total Property, Plant and Equipment, Gross		17,457			14,656
Accumulated Depreciation, Depletion and Amortization		(4,945	)		(4,392	)
Total Property, Plant and Equipment, Net		12,512			10,264
Goodwill		696			696
Other Noncurrent Assets		548			484
Total Assets	$	15,833		$	13,282
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,132		$	927
Other Current Liabilities		826			495
Total Liabilities, Current		1,958			1,422
Long-Term Debt		3,507			2,272
Deferred Income Taxes, Noncurrent		2,235			2,110
Other Noncurrent Liabilities		551			630
Total Liabilities		8,251			6,434
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued		-			-
Common Stock - Par Value $3.33 1/3 per share; 250 Million Shares Authorized; 196 Million and 195 Million Shares Issued, Respectively		655			651
Additional Paid in Capital		2,467			2,385
Accumulated Other Comprehensive Loss		(85	)		(104	)
Treasury Stock, at Cost; 19 Million Shares		(640	)		(624	)
Retained Earnings		5,185			4,540
Total Shareholders’ Equity		7,582			6,848
Total Liabilities and Shareholders’ Equity	$	15,833		$	13,282

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

4

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Nine Months Ended September 30,
	2011			2010
Cash Flows From Operating Activities
Net Income	$	749		$	673
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		681			662
Asset Impairments		139			100
Dry Hole Cost		57			57
Deferred Income Taxes		147			109
Dividends (Income) from Equity Method Investees, Net		23			6
Unrealized Gain on Commodity Derivative Instruments		(140	)		(215	)
Gain on Divestitures		(26	)		(114	)
Other Adjustments for Noncash Items Included in Income		52			40
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable		(7	)		(63	)
(Increase) Decrease in Other Current Assets		(17	)		18
Increase in Accounts Payable		131			214
Increase  in Current Income Taxes Payable		52			20
(Decrease) in Other Current Liabilities		(25	)		(17	)
Other Operating Assets and Liabilities, Net		(31	)		(38	)
Net Cash Provided by Operating Activities		1,785			1,452
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,868	)		(1,326	)
Marcellus Shale Asset Acquisition		(519	)		-
Central DJ Basin Asset Acquisition		-			(458	)
Additions to Equity Method Investments		(73	)		-
Proceeds from Divestitures		77			552
Net Cash Used in Investing Activities		(2,383	)		(1,232	)
Cash Flows From Financing Activities
Exercise of Stock Options		32			35
Excess Tax Benefits from Stock-Based Awards		11			19
Dividends Paid, Common Stock		(104	)		(95	)
Purchase of Treasury Stock		(16	)		(12	)
Proceeds from Credit Facilities		520			760
Repayment of Credit Facilities		(470	)		(792	)
Proceeds from Issuance of Senior Long-Term Debt, Net		836			-
Settlement of Interest Rate Derivative Instrument		(40	)		-
Net Cash Provided By (Used In) Financing Activities		769			(85	)
Increase in Cash and Cash Equivalents		171			135
Cash and Cash Equivalents at Beginning of Period		1,081			1,014
Cash and Cash Equivalents at End of Period	$	1,252		$	1,149

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

5

Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)

	Common Stock		Additional Paid in Capital			Acumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2010	$	651	$	2,385		$	(104	)	$	(624	)	$	4,540		$	6,848
Net Income		-		-			-			-			749			749
Stock-based Compensation		-		43			-			-			-			43
Exercise of Stock Options		2		30			-			-			-			32
Tax Benefits Related to Exercise of Stock Options		-		11			-			-			-			11
Restricted Stock Awards, Net		2		(2	)		-			-			-			-
Dividends (58 cents per share)		-		-			-			-			(104	)		(104	)
Changes in Treasury Stock, Net		-		-			-			(16	)		-			(16	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		-			15			-			-			15
Net Change in Other		-		-			4			-			-			4
September 30, 2011	$	655	$	2,467		$	(85	)	$	(640	)	$	5,185		$	7,582
December 31, 2009	$	645	$	2,260		$	(75	)	$	(615	)	$	3,942		$	6,157
Net Income		-		-			-			-			673			673
Stock-based Compensation		-		40			-			-			-			40
Exercise of Stock Options		3		32			-			-			-			35
Tax Benefits Related to Exercise of Stock Options		-		19			-			-			-			19
Restricted Stock Awards, Net		2		(2	)		-			-			-			-
Dividends (54 cents per share)		-		-			-			-			(95	)		(95	)
Changes in Treasury Stock, Net		-		-			-			(12	)		-			(12	)
Oil and Gas Cash Flow Hedges
Realized Amounts Reclassified Into Earnings		-		-			10			-			-			10
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		-			(92	)		-			-			(92	)
Net Change in Other		-		-			2			-			-			2
September 30, 2010	$	650	$	2,349		$	(155	)	$	(627	)	$	4,520		$	6,737

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

6

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 1.  Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our key operating areas are onshore in the US, primarily in the DJ Basin and the Marcellus shale, in the deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore 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, 2011 and December 31, 2010 and for the three and nine months ended September 30, 2011 and 2010 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. Operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. 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, 2010.

Consolidation   Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries.  In addition, we use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.

Estimates   The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Other Revenues
Electricity Sales (1)	$	-		$	19		$	32		$	53
Other		-			(2	)		1			(1	)
Total	$	-		$	17		$	33		$	52
Production Expense
Lease Operating Expense	$	98		$	95		$	288		$	283
Production and Ad Valorem Taxes		38			29			108			96
Transportation Expense		17			17			53			51
Total	$	153		$	141		$	449		$	430
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	(1	)	$	-		$	18		$	27
Electricity Generation Expense (1)		-			9			26			26
Loss on Involuntary Conversion (3)		-			-			4			-
Other, Net		3			(5	)		(3	)		6
Total	$	2		$	4		$	45		$	59
Other Non-Operating (Income) Expense, Net
Deferred Compensation (Income) Expense (4)	$	(18	)	$	15		$	(15	)	$	4
Interest Income		(2	)		(1	)		(7	)		(4	)
Other (Income) Expense, Net		4			(2	)		6			(1	)
Total	$	(16	)	$	12		$	(16	)	$	(1	)

(1) Electricity sales include sales from the Machala power plant located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts.  See Note 3. Acquisitions and Divestitures.

(2) Amounts relate to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011 and costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the deepwater Gulf of Mexico drilling moratorium in 2010.

7

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

(3) The loss on involuntary conversion represents our insurance deductible related to the Leviathan-2 appraisal well control incident. We suspended operations on the Leviathan-2 well, offshore Israel, in May 2011 when we identified water flowing to the sea floor from the wellbore. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. See footnote (2) below.

(4) Amount represents increases (decreases) 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:

	September 30,			December 31,
	2011			2010
(millions)
Accounts Receivable, Net
Commodity Sales	$	228		$	291
Joint Interest Billings		253			259
Other		73			33
Allowance for Doubtful Accounts (1)		(8	)		(27	)
Total	$	546		$	556
Other Current Assets
Inventories, Current	$	120		$	112
Commodity Derivative Assets, Current		87			62
Deferred Income Taxes, Net, Current		15			8
Probable Insurance Claims (2)		25			-
Prepaid Expenses and Other Assets, Current		32			19
Total	$	279		$	201
Other Noncurrent Assets
Equity Method Investments (3)	$	339		$	285
Mutual Fund Investments		101			112
Commodity Derivative Assets, Noncurrent		44			-
Other Assets, Noncurrent		64			87
Total	$	548		$	484
Other Current Liabilities
Production and Ad Valorem Taxes	$	128		$	110
Commodity Derivative Liabilities, Current		6			24
Interest Rate Derivative Liability, Current		-			63
Income Taxes Payable		143			90
Asset Retirement Obligations, Current		45			45
Interest Payable		18			36
CONSOL Installment Payment (4)		322			-
Current Portion of FPSO Lease Obligation		33			-
Other		131			127
Total	$	826		$	495
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	210		$	229
Asset Retirement Obligations, Noncurrent		215			208
Accrued Benefit Costs, Noncurrent		63			76
Commodity Derivative Liabilities, Noncurrent		-			51
Other		63			66
Total	$	551		$	630

(1) The decrease in the allowance for doubtful accounts from December 31, 2010 is due primarily to the transfer of assets to the Ecuadorian government. See Note 3.  Acquisitions and Divestitures.

8

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

(2) Amount represents the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible. See footnote (3) above.

(3) The increase in equity method investments from December 31, 2010 is due to our acquisition of a 50% interest in CONE Gathering LLC. See Note 3. Acquisitions and Divestitures.

(4) See Note 3. Acquisitions and Divestitures and Note 5. Debt.

Recently Issued Accounting Standards Updates   In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position and results of operations.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05: Comprehensive Income (Topic 220): Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of ASU 2011-05. We do not expect ASU 2011-05 to have any impact on our financial position and results of operations as it is a change in presentation only.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08: Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment (ASU 2011-08).ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. Under ASU 2011-08, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 is effective for annual periods beginning after December 15, 2011. We expect to adopt the provisions of ASU 2011-08 for our annual impairment test as of December 31, 2011. We do not expect ASU 2011-08 to have any impact on our financial position and results of operations as it is a change in application of the goodwill impairment test only.

Note 3.   Acquisitions and Divestitures

Marcellus Shale Joint Venture Partnership On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired  50% interests in 628,000 net undeveloped acres, existing Marcellus production, and existing infrastructure for approximately $1.2 billion. We and CONSOL formed CONE Gathering LLC, which we will account for using the equity method, to own and operate existing and future infrastructure.

We paid a total of $592 million in cash at the closing of the above transaction, funded with available cash and amounts drawn under our credit facility. In addition, we will make two additional installment payments of $328 million each, which will be paid September 30, 2012 and 2013.

In addition, we have agreed to fund one-third of CONSOL’s 50% working interest share of future drilling and completion costs, up to approximately $2.1 billion (CONSOL Carried Cost Obligation). The CONSOL Carried Cost Obligation is expected to extend over an eight-year period. It is capped at $400 million in each calendar year and will be suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Therefore, specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time. Amounts paid pursuant to the CONSOL Carried Cost Obligation will be recorded as increases in property, plant and equipment in our consolidated balance sheets and as investing activities in our consolidated statements of cash flows.

As a result of the transaction, we recorded the following:

	September 30,
	2011
(millions)
Unproved Oil and Gas Properties	$	790
Proved Oil and Gas Properties		370
Investment in CONE Gathering LLC		73
Total Assets Acquired (1)	$	1,233

(1) Total reflects impact of discount on remaining installment payments. See Note 5. Debt.

9

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

To estimate the fair value of the proved oil and gas properties as of the acquisition date, we used an income approach. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:

· estimated quantities of crude oil and natural gas prepared by our qualified petroleum engineers;

· management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;

· estimated future production rates based on our experience with similar properties which we operate; and

· estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.

We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.

Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.

See Note 5. Debt and Note 7. Fair Value Measurements and Disclosures.

Gas Gathering Agreement with CONE Gathering LLC   On September 30, 2011, in connection with the Marcellus shale joint venture arrangement described above, we entered into a 50-year gathering and marketing agreement with CONE Gathering LLC. Under the terms of the gathering and marketing agreement, we will pay CONE Gathering LLC a minimum annual revenue commitment (MARC). The fee will be adjusted annually based on projected gathering volumes, operating expenses, capital expenditures, and other factors. We expect the MARC to total approximately $3 million in 2011 and $23 million in 2012. Amounts to be paid under the MARC for years beyond 2012 have not yet been determined.

We also have agreed to fund an annual work program for the construction of additional pipeline assets to receive and deliver production from future wells. Amounts to be contributed in future years to fund our proportionate share of the annual work program will be dependent upon anticipated production locations, volumes and other factors.  We will account for our 50% interest in CONE Gathering LLC using the equity method; therefore, our share of income will be reported as income from equity method investees in our consolidated statements of operations. Our investment in CONE Gathering LLC will be reported as investment in equity method investee in our consolidated balance sheets and will reflect our cash contributions to the entity.

Divestitures In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.  We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets and Block 3 production sharing contract (PSC), which was terminated by the government of Ecuador on November 25, 2010, and the assignment of the Machala Power Electricity concession and its associated assets. Our net book value for the assets had been reduced due to previous impairment charges, resulting in a gain of $26 million before tax. We did not consider the property disposition material for discontinued operations presentation.

10

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

In August 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. Information regarding the sale is as follows:

	Nine Months Ended September 30,
	2010
(millions)
Cash Proceeds	$	552
Less
Net Book Value of Assets Sold		(394	)
Goodwill Allocated to Assets Sold		(61	)
Asset Retirement Obligations Associated with Assets Sold		10
Other Closing Adjustments		7
Gain on Asset Sale	$	114

Note 4.  Asset Impairments

Pre-tax (non-cash) asset impairment charges were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
East Texas (Onshore US)	$	-	$	-	$	116	$	-
Iron Horse (Onshore US)		-		71		15		71
New Albany Shale (Onshore US)		-		19		-		19
Other		-		10		8		10
Total	$	-	$	100	$	139	$	100

2011   Due to field performance combined with a low natural gas price environment, we determined that the carrying amounts of certain of our onshore US developments, primarily in East Texas, were not recoverable from future cash flows and, therefore, were impaired at June 30, 2011.

2010   Due to declines in natural gas prices and drilling results, we determined that the carrying amounts of our Iron Horse development and certain other US properties were not recoverable from future cash flows and, therefore, were impaired at September 30, 2010. We also recorded an impairment related to non-core, New Albany shale assets which were held-for-sale at September 30, 2010.

Assets to be held and used were written down to their estimated fair values, which were determined using discounted cash flow models. Assets held for sale were reduced to expected sales proceeds less costs to sell. See Note 7. Fair Value Measurements and Disclosures.

11

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 5. Debt

Our debt consists of the following:

	September 30,						December 31,
	2011						2010
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due December 9, 2012	$	400			0.56	%	$	350			0.57	%
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	%		-			-
FPSO Lease Obligation		351			-			295			-
5¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%
8¼% Senior Notes, due March 1, 2019		1,000			8.25	%		1,000			8.25	%
7¼% Notes, due October 15, 2023		100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%
6% Senior Notes, due March 1, 2041		850			6.00	%		-			-
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		3,891						2,279
Unamortized Discount		(29	)					(7	)
Total Debt, Net of Discount		3,862						2,272
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(322	)					-
FPSO Lease Obligation		(33	)					-
Long-Term Debt Due After One Year	$	3,507					$	2,272

CONSOL Installment Payments   On September 30, 2011, we closed an agreement with CONSOL for the development of Marcellus shale properties. In addition to the cash paid at closing, we agreed to make two installment payments of $328 million each on September 30, 2012 and 2013. The installment payments have been discounted at the prevailing market rates for similar debt instruments. The CONSOL installment loan is a non-cash financing activity.  See Note 3. Acquisitions and Divestitures and Note 7. Fair Value Measurements and Disclosures.

FPSO Lease Obligation   We have entered into an agreement to lease a floating production, storage and offloading vessel (FPSO) to be used in the development of the Aseng field, offshore Equatorial Guinea. The amount of the FPSO lease obligation is based on the discounted present value of future minimum lease payments and the percentage of construction activities completed as of the reporting dates, and therefore does not reflect future minimum lease payments. The increase in the FPSO lease obligation is a non-cash financing activity. Amounts due within one year equal the amount by which the FPSO lease obligation is expected to be reduced during the next 12 months as lease payments begin. We currently expect production to commence, and lease payments to begin, by year end 2011.

Issuance of 6% Senior Notes   On February 18, 2011, we closed an offering of $850 million senior unsecured notes receiving net proceeds of $836  million, after deducting discount and underwriting fees. The notes are due March 1, 2041, and pay interest semi-annually at 6%. Total debt issuance costs of approximately $9 million were incurred and are being amortized to expense over the term of the notes. Approximately $470 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility and the balance of the proceeds will be used for general corporate purposes. The notes are senior unsecured debt and rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest. See Note 6. Derivative Instruments and Hedging Activities –Interest Rate Derivative Instrument.

12

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Annual Debt Maturities and FPSO Lease Payments    Annual maturities of outstanding debt and estimated annual FPSO lease payments are as follows:

	Debt Principal Payments		FPSO Lease Payments
(millions)
September 30, 2011
2011	$	-	$	12
2012		728		72
2013		328		72
2014		200		72
2015		-		70
Thereafter		2,284		198
Total	$	3,540	$	496

New Credit Facility    On October 14, 2011, we entered into a credit agreement with certain commercial lending institutions (the Credit Agreement) which provides for a new $3.0 billion unsecured five-year revolving credit facility (the New Credit Facility). The New Credit Facility replaces our $2.1 billion credit facility maturing December 9, 2012. Also on October 14, 2011, we borrowed $400 million under the New Credit Facility, which was used to repay outstanding borrowings under and to terminate the $2.1 billion credit facility.

The New Credit Facility (i) provides for an initial commitment of $3.0 billion with an option to increase the overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iv) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.

The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the New Credit Facility and require the immediate repayment of any outstanding advances under the New Credit Facility. The Credit Agreement does not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby.

The New Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

Note 6.  Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   In order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps.

The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.

13

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar.  We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.

Wealso enter into forward contracts or swap agreements to hedge exposure to interest rate risk.

While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.

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

Counterparty Credit Risk   Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of highly rated major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts 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 settled at the time of election.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.

Interest Rate Derivative Instrument   In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated debt issuance. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the 6% senior notes. The ineffective portion of the interest rate swap was de minimis. See Note 5. Debt.

Unsettled Derivative Instruments As of September 30, 2011, we had entered into the following crude oil derivative instruments:  

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX WTI (1)		5,000	$	85.52	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX WTI		13,000		-		-		80.15		94.63
2011	Three-Way Collars	NYMEX WTI		12,000		-		58.33		78.33		100.71
2012	Swaps	NYMEX WTI		5,000		91.84		-		-		-
2012	Swaps	Dated Brent		8,000		89.06		-		-		-
2012	Three-Way Collars	NYMEX WTI		23,000		-		61.09		83.04		101.66
2012	Three-Way Collars	Dated Brent		3,000		-		70.00		95.83		105.00
2013	Swaps	Dated Brent		3,000		98.03		-		-		-
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		5,000		-		80.00		99.71		127.32
Instruments Entered Into During October 1-15, 2011
2013	Three-Way Collars	Dated Brent		5,000		-		90.00		102.00		128.15

(1) West Texas Intermediate

14

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

As of September 30, 2011, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX HH (1)		25,000	$	6.41	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX HH		140,000		-		-		5.95		6.82
2011	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.00		6.70
2012	Swaps	NYMEX HH		30,000		5.10		-		-		-
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.25		5.59

(1) Henry Hub

As of September 30, 2011, we had entered into the following natural gas basis swaps:

Period	Index	Index Less Differential	MMBtu Per Day	Weighted Average Differential
2011	IFERC CIG (1)	NYMEX HH	140,000	$	(0.70)
2012	IFERC CIG	NYMEX HH	150,000		(0.52)

(1) Colorado Interstate Gas – Northern System

15

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Fair Value Amounts and Gains and Losses on Derivative Instruments   The fair values of derivative instruments in our consolidated balance sheets were as follows:

Fair Value of Derivative Instruments

	Asset Derivative Instruments						Liability Derivative Instruments
	September 30,			December 31,			September 30,			December 31,
	2011			2010			2011			2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
(millions)
Commodity Derivative Instruments (Not Designated as Hedging Instruments)	Current Assets	$	87	Current Assets	$	62	Current Liabilities	$	6	Current Liabilities	$	24
	Noncurrent Assets		44	Noncurrent Assets		-	Noncurrent Liabilities		-	Noncurrent Liabilities		51
Interest Rate Derivative Instruments (Designated as Hedging Instruments)	Current Assets		-	Current Assets		-	Current Liabilities		-	Current Liabilities		63
Total		$	131		$	62		$	6		$	138

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

Commodity Derivative Instruments Not Designated as Hedging Instruments

Amount of Gain on Derivative Instruments Recognized in Income

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Realized Mark-to-Market Gain	$	(22	)	$	(33	)	$	(39	)	$	(65	)
Unrealized Mark-to-Market Gain		(300	)		(5	)		(140	)		(215	)
Total Gain on Commodity Derivative Instruments	$	(322	)	$	(38	)	$	(179	)	$	(280	)

16

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Derivative Instruments in Cash Flow Hedging Relationships

	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss						Amount of (Gain) Loss on Derivative Instruments Reclassified from  Accumulated Other Comprehensive Loss
		2011			2010		2011		2010
(millions)
Three Months Ended September 30,
Commodity Derivative Instruments in Previously Designated
Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	5
Natural Gas Derivative Instruments			-			-		-		-
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			-			47		-		-
Total		$	-		$	47	$	-	$	5
Nine Months Ended September 30,
Commodity Derivative Instruments in Previously Designated
Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	14
Natural Gas Derivative Instruments			-			-		-		1
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			(23	)		141		1		-
Total		$	(23	)	$	141	$	1	$	15

(1) Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.

AOCL at September 30, 2011 included deferred losses of $27 million, net of tax, related to interest rate derivative instruments. This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April 2014 and March 2041.  Approximately $2 million of deferred losses (net of tax) will be reclassified to earnings during the next 12 months and will be recorded as an increase in interest expense.

Note 7.  Fair Value Measurements and Disclosures

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

Mutual Fund Investments   Our mutual fund investments, which primarily include assets held in a rabbi trust, 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 consist of variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps. We estimate the fair values of these instruments based on 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 (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 6. Derivative Instruments and Hedging Activities.

Interest Rate Derivative Instrument   We estimated the fair value of our forward starting swap based on published interest rate yield curves as of the date of the estimate. The fair values of interest rate derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of interest rate derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. See Note 6. Derivative Instruments and Hedging Activities.

17

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

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.

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, 2011
Financial Assets
Mutual Fund Investments	$	101			$	-		$	-	$	-		$	101
Commodity Derivative Instruments		-				174			-		(43	)		131
Financial Liabilities
Commodity Derivative Instruments		-				(49	)		-		43			(6	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(152	)			-			-		-			(152	)
December 31, 2010
Financial Assets
Mutual Fund Investments	$	112			$	-		$	-	$	-		$	112
Commodity Derivative Instruments		-				106			-		(44	)		62
Financial Liabilities
Commodity Derivative Instruments		-				(119	)		-		44			(75	)
Interest Rate Derivative Instrument		-				(63	)		-		-			(63	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(178	)			-			-		-			(178	)

(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 master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.

18

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

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:

Asset Impairments   We determined that the carrying amounts of certain onshore US assets were not recoverable from future cash flows and, therefore, were impaired.  The assets were reduced to their estimated fair values. Information about the impaired assets is as follows:

	Fair Value Measurements Using
Description	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)
Three Months Ended September 30, 2011
Impaired Oil and Gas Properties	$	-	$	-	$	-	$	-	$	-
Three Months Ended September 30, 2010
Impaired Oil and Gas Properties		-		-		48		148		100
Nine Months Ended September 30, 2011
Impaired Oil and Gas Properties	$	-	$	-	$	32	$	171	$	139
Nine Months Ended September 30, 2010
Impaired Oil and Gas Properties		-		-		48		148		100

(1) Amount represents net book value atdate of assessment.

The fair values of the properties were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate. See Note 4. Asset Impairments.

Additional Fair Value Disclosures

Debt   The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues.  The carrying amounts of floating-rate debt approximate fair value because the interest rate paid on such debt was set for periods of three months or less. The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar instruments. See Note 5. Debt. Fair value information regarding our debt is as follows:

	September 30,				December 31,
	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	3,511	$	4,031	$	1,977	$	2,302

(1) Excludes FPSO lease obligation.

19

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 8.  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:

	Nine Months Ended September 30,
(millions)
Capitalized Exploratory Well Costs, Beginning of Period		$	466
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves			158
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1)			(55	)
Capitalized Exploratory Well Costs Charged to Expense			(15	)
Capitalized Exploratory Well Costs, End of Period		$	554

(1) Includes $13 million related to the Flyndre project in the North Sea.

The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	September 30,		December 31,
	2011			2010
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	196	$	166
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling		358		300
Balance at End of Period	$	554	$	466
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling		10		9

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of September 30, 2011:

			Suspended Since
	Total		2010		2009		2008 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	113	$	7	$	19	$	87
Offshore Cameroon
YoYo		39		1		2		36
Offshore Israel
Dalit		22		1		21		-
Deepwater Gulf of Mexico
Deep Blue		73		54		19		-
Gunflint		58		2		6		50
Redrock		21		1		2		18
North Sea
Selkirk		23		1		1		21
Other
3 projects of $10 million or less each		9		9		-		-
Total	$	358	$	76	$	70	$	212

Blocks O and I   Blocks O and I are crude oil, natural gas and natural gas condensate discoveries. During third quarter 2011 we continued to evaluate results of the appraisal well at the Carmen/Diega prospect.

YoYo   YoYo is a 2007 natural gas and condensate discovery.  We have acquired and processed additional 3-D seismic information.

Dalit   Dalit is a 2009 natural gas discovery. We are currently working with our partners on a cost-effective development plan.

20

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Deep Blue   Deep Blue (Green Canyon Block 723) is an exploratory well which found hydrocarbon pay in multiple intervals. When the deepwater Gulf of Mexico moratorium was announced in May 2010, we were required to suspend sidetrack drilling activities.  During third quarter 2011, we obtained approval for a drilling permit and resumed exploration drilling.

Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. Our plans to conduct appraisal drilling activities in 2010 were delayed by the deepwater Gulf of Mexico moratorium. Once a drilling permit is approved, we plan to resume drilling activities. We are also reviewing host platform options.

Redrock   Redrock (Mississippi Canyon Block 204) is a 2006 natural gas/condensate discovery and is currently considered a co-development candidate with Raton South (Mississippi Canyon Block 292). We are in the process of developing Raton South as a subsea tieback to a host platform at Viosca Knoll Block 900.  We plan to develop Redrock after Raton South commences production, which is currently expected to occur by the end of 2011.

Selkirk   The Selkirk project is located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.

Note 9.  Asset Retirement Obligations

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

	Nine Months Ended September 30,
	2011			2010
(millions)
Asset Retirement Obligations, Beginning Balance	$	253		$	232
Liabilities Incurred		2			14
Liabilities Settled		(19	)		(35	)
Revision of Estimate		9			11
Accretion Expense		15			13
Asset Retirement Obligations, Ending Balance	$	260		$	235

Liabilities settled in 2011 related primarily to deepwater and shelf properties in the Gulf of Mexico. Liabilities settled in 2010 related to US onshore assets sold and a Gulf of Mexico shelf asset.

Liabilities incurred in 2010 were due primarily to the Central DJ Basin asset acquisition.

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

Note 10.   Employee Benefit Plans

We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. Net periodic benefit cost related to the retirement and restoration plans was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Service Cost	$	3		$	4		$	10		$	11
Interest Cost		3			3			10			10
Expected Return on Plan Assets		(4	)		(3	)		(11	)		(10	)
Other		2			1			5			4
Net Periodic Benefit Cost	$	4		$	5		$	14		$	15

During the nine months ended September 30, 2011, we made cash contributions of $23 million to the pension plan.

21

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 11.   Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Stock-Based Compensation Expense	$	15		$	13		$	43		$	40
Tax Benefit Recognized		(5	)		(5	)		(15	)		(14	)

During the nine months ended September 30, 2011, we granted stock options and awarded shares of restricted stock (subject to service conditions) as follows:

	Number Granted/Awarded		Weighted Average Fair Value
Stock Options		985,503	$	30.18
Shares of Restricted Stock		403,097	$	90.34

On April 26, 2011, our stockholders approved the amendment and restatement of our 1992 Stock Option and Restricted Stock Plan to increase the number of shares of common stock authorized for issuance under the plan from 24 million to 31 million and modify certain plan provisions.

Note 12.  Basic and Diluted Earnings Per Share

Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock may include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings per share:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
(millions, except per share amounts)
Net Income	$	441		$	232	$	749		$	673
Earnings Adjustment from Assumed Conversion of
Dilutive Shares of Common Stock in Rabbi Trust (1)		(12	)		-		(10	)		3
Net Income Used for Diluted Earnings Per Share Calculation	$	429		$	232	$	739		$	676
Weighted Average Number of Shares Outstanding, Basic		177			175		176			175
Incremental Shares from Assumed Conversion of
Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust		3			2		3			3
Weighted Average Number of Shares Outstanding, Diluted		180			177		179			178
Earnings Per Share, Basic	$	2.50		$	1.33	$	4.25		$	3.86
Earnings Per Share, Diluted		2.39			1.31		4.12			3.80
Number of antidilutive stock options and shares of restricted
stock excluded from calculation above		1			2		2			2

(1) Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the NBL shares held in the rabbi trust are included in the diluted share count.  For this reason, the diluted earnings per share calculations for the three and nine months ended September 30, 2011 exclude deferred compensation gains, net of tax; and the diluted earnings per share calculation for the nine months ended September 30, 2010 excludes a deferred compensation loss, net of tax.

22

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 13.  Income Taxes

The income tax provision consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Current	$	179		$	42		$	289		$	180
Deferred		102			24			147			109
Total Income Tax Provision	$	281		$	66		$	436		$	289
Effective Tax Rate		39	%		22	%		37	%		30	%

Our effective tax rate increased for the first nine months of 2011 as compared with the first nine months of 2010. This was primarily due to the changes in Israeli and UK tax law discussed below and to a $16 million increase in the valuation allowance against our deferred tax asset for foreign tax credits.  Partially offsetting this increase was the impact of greater earnings from equity method subsidiaries in 2011, which has the effect of decreasing the rate when we have pre-tax income. In third quarter 2010, we reversed a $28 million valuation allowance which had been established against a deferred tax asset of the same amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations and recorded a corresponding reduction in income tax expense. Finally, the rate for the first nine months of 2010 was increased by a nondeductible allocation of goodwill to assets sold.

Changes in Israeli Tax Law   In March 2011, the Israeli government enacted the Oil Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs.  We expect these changes to increase our 2011 consolidated effective income tax rate by approximately two percentage points. We expect no remeasurement of our deferred tax assets or liabilities as of December 31, 2010.

Changes in UK Tax Law Also in March 2011, the UK government announced that the Finance Bill 2011 will increase the rate of the Supplementary Charge levied on oil and gas income in the UK from 20% to 32% effective March 24, 2011. This change, which became law on July 19, 2011, increased the tax rate on our UK oil and gas income from 50% to 62% and our 2011 consolidated effective income tax rate by approximately four percentage points. The change also resulted in a remeasurement of our UK deferred tax liability as of December 31, 2010 to reflect the higher effective rate. As a result, we recorded a $34 million increase in both our deferred income tax liability and deferred income tax expense during third quarter 2011. These changes are reflected in our balance sheet and results of operations at September 30, 2011.

Years Remaining Open to Examination   In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2006, Equatorial Guinea – 2007, Israel – 2008, UK – 2007, the Netherlands – 2009, and China – 2006.

Note 14.  Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholders’ equity and classified as AOCL. Comprehensive income was calculated as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
(millions)
Net Income	$	441	$	232		$	749		$	673
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings		-		5			-			15
Less Tax Provision		-		(2	)		-			(5	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		(47	)		23			(141	)
Less Tax Provision		-		16			(8	)		49
Net Change in Other		1		1			4			2
Other Comprehensive Income (Loss)		1		(27	)		19			(80	)
Comprehensive Income	$	442	$	205		$	768		$	593

23

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 15.  Segment Information

We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Senegal and Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), and new ventures.

	Consolidated			United States			West Africa			Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended September 30, 2011
Revenues from Third Parties	$	874		$	520		$	153		$	108	$	45	$	48
Income from Equity Method Investees		50			-			50			-		-		-
Total Revenues		924			520			203			108		45		48
DD&A		225			180			13			8		10		14
Gain on Commodity Derivative Instruments		(322	)		(213	)		(109	)		-		-		-
Income (Loss) Before Income Taxes		722			418			270			88		23		(77	)
Three Months Ended September 30, 2010
Revenues from Third Parties	$	726		$	458		$	64		$	63	$	99	$	42
Reclassification from AOCL (1)		(5	)		(5	)		-			-		-		-
Income from Equity Method Investees		34			-			34			-		-		-
Total Revenues		755			453			98			63		99		42
DD&A		231			184			10			7		20		10
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
(Gain) Loss on Commodity Derivative Instruments		(38	)		(49	)		11			-		-		-
Income (Loss)  Before Income Taxes		298			211			64			51		59		(87	)
Nine Months Ended September 30, 2011
Revenues from Third Parties	$	2,632		$	1,578		$	401		$	236	$	271	$	146
Income from Equity Method Investees		146			-			146			-		-		-
Total Revenues		2,778			1,578			547			236		271		146
DD&A		681			534			30			19		62		36
Gain on Divestiture (2)		(26	)		(1	)		-			-		-		(25	)
Asset Impairments (3)		139			137			-			-		2		-
Gain on Commodity Derivative Instruments		(179	)		(163	)		(16	)		-		-		-
Income (Loss) Before Income Taxes		1,185			631			460			184		161		(251	)
Nine Months Ended September 30, 2010
Revenues from Third Parties	$	2,169		$	1,425		$	243		$	144	$	227	$	130
Reclassification from AOCL (1)		(15	)		(15	)		-			-		-		-
Income from Equity Method Investees		85			-			85			-		-		-
Total Revenues		2,239			1,410			328			144		227		130
DD&A		662			543			28			18		45		28
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
Gain on Commodity Derivative Instruments		(280	)		(277	)		(3	)		-		-		-
Income (Loss) Before Income Taxes		962			681			258			110		132		(219	)
September 30, 2011
Goodwill	$	696		$	696		$	-		$	-	$	-	$	-
Total Assets		15,833			10,921			2,544			1,540		625		203
December 31, 2010
Goodwill		696			696			-			-		-		-
Total Assets		13,282			9,091			2,270			919		770		232

24

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

(1) Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues. All hedge gains and losses had been reclassified to revenues by December 31, 2010.

(2) See Note 3. Acquisitions and Divestitures.

(3) See Note 4. Asset Impairments.

Note 16.  Commitments and Contingencies

Legal Proceedings  We are involved in various legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

See also Part II. Other Information, Item 1. Legal Proceedingsfor further information on pending cases.

Marcellus Shale Joint Venture Partnership See Note 3. Acquisitions and Dispositions for a description of the CONSOL Carried Cost Obligation and  MARC.

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

EXECUTIVE OVERVIEW

We are an independent energy company engaged in global crude oil and natural gas exploration and production. Our strategy is to achieve growth in earnings and cash flows through the continued expansion of a high quality portfolio of assets that is diversified among US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.

Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.

Our financial results for third quarter 2011 included:

· net income of $441 million, as compared with $232 million for third quarter 2010;

· gain on commodity derivative instruments of $322 million (including unrealized mark-to-market gain of $300 million) as compared with a gain on commodity derivative instruments of $38 million (including unrealized mark-to-market gain of $5 million) for third quarter 2010;

· diluted earnings per share of 2.39, as compared with $1.31 for third quarter 2010;

· cash flow provided by operating activities of $556 million, as compared with $608 million for third quarter 2010;

· capital spending, on a cash basis, of $1.2 billion (including $592 million for Marcellus shale assets and equity method investments), as compared with $536 million for third quarter of 2010;

· total liquidity of almost $3.0 billion at the end of the period as compared with $2.8 billion at December 31, 2010; and

· ratio of debt-to-book capital of 34% as compared with 25% at December 31, 2010.

Operational events for third quarter 2011 included:

United States

· produced a record 65 MBoe/d in the DJ Basin with horizontal production exiting the quarter at over 11 MBoe/d;

· completed 25 new horizontal Niobrara wells and added a fifth rig to the program;

· established a new significant position in the Marcellus shale with the acquisition of 314,000 net acres and 50 MMcf/d of existing net production;

International

· Aseng FPSO departed shipyard for Equatorial Guinea;

· record natural gas sales in Israel of 228 MMcf/d, an increase of 28% from the third quarter last year;

· drilled two wells at the Noa development project offshore Israel, ahead of schedule and below anticipated costs; and

· spud the Cyprus A prospect on Block 12 offshore Cyprus.

Entry into Marcellus Shale Joint Venture

On September 30, 2011, we entered an agreement with CONSOL to jointly develop oil and gas assets in the Marcellus shale areas of southwest Pennsylvania and northwest West Virginia. The Marcellus shale joint venture strengthens and rebalances our portfolio, providing an entirely new, material growth area, which will impact future reserves, production, and cash flows.  This transaction complements and further strengthens our US portfolio by adding a high quality asset with substantial growth potential. It significantly increases our inventory of low risk repeatable projects while exposing us to more North American unconventional resources, and we believe the area is one of the most economically attractive natural gas developments onshore US due to its low operating and development cost structure and close access to Northeastern gas markets. The Marcellus shale joint venture, combined with our other domestic projects in the DJ Basin and the deepwater Gulf of Mexico, provide balance to our rapidly expanding international programs.

Under the terms of the agreement, we acquired 50% interests in 628,000 net undeveloped acres, existing Marcellus production, and existing infrastructure for approximately $1.2  billion. Payments will be made in three equal annual installments, with the first installment made at closing.  We will pay an additional $2.1 billion in the form of a carry of CONSOL’s drilling and completion costs. The carry, which we expect to extend over approximately eight years, is capped at $400 million annually and suspended if average Henry Hub natural gas prices fall and remain below $4 per MMBtu for three consecutive months. Initially, we will be the designated operator of the wet gas areas (areas with more condensate or liquids) and CONSOL will be the designated operator of the dry gas areas (areas with little or no condensate or liquids).

As a result of the transaction, we acquired net proved reserves of approximately 400 Bcfe, based on reserves estimates as of December 31, 2010, and 50 MMcf/d of existing production at September 30, 2011.

26

As a result of this transaction, we are now focusing on three core areas within the US: the DJ Basin; the Marcellus shale; and the deepwater Gulf of Mexico.  We are also considering the divestiture of certain mature, non-core onshore US properties from our portfolio.

See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures and Note 5. Debt, Recent Developments in the Marcellus Shale, Liquidity and Capital Resources, and Part II. Other Information. Item 1A. Risk Factors Our entry into the Marcellus shale through our joint venture with CONSOL will subject us to certain financial, operational and legal obligations and additional risks associated with crude oil and natural gas development activities in that region.

Recent Developments in the Eastern Mediterranean

Cyprus   We are currently drilling the Cyprus A-1 exploration well in Block 12, offshore Cyprus. In 1974 the island of Cyprus was partitioned into two parts; the Republic of Cyprus with the majority of the south under its effective control, and the Turkish controlled area in the north, which calls itself the Turkish Republic of Northern Cyprus and is recognized only by Turkey. The United Nations recognizes the sovereignty of the Republic of Cyprus over the entire island. The Republic of Cyprus has been a member of the European Union since May 1, 2004.  The Turkish government opposes the current exploratory activities being conducted by the Republic of Cyprus, claiming it will have a detrimental effect on reunification negotiations, which have been conducted over three decades and are currently being brokered by the United Nations.  While Turkey has voiced its opposition to the drilling activity, the European Union, Russia and the US have supported Cyprus' right to drill.

Israel   Israel’s diplomatic relations with Turkey and Egypt have been deteriorating. In September 2011, Turkey downgraded diplomatic and trade ties with Israel.

These events have increased the political and social uncertainty in the region; and, at this time, we are uncertain of the outcome of these events.  Disruptions caused by territorial or boundary disputes could have an adverse effect on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges. In addition, we may not have enough insurance to cover any losses.

Recent Developments Surrounding the Use of Hydraulic Fracturing and Production from Shale Formations

Hydraulic fracturing is a process commonly used to stimulate production of natural gas and/or oil from dense subsurface rock formations, including shale. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs, including the DJ Basin. We are in the process of securing additional water rights that will support our DJ Basin drilling program and implementing a pilot water recycling program.

We also expect to use hydraulic fracturing in the development of the Marcellus shale.Our joint development agreement with CONSOL provides us with access to water resources, which we believe will be adequate to execute our development program, and we anticipate the ability to recycle most of the water produced from hydraulic fracturing activities in the Marcellus shale.

As the use of hydraulic fracturing has expanded in recent years, public concern has grown over its possible effects on the environment, including drinking water supplies.  We do not believe that properly conducted hydraulic fracturing poses a meaningful risk to water supplies. However, the use of hydraulic fracturing continues to be the subject of controversy in the US where it is often opposed by environmental activists as well as by local citizens in certain areas.

Federal and state rules and regulations governing the reporting and use of hydraulic fracturing continue to evolve. For example, on July 28, 2011, the Environmental Protection Agency (EPA) issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells which would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed rules include maximum achievable control technology standards for certain equipment not currently subject to such standards.  Final action on the proposed rules is expected no later than February 28, 2012.

Earlier in 2011, the US Secretary of Energy formed the Shale Gas Production Subcommittee (Subcommittee), a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of hydraulic fracturing.  On August 18, 2011, the Subcommittee issued its 90-Day Report (Report), which focused exclusively on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other areas, communications, air quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas.  The Subcommittee is scheduled to issue a 180-day final report in November 2011. We will continue to monitor the impact the Subcommittee’s recommendations, and any resulting rule-making activities, could have on our exploration and development activities in shale formations.

In June 2011, Texas adopted a law requiring disclosure of certain information regarding the components used in the hydraulic-fracturing process.

27

We continue to monitor new and proposed legislation to assess the potential impact on our operations. We are currently evaluating the possible impact any proposed rules, such as those described above, could have on our business.  Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves.

See Part II. Other Information. Item 1A. Risk Factors Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

Recent Developments in the Marcellus Shale

On September 7, 2011, an intermediate appellate court (Superior Court) of Pennsylvania issued an opinion in Butler v. Powers regarding the meaning of a deed. As a result, traditional views of how ownership of shale gas is determined in that state have been called into question. The issue is whether shale gas is different from other natural gas and should be considered part of mineral rights, rather than oil and gas rights, because it is contained inside rock. At this time, no case law or interpretation of existing law has changed, nor has there been an indication that either the Superior Court or the Pennsylvania Supreme Court will seek to change existing law. Based upon the limited review performed to date, we believe that any adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL.

On October 3, 2011, Governor Tom Corbett of Pennsylvania announced his plan for state oversight of the Marcellus shale natural gas industry. His plan includes numerous recommendations recently proposed by the Marcellus Shale Advisory Commission. Standards related to unconventional drilling would include increases in well setback distances, increases in bonding requirements, increases in penalties, expansion of the distance from a well for which a driller can be liable for environmental damage, and broadening of the Department of Environmental Protection’s authority to withhold or revoke permits. The plan also allows for an impact fee, which would be adopted by counties for use by local communities experiencing the actual impacts of drilling. The fee will be used by local governments, counties and state agencies that are involved in Marcellus Shale natural gas drilling. We are monitoring rule-making activities of the Pennsylvania legislature to assess the possible impact any recommendations could have on our business. Enactment of an impact fee and/or other proposals would likely result in a lower rate of return on our development project.

See Part II. Other Information. Item 1A. Risk Factors  Our entry into the Marcellus shale through our joint venture with CONSOL will subject us to certain financial, operational and legal obligations and additional risks associated with crude oil and natural gas development activities in that region  and  Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

Impact of Amendments to Rule 318A

On August 9, 2011, the Colorado Oil and Gas Conservation Commission approved amendments to The Greater Wattenberg Area Special Well Location Rule 318A (Rule 318A), which addresses oil and gas well drilling, production, commingling and spacing in the Wattenberg field. The amendments, which became effective on October 1, 2011, remove the limit on the number of wells which can produce from a particular formation and address areas such as infill drilling, water sampling and waste management plans. We believe the amendments will enhance our horizontal well drilling program by removing the numerical limitation on wells, allowing wellbore spacing units and permitting wells to cross section lines.

Exploration Program Update

We have significant remaining exploration potential, primarily in the onshore US, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean and other international areas where we hold acreage positions. Significant exploratory wells were in progress at September 30, 2011, and we expect to continue an active exploratory drilling program in fourth quarter 2011. We do not always encounter commercially productive reservoirs through our drilling operations and, as a result, dry hole cost could be significant. Updates of our significant exploration activities are as follows:

DJ Basin (US Onshore)We continue to acquire 3-D seismic information and appraise our acreage in Northern Colorado and Wyoming.

Deep Blue (Deepwater Gulf of Mexico)   We obtained approval for a drilling permit and resumed exploratory drilling during third quarter 2011.

Dolphin 1 (Offshore Israel) We are in the process of drilling the Dolphin 1 prospect in the Hanna license, southwest of the Tamar gas field.

Leviathan (Offshore Israel)   We are conducting appraisal drilling activities at the Leviathan-3 well.

28

Cyprus A-1 (Offshore Cyprus)   We are in the process of drilling the Cyprus A-1 exploratory well in Block 12.

Major Development Projects Update

During third quarter 2011, we continued to advance our major development projects, which we expect to deliver significant growth over the next several years. Updates on our significant development projects are as follows:

DJ Basin (US Onshore)  We have increased our horizontal drilling activity targeting the Niobrara formation, completing 25 horizontal wells during the quarter. We recently added another drilling rig to our program and are currently running five horizontal drilling rigs.

Marcellus Shale Joint Venture (US Onshore)   We are in the process of assuming operatorship of the wet gas areas. There are currently four horizontal rigs operating on the joint venture properties and we expect that an additional rig will be added during fourth quarter 2011. See Part II. Other Information. Item 1A. Risk Factors – Our entry into the Marcellus shale through our joint venture with CONSOL will subject us to certain financial, operational and legal obligations and additional risks associated with crude oil and natural gas development activities in that region.

Galapagos (Deepwater Gulf of Mexico)  Installation of topside equipment at the host facility and subsea tiebacks for the Santa Cruz, Isabela and Santiago wells are progressing. We currently expect production to commence in early 2012.

Gunflint (Deepwater Gulf of Mexico)   Once a drilling permit is approved, we plan to conduct appraisal drilling to help define the extent of the reservoir and a potential development scenario.

Aseng (Offshore Equatorial Guinea) The FPSO sailed for the Aseng field during third quarter and arrived on October 16, 2011. We currently expect production to commence by year end 2011. We have executed an oil sale, purchase, and marketing agreement with Glencore Energy UK Ltd for our share of Aseng production.

Alen (Offshore Equatorial Guinea) Platform fabrication is underway. We have commenced development drilling and currently expect production to commence by the end of 2013.

Carmen/Diega (Offshore Equatorial Guinea)   We are evaluating drilling results and formulating a development plan.

West Africa Gas Project (Offshore Equatorial Guinea)    The Equatorial Guinea Ministry of Mines, Industry and Energy is considering the development of an integrated gas project (Integrated project) which includes upstream gas projects, the required gas transportation system, and a second LNG train. A Coordinating Committee was formed to determine the viability and scope of the Integrated project. We have been appointed chair of the Coordinating Committee.

Tamar (Offshore Israel) Development drilling, platform fabrication and subsea production system installation are underway. Tamar remains on schedule for commissioning beginning in late 2012.

Noa (Offshore Israel)   The Noa field will be developed as a subsea tieback to the Mari-B platform. Two development wells have been drilled, FEED (front end engineering and design) work continues, and bid packages are being evaluated. Production is expected to commence in the second half of 2012.

Leviathan (Offshore Israel)   We are evaluating potential development scenarios for the Leviathan natural gas discovery and planning pre-FEED activities.

Leviathan-2 Insurance Recoveries

In May 2011, we ended drilling operations at the Leviathan-2 appraisal well location offshore Israel. During the drilling process, we identified water flowing to the sea floor from the wellbore. We are monitoring the wellbore and there are no indications of any hydrocarbons in the produced water.

The incident was a covered event under our well control insurance; therefore, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. As of September 30, 2011, we had recorded a loss on involuntary conversion of $4 million. In addition, we wrote off the net book value of the asset and recorded a corresponding receivable for probable insurance claims of $25 million. We expect to continue to incur costs and submit claims in the normal course of business in 2011 and 2012 and expect the final amount recovered to increase from the current estimate. See Item 1. Financial Statements – Note 2. Basis of Presentation and Liquidity and Capital Resources – Insurance Recoveries, below.

Asset Impairments

We recorded asset impairment charges of $139 million during the first nine months of 2011 and $100 million during the first nine months of 2010. The impairments were primarily due to field performance and/or a low natural gas price environment. Future decreases in forward natural gas prices or other factors, such as significant increases in development or operating costs or unsatisfactory drilling results, could result in additional impairment charges. See Item 1. Financial Statements – Note 4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures, and Potential for Future Asset Impairments, below.

29

Divestitures

In May 2011, we completed the transfer of our assets in Ecuador to various government-affiliated entities. We received compensation for the offshore Amistad field assets and Block 3 PSC which was terminated by the government of Ecuador on November 25, 2010, as well as for the Machala Power Electricity concession and its associated assets and recorded a gain of approximately $26 million. In August 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas for sales proceeds of $552 million and recorded a gain of $114 million on the sale. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

Sales Volumes

On a BOE basis, total sales volumes were 3% lower third quarter 2011 as compared with third quarter 2010, and our mix of sales volumes was 37% global liquids, 36% international natural gas, and 27% US natural gas. International sales volumes were higher in Equatorial Guinea, due to more liftings, and Israel. US production decreased slightly year to year due to sales of mature, non-core properties in 2010. Our volumes for third quarter 2011 did not include natural gas in Ecuador, where our PSC was terminated in late 2010. In addition, we have suspended spot sales of natural gas from the Mari-B field in Israel in order to assure adequate supply to our customers under long-term sales contracts. See Results of Operations – Revenues, below.

Commodity Price Changes and Hedging

Average realized crude oil prices for third quarter 2011 increased 34% as compared with third quarter 2010 and were driven by stronger global crude oil markets.

Total average realized natural gas prices for third quarter 2011 increased 14% as compared with third quarter 2010 primarily due to higher international natural gas pricing.

We have hedged approximately 49% of our expected global crude oil production and 56% of our expected domestic natural gas production for the remainder of 2011.

OPERATING OUTLOOK

Our expected crude oil, natural gas and NGL production for 2011 may be impacted by several factors including:

· overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, are expected to maintain our near-term production volumes;

· timing of major development project completion and initial production;

· ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;

· ramp-up of development activity in the Marcellus shale;

· natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations and in the North Sea;

· variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;

· Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt;

· variations in North Sea sales volumes due to potential FPSO downtime and timing of liftings;

· potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;

· potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus shale areas of our US operations;

· potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus shale areas of our US operations; and

· potential purchases of producing properties and/or divestments of non-core operating assets.

2011 Capital Investment Program

Our 2011 capital program is expected to total approximately $3.0 billion, excluding our Marcellus shale joint venture acquisition costs. The capital program includes approximately $110 million for planned development in our new Marcellus shale core area during the remainder of 2011. We expect to accrue approximately $70 million for the Aseng FPSO lease obligation during 2011. We expect to contribute approximately $12 million in 2011 to CONE Gathering LLC to fund our share of the work program.

We expect that the 2011 capital investment program will be funded from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as our issuance of long-term debt in first quarter 2011. See Liquidity and Capital Resources.

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We will evaluate the level of capital spending throughout the year based on the following factors, among others:

· commodity prices;

· cash flows from operations;

· operating and development costs and possible inflationary pressures;

· permitting activity in the deepwater Gulf of Mexico;

· potential changes in the fiscal regimes of the US and other countries in which we operate;

· impact of implementation of the Dodd-Frank Act on our business practices, including, among others, requirements regarding the posting of cash collateral in hedging transactions;

· drilling results;

· property acquisitions and divestitures; and

· potential legislative or regulatory changes regarding the use of hydraulic fracturing.

Current Global Economic Situation, Changes in Fiscal Regimes and Market Regulations

The recovery from the global financial crisis has been slow and uneven. In the past few months various events, including the US debt downgrade, the European debt crisis, slower GDP growth rates, and reduced consumer demand, have increased economic uncertainty. Many governments are facing demands to increase social spending. Increased spending on public entitlement and/or economic stimulus programs, coupled with a reduced tax base, has resulted in significant budget deficits in many countries. Against this backdrop, global commodity prices have recovered significantly.

In order to address negative fiscal situations and initiate deficit reduction measures, many governments are seeking additional revenue sources, including increases in government take from oil and gas projects. Recently, the President of the United States proposed the American Jobs Act of 2011 (American Jobs Act). The American Jobs Act contains various measures, including tax increases and other revenue-raising proposals, designed to reduce the federal deficit by $3 trillion. Certain proposals, if enacted, would eliminate key US federal income tax incentives currently available to oil and natural gas exploration and production companies including: the repeal of the percentage depletion allowance for oil and natural gas properties, the elimination of current deductions for intangible drilling and development costs, the elimination of the deduction for certain domestic production activities, and an extension of the amortization period for certain geological and geophysical expenditures. In addition, the Joint Select Committee on Deficit Reduction, a panel established by the recent Budget Control Act of 2011, is charged with recommending at least $1.2 trillion in deficit reductions by November 23, 2011.

Future economic and political changes in the US or other countries in which we operate could result in governments enacting additional taxes and/or other market interventions, which could be detrimental to oil and gas companies. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

During the first nine months of 2011, fiscal regime changes occurred in both Israel and the UK.

Israel    In March 2011, the Israeli government enacted the Oil Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs. We currently expect these changes to increase our 2011 consolidated income tax expense by approximately $25 million and increase our 2011 consolidated effective income tax rate by approximately two percentage points. We expect no remeasurement of our deferred tax assets or liabilities as of December 31, 2010. The impact of these changes is reflected in our balance sheet and results of operations at September 30, 2011.

The change in Israel’s fiscal regime may negatively impact our future operations by reducing future project profitability, as compared with profitability under the previous fiscal regime, and potentially reducing the economic attractiveness of exploration activities.

UK   Also in March 2011, the UK government announced that the Finance Bill 2011 will increase the rate of the Supplementary Charge levied on oil and gas income in the UK from 20% to 32% effective March 24, 2011. This change became law on July 19, 2011. We expect the change will increase the tax rate on our UK oil and gas income from 50% to 62%, resulting in an increase of approximately $54 million in our 2011 consolidated income tax expense and an increase in our 2011 consolidated effective income tax rate by approximately four percentage points. The estimated increases in our consolidated income tax expense and effective income tax rate include the impact of remeasuring our UK deferred tax liability as of December 31, 2010 to reflect the higher effective rate. During third quarter 2011, we recorded an increase in both our deferred income tax liability and deferred income tax expense of $34 million. The impact of these changes is reflected in our balance sheet and results of operations at September 30, 2011.

See Item 1. Financial Statements – Note 13. Income Taxes.

Israeli Interministerial Committee   The Israeli Interministerial Committee to Examine Government Policy on Israel’s Natural Gas Economy (Interministerial Committee) has been charged with the task of proposing a government policy for developing the natural gas economy in Israel. Objectives include ensuring energy security for the economy, encouraging competition among various sectors in the local economy, and generating economic and political benefits for Israel.  Among other things, the Interministerial Committee will examine the best policy for safeguarding reserves to provide for local consumption and for exporting natural gas. The Interministerial Committee is expected to present its recommendations by February 29, 2012. We are monitoring the activities of the Interministerial Committee to assess the possible impact any recommendations could have on our business.

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Potential for Future Asset Impairments

The domestic natural gas market remains weak. A decrease in forward natural gas prices for the remainder of 2011 could result in significant impairment charges. Our Piceance basin (western Colorado), Shattuck (western Oklahoma), and Bowdoin (north central Montana) properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These assets, which have a combined net book value of approximately $1.0 billion at September 30, 2011, are at risk of impairment if future NYMEX Henry Hub natural gas prices experience further decline. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. See Item 1. Financial Statements – Note 4. Asset Impairments.

Risk and Insurance Program

Our business is subject to all of the operating risks normally associated with the exploration, production, gathering, processing and transportation of crude oil and natural gas, including hurricanes, blowouts, well cratering and fire, any of which could result in damage to, or destruction of, oil and natural gas wells or formations or production facilities and other property and injury to persons. As protection against financial loss resulting from many, but not all of these operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of production), employer’s liability, comprehensive general liability and worker’s compensation insurance.  We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

For example, in certain international locations (including Equatorial Guinea and Israel) we carry business interruption insurance for loss of revenue arising from physical damage to our facilities caused by fire and natural disasters. The coverage is subject to customary deductibles, waiting periods and recovery limits.

In the Gulf of Mexico, we self-insure for windstorm exposure. Our Gulf of Mexico assets are primarily subsea operations; therefore, our windstorm exposure is limited. In addition, the cost of windstorm insurance continues to be very expensive and coverage amounts are limited. We believe it is more cost-effective for us to self-insure these assets. As a result, we are responsible for substantially all windstorm-related damages to our Gulf of Mexico assets.

In accordance with industry practice, oil and gas well owners generally indemnify drilling rig contractors against certain risks, such as those arising from property and environmental losses, pollution from sources such as oil spills, or contamination resulting from well blowout or fire or other uncontrolled flow of hydrocarbons. Most of our domestic and international drilling contracts contain such indemnification clauses. In addition, oil and gas well owners typically assume all costs of well control in the event of an uncontrolled well. We currently carry insurance protection for our net share of any potential financial losses occurring as a result of events such as the Deepwater Horizon Incident. This protection consists of $500 million of well control, pollution cleanup and consequential damages coverage and $326 million of additional pollution cleanup and consequential damages coverage, which also covers third party personal injury and death.  Consequently, if we were to experience an accident similar to the Deepwater Horizon Incident, our total insurance for cleanup and consequential damages would cover a gross loss of $826 million, subject to reduction for claims related to well control and third party damages.

We expect the future availability and cost of insurance will be impacted by the Japanese earthquake and subsequent tsunami as well as by the Deepwater Horizon Incident.  Impacts could include tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills. We anticipate that current changes in the types of coverage available in the insurance market will result in lower effective coverages and/or the incurrence of higher premiums to achieve past levels of coverage.

During 2010, various Congressional committees began pursuing legislation to increase or remove liability caps for deepwater drilling. The current $75 million liability limit under the Oil Pollution Act may be materially increased or lifted in its entirety.  Such a requirement would ultimately require a company to maintain either a much higher level of insurance coverage than was standard for the industry in the past, or a financial position large enough that a company could settle its own damage claims. We anticipate that, at a minimum, less insurance coverage will be available and at a higher cost. We continue to monitor the legislative and regulatory response to the Deepwater Horizon Incident and its impact on the insurance market and our overall risk profile. Accordingly, we may adjust our risk and insurance program to provide protection at insured levels that reflect our perception of the cost of risk relative to frequency and severity of the exposure.

Deepwater drilling entails inherent risks. We have a risk assessment program that analyzes safety and environmental hazards and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We have a strong safety performance record and continue to manage our risks and operations such that the likelihood of a significant accident or spill is remote. However, if an event occurs that is not covered by insurance or not fully protected by insured limits, it could have a material adverse impact on our results of operations, cash flows and financial condition.

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Oil Spill Response Preparedness

We maintain membership in Clean Gulf Associates (CGA), a nonprofit association of production and pipeline companies operating in the Gulf of Mexico. On behalf of its membership, CGA has contracted with Helix Energy Solutions Group (HESG) for the provision of subsea intervention, containment, capture and shut-in capacity for deepwater Gulf of Mexico exploration wells. The system, known as the Helix Fast Response System (HFRS), at full production capacity, can process up to 55 MBbl/d of oil, 70 MBbl/d of liquids and 95 MMcf/d of natural gas, at 10,000 pounds per square inch (psi) in water depths to 10,000 feet. The containment resources also include a 15,000 psi-gauge intervention capping stack designed to handle extremely high-pressure, deeper wells in the deepwater Gulf of Mexico. We have entered into a separate utilization agreement with HESG which specifies the asset day rates should the HFRS system be deployed.

Recently Issued Accounting Standards Update

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

RESULTS OF OPERATIONS

Revenues

Revenues were as follows:

					Increase from
	2011		2010		Prior Year
(millions)
Three Months Ended September 30, 2011
Oil, Gas and NGL Sales	$	874	$	704		24	%
Income from Equity Method Investees		50		34		47	%
Other Revenues		-		17		(100	%)
Total	$	924	$	755		22	%
Nine Months Ended September 30, 2011
Oil, Gas and NGL Sales	$	2,599	$	2,102		24	%
Income from Equity Method Investees		146		85		72	%
Other Revenues		33		52		(37	%)
Total	$	2,778	$	2,239		24	%

Changes in revenues are discussed below.

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Oil, Gas and NGL SalesAverage daily sales volumes and average realized sales prices were as follows:

	Sales Volumes								Average Realized Sales Prices
	Crude Oil & Condensate		Natural Gas		NGLs		Total		Crude Oil & Condensate		Natural Gas		NGLs
	(MBbl/d)		(MMcf/d)		(MBbl/d)		(MBoe/d) (1)		(Per Bbl)		(Per Mcf)		(Per Bbl)
Three Months Ended September 30, 2011
United States		38		358		16		113	$	91.21	$	3.98	$	49.57
Equatorial Guinea (2)		15		250		-		57		108.11		0.27		-
Israel		-		228		-		38		-		5.15		-
North Sea		4		4		-		5		115.67		8.41		-
China		4		-		-		4		108.57		-		-
Total Consolidated Operations		61		840		16		217		98.15		3.21		49.57
Equity Investees (3)		2		-		5		7		107.90		-		72.70
Total Operations		63		840		21		224	$	98.43	$	3.21	$	55.74
Three Months Ended September 30, 2010
United States (4)		41		399		13		120	$	71.28	$	3.87	$	36.30
Equatorial Guinea (2)		8		243		-		49		76.28		0.27		-
Israel		-		178		-		30		-		3.85		-
North Sea		13		6		-		14		78.89		5.82		-
Ecuador (5)		-		28		-		5		-		-		-
China		4		-		-		4		71.37		-		-
Total Consolidated Operations		66		854		13		222		73.41		2.82		36.30
Equity Investees (3)		2		-		6		8		77.03		-		50.83
Total Operations		68		854		19		230	$	73.53	$	2.82	$	40.77
Nine Months Ended September 30, 2011
United States		37		373		14		114	$	95.10	$	4.09	$	49.19
Equatorial Guinea (2)		13		244		-		54		108.40		0.27		-
Israel		-		180		-		30		-		4.80		-
North Sea		8		6		-		9		112.99		7.90		-
China		4		-		-		4		104.99		-		-
Total Consolidated Operations		62		803		14		211		100.86		3.12		49.19
Equity Investees (3)		2		-		5		7		109.20		-		74.70
Total Operations		64		803		19		218	$	101.09	$	3.12	$	55.95
Nine Months Ended September 30, 2010
United States (4)		40		399		13		119	$	73.31	$	4.38	$	40.17
Equatorial Guinea (2)		11		221		-		48		75.44		0.27		-
Israel		-		129		-		22		-		4.08		-
North Sea		10		7		-		11		77.33		5.25		-
Ecuador (5)		-		28		-		4		-		-		-
China		4		-		-		4		73.27		-		-
Total Consolidated Operations		65		784		13		208		74.30		3.13		40.17
Equity Investees (3)		2		-		5		7		75.84		-		52.04
Total Operations		67		784		18		215	$	74.35	$	3.13	$	43.58

(1) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price differentials, the price for a barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.

(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 and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

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

(4) Average realized crude oil and condensate prices reflect reductions of $1.25 per Bbl for third quarter 2010 and $1.31 per Bbl for the first nine months of 2010 from hedging activities.

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Average realized natural gas prices reflect a reduction of $0.01 per Mcf for the first nine months of 2010 from hedging activities.  The average realized natural gas price for the third quarter of 2010 was not impacted by hedging activities, as the net deferred amounts reclassified from AOCL were de minimis.

The price reductions resulted from hedge gains/losses that were previously deferred in AOCL.  All hedge gains or losses had been reclassified to revenues by December 31, 2010.

(5) Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales for 2010 were eliminated for accounting purposes. Electricity sales (through May 2011) are included in other revenues. See Item 1. Financial Statements – Note 2. Basis of Presentation and Note 3. Acquisitions and Divestitures.

If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:

	Commodity Price Increase (Decrease)
	2011					2010
	Crude Oil & Condensate			Natural Gas		Crude Oil & Condensate			Natural Gas
	(Per Bbl)			(Per Mcf)		(Per Bbl)			(Per Mcf)
Three Months Ended September 30,
United States	$	(1.23	)		.79	$	0.86		$	0.87
Equatorial Guinea		-			-		(2.09	)		-
Total Consolidated Operations		(.77	)		.34		0.27			0.41
Total Operations		(.74	)		.34		0.26			0.41
Nine Months Ended September 30,
United States	$	(3.52	)		.74	$	0.16		$	0.63
Equatorial Guinea		-			-		(1.86	)		-
Total Consolidated Operations		(2.10	)		.34		(0.22	)		0.32
Total Operations		(2.04	)		.34		(0.21	)		0.32

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

	Sales Revenues
	Crude Oil & Condensate			Natural Gas			NGLs		Total
(millions)
Three Months Ended September, 2010	$	446		$	214		$	44	$	704
Changes due to
Increase (Decrease) in Sales Volumes		(30	)		4			8		(18	)
Increase in Sales Prices Before Hedging		134			31			18		183
Change in Amounts Reclassified from AOCL		5			-			-		5
Three Months Ended September 30, 2011	$	555		$	249		$	70	$	874
Nine Months Ended September 30, 2010	$	1,313		$	646		$	143	$	2,102
Changes due to
Increase (Decrease) in Sales Volumes		(46	)		40			17		11
Increase (Decrease) in Sales Prices Before Hedging		439			(4	)		36		471
Change in Amounts Reclassified from AOCL		14			1			-		15
Niine Months Ended September 30, 2011	$	1,720		$	683		$	196	$	2,599

Crude oil and condensate sales – Revenues from crude oil and condensate sales increased during the third quarter and first nine months of 2011 as compared with 2010 due to the following:

· increases in average realized prices;

· higher sales volumes in the DJ Basin attributable to the continued acceleration of our vertical and horizontal drilling programs in Wattenberg;

· higher sales volumes attributable to the Central DJ Basin asset acquisition that closed in March 2010; and

· higher sales volumes in Equatorial Guinea due to a higher number of liftings;

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partially offset by:

· decreases in sales volumes from the Gulf Coast and Mid-Continent areas due to natural field decline;

· a decrease in onshore US volumes due to the sale of certain Oklahoma and Illinois Basin assets in 2010; and

· a decrease in North Sea volumes due to downtime in the Dumbarton field for FPSO maintenance.

Revenues from crude oil and condensate sales included deferred losses of $5 million for the third quarter of 2010 and $14 million for the first nine months of 2010 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges.  As of December 31, 2010, there were no further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to crude oil revenues.

Natural gas sales – Revenues from natural gas sales increased during the third quarter and first nine months of 2011 as compared with 2010 due to the following:

· higher natural gas prices during third quarter 2011 primarily due to increases in sales prices in Israel which benefit from strong global liquids markets;

· an increase in Israel sales volumes due to an increase in demand for our natural gas driven by higher electricity production and lower levels of competitor natural gas imports from Egypt;

· higher sales volumes in the DJ Basin attributable to the continued acceleration of our vertical and horizontal drilling programs in the Wattenberg area ;

· higher sales volumes attributable to the Central DJ Basin asset acquisition that closed in March 2010; and

· higher sales volumes in Equatorial Guinea as compared with the first nine months of 2010, during which time the Alba field experienced a planned shut-down for facilities maintenance and repair;

partially offset by:

· a decrease in onshore US sales volumes due to the sale of certain Oklahoma and Illinois Basin assets in 2010; and

· decreases in sales volumes from the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas due to natural field decline.

Revenues from natural gas sales included a deferred loss of $1 million for the first nine months of 2010 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges. Revenues for the third quarter of 2010 included de minimis amounts reclassified from AOCL. As of December 31, 2010, there were no further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to natural gas revenues.

NGL sales – Most of our US NGL production is from the Wattenberg area and deepwater Gulf of Mexico. NGL sales revenues increased during the third quarter and first nine months of 2011 as compared with 2010 due to higher realized prices and a slight increase in sales volumes due to ongoing development activity in the Wattenberg area.

Income from Equity Method InvesteesWe have a 45% interest in Atlantic Methanol Production Company, LLC, which owns and operates a methanol plant and related facilities and a 28% interest in Alba Plant LLC, which owns and operates a liquefied petroleum gas processing plant. Both plants are located onshore on Bioko Island in Equatorial Guinea.  Equity method investments are included in other noncurrent assets in our consolidated balance sheets, our share of earnings is reported as income from equity method investees in our consolidated statements of operations, and our share of dividends is reported within cash flows from operating activities in our consolidated statements of cash flows.

The increase in income from equity method investees for the third quarter and first nine months of 2011 as compared with 2010 was due to increases in average realized condensate, LPG and methanol prices due to global economic recovery, and increases in methanol sales volumes. Condensate and LPG sales volumes and average realized prices are included in the average daily sales volumes and average realized sales prices table above.

Methanol sales volumes and prices were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Methanol Sales Volumes (Mmgal)		41		33		119		102
Methanol Sales Prices (per gallon)	$	1.08	$	0.84	$	1.04	$	0.84

Other Revenues   Other revenues include electricity sales and other revenues from operating activities. See Item 1. Financial Statements – Note 2.  Basis of Presentation.

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Operating Costs and Expenses

Operating costs and expenses were as follows:

							Increase (Decrease)
	2011			2010			from Prior Year
(millions)
Three Months Ended September 30,
Production Expense	$	153		$	141			9	%
Exploration Expense		57			35			63	%
Depreciation, Depletion and Amortization		225			231			(3	%)
General and Administrative		89			65			37	%
Gain on Divestitures		-			(114	)		(100	%)
Asset Impairments		-			100			(100	%)
Other Operating (Income) Expense, Net		2			4			(50	%)
Total	$	526		$	462			14	%
Nine Months Ended September 30,
Production Expense	$	449		$	430			4	%
Exploration Expense		195			167			17	%
Depreciation, Depletion and Amortization		681			662			3	%
General and Administrative		254			194			31	%
Gain on Divestitures		(26	)		(114	)		(77	%)
Asset Impairments		139			100			39	%
Other Operating (Income) Expense, Net		45			59			(24	%)
Total	$	1,737		$	1,498			16	%

Changes in operating costs and expenses are discussed below.

Production Expense   Components of production expense were as follows:

	Total per BOE (1)		Total		United States		Equatorial Guinea		Israel		North Sea		Other Int'l, Corporate
(millions, except unit rate)
Three Months Ended September 30, 2011
Lease Operating Expense (2)	$	4.89	$	98	$	66	$	12	$	2	$	10		$	8
Production and Ad Valorem Taxes		1.92		38		25		-		-		-			13
Transportation Expense		0.88		17		15		-		-		2			-
Total Production Expense	$	7.69	$	153	$	106	$	12	$	2	$	12		$	21
Three Months Ended September 30, 2010
Lease Operating Expense (2)	$	4.65	$	95	$	60	$	11	$	2	$	16		$	6
Production and Ad Valorem Taxes		1.40		29		24		-		-		-			5
Transportation Expense		0.84		17		14		-		-		2			1
Total Production Expense	$	6.89	$	141	$	98	$	11	$	2	$	18		$	12
Nine Months Ended September 30, 2011
Lease Operating Expense (2)	$	5.00	$	288	$	188	$	35	$	9	$	38		$	18
Production and Ad Valorem Taxes		1.87		108		77		-		-		-			31
Transportation Expense		0.92		53		45		-		-		6			2
Total Production Expense	$	7.79	$	449	$	310	$	35	$	9	$	44		$	51
Nine Months Ended September 30, 2010
Lease Operating Expense (2)	$	4.97	$	283	$	193	$	31	$	7	$	38		$	14
Production and Ad Valorem Taxes		1.69		96		80		-		-		-			16
Transportation Expense		0.90		51		44		-		-		5			2
Total Production Expense	$	7.56	$	430	$	317	$	31	$	7	$	43		$	32

(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.

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For the third quarter and first nine months of 2011, total production expense increased as compared with 2010 due to the following:

· an increase in US lease operating expense due to higher sales volumes from the Wattenberg area due to ongoing development activities;

· increases in Equatorial Guinea and Israel lease operating expense due to higher sales volumes, as discussed above; and

· an increase in China production taxes due to higher commodity prices;

partially offset by:

· a decrease in US lease operating expense due to the sale of certain Oklahoma and Illinois Basin assets in 2010;  and

· a decrease in US production taxes due to lower crude oil sales volumes related to the sale of certain Oklahoma assets in 2010 and natural field decline in the Gulf Coast and Mid-Continent areas.

Oil and Gas Exploration Expense   Components of oil and gas exploration expense were as follows:

	Total		United States			West Africa (1)		Eastern Mediter- ranean (2)		North Sea		Other Int'l, Corporate (3)
(millions)
Three Months Ended September 30, 2011
Dry Hole Cost	$	13	$	-		$	13	$	-	$	-	$	-
Seismic		8		5			-		-		-		3
Exploration Expense		33		14			1		1		1		16
Other		3		3			-		-		-		-
Total Exploration Expense	$	57	$	22		$	14	$	1	$	1	$	19
Three Months Ended September 30, 2010
Dry Hole Cost	$	2	$	1		$	-	$	-	$	-	$	1
Seismic		17		4			-		4		-		9
Exploration Expense		12		(4	)		1		1		1		13
Other		4		4			-		-		-		-
Total Exploration Expense	$	35	$	5		$	1	$	5	$	1	$	23
Nine Months Ended September 30, 2011
Dry Hole Cost	$	57	$	20		$	37	$	-	$	-	$	-
Seismic		47		28			1		3		-		15
Exploration Expense		77		26			4		1		2		44
Other		14		14			-		-		-		-
Total Exploration Expense	$	195	$	88		$	42	$	4	$	2	$	59
Nine Months Ended September 30, 2010
Dry Hole Cost	$	57	$	53		$	3	$	-	$	-	$	1
Seismic		52		32			5		6		-		9
Exploration Expense		46		4			4		2		2		34
Other		12		12			-		-		-		-
Total Exploration Expense	$	167	$	101		$	12	$	8	$	2	$	44

(1) West Africa includes Equatorial Guinea, Cameroon, Senegal and Guinea-Bissau.

(2) Eastern Mediterranean includes Israel and Cyprus.

(3) Other International includes China and various international new ventures such as offshore Nicaragua and offshore France.

Oil and gas exploration expense for the third quarter and first nine months of 2011 included the following:

· dry hole cost associated with exploratory drilling in the US Rocky Mountain area and offshore Senegal and Guinea-Bissau;

· acquisition of seismic information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, offshore Nicaragua, offshore France, and offshore Cyprus; and

· staff expense associated with new ventures offshore Nicaragua and offshore France.

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Oil and gas exploration expense for the third quarter and first nine months of 2010 included the following:

· US dry hole cost associated with the Double Mountain exploration well in the deepwater Gulf of Mexico;

· acquisition of seismic information in the US in support of Central Gulf of Mexico lease sales and in West Africa for Cameroon;

· and staff expense associated with new ventures.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
DD&A Expense (millions) (1)	$	225	$	231	$	681	$	662
Unit Rate per BOE (2)	$	11.30	$	11.35	$	11.84	$	11.64

(1) For DD&A expense by geographical area, see Item 1. Financial Statements – Note 15. Segment Information.

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

Total DD&A expense for the first nine months of 2011 increased as compared with 2010 due to the following:

· higher DD&A expense in the Wattenberg area of our onshore US operations due to higher sales volumes resulting from ongoing capital spending;

· higher DD&A expense in Equatorial Guinea due to higher sales volumes; and

· higher DD&A expense in China due to higher costs associated with development activities;

 partially offset by:

· lower DD&A expense in the deepwater Gulf of Mexico, Gulf Coast, and Mid-Continent areas of our US operations due to lower sales volumes resulting from natural field decline; and

· the cessation of DD&A associated with certain Oklahoma and Illinois Basin assets sold during 2010.

Changes in the unit rate per BOE for the third quarter and first nine months of 2011 as compared with 2010 were due to changes in the mix of production. For example, sales volumes from Equatorial Guinea and Israel have lower DD&A rates.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
G&A Expense (millions)	$	89	$	65	$	254	$	194
Unit Rate per BOE (1)	$	4.45	$	3.20	$	4.41	$	3.42

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

G&A expense for the third quarter and first nine months of 2011 increased as compared with 2010 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and increased exploration activities.

Gain on Divestitures   Gain on divestitures was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
(millions)
Gain on Divestitures	$	-	$	(114	)	$	(26	)	$	(114	)

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

Asset Impairments    Asset impairment expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Asset Impairments	$	-	$	100	$	139	$	100

See Item 1. Financial Statements – Note 4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Deepwater Gulf of Mexico Moratorium Expense	$	(1	)	$	-		$	18		$	27
Electricity Generation Expense		-			9			26			26
Loss on Involuntary Conversion		-			-			4			-
Other, Net		3			(5	)		(3	)		6
Total	$	2		$	4		$	45		$	59

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

Other (Income) Expense

Other (income) expense was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Gain on Commodity Derivative Instruments	$	(322	)	$	(38	)	$	(179	)	$	(280	)
Interest, Net of Amount Capitalized		14			21			51			60
Other Non-Operating (Income) Expense, Net		(16	)		12			(16	)		(1	)
Total	$	(324	)	$	(5	)	$	(144	)	$	(221	)

Gain on Commodity Derivative Instruments     Gain on commodity derivative instruments is a result of mark-to-market accounting.   See Item 1. Financial Statements – Note 6.  Derivative Instruments and Hedging Activities and Note 7.  Fair Value Measurements and Disclosures.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions, except unit rate)
Interest Expense	$	48		$	36		$	138		$	105
Capitalized Interest		(34	)		(15	)		(87	)		(45	)
Interest Expense, Net	$	14		$	21		$	51		$	60
Unit Rate per BOE (1)	$	0.69		$	1.02		$	0.89		$	1.05

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

Interest expense increased for the third quarter and first nine months of 2011 as compared with 2010. The increase in interest expense resulted from a higher outstanding debt balance during the period and the interest associated with our 6% senior unsecured notes issued in first quarter 2011. The higher rate on the senior unsecured notes replaced the substantially lower rate applicable to our revolving credit facility which was repaid with proceeds from our debt offering. See also Liquidity and Capital Resources – Financing Activities below.

The increase in the amount of interest capitalized is due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, West Africa, and Israel and a higher weighted average interest rate associated with our 6% senior unsecured notes, which impacted the average rate we pay on long-term debt.

Other Non-operating (Income) Expense, Net   Other non-operating (income) expense, net includes deferred compensation (income) expense, interest income and other (income) expense. See Item 1. Financial Statements – Note 2. Basis of Presentation.

Income Tax Provision

See Current Global Economic Situation, Changes in Fiscal Regimes and Market Regulations, above, and Item 1. Financial Statements – Note 13. Income Taxes for a discussion of the change in our effective tax rate for the first nine months of 2011 as compared with 2010.

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LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

In seeking to effectively fund and monetize our major development projects, we employ a capital structure and financing strategy designed to provide ample liquidity throughout the commodity price cycle.  Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects while also maintaining the capability to execute a robust exploration program and financially attractive periodic mergers and acquisitions activity.  We endeavor to maintain an investment grade debt rating in service of these objectives.  We also utilize a commodity price hedging program to reduce commodity price uncertainty and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and operations.

Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under our credit facility. Occasional sales of non-strategic crude oil and natural gas properties as well as our periodic access to capital markets may also generate cash.

Our financial capacity, coupled with our balanced and diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.

Marcellus Shale Joint Venture   On September 30, 2011 we closed a joint venture partnership arrangement with a subsidiary of CONSOL Energy, Inc. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures and Note 5. Debt.

The transaction is structured in a unique way from a financial perspective. We have spread the payment over a three-year period, beginning at closing. The $2.1 billion CONSOL Carried Cost Obligation is expected to extend over an eight-year period and is capped at $400 million in each calendar year and will be suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. These conditions allow us to integrate a new core area into our existing long range plan while maintaining our strong balance sheet and financial flexibility. We funded the initial cash payment with cash on hand and borrowings under our credit facility and expect to fund the remaining installment payments and CONSOL Carried Cost Obligation with cash on hand and our credit facility. Targeted divestments of non-core assets may also be a source of funding.

Available Liquidity    Information regarding cash and debt balances was as follows:

	September 30,			December 31,
	2011			2010
(millions, except percentages)
Cash and Cash Equivalents	$	1,252		$	1,081
Amount Available to be Borrowed Under Credit Facility (1)		1,700			1,750
Total Liquidity	$	2,952		$	2,831
Total Debt (2)	$	3,891		$	2,279
Total Shareholders' Equity		7,582			6,848
Ratio of Debt-to-Book Capital (3)		34	%		25	%

(1) See Credit Facility below.

(2) Total debt includes FPSO lease obligation and remaining CONSOL installment payments and excludes unamortized debt discount.

(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 shareholders’ equity.

Cash and Cash Equivalents   We had approximately $1.25billion in cash and cash equivalents at September 30, 2011, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $986 million of this cash is attributable to our foreign subsidiaries.  We currently intend to use our international cash to fund international programs, including the planned developments in Equatorial Guinea and Israel. At September 30, 2011, we believe that sufficient liquidity is available in the US to fund our planned domestic programs. We currently do not expect to need additional foreign funds for US working capital or investment purposes. However, we have the ability to repatriate additional funds if we desire to do so. Any foreign cash repatriated would likely be subject to additional US income taxes and could result in an increase in our tax liability, after considering available foreign tax credits and/or other tax attributes.

Credit Facility   At September 30, 2011, we had an unsecured revolving credit facility that was due to mature December 9, 2012. The commitment was $2.1 billion until December 9, 2011, at which time the commitment would reduce to $1.8 billion. We borrowed $400 million under the credit facility in order to finance the Marcellus shale property acquisitions, and ended third quarter 2011 with $1.7 billion remaining available for borrowing.  On October 14, 2011, we terminated the existing $2.1 billion credit facility and entered into a Credit Agreement which provides for a new $3.0 billion unsecured revolving credit facility due October 14, 2016. See Financing Activities New Credit Facility below.

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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 include variable to fixed price commodity swaps, two and three-way collars and basis swaps. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. None of our counterparty agreements contain margin requirements.  We also use derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings.

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, 2011 the fair value of our commodity derivative assets was $131 million and the fair value of our commodity derivative liabilities was $6 million (after consideration of netting agreements).  See Item 1. Financial Statements – Note 6.  Derivative Instruments and Hedging Activities for a discussion of counterparty credit risk and Note 7.  Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of derivative instruments.

Insurance Recoveries   In May 2011, we ended drilling operations at the Leviathan-2 appraisal well location offshore Israel. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. We do not expect any delays in the insurance claim recovery process to have a significant impact on our cash flows or liquidity. See Item 1. Financial Statements – Note 2. Basis of Presentation and Leviathan-2 Insurance Recoveries, above.

Contractual Obligations

The following table updates certain contractual obligations from amounts reported in our Annual Report on Form 10-K for the year ended December 31, 2010. Unless otherwise noted, all amounts are net to our interest:

Obligation	Total		2011		2012 and 2013		2014 and 2015		2016 and beyond
(millions)
Long-Term Debt (Excluding Interest) (1)	$	3,540	$	-	$	1,056	$	200	$	2,284
Cash Payments for Interest (2)		3,091		19		374		339		2,359
CONE Gathering LLC MARC (3)		26		3		23		-		-
FPSO Lease Payments (4)		496		12		144		142		198

(1) Long-term debt excludes our FPSO lease obligation. See Item 1. Financial Statements – Note 5. Debt.

(2) Cash payments for interest are based on the total debt balance, scheduled maturities and interest rates in effect at September 30, 2011.

(3) Represents minimum annual revenue commitments. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

(4) The FPSO arrived at the Aseng field offshore Equatorial Guinea on October 16, 2011. Annual lease payments, net to our interest, exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations. These payments are also subject to change based on change orders implemented during the construction period, final accounting treatment, and other factors.  See Item 1. Financial Statements – Note 5. Debt.

CONSOL Carried Cost ObligationThe CONSOL Carried Cost Obligation represents our agreement to fund up to approximately $2.1 billion of CONSOL’s future drilling and completion costs. The CONSOL Carried Cost Obligation is expected to extend over an eight-year period. It is capped at $400 million in each calendar year and will be suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Therefore, specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures and Note 5. Debt.

Cash Flows

Cash flow information is as follows:

	Nine Months Ended September 30,
	2011			2010
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	1,785		$	1,452
Investing Activities		(2,383	)		(1,232	)
Financing Activities		769			(85	)
Increase in Cash and Cash Equivalents	$	171		$	135

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Operating Activities   Net cash provided by operating activities for the first nine months of 2011 increased as compared with 2010 primarily due to higher revenues, which benefitted from increases in commodity prices. The increase in cash flow was partially offset by increases in general and administrative expense and interest expense. See Item 1. Financial Statements – Consolidated Statements of Cash Flows.

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. Capital spending for property, plant and equipment increased by $542 million during the first nine months of 2011 as compared with 2010, primarily due to our increased major project development activity in the Wattenberg area, offshore West Africa, and offshore Israel. We also made an initial investment of $519 in Marcellus shale assets and $73 million in  CONE Gathering LLC. Investing activities were offset by $77 million proceeds from divestitures of non-core assets including our Ecuador assets and certain onshore US assets.  Additional investing activities for 2010 included $458 million related to the Central DJ Basin asset acquisition, offset by proceeds of $552 million from the sale of non-core onshore US assets.

Financing Activities   Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first nine months of 2011, funds were provided by net cash proceeds from borrowings under our revolving credit facility ($520 million) and the issuance of 6% senior notes ($836 million). Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($43 million). We used a portion of the proceeds from the issuance of senior notes to repay amounts outstanding under our credit facility ($470 million). We also used cash to settle an interest rate lock ($40 million), pay dividends on our common stock ($104 million) and repurchase shares of our common stock ($16 million).

In comparison, during the first nine months of 2010, $32 million of funds were provided by net increases in borrowings under our revolving credit facility and used to fund the Central DJ Basin asset acquisition and other capital expenditures. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($54 million). We used cash to pay dividends on our common stock ($95 million) and repurchase shares of our common stock ($12 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,
	2011		2010			2011		2010
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition	$	826	$	86		$	883	$	294
Proved Property Acquisition		370		(11	)		370		352
Exploration (1)		58		51			286		222
Development		604		459			1,478		1,096
Corporate and Other		40		23			128		81
Total	$	1,898	$	608		$	3,145	$	2,045
Other
Investment in Equity Method Investee	$	73	$	-		$	73	$	-
Increase in FPSO Lease Obligation		5		80			56		188

(1) Amount for three and nine months ended September 30, 2011 is net of probable insurance proceeds totaling $25 million related to our Leviathan -2 appraisal well offshore Israel.

2011   Unproved property acquisition costs include $790 million related to our acquisition of a 50% interest in Marcellus shale undeveloped leases, $40 million related to our position offshore Senegal and Guinea-Bissau (the AGC Profond block), and miscellaneous onshore US lease acquisitions. Proved property acquisition costs include $370 million related to the Marcellus shale. The increase in development costs is due to increased capital spending on major development projects located in the DJ Basin, offshore Equatorial Guinea and offshore Israel.

In connection with the Marcellus shale joint venture, we acquired a 50% interest in CONE Gathering Company LLC for $73 million in cash. CONE Gathering LLC was formed for the purpose of owning and operating the existing gathering assets and constructing, owning and operating all of the additional gathering lines and related facilities that will be needed during the course of the Marcellus shale development and will be accounted for using the equity method.

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

2010    Unproved property acquisition costs included $38 million for lease bonuses paid on deepwater Gulf of Mexico lease blocks, $146 million related to the Central DJ Basin asset acquisition, and the remainder primarily for other onshore US lease acquisitions. Proved property acquisition costs related to the Central DJ Basin asset acquisition.

FPSO Lease Obligation   The FPSO lease obligation represents the increase in construction costs to date on the Aseng FPSO to be used in the development of the Aseng field in Equatorial Guinea. See Item 1. Financial Statements – Note 5. Debt.

Financing Activities

New Credit Facility   On October 14, 2011, we entered into a Credit Agreement which provides for a new $3.0 billion unsecured revolving credit facility (the New Credit Facility). The New Credit Facility replaces our $2.1 billion credit facility maturing December 9, 2012.

The New Credit Facility (i) provides for an initial commitment of $3.0 billion with an option to increase the overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iv) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.

Also on October 14, 2011, we drew down $400 million under the New Credit Facility, the proceeds of which were utilized to repay outstanding borrowings under and to terminate our existing $2.1 billion credit facility maturing December 9, 2012. After the draw down, $2.6 billion remained available for borrowing under the New Credit Facility.

See Item 1. Financial Statements – Note 5. Debt.

CONSOL Installment Payments   On September 30, 2011, we closed an agreement with CONSOL under which we agreed to purchase a 50% interest in undeveloped Marcellus shale acreage. In addition to the cash paid at closing, we agreed to make two additional installment payments of $328 million each on September 30, 2012 and 2013. The installment payments have been discounted at the prevailing market rates for similar debt instruments, a weighted average of 1.76%.  See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures and Note 5. Debt.

Public Debt Offering In order to provide increased liquidity and lengthen our weighted average debt maturity, on February 18, 2011, we completed an underwritten public offering of $850 million of 6% senior unsecured notes due March 1, 2041, receiving net proceeds of $836 million after deducting discount and underwriting fees.Approximately $470 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility maturing 2012 and the balance of the proceeds will be used for general corporate purposes.

Fixed-Rate Debt   Our outstanding fixed-rate debt, including the remaining CONSOL installment payments, totaled approximately $3.1 billion at September 30, 2011. The weighted average interest rate on fixed-rate debt was 6.01%, with maturities ranging from 2012 to 2097. Approximately 17% of our fixed rate debt matures within the next five years.

FPSO Lease Obligation   We have an agreement for the construction and lease of an FPSO to be used for development of the Aseng field, offshore Equatorial Guinea. The FPSO is currently being installed at the Aseng field, and we are including the FPSO lease obligation in our balance sheet based upon the percentage of construction activities completed at the end of each reporting period. The obligation increased $56 million during the first nine months of 2011. We currently expect Aseng production to commence, and lease payments to begin, by year end 2011.

Ratio of Debt-to-Book Capital   Our ratio of debt-to-book capital was 34% at September 30, 2011 as compared with 25% at December 31, 2010. 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 shareholders’ equity.

Other Short-Term Borrowings   Our committed credit facility may be supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. There were no amounts outstanding under uncommitted credit lines at September 30, 2011 or December 31, 2010, nor did we borrow any funds under uncommitted credit lines during the first nine months of 2011. Depending upon future credit market conditions, these sources may or may not be available. However, we are not dependent on them to fund our day-to-day operations.

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Dividends   We paid total cash dividends of 58 cents per share of our common stock during the first nine months of 2011 and 54 cents per share during the first nine months of 2010. 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 $32 million during the first nine months of 2011 and $35 million during the first nine months of 2010.

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 181,234 shares with a value of $16 million during the first nine months of 2011 and 164,515 shares with a value of $12 million during the first nine months of 2010.  

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes   Weareexposed to market risk in the normal course of business operations, and the uncertainty 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, 2011, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. 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 receivable position with a fair value of $125 million. Based on the September 30, 2011 published commodity futures price strips for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative receivable by approximately $17 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would decrease the fair value of our net commodity derivative receivable by approximately $6 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 and the amount of interest we earn on our short-term investments.

At September 30, 2011, we had approximately $3.5 billion (excluding the FPSO lease obligation and unamortized debt discount) of long-term debt outstanding. Debt outstanding included $3.1 billion of fixed-rate debt with a weighted average interest rate of 6.01%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss. See Item 1. Financial Statements – Note 5. Debt.

We occasionally enter into interest rate derivative instruments such as forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate derivative instruments used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At September 30, 2011, AOCL included $27 million, net of tax, related to interest rate derivative instruments. This amount is currently being reclassified to earnings as adjustments to interest expense over the terms of our 5¼% senior notes due April 2014 and 6% senior notes due March 1, 2041. See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities.

We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of September 30, 2011, our cash and cash equivalents totaled approximately $1.25 billion, approximately 72% of which was invested in money market funds and short-term investments with major financial institutions. A hypothetical 25 basis point change in the floating interest rates applicable to the amount invested as of September 30, 2011 would result in a change in annual interest income of approximately $2 million.

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 foreign deferred tax liabilities in certain foreign tax jurisdictions, are denominated in a foreign 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. This risk may be mitigated to the extent commodity prices increase in response to a devaluation of the US dollar.

Transaction gains or losses were not material in any of the periods presented and are included in other (income) expense, net in the consolidated statements of operations.

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.

46

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 that 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 herein, if any, and included in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011, and our Annual Report on Form 10-K for the year ended December 31, 2010, 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, 2010 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) under the Securities Exchange Act of 1934, as amended, are effective. There were no changes in internal control over financial reporting 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.

Part II. Other Information

Item 1.  Legal Proceedings

Piceance Basin Matter    In October 2011, we received a Notice of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (Commission) regarding the reporting of gas analyses indicating the presence of hydrogen sulfide to the Commission and local government designee within certain areas of our Piceance basin operations. At this time, the Commission has not established a proposed penalty for this NOAV.  Given the inherent uncertainty in administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time. However, we believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our financial position, results of operations or cash flows.

See Item I. Financial Statements – Note 16. Commitments and Contingencies.

Item 1A.  Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011, or our Annual Report on Form 10-K for the year ended December 31, 2010, other than the following:

Our entry into the Marcellus shale through our joint venture with CONSOL will subject us to certain financial, operational and legal obligations and additional risks associated with crude oil and natural gas development activities in that region.

On September 30, 2011 we finalized a joint venture partnership arrangement with CONSOL where, among other things, we have agreed to develop significant acreage in the Marcellus shale. This arrangement represents the entry into a new core area for us in which we have very limited experience. Under the arrangement, we purchased a 50% interest in CONSOL’s undeveloped acreage and have agreed to act as operator on a portion of the acreage. Additionally, we have committed to make significant capital expenditures, consisting primarily of a $2.1 billion Carried Cost Obligation, and have agreed to other operational and legal obligations.  If we do not meet our financial commitments or perform our other obligations on a timely basis, our rights to participate in the joint venture, and our anticipated operations in the Marcellus shale, could be adversely affected.

47

We plan to drill numerous wells in the Marcellus shale over a multi-year period. These activities will be subject to many risks including, among others:

· Development drilling in emerging resource plays such as the Marcellus shale may not result in commercially productive quantities of crude oil and natural gas reserves;

· We have limited exploration and development experience in the Marcellus shale and limited information regarding ultimate recoverable reserves and production decline rates; therefore, our estimates of economically recoverable quantities of crude oil and natural gas reserves may vary substantially and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates;

· Our operations in the Marcellus shale will require significant additional attention and we may not be able to attract and retain personnel with the necessary skills to successfully carry out our joint development program;

· Our entry into the Marcellus shale will place additional burdens on our financial resources and internal financial controls;

· The high level of current and planned development activity in the Marcellus shale may result in increased competition for drilling rigs and oilfield services such as hydraulic fracturing, gathering, processing and/or transportation, thus hindering our ability to develop our reserves and market our production;

· Significant activism in New York, Pennsylvania and West Virginia against oil and gas development activities, particularly regarding the use of hydraulic fracturing, could, among other things, delay or limit our access to crude oil and natural gas reserves;

· Additional environmental regulation or legislation could result in higher development and/or production costs;

· Enactment of local impact fees in Pennsylvania, such as recommended by the Marcellus Shale Advisory Committee and supported by the governor of Pennsylvania, a severance tax in Pennsylvania, such as has been proposed by various groups in the past,  and /or permit fees for drilling such as adopted by a joint legislative committee in West Virginia,  would likely result in a lower rate of return on our development project;

· Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could hinder our ability to develop our reserves or increase our development and operating costs.

We may not be able to compensate for or fully mitigate these risks.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil and natural gas from many reservoirs, including Wattenberg and the Marcellus shale, require the use and disposal of significant quantities of water.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in these regions. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

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

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)
07/01/11 - 07/31/11		462	$	90.73		-		-
08/01/11 - 08/31/11		53		88.39		-		-
09/01/11 - 09/30/11		181		84.56		-		-
Total		696	$	88.95		-		-

(1) Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares issued under stock-based compensation plans.

Item 3. Defaults Upon Senior Securities

None.

48

Item 4. (Removed and Reserved)

Item 5.  Other Information

None.

Item 6.  Exhibits

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

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	October 20, 2011	/s/ Kenneth M. Fisher
		Kenneth M. Fisher
		Senior Vice President, Chief Financial Officer

49

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 Annex I (Definitions) thereto, filed herewith.
3.1	Certificate of Incorporation, as amended through May 16, 2005, of the Registrant (filed as Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference).
3.2	By-Laws of Noble Energy, Inc. as amended through June 1, 2009 (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 17, 2009) filed February 20, 2009 and incorporated herein by reference).
10.1	Joint Development Agreement dated September 30, 2011 between CNX Gas Company LLC and Noble Energy, Inc., filed herewith.
10.2	$3.0 billion five-year Credit Agreement, dated October 14, 2011, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, Bank of America, N.A., Mizuho Corporate Bank, LTD., and Morgan Stanley MUFG Loan Partners, LLC, as documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1  to the Registrant’s Current Report on Form 8-K (Date of Event: October 14, 2011) filed October 18, 2011 and incorporated herein by reference).
31.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
31.2	Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
32.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), filed 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), filed 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

50

EX-2.1

Exhibit 2.1

ASSET ACQUISITION AGREEMENT

BY AND BETWEEN

CNX GAS COMPANY LLC

as CONSOL

and

NOBLE ENERGY, INC.

as NOBLE

EXECUTED ON AUGUST 17, 2011

TABLE OF CONTENTS

		Page
ARTICLE I	DEFINITIONS AND INTERPRETATION	1
1.1	Defined Terms	1
1.2	References and Rules of Construction	1
ARTICLE II	ASSET ACQUISITION	2
2.1	Asset Acquisition	2
2.2	Excluded Assets	3
2.3	Revenues and Expenses	3
ARTICLE III	CONSIDERATION	4
3.1	Consideration	5
3.2	Adjustments to Closing Cash Payment	5
3.3	Adjustment Methodology	7
3.4	Preliminary Settlement Statement	7
3.5	Final Settlement Statement	7
3.6	Disputes	8
3.7	Allocated Values	8
ARTICLE IV	ACCESS / DISCLAIMERS	8
4.1	Access	8
4.2	Confidentiality	11
4.3	Disclaimers	11
ARTICLE V	TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS	13
5.1	General Disclaimer of Title Warranties and Representations	13
5.2	Special Warranty	13
5.3	Notice of Title Defects; Defect Adjustments	13
5.4	Casualty or Condemnation Loss	18
5.5	Preferential Purchase Rights and Consents to Assign	19
ARTICLE VI	ENVIRONMENTAL MATTERS	21
6.1	Environmental Defects	21
6.2	NORM, Wastes and Other Substances	24
ARTICLE VII	REPRESENTATIONS AND WARRANTIES OF CONSOL	24
7.1	Organization, Existence	24
7.2	Authorization	24
7.3	No Conflicts	25
7.4	Consents	25
7.5	Bankruptcy	25

i

7.6	Foreign Person	25
7.7	Litigation	25
7.8	Material Contracts	25
7.9	No Violation of Laws	27
7.10	Preferential Purchase Rights	27
7.11	Payment of Royalties	27
7.12	Imbalances	27
7.13	Current Commitments	27
7.14	Asset Taxes	28
7.15	Brokers’ Fees	28
7.16	Delivery of Hydrocarbons	28
7.17	Partnerships	28
7.18	Bonds and Credit Support	28
7.19	Environmental	28
7.20	Payout Status	29
7.21	Permits	29
7.22	Marcellus Wells	29
7.23	Suspense Accounts	29
7.24	Depletion	29
7.25	Condemnation and Eminent Domain	29
7.26	Mandatory Drilling Obligations	30
7.27	Offset Obligations	30
7.28	Requisite Noteholders	30
ARTICLE VIII	NOBLE’S REPRESENTATIONS AND WARRANTIES	30
8.1	Organization; Existence	30
8.2	Authorization	30
8.3	No Conflicts	30
8.4	Consents	31
8.5	Bankruptcy	31
8.6	Litigation	31
8.7	Regulatory	31
8.8	Financing	31
8.9	Independent Evaluation	31
8.10	Brokers’ Fees	32
8.11	Accredited Investor	32
8.12	Oil & Gas Interests	32
ARTICLE IX	CERTAIN AGREEMENTS	32
9.1	Conduct of Business	32
9.2	Governmental Bonds	34
9.3	HSR Act	34
9.4	Additional Interests	35
9.5	Non-Solicitation of Employees	35
9.6	Gathering Assets	35
9.7	Further Assurances	35

ii

9.8	CONSOL Indentures	36
9.9	Secondees	36
9.10	Subsurface Access Easement	36
9.11	Exclusivity	36
9.12	Downstream Contracts; Processing Contracts; Gathering Contracts	36
9.13	Development Plan and Annual Plan and Budget	36
ARTICLE X	NOBLE’S CONDITIONS TO CLOSING	37
10.1	Representations	37
10.2	Performance	37
10.3	No Legal Proceedings	37
10.4	Title Defects and Environmental Defects	37
10.5	Certificate	38
10.6	HSR Act	38
10.7	Closing Deliverables	38
ARTICLE XI	CONSOL’S CONDITIONS TO CLOSING	38
11.1	Representations	38
11.2	Performance	38
11.3	No Legal Proceedings	38
11.4	Title Defects and Environmental Defects	38
11.5	HSR Act	39
11.6	Certificate	39
11.7	Closing Deliverables	39
11.8	Indenture	39
ARTICLE XII	CLOSING	39
12.1	Date of Closing	39
12.2	Place of Closing	39
12.3	Closing Obligations	39
12.4	Records	41
ARTICLE XIII	ASSUMPTION; INDEMNIFICATION; SURVIVAL	41
13.1	Assumption by Noble	41
13.2	Indemnities of CONSOL	41
13.3	Indemnities of Noble	43
13.4	Limitation on Liability	43
13.5	Express Negligence	43
13.6	Exclusive Remedy	44
13.7	Indemnification Procedures	44
13.8	Survival	46
13.9	Non-Compensatory Damages	47
13.10	Cooperation by Noble Concerning Retained Litigation	47
13.11	Waiver of Right to Rescission	47
13.12	Insurance	47

iii

13.13	Materiality	47
ARTICLE XIV	TERMINATION, DEFAULT AND REMEDIES	47
14.1	Right of Termination	47
14.2	Effect of Termination	48
14.3	Return of Documentation and Confidentiality	49
ARTICLE XV	MISCELLANEOUS	50
15.1	Appendices, Exhibits and Schedules	50
15.2	Expenses and Taxes	50
15.3	Tax Treatment	51
15.4	Value Allocations for Tax Purposes	52
15.5	Assignment	52
15.6	Preparation of Agreement	52
15.7	Publicity	53
15.8	Notices	53
15.9	Further Cooperation	55
15.10	Filings, Notices and Certain Governmental Approvals	55
15.11	Entire Agreement; Conflicts	55
15.12	Successors and Permitted Assigns	56
15.13	Parties in Interest	56
15.14	Amendment	56
15.15	Waiver; Rights Cumulative	56
15.16	Governing Law; Jurisdiction; Venue; Jury Waiver	56
15.17	Severability	56
15.18	Counterparts	57

iv

LIST OF APPENDIXES, EXHIBITS AND SCHEDULES

Appendixes
Appendix I	―	Definitions
Exhibits
Exhibit A	―	Leases
Exhibit A-1	―	Marcellus Formation Log
Exhibit B	―	Marcellus Wells (WI/NRI), Allocated Values
Exhibit C	―	Rights-Of-Way
Exhibit D	―	Form of Tax Partnership Agreement
Exhibit E	―	Form of Assignment
Exhibit F	―	Excluded Assets
Exhibit G	―	Form of Development Agreement
Exhibit H	―	[Reserved]
Exhibit I	―	Gathering Term Sheet
Exhibit J	―	Form of CONSOL Secondment Agreement
Exhibit K	―	Form of Noble Secondment Agreement
Exhibit L	―	Form of Water Use Agreement
Exhibit M	―	Form of Services Agreement
Exhibit N	―	Form of Surface Use Agreement
Exhibit O	―	Form of NAESB Agreement and Transaction Confirmation

v

Schedules
Schedule 1.1	―	Net Acre Allocation
Schedule 1.2	―	Minimum Net Acres
Schedule 2.1	―	Geophysical/Seismic Data
Schedule 7.3	―	No Conflicts
Schedule 7.4	―	Consents
Schedule 7.7	―	Litigation
Schedule 7.8(a)	―	Material Contracts – Part 1
Schedule 7.8(b)	―	Material Contracts – Part 2
Schedule 7.9	―	Violation of Laws
Schedule 7.10	―	Preferential Purchase Rights
Schedule 7.12	―	Imbalances
Schedule 7.13	―	Current Commitments
Schedule 7.14(a)	―	Asset Taxes
Schedule 7.14(b)	―	Tax Basis
Schedule 7.16	―	Delivery of Hydrocarbons
Schedule 7.17	―	Partnerships
Schedule 7.18	―	Bonds and Credit Support
Schedule 7.19	―	Environmental
Schedule 7.20	―	Payout Status
Schedule 7.23	―	Suspense Accounts
Schedule 7.24	―	Depletion
Schedule 7.25	―	Condemnation and Eminent Domain
Schedule 7.26	―	Mandatory Drilling Obligations
Schedule 7.27	―	Offset Obligations
Schedule 9.1	―	Conduct of Business
Schedule 9.6	―	Existing Gathering Assets Provisions
Schedule 9.12(a)	―	Processing Contract Provisions
Schedule 9.12(b)	―	Processing Contracts
Schedule 9.12(c)	―	Gathering Contract Provisions
Schedule 9.12(d)	―	Gathering Contracts

vi

ASSET ACQUISITION AGREEMENT

THIS ASSET ACQUISITION AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into the 17th day of August, 2011, 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

CONSOL and Noble desire to enter into an arrangement 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 hereinafter described, and in connection therewith CONSOL desires to transfer to Noble, and Noble desires to acquire from CONSOL, a portion of CONSOL’s right, title and interest in and to such properties and related Conveyed Interests (as hereinafter defined) in accordance with this Agreement.

The transfer of the Conveyed Interests and the Parties’ agreement regarding the joint exploration and development of the properties underlying the Conveyed Interests will be consummated on the terms and conditions set forth in this Agreement and the Development Agreement (as hereinafter defined), each of which is an integral part of a single transaction.

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 I

DEFINITIONS AND INTERPRETATION

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

1.2     References 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 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.

1

ARTICLE II

ASSET ACQUISITION

2.1     Asset Acquisition.  Subject to the terms and conditions of this Agreement, CONSOL agrees to transfer, and Noble agrees to acquire, the following interests and properties (less and except for the Excluded Assets, such interests and properties described in subsections (a) and (b) of this Section, collectively, the “Conveyed Interests”):

(a)           an undivided 50% of all of CONSOL’s right, title and interest in and to the following assets and properties:

(i)           the oil, gas and/or mineral leases and oil and gas mineral fee interests more particularly described in Exhibit A, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths within the Marcellus Formation (such 50% of CONSOL’s interest in such leases and oil and gas mineral fee interests as so limited, collectively, the “Leases”), including all working interests, overriding royalty interests, net profits interests, carried interests or similar rights or interest in the Leases, and together with all rights, privileges, benefits and powers conferred upon the holder of the Leases with respect to the use and occupation of the surface of the lands covered thereby that may be necessary, convenient or incidental to the possession and enjoyment of the Leases;

(ii)          all oil and gas wells drilled on the Leases or the Units insofar and only insofar as such wells are producing from, or have been drilled to produce from, those depths within the Marcellus Formation, including the oil and gas wells listed on Exhibit B (such 50% of CONSOL’s interest in such wells as so limited, the“Marcellus Wells”) and all fresh water wells, injection wells, salt water disposal wells and other wells of every nature and kind located on the Leases or the Units, in each case, to the extent that they are primarily used in connection with the Marcellus Wells, the Leases or the Units (such 50% of CONSOL’s interest in such wells as so limited, collectively with the Marcellus Wells, the “Wells”);

(iii)         all interests in pools or units which include all or a part of any Lease insofar and only insofar as such pools or units cover depths within the Marcellus Formation (such 50% interest in such pools and units, the “Units”);

(iv)         to the extent they may be assigned (after exercising commercially reasonable efforts to obtain any and all relevant consents), all permits, licenses, servitudes, easements, rights-of-way, surface use agreements, water access and water use agreements and other similar surface use or water rights, in each case, to the extent primarily used in connection with the ownership or operation of the Properties, including those set forth in Exhibit C (such 50% of CONSOL’s interest in the foregoing, collectively, the “Rights-Of-Way” and the Leases, Units, Wells and Rights-Of-Way being collectively referred to hereinafter as the “Properties”);

2

(v)         all equipment, machinery, fixtures and other personal property, operational or nonoperational, in each case, to the extent primarily used in connection with the Properties or the other Conveyed Interests, including well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, manifolds, structures, materials and other items primarily used or held for the use in the operation of the Properties (such 50% of CONSOL’s interest in such properties, the “Personal Property”); and

(vi)        all Hydrocarbons produced from or allocated to the Leases, Marcellus Wells or Units on and after the Effective Time.

(b)           all of CONSOL’s right, title and interest in and to the following assets and properties to the extent, and only to the extent, that such assets and properties relate to the interests described in subsection (a) above:

(i)          to the extent assignable, all Applicable Contracts and all rights thereunder;

(ii)         all Well Imbalances relating to the Conveyed Interests;

(iii)        copies (in digital form, if available) of the following, to the extent (A) in CONSOL’s or its Affiliates’ possession or (B) to which CONSOL has the right but are in the possession of a Third Party:  (1) land and title records (including abstracts of title, title opinions (including title opinions that cover both the Marcellus Formation and other formations) and title curative documents), (2) contract files, (3) correspondence, (4) maps, operations, environmental, production and accounting records, (5) facility and engineering/well files, (6) division order files (including division and interest statements), (7) engineering and/or production files, (8) environmental files, (9) permitting files and (10) geological data, but excluding any of the foregoing items that are primarily used in connection with the ownership or operation of the Excluded Assets (the “Records”); and

(iv)        to the extent assignable without payment of fees or other penalties unless Noble agrees to, and does, pay such fees and penalties, all geophysical data, and other seismic and related technical data and information listed on Schedule 2.1.

2.2     Excluded Assets.  CONSOL shall reserve and retain all of the Excluded Assets.

2.3     Revenues and Expenses.

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(a)           For purposes of determining the amount of the adjustment to the Closing Cash Payment provided for in Section 3.2, the principles set forth in this Section 2.3 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 Closing Cash Payment hereunder or otherwise) for all Property Expenses, in each case attributable to the Conveyed Interests for the period of time prior to the Effective Time.  Except as expressly provided otherwise in this Agreement, and 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 Closing Cash Payment hereunder or otherwise) for all Property Expenses, in each case, attributable to the Conveyed Interests for the period of time from and after the Effective Time.  All Property Expenses attributable to the Conveyed Interests, 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. 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)           If, after the Parties’ agreement upon the Final Settlement Statement, (i) any Party receives monies belonging to the other, including proceeds of production, then such amount shall, within five Business Days after the end of the month in which such amounts were received, be paid over to the proper Party, (ii) any Party pays monies for Property Expenses which are the obligation of the other Party hereto, then such other Party shall, within five Business Days after the end of the month in which the applicable invoice and proof of payment of such invoice were received, reimburse the Party which paid such Property Expenses, (iii) a Party receives an invoice of an expense or obligation which is owed by the other Party, such Party receiving the invoice shall promptly forward such invoice to the Party obligated to pay the same, and (iv) an invoice or other evidence of an obligation is received by a Party, which is partially an obligation of both CONSOL and Noble, then the Parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee.

(c)           Each of CONSOL and Noble shall be permitted to offset any Property Expenses owed by such Party to the other Party pursuant to this Section 2.3 against revenues owing by such Party to such other Party pursuant to this Section 2.3, but not otherwise.

ARTICLE III

CONSIDERATION

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3.1     Consideration.  The consideration for (x) the transfer of the Conveyed Interests and the transactions contemplated hereby and (y) the assumption of the Assumed Obligations, shall be comprised of the following two components:

(a)           an amount equal to $160,000,000 to be paid at Closing in cash by Noble to a Tax Partnership Account designated by CONSOL (the “Cost Reconciliation Account”) by wire transfer in same day funds for the Marcellus Wells (the “Producing Properties Cash Payment”); and

(b)           an aggregate amount equal to $1,066,888,125 to be paid in cash by Noble to the Cost Reconciliation Account by wire transfer in same day funds in three installments: (i) one installment of $355,629,375 to be paid at Closing as and when provided in this Agreement (the “First Cash Payment” and collectively with the Producing Properties Cash Payment, the “Closing Cash Payment”), (ii) one installment of $355,629,375 to be paid on the first anniversary date of Closing (the “Second Cash Payment”), and (iii) one installment of $355,629,375 to be paid on the second anniversary date of Closing (the “Third Cash Payment” and collectively with the Second Cash Payment, the “Post Closing Cash Payments”).

3.2Adjustments to Closing Cash Payment.  The Closing Cash Payment shall be adjusted as follows, and the resulting amount shall be herein called the “Adjusted Closing Cash Payment”:

(a)            The Closing Cash Payment shall be adjusted upward by the following amounts (without duplication):

(i)           an amount equal to the value of all Hydrocarbons attributable to the Conveyed Interests in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time, the value to be based upon the contract price in effect as of the Effective Time (or if there is no contract price, then the posted price in the field in which such Hydrocarbons were produced or if no such posted price exists for such Hydrocarbons, the market price in the field in which such Hydrocarbons were produced, (in each case) in effect as of the Effective Time), net of (A) amounts payable as Burdens on such production and severance Taxes deducted by the purchaser of such production and (B) expenses (other than Property Expenses) directly incurred in earning or receiving such proceeds and any sale, excise or similar Taxes or fees payable or incurred in connection therewith not reimbursed or reimbursable to CONSOL;

(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 Conveyed Interests during the Interim Period, whether paid before or after the Effective Time, including (A) Burdens, (B) rentals and other lease maintenance payments and (C) property, severance and production Taxes and any other Taxes (exclusive of income and franchise Taxes) based upon or measured by the ownership of the Conveyed Interests, the production of Hydrocarbons or the receipt of proceeds therefrom;

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(iii)         the amount of all prepaid expenses attributable to the Conveyed Interest that are paid or incurred by, or on behalf of, CONSOL that are attributable to the period of time after the Effective Time, including prepaid utility charges, and prepaid ad valorem, property, production, severance and similar Taxes based upon, or measured by the ownership of, the Conveyed Interests or the production of Hydrocarbons or the receipt of proceeds therefrom;

(iv)         the amount of all Asset Taxes prorated to Noble in accordance with Section 15.2 but paid or payable by CONSOL; and

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

(b)           The Closing Cash Payment shall be adjusted downward by the following amounts (without duplication):

(i)           an amount equal to all proceeds received by CONSOL attributable to the sale of Hydrocarbons (A) produced from or allocable to the Conveyed Interests 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 Closing Cash Payment adjustment was made pursuant to Section 3.2(a), (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;

(ii)          if CONSOL makes the election under Section 5.3(d)(i) with respect to a Title Defect asserted by Noble prior to Closing, the Title Defect Amount with respect to such Title Defect if such Title Defect Amount has been determined prior to Closing;

(iii)         if CONSOL makes the election under Section 6.1(b)(i) with respect to an Environmental Defect asserted by Noble, the Remediation Amount with respect to such Environmental Defect if such Remediation Amount has been determined prior to Closing;

(iv)         an amount determined pursuant to Section 4.1(b), Section 5.5(a)(i), Section 5.5(b)(i) or Section 9.1(b)(i) for any Conveyed Interests excluded from the transaction contemplated hereby pursuant to such Sections;

(v)          the amount of all Asset Taxes prorated to CONSOL in accordance with Section 15.2 but payable by Noble;

(vi)         any amounts payable to Noble pursuant to Section 5.4(c); and

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

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3.3     Adjustment Methodology. When available, actual figures will be used for the adjustments to the Closing Cash Payment at Closing.  To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section 3.5 and Section 3.6.

3.4     Preliminary Settlement Statement.  Not less than five Business Days prior to the Closing, CONSOL shall prepare and submit to Noble for review, using and based on the best information available to CONSOL, a draft settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Closing Cash Payment, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with the designation of CONSOL’s accounts for the wire transfers of funds as set forth in Section 12.3(d).  Within three Business Days of receipt of the Preliminary Settlement Statement, Noble will deliver to CONSOL a written report containing all changes with the explanation therefor that Noble proposes to be made to the Preliminary Settlement Statement, if any.  The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to adjust the Closing Cash Payment at Closing; provided that if the Parties cannot agree on the Preliminary Settlement Statement prior to the Closing, the Preliminary Settlement Statement as presented by CONSOL will be used to adjust the Closing Cash Payment at Closing.

3.5     Final Settlement Statement.  On or before the date that is 120 days following the Closing Date, a final settlement statement (the “Final Settlement Statement”) will be prepared by CONSOL, based on actual revenues and expenses during the Interim Period and which takes into account all final adjustments made to the Closing Cash Payment and shows the resulting final Adjusted Closing Cash Payment.  The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement.  As soon as practicable, and in any event within 30 days after receipt of the Final Settlement Statement, Noble will deliver to CONSOL a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Dispute Notice”).  Any changes not so specified in the Dispute Notice shall be deemed waived and CONSOL’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed specifically in the Dispute Notice shall prevail.  If Noble fails to timely deliver a Dispute Notice to CONSOL containing changes Noble proposes to be made to the Final Settlement Statement, the Final Settlement Statement as delivered by CONSOL will be deemed to be mutually agreed upon by the Parties and will be final and binding on the Parties.  If the final Adjusted Closing Cash Payment set forth in the Final Settlement Statement is mutually agreed upon by CONSOL and Noble (or deemed agreed, as the case may be), the Final Settlement Statement and the final Adjusted Closing Cash Payment as so agreed or deemed agreed, shall be final and binding on the Parties, subject to the provisions of Section 2.3(b).  Once the final Adjusted Closing Cash Payment has been agreed (or deemed agreed) upon by the Parties pursuant to this Section 3.5 or determined by the Accounting Arbitrator pursuant to Section3.6, as applicable, then, if the final Adjusted Closing Cash Payment is (a) more than the Adjusted Closing Cash Payment used at Closing pursuant to Section 3.4, Noble shall pay into the Cost Reconciliation Account the amount of such difference, and (b) less than the Adjusted Closing Cash Payment used at Closing pursuant to Section 3.4, CONSOL shall pay 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 Days after the date such final Adjusted Closing Cash Payment is agreed, or deemed agreed, pursuant to this Section 3.5 or determined pursuant to Section 3.6, as applicable.

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3.6     Disputes.  If CONSOL and Noble are unable to resolve the matters addressed in the Dispute Notice (if any), each of Noble and CONSOL shall within 14 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 PricewaterhouseCoopers LLP, or if PricewaterhouseCoopers LLP 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 Final Settlement 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.  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 one-half by Noble and one-half by CONSOL.  The Final Settlement Statement and final Adjusted Closing Cash Payment determined by the Accounting Arbitrator pursuant to this Section 3.6 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 2.3(b)).

3.7     Allocated Values.  The “Allocated Value” for any Conveyed Interest equals (a) with respect to any Lease (or portion thereof) included in the Conveyed Interests for which there is not an associated Marcellus Well, the applicable Net Acre Allocation with respect to the Conveyed Interest in such Lease, and (b) with respect to any Marcellus Well included in the Conveyed Interests, the amount allocated to the Conveyed Interest in such Marcellus Well on Exhibit B, and, in each case, such Allocated Values shall be used in calculating adjustments to the Closing Cash Payment and Carried Cost Obligation as provided herein.

ARTICLE IV

ACCESS / DISCLAIMERS

4.1           Access.  

(a)           From and after the date hereof and up to and including the earlier of (i) the date upon which this Agreement is terminated pursuant to the terms hereof and (ii) the date the Records are delivered to Noble pursuant to Section 12.4, but subject to the other provisions of this Section 4.1 and obtaining any required consents of Third Parties, including Third Party operators of the Conveyed Interests (with respect to which consents CONSOL shall use commercially reasonable efforts to obtain), CONSOL shall afford to Noble and its Affiliates and their respective officers, employees, agents, accountants, attorneys, investment bankers, consultants and other authorized representatives (the “Noble Representatives”) reasonable access, during normal business hours, to the Conveyed Interests and all Records and other documents in CONSOL’s or its Affiliates’ possession relating to the Conveyed Interests.  CONSOL shall also make available to Noble and the Noble Representatives, upon reasonable notice during normal business hours, CONSOL’s personnel knowledgeable with respect to the Conveyed Interests in order that Noble may make such diligence investigation as Noble considers necessary or appropriate.  All investigations and due diligence conducted by Noble or any Noble Representative shall be conducted at Noble’s sole cost, risk and expense and any conclusions made from any examination done by Noble or any Noble Representative shall result from Noble’s own independent review and judgment.  Noble shall coordinate its access rights and physical inspections of the Conveyed Interests with CONSOL to minimize any inconvenience to or interruption of the conduct of business by CONSOL and CONSOL shall have the right to accompany Noble and any Noble Representative in connection with any physical inspection of the Conveyed Interests.  Noble shall, and shall cause all Noble Representatives to, abide by CONSOL’s, and any Third Party operator’s safety rules, regulations, and operating policies while conducting its due diligence evaluation of the Conveyed Interests, including any environmental or other inspection or assessment of the Conveyed Interests, and to the extent required by any Third Party operator, execute and deliver any required bonding agreement of such Third Party operator or provide evidence that Noble maintains insurance as may be required by such Third Party operator.

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(b)           Before conducting any sampling, boring, drilling or other invasive investigation activities with respect to any environmental due diligence (“Invasive Activities”) on or with respect to any of the Conveyed Interests, Noble shall furnish CONSOL with a written description of the proposed scope of the Invasive Activities to be conducted, including a description of the activities to be conducted and a description of the approximate location and expected timing of such activities.  If CONSOL reasonably determines that any of the proposed Invasive Activities may unreasonably interfere with normal operation of the Conveyed Interests or the real property and other assets associated with the Conveyed Interests or if CONSOL reasonably determines that it is necessary in order to comply with CONSOL’s safety policies and procedures, CONSOL may require appropriate modification of the proposed Invasive Activity.  CONSOL shall notify Noble of any such modification within three Business Days.  Any Invasive Activities shall be conducted by a reputable environmental consulting or engineering firm, approved in advance by CONSOL (such approval not to be unreasonably withheld or delayed) and, once approved, such environmental consulting or engineering firm shall be deemed to be a “Noble Representative.”  CONSOL shall have the right, at its option, to split any samples collected from the Conveyed Interests with Noble.  Notwithstanding anything herein to the contrary, Noble shall not have access to, and shall not be permitted to conduct any environmental due diligence (including any Phase I environmental property assessment) with respect to, any Conveyed Interests where CONSOL does not have the authority to grant access for such due diligence, unless Noble obtains the necessary authority.  If CONSOL is unable to grant access to Noble to conduct any Invasive Activities recommended in a Third Party environmental assessment prepared for Noble with respect to any Conveyed Interest, then Noble may, at its option, require CONSOL to retain the affected Conveyed Interests by delivering written notice thereof at least 5 Business Days before the Closing, such Conveyed Interests shall be considered Excluded Assets for all purposes hereunder and the Closing Cash Payment shall be adjusted downward by the Allocated Value of such Conveyed Interests.

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(c)           Noble hereby Indemnifies each of the operators of the Conveyed Interests and each CONSOL Indemnified Party from and against any and all Liabilities (including any injury, loss or damage arising out of such entry that may occur to Noble or any Noble Representative) arising out of, resulting from or relating to any office visit, field visit, environmental property assessment or other due diligence activity conducted by Noble or any Noble Representative with respect to the Conveyed Interests, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, A MEMBER OF THE CONSOL INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING ON THE ACCOUNT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF CONSOL INDEMNIFIED PARTIES.

(d)           Noble agrees to promptly provide CONSOL, but in any event no later than the earlier of (i) 30 days after receipt or creation of such reports and/or test results or (ii) the date Noble delivers an Environmental Defect Notice which relies, in whole or in part, on such reports and/or test results, copies of all final reports and test results prepared by Noble and/or any Noble Representative, which contain data collected or generated from Noble’s due diligence with respect to the Conveyed Interests, including all environmental and title reports.  CONSOL shall not be deemed by its receipt of said reports and/or test results or otherwise to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Conveyed Interests or to the accuracy of said documents or the information contained therein.

(e)           Upon completion of Noble’s due diligence, Noble shall at its sole cost and expense and without any cost or expense to CONSOL or its Affiliates, (i)  repair any damage to the Conveyed Interests (including the real property and other assets associated therewith) to their approximate condition prior to commencement of Noble’s due diligence or if such repairs are impossible or impracticable, replace the Conveyed Interests affected by such damage; provided that Noble shall only be obligated to make such repairs or replacements to the extent such damage was caused by or arose out of Noble’s due diligence, and (ii) remove all equipment, tools or other property brought onto the Conveyed Interests in connection with Noble’s due diligence.  Any material disturbance to the Conveyed Interests (including the real property and other assets associated therewith) resulting from the due diligence conducted by or on behalf of Noble will be promptly corrected by Noble.

(f)           During all periods that Noble and/or any of Noble’s Representatives are on the Conveyed Interests, Noble shall maintain, at its sole expense and with insurers reasonably satisfactory to CONSOL, policies of insurance of the types and in the amounts reasonably requested by CONSOL.  Coverage under all insurance required to be carried by Noble hereunder will (i) be primary insurance, (ii) list CONSOL Indemnified Parties (other than the shareholders of CONSOL Energy Inc.) as additional insureds, (iii) waive subrogation against CONSOL Indemnified Parties and (iv) provide for 30 days prior notice to CONSOL in the event of cancellation or modification of the policy or reduction in coverage.  Upon request by CONSOL, Noble shall provide evidence of such insurance to CONSOL prior to entering the lands underlying the Conveyed Interests.

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4.2    Confidentiality.  Noble acknowledges that, pursuant to its right of access to the Records or the Conveyed Interests, Noble will become privy to confidential and other information of CONSOL and that such confidential information shall be held confidential by Noble and the Noble Representatives in accordance with the terms of the Confidentiality Agreement.  If the Closing should occur, the foregoing confidentiality restriction on Noble, including the Confidentiality Agreement, shall terminate (except as to (a) any Conveyed Interests that are excluded from the transactions contemplated hereby pursuant to the provisions of this Agreement, (b) the Excluded Assets and (c) information related to any assets other than the Conveyed Interests).

4.3     Disclaimers.  

(a)           EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII AND WITH RESPECT TO THE SPECIAL WARRANTY OF TITLE SET FORTH IN THE ASSIGNMENT, (I) CONSOL MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) CONSOL EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO NOBLE OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO NOBLE BY A MEMBER OF THE CONSOL INDEMNIFIED PARTIES).

(b)           EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE VII AND WITH RESPECT TO THE SPECIAL WARRANTY OF TITLE SET FORTH IN THE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, CONSOL EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, BY ANY MEMBER OF THE CONSOL INDEMNIFIED PARTIES, AS TO (I) TITLE TO ANY OF THE CONVEYED INTERESTS, (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 CONVEYED INTERESTS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE CONVEYED INTERESTS, (IV) ANY ESTIMATES OF THE VALUE OF THE CONVEYED INTERESTS OR FUTURE REVENUES GENERATED BY THE CONVEYED INTERESTS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE CONVEYED INTERESTS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE CONVEYED INTERESTS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY CONSOL OR THIRD PARTIES WITH RESPECT TO THE CONVEYED INTERESTS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO NOBLE OR ITS 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 REPRESENTED OTHERWISE IN ARTICLE VII OR WITH RESPECT TO THE SPECIAL WARRANTY OF TITLE SET FORTH IN THE ASSIGNMENT, CONSOL 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 CONVEYED INTERESTS, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT NOBLE SHALL BE DEEMED TO BE OBTAINING THE CONVEYED INTERESTS 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 NOBLE, SUBJECT TO ITS RIGHTS UNDER ARTICLE V, HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS NOBLE DEEMS APPROPRIATE.

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(c)           EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN SECTION 7.19 AND SUBJECT TO NOBLE’S RIGHTS UNDER SECTION 13.2(g) AND SECTION 13.2(h), WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, CONSOL 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 THE CONVEYED INTERESTS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO NOBLE’S RIGHTS UNDER SECTIONS 6.1 AND 7.19, NOBLE SHALL BE DEEMED TO BE TAKING THE CONVEYED INTERESTS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT NOBLE, SUBJECT TO ITS RIGHTS UNDER ARTICLE VI,  HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS NOBLE 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 4.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

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ARTICLE V

TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

5.1    General Disclaimer of Title Warranties and Representations.  Except for the special warranty of title contained in the Assignment and subject to and without limiting Noble’s remedies for Title Defects set forth in this Article V, CONSOL makes no warranty or representation, express, implied, statutory or otherwise, with respect to CONSOL’s title to any of the Conveyed Interests and Noble hereby acknowledges and agrees that Noble’s sole and exclusive remedy for any defect of title or any other title matter, including any Title Defect, with respect to any of the Conveyed Interests (a) before the Title Defect Claim Date, shall be as set forth in Section 5.3 and (b) after the Title Defect Claim Date, shall be pursuant to the special warranty of title, to the extent applicable, contained in the Assignment.

5.2    Special Warranty.  The Assignment delivered at the Closing will contain a special warranty of title by CONSOL to the Marcellus Wells, Leases and the Subsurface Access Easement pursuant to the terms of the Assignment.

5.3     Notice of Title Defects; Defect Adjustments.  

(a)           Title Defect Notices.  On or before the Title Defect Claim Date, Noble must deliver claim notices to CONSOL meeting the requirements of this Section 5.3(a) (collectively the “Title Defect Notices” and individually a “Title Defect Notice”) setting forth any matters which, in Noble’s reasonable opinion, constitute Title Defects and which Noble intends to assert as a Title Defect pursuant to this Article V.  For all purposes of this Agreement and notwithstanding anything herein to the contrary (except for the special warranty of title contained in the Assignment as limited by Section 5.2), Noble shall be deemed to have waived, and CONSOL shall have no liability for, any Title Defect which Noble fails to assert as a Title Defect by a properly delivered Title Defect Notice received by CONSOL on or before the Title Defect Claim Date.  To be effective, each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defect(s), (ii) the Marcellus Wells or Leases affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for CONSOL to verify the existence of the alleged Title Defect(s), and (v) the amount by which Noble reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations (in reasonable detail) upon which Noble’s belief is based.  To give CONSOL an opportunity to commence reviewing and curing Title Defects, Noble agrees to use reasonable efforts to give CONSOL, on or before the end of each calendar month prior to the Title Defect Claim Date, written notice of all Title Defects discovered by Noble during the preceding calendar month, which notice may be preliminary in nature and supplemented prior to the expiration of the Title Defect Claim Date.  Noble shall also promptly furnish CONSOL with written notice of any Title Benefit which is discovered by any of Noble’s or any of its Affiliate’s employees, title attorneys, landmen or other title examiners while conducting Noble’s due diligence with respect to the Conveyed Interests prior to the Title Defect Claim Date.

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(b)           Title Benefit Notices.  CONSOL shall have the right, but not the obligation, to deliver to Noble on or before the Title Defect Claim Date with respect to each Title Benefit a notice (a “Title Benefit Notice”) including (i) a description of the Title Benefit, (ii) the Marcellus Wells or Leases affected by the Title Benefit (each a “Title Benefit Property”), and (iii) the amount by which CONSOL reasonably believes the Allocated Value of such Title Benefit Property is increased by the Title Benefit, and the computations upon which CONSOL’s belief is based.

(c)           CONSOL’s Right to Cure.  CONSOL shall have the right, but not the obligation, to attempt, at its sole cost, to cure any Title Defect of which it has been advised by Noble at any time prior to 180 days following CONSOL’s receipt of a Title Defect Notice with respect to such Title Defect (such date of receipt with respect to each Title Defect, the “Title Defect Notice Date”); provided, however, that, if after the diligent pursuit of other remedies reasonably available to CONSOL to cure any such Title Defect, CONSOL reasonably believes that such Title Defect can be cured through a quiet title or similar proceeding, then the applicable Cure Period with respect to such Title Defect shall be extended to 18 months following the applicable Title Defect Notice Date, notwithstanding CONSOL’s previous attempt to cure such Title Defect without the use of a quiet title or similar proceeding, so long as CONSOL’s initial attempt to cure such Title Defect was diligently pursued and CONSOL initiates the quiet title or similar proceeding on or before the end of the original 180-day Cure Period and diligently pursues such proceeding (the “Cure Period”).  In the event that an adjustment for a Title Defect Amount is made to the Closing Cash Payment or the Carry Cost Obligation and CONSOL thereafter cures, during the applicable Cure Period, the Title Defect for which such adjustment was made, then (i) if the adjustment was made to the Closing Cash Payment, Noble shall promptly, but in any event within ten Business Days after such Title Defect has been cured and Noble has received written notice from CONSOL thereof, pay to CONSOL the amount by which the Closing Cash Payment was adjusted on account of such Title Defect, or (ii) if the adjustment was made to the Carry Cost Obligation, then the Carry Cost Obligation shall, within ten Business Days after such Title Defect has been cured and Noble has received written notice from CONSOL thereof, be increased by the amount by which the Carry Cost Obligation was reduced on account of such Title Defect.

(d)           Remedies for Title Defects.  Subject to (w) CONSOL’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted with respect thereto, (x) the rights of the Parties pursuant to Section 14.1(c), (y) the Individual Title Defect Threshold and (z) after decreasing the aggregate Title Defect Amounts by the Title Benefit Amount and the Title Defect Deductible, in the event that any Title Defect timely asserted by Noble in accordance with Section 5.3(a) is not waived in writing by Noble or cured during the Cure Period, CONSOL shall elect to:

(i)           for any Title Defect (A) properly asserted by Noble prior to Closing and for which the Title Defect Amount is agreed to prior to Closing, reduce the Closing Cash Payment by an amount determined pursuant to Section 5.3(g) or Section 5.3(j) (the “Title Defect Amount”), or (B) properly asserted by Noble (i) prior to Closing for which the Title Defect Amount is not agreed to prior to Closing or (ii) after Closing, in each case, reduce the Carried Cost Obligation by the Title Defect Amount of such Title Defect;

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(ii)          upon obtaining Noble’s prior written consent, assume and Indemnify Noble against all Liability (up to the Allocated Value of the affected Conveyed Interest) resulting from such Title Defect with respect to the applicable Conveyed Interests pursuant to an indemnity agreement prepared by CONSOL in a form and substance reasonably acceptable to Noble (a “Title Indemnity Agreement”); or

(iii)         with respect to any Title Defect arising on account of there being less than the Minimum Net Acres for any Area, at CONSOL’s sole cost and expense, obtain additional Net Acres by the acquisition of leases and/or oil and gas mineral fee interests within such Area, or agree to assign to Noble a greater percentage of CONSOL’s interest in one or more existing Leases in such Area, in each case, in order to provide Noble with the Minimum Net Acres for such Area; provided that such additional interests obtained by CONSOL pursuant to this Section 5.3(d)(iii) shall contain material terms reasonably similar to, and be of reasonably similar value as, in each case, those interests giving rise to the Title Defect Properties relating to the Title Defect in question.

(e)           Remedies for Title Benefits.  With respect to each Title Benefit Property reported under Section 5.3(b), the aggregate Title Defect Amounts shall be decreased by an amount equal to the increase in the Allocated Value for the Conveyed Interest attributable to the Title Benefit Property relating to such Title Benefit, as determined pursuant to Section 5.3(h) or Section 5.3(j) (the “Title Benefit Amount”).  A Title Benefit shall only be taken into account if Noble has actual Knowledge of such Title Benefit on or prior to the Title Defect Claim Date.

(f)            Exclusive Remedy.  Except for CONSOL’s special warranty of title contained in the Assignment, and subject to either Party’s rights to terminate this Agreement pursuant to Section 14.1(c), Noble hereby acknowledges and agrees that Section 5.3(d) shall be Noble’s sole and exclusive remedy for any defect of title or any title matter, including any Title Defect, and Noble hereby expressly waives any and all other rights or remedies with respect thereto.

(g)           Title Defect Amount.  The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Conveyed Interest attributed to the affected Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following terms and conditions:

(i)           if Noble and CONSOL agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

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(ii)          if the Title Defect is an Encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii)         if the Title Defect represents a discrepancy such that the actual aggregate Net Acres for the applicable Area is less than the Minimum Net Acres for such Area, then the Title Defect Amount shall be the product obtained by multiplying the difference between such Net Acres amounts for the applicable Area by the Net Acre Allocation applicable to such Area;

(iv)         if the Title Defect represents an Encumbrance upon, or other Title Defect affecting, the Title Defect Property of a type not described above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Conveyed Interest attributed to the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Noble and CONSOL and such other reasonable factors as are necessary to make a proper evaluation; provided, however, that if such Title Defect is reasonably capable of being cured, the Title Defect Amount shall not be greater than the lesser of (A) the reasonable cost and expense of curing such Title Defect and (B) the Allocated Value of the Conveyed Interest attributable to the Title Defect Property;

(v)          the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vi)         notwithstanding anything to the contrary in this Article V, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of the Conveyed Interest attributable to such Title Defect Property.

(h)           Title Benefit Amount.  The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions:

(i)           if Noble and CONSOL agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii)          if the Title Benefit represents a discrepancy such that the actual aggregate Net Acres for any Area is greater than the Minimum Net Acres for such Area, then the Title Benefit Amount shall be the product obtained by multiplying the positive difference between such Net Acres amounts for the applicable Area by the Net Acre Allocation applicable to such Area; and

(iii)         if the Title Benefit is of a type not described above, then the Title Benefit Amounts shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of such Title Benefit Property affected by such Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of such Title Benefit Property, the values placed upon the Title Benefit by Noble and CONSOL and such other reasonable factors as are necessary to make a proper evaluation.

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(i)           Title Deductibles.  Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Closing Cash Payment or the Carried Cost Obligation (as applicable) or any other remedy provided by CONSOL hereunder for any individual Title Defect for which the Title Defect Amount does not exceed $25,000 (the “Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustments to the Closing Cash Payment or the Carried Cost Obligation (as applicable) or any other remedy provided by CONSOL hereunder for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless (A) the sum of the Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold, in the aggregate (excluding any Title Defect Amounts attributable to Title Defects cured by CONSOL or for which CONSOL provides an indemnity pursuant to Section 5.3(d)(ii)) less the sum of all the Title Benefit Amounts determined under Section 5.3(h), exceeds (B) the Title Defect Deductible, after which point Noble shall be entitled to remedies for such Title Defects only to the extent that the Title Defect Amounts with respect thereto are in excess of the Title Defect Deductible.  For the avoidance of doubt, if CONSOL elects pursuant to Section 5.3(d)(ii) to Indemnify Noble for any Title Defect, then, after such election, relating to the Title Defect for which CONSOL provides an indemnity pursuant to Section 5.3(d)(ii) (x) will not be counted towards the Title Defect Deductible and (y) will be counted for purposes of Section 14.1(c).

(j)           Title Dispute Resolution.  CONSOL and Noble shall attempt to agree on each Title Defect, Title Benefit, Title Defect Amount and Title Benefit Amount (collectively “Title Disputes”) prior to the applicable Title Dispute Date.  If CONSOL and Noble are unable to agree by on any Title Dispute by the applicable Title Dispute Date, then either Party shall have the right to elect, upon written notice to the other Party, to initiate arbitration to resolve such Title Dispute.  All Title Disputes shall be exclusively and finally resolved pursuant to this Section 5.3(j).  There shall be a single arbitrator, who shall be a title attorney with at least ten years experience in oil and gas titles involving properties in the regional area in which the Title Defect Properties are located (the “Title Arbitrator”).  The Title Arbitrator shall be selected by mutual agreement of Noble and CONSOL within 15 days after the election by a Party to utilize the provisions of this Section 5.3(j) with respect to a Title Dispute.  If the Parties are unable to mutually agree upon the Title Arbitrator, the Pittsburgh, Pennsylvania office of the AAA shall appoint the Title 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 5.3(j).  The Title Arbitrator’s determination shall be made within 30 days after submission of Title Disputes and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in Section 5.3(g) and Section 5.3(h) and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination.  The Title Arbitrator, however, may not award (i) Noble a greater Title Defect Amount than the Title Defect Amount claimed by Noble in its applicable Title Defect Notice or (ii) CONSOL a greater Title Benefit Amount than the Title Benefit Amount claimed by CONSOL in the applicable Title Benefit Notice.  The Title Arbitrator shall act for the limited purpose of determining the specific Title Disputes submitted by either Party and the Title Arbitrator may not award damages, interest or penalties to either Party with respect to any Title Dispute. CONSOL and Noble shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator.  Each of CONSOL and Noble shall bear one-half of the costs and expenses of the Title Arbitrator.  To the extent that the award of the Title Arbitrator with respect to any Title Dispute is not taken into account as an adjustment to the Closing Cash Payment pursuant to Section 3.4 and Section 3.5 and the applicable Party would otherwise be entitled to an adjustment under the provisions of Section 5.3(i), then within ten days after the Title Arbitrator delivers written notice to Noble and CONSOL of his award with respect to a Title Dispute, and subject to Section 5.3(i), (A) the Carried Cost Obligation shall be increased by the amount so awarded by the Title Arbitrator to CONSOL and (B) the Carried Cost Obligation shall be decreased by the amount so awarded by the Title Arbitrator to Noble.  Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 5.3(j) with respect to any Title Defect properly asserted by Noble prior to the Closing and to the extent any adjustments are not agreed upon by the Parties as of the Closing, the Closing Cash Payment shall not be adjusted therefor at Closing and subsequent adjustments to the Carried Cost Obligation, if any, will be made pursuant to this Section 5.3(j).

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5.4     Casualty or Condemnation Loss.  

(a)           Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the Conveyed Interest, 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 Personal Property due to ordinary wear and tear, in each case, with respect to the Conveyed Interests and Noble shall not assert such matters as any casualty losses or Title Defects hereunder.

(b)           If, after the date of this Agreement but prior to the Closing Date, any portion of the Conveyed Interests is destroyed or damaged by Casualty (other than downhole destruction or impairment through downhole risks) or is taken in condemnation or under right of eminent domain, and the amount of the costs and expenses associated with repairing or restoring the Conveyed Interest(s) affected by such Casualty or taking, determined in the same manner as a Title Defect in accordance with Section 5.3(g), for any Lease, Unit or Marcellus Well taken exceeds 5% of the Total Amount, then Noble shall nevertheless be required to close, and CONSOL shall elect by written notice to Noble prior to Closing either to (i) cause the Conveyed Interest(s) affected by such Casualty or taking to be repaired or restored to at least its condition prior to such casualty or taking, at CONSOL’s sole cost, as promptly as reasonably practicable (which work may extend after the Closing Date), or (ii) treat such Casualty or taking as a Title Defect with respect to the affected Conveyed Interest(s) under Section 5.3.  In the event CONSOL elects not to repair or restore the affected Conveyed Interest(s), any dispute with respect to the value of the Conveyed Interest(s) affected by such Casualty or taking shall be submitted to a “Casualty and Condemnation Arbitrator”, being an attorney with at least ten years experience in oil and gas related matters, and the amount attributable to each such disputed Casualty or taking shall be finally resolved following a procedure substantially similar to that set forth in Section 5.3(j).  CONSOL shall retain all rights to insurance and other claims against Third Parties with respect to the Casualty or taking except to the extent the Parties otherwise agree in writing.

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(c)           If, after the date of this Agreement but prior to the Closing Date, (i) any portion of the Conveyed Interests is destroyed or damaged by Casualty or is taken in condemnation or under right of eminent domain, and the loss as a result of such individual Casualty or taking is 5% of the Total Amount or less, or (ii) any downhole Conveyed Interest (regardless of the amount of loss) is destroyed or otherwise impaired by Casualty, then Noble shall nevertheless be required to close and accept as compensation all sums paid to CONSOL by Third Parties by reason of such Casualty or taking, to the extent attributable to the Conveyed Interests so affected, and CONSOL shall assign, transfer and set over to Noble, or subrogate Noble to, all of CONSOL’s right, title and interest (if any) in any insurance claims, unpaid awards and other rights arising out of such Casualty or taking against Third Parties (other than Affiliates of CONSOL and, as applicable, such Affiliates’ directors, officers, employees and agents), but only to the extent such claims, awards and other rights are attributable to the Conveyed Interests.

5.5     Preferential Purchase Rights and Consents to Assign.  

(a)           With respect to each Preferential Purchase Right set forth in Schedule 7.10, prior to Closing, CONSOL 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 CONSOL that it intends to consummate the acquisition of the Conveyed Interest to which its Preferential Purchase Right applies or if the time for exercising such Preferential Purchase Right has not expired, then the Conveyed Interest subject to such Preferential Purchase Right shall be excluded from the Conveyed Interests to be assigned to Noble at Closing (but only to the extent of the portion of such Conveyed Interest affected by the Preferential Purchase Right), and the Closing Cash Payment shall be reduced by the Allocated Value of such Conveyed Interest (or portion thereof) so excluded.  CONSOL shall be entitled to all consideration given by any Person exercising a Preferential Purchase Right prior to Closing.  If such holder of such Preferential Purchase Right thereafter fails to consummate the acquisition of the Conveyed Interest (or portion thereof) covered by such Preferential Purchase Right on or before 90 days following the Closing Date or the time for exercising such Preferential Purchase Right expires without exercise by the holder thereof (A) CONSOL shall so notify Noble and (B) CONSOL shall assign, on the tenth Business Day following receipt of such notice or termination of such right without exercise, such Conveyed Interest (or portion thereof) that was so excluded to Noble effective as of the Effective Time pursuant to an instrument in substantially the same form as the Assignment, and Noble shall pay into a Tax Partnership Account designated by CONSOL the amount by which the Closing Cash Payment was reduced at Closing with respect to such excluded Conveyed Interest (or portion thereof) (as adjusted pursuant to Section 3.2 through the date of such conveyance); and

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(ii)          All Conveyed Interests 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 sold to Noble at Closing pursuant to the provisions of this Agreement.

(b)           With respect to each Consent set forth in Schedule 7.4 (subject to the provisions of (x) Schedule 9.12(a) with respect to the Processing Contracts and (y) Schedule 9.12(c) with respect to the Gathering Contracts), CONSOL, prior to Closing, 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.

(i)           If (A) CONSOL fails to obtain a Consent set forth in Schedule 7.4 prior to Closing and the failure to obtain such Consent would cause (1) the assignment of the Conveyed Interests affected thereby to Noble to be void or (2) the termination of a Lease under the express terms thereof, (B) a Consent requested by CONSOL is denied in writing, or (C) the Consent is required from a Governmental Authority (other than a Customary Post Closing Consent), then, in each case, (x) the Conveyed Interest (or portion thereof) affected by such un-obtained Consent shall be excluded from the Conveyed Interests to be assigned to Noble at Closing, and the Closing Cash Payment shall be reduced by the Allocated Value of such Conveyed Interest (or portion thereof) so excluded.  In the event that any such Consent (with respect to a Conveyed Interest excluded pursuant to this Section 5.5(b)(i)) that was not obtained prior to Closing is obtained within one year following the Closing Date, then, on the tenthBusiness Day after such Consent is obtained, CONSOL shall assign the Conveyed Interest (or portion thereof) that was so excluded as a result of such previously un-obtained Consent to Noble pursuant to an instrument in substantially the same form as the Assignment, and Noble shall pay into a Tax Partnership Account designated by CONSOL the amount by which the Closing Cash Payment was reduced at Closing with respect to the Conveyed Interest (or portion thereof) so excluded (as adjusted pursuant to Section 3.2 through the date of such conveyance);

(ii)          If CONSOL fails to obtain a Consent set forth in Schedule 7.4 prior to Closing (A) and the failure to obtain such Consent would not cause (1) the assignment of the Conveyed Interest (or portion thereof) affected thereby to Noble to be void or (2) the termination of a Lease under the express terms thereof, (B) such Consent requested by CONSOL is not denied in writing by the holder thereof, and (C) such Consent is not required from a Governmental Authority (or is a Customary Post Closing Consent), then the Conveyed Interest (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by CONSOL to Noble at Closing as part of the Conveyed Interests.  Any Liability that arises due to the failure to obtain such Consent shall be borne 50% by CONSOL and 50% by Noble and

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(iii)         Prior to Closing, CONSOL shall use its commercially reasonable efforts, with reasonable assistance from Noble (including Noble providing requested assurances of financial condition and operator qualifications), to obtain all Consents listed on Schedule 7.4; provided, however, that CONSOL shall not be required to incur any Liability or pay any money in order to obtain any such Consent.

ARTICLE VI

ENVIRONMENTAL MATTERS

6.1     Environmental Defects.

(a)           Assertions of Environmental Defects.  Noble must deliver claim notices to CONSOL meeting the requirements of this Section 6.1(a) (collectively the “Environmental Defect Notices” and individually an “Environmental Defect Notice”) not later than the Environmental Defect Claim Date setting forth any matters that, in Noble’s reasonable opinion, constitute Environmental Defects and that Noble intends to assert as Environmental Defects pursuant to this Section 6.1.  Subject to Noble’s rights under Section 13.2(g) and Section 13.2(h), for all purposes of this Agreement, Noble shall be deemed to have waived, and CONSOL shall have no liability for, any Environmental Defect that Noble fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by CONSOL on or before the Environmental Defect Claim Date.  To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Defect (including the applicable Environmental Law violated or implicated thereby), (ii) a description of each Conveyed Interest (or portion thereof) that is affected by the alleged Environmental Defect, (iii) Noble’s assertion of the Allocated Value of the portion of the Conveyed Interests affected by the alleged Environmental Defect, (iv) supporting documents reasonably necessary for CONSOL to verify the existence of the alleged Environmental Defect, and (v) a calculation of the Remediation Amount (itemized in reasonable detail) that Noble asserts is attributable to such alleged Environmental Defect.  Noble’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Defect and reasonably identify the assumptions used by Noble in calculating the Remediation Amount, including the standards that Noble asserts must be met to comply with Environmental Laws. CONSOL shall have the right, but not the obligation, to attempt, at CONSOL’s sole cost, to cure any claimed Environmental Defect on or before Closing.

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(b)           Remedies for Environmental Defects.  Subject to (x) CONSOL’s continuing right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto, (y) the rights of the Parties pursuant to Section 14.1(c), and (z) the Individual Environmental Threshold and the Environmental Defect Deductible, in the event that any Environmental Defect timely asserted by Noble in accordance with Section 6.1(a) is not waived in writing by Noble or cured before Closing, CONSOL shall, at its sole option, elect to:

(i)           reduce the Closing Cash Payment by the Remediation Amount;

(ii)          assume responsibility for the Remediation of such Environmental Defect and CONSOL shall assume and Indemnify Noble for Liability incurred by Noble resulting from such Environmental Defect or the Remediation of such Environmental Defect; or

(iii)         upon obtaining Noble’s prior written consent, assume and Indemnify Noble against all Liability resulting from such Environmental Defect with respect to the Conveyed Interests pursuant to an indemnity agreement prepared by CONSOL in a form and substance reasonably acceptable to Noble (each, an “Environmental Indemnity Agreement”).

If CONSOL elects the option set forth in clause (i) above, Noble shall be deemed to have assumed responsibility for all costs and expenses attributable to the Remediation of the applicable Environmental Defect and all Liabilities (net to the Conveyed Interests) with respect thereto and Noble’s obligations with respect to the foregoing shall be deemed to constitute Assumed Obligations.  If CONSOL elects the option set forth in clause (ii) above, CONSOL shall use reasonable efforts to implement such Remediation in a manner which is consistent with the requirements of Environmental Laws in a timely fashion for the type of Remediation that CONSOL elects to undertake, and Noble, effective as of the Closing, to the extent necessary, hereby grants to CONSOL and its representatives access to the Conveyed Interests to conduct such Remediation.  CONSOL will be deemed to have adequately completed the Remediation required in the immediately preceding sentence (1) upon receipt of a certificate or approval from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to comply with existing Laws or (2) upon receipt of a certificate from a licensed Third Party professional engineer approved by both Parties that the Remediation has been implemented to the extent necessary to comply with existing Laws, if the certificate or approval from the Government Authority is not applicable.

(c)           Exclusive Remedy.  Subject to either Party’s right to terminate this Agreement pursuant to Section 14.1(c) and the rights of Noble (i) under Section 13.2(g) and Section 13.2(h) and (ii) for any breach of Section 7.19 by CONSOL, Section 6.1(b) shall be the exclusive right and remedy of Noble with respect to any Environmental Defect or other environmental matter.

(d)           Environmental Deductibles.  Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Closing Cash Payment or any other remedy provided by CONSOL hereunder for any individual Environmental Defect for which the Remediation Amount does not exceed $100,000 (the “Individual Environmental Threshold”); and (ii) in no event shall there be any adjustments to the Closing Cash Payment or any other remedy provided by CONSOL hereunder for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Threshold unless (A) the sum of the Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Threshold, in the aggregate (excluding any Remediation Amounts attributable to Conveyed Interests subject to Environmental Defects cured by CONSOL or for which CONSOL provides an Environmental Indemnity Agreement pursuant to Section 6.1(b)(iii)) exceeds (B) the Environmental Defect Deductible, after which point Noble shall be entitled to remedies for such Environmental Defect only to the extent that the Remediation Amounts with respect thereto are in excess of the Environmental Defect Deductible.  For the avoidance of doubt, if CONSOL elects pursuant to Section 6.1(b)(iii) to Indemnify Noble with respect to any Environmental Defect, then, after such election, the Remediation Amounts for such Environmental Defect (x) will not be counted towards the Environmental Defect Deductible, and (y) will be counted for purposes of Section 14.1(c).

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(e)           Environmental Dispute Resolution.  CONSOL and Noble shall attempt to agree on all Environmental Defects and Remediation Amounts (collectively, the “Environmental Disputes”) prior to Closing.  If CONSOL and Noble are unable to agree upon any Environmental Dispute by Closing, then either Party shall have the right to elect, upon written notice to the other Party, to initiate arbitration to resolve such Environmental Dispute.  All Environmental Disputes shall be exclusively and finally resolve such Environmental Dispute through arbitration pursuant to this Section 6.1(e).  There shall be a single arbitrator, who shall be an environmental attorney with at least ten years experience in environmental matters involving oil and gas producing properties in the regional area in which the affected Conveyed Interests are located (the “Environmental Arbitrator”).  The Environmental Arbitrator shall be selected by mutual agreement of Noble and CONSOL within 15 days after the election by a Party to utilize the provisions of this Section 6.1(e) with respect to an Environmental Dispute.  If the Parties are unable to mutually agree upon the Environmental Arbitrator, the Pittsburgh, Pennsylvania office of the AAA shall appoint such Environmental 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 6.1(e).  The Environmental Arbitrator’s determination shall be made within 30 days after submission of the Environmental Disputes and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 6.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary to make a proper determination.  The Environmental Arbitrator, however, may not award Noble a greater Remediation Amount than the Remediation Amount claimed by Noble in its applicable Environmental Defect Notice.  The Environmental Arbitrator shall act for the limited purpose of determining the specific Environmental Disputes submitted by either Party and may not award damages, interest or penalties to either Party with respect to any Environmental Dispute. CONSOL and Noble shall each bear its own legal fees and other costs of presenting its case to the Environmental Arbitrator.  Each of CONSOL and Noble shall bear one-half of the costs and expenses of the Environmental Arbitrator.  To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Closing Cash Payment pursuant to Section 3.4 or Section 3.5, and the applicable Party would otherwise be entitled to an adjustment under the provisions of Section 6.1(d), then within ten days after the Environmental Arbitrator delivers written notice to Noble and CONSOL of his award with respect to a Remediation Amount, and subject to Section 6.1(d), (i) the Carried Cost Obligation shall be increased by the amount so awarded by the Environmental Arbitrator to CONSOL and (ii) the Carried Cost Obligation shall be decreased by the amount so awarded by the Environmental Arbitrator to Noble.  Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 6.1(e), and to the extent any adjustments are not agreed upon by the Parties as of the Closing, the Closing Cash Payment shall not be adjusted therefor at Closing and subsequent adjustments to the Carried Cost Obligation, if any, will be made pursuant to this Section 6.1(e).

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6.2     NORM, Wastes and Other Substances.  Noble acknowledges that the Conveyed Interests have been used for exploration, development and production of oil and gas and that there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Conveyed Interests or associated with the Conveyed Interests.  Equipment and sites included in the Conveyed Interests may contain asbestos, NORM or other Hazardous Substances.  NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms.  The wells, materials and equipment located on the Conveyed Interests or included in the Conveyed Interests may contain NORM and other wastes or Hazardous Substances.  NORM containing material and/or other wastes or Hazardous Substances may have come in contact with various environmental media, including water, soils or sediment.  Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Conveyed Interests.  Notwithstanding anything herein to the contrary, Noble shall not be permitted to claim any Environmental Defect on the account of the presence of NORM on the properties underlying the Conveyed Interests.

ARTICLE VII

REPRESENTATIONS AND WARRANTIES OF CONSOL

CONSOL represents and warrants to Noble as follows:

7.1     Organization, Existence.  CONSOL is a limited liability company duly formed and validly existing under the Laws of the state of its formation.  CONSOL has all requisite power and authority to own and operate its property (including the Conveyed Interests) 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.

7.2     Authorization.  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 (a) all necessary limited liability company action on the part of CONSOL and (b) its members.  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).

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7.3     No Conflicts.  Except as set forth on Schedule 7.3 and assuming the receipt of all consents (including any Consent) and the waiver of, or compliance with, all Preferential Purchase Rights, the execution, delivery and performance by CONSOL of this Agreement and the consummation of the transactions contemplated herein 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 Lease, Applicable Contract, note, bond, mortgage, indenture or license to which CONSOL is a party or by which CONSOL or the Conveyed Interests may be bound or (c) violate any Law applicable to CONSOL or any of the Conveyed Interests, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

7.4     Consents.  Except (a) as set forth on Schedule 7.4, (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 and (e) any consents or approvals required under the HSR Act, 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 Conveyed Interests or the consummation of the transactions contemplated by this Agreement by CONSOL (each, a “Consent”).

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

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

7.7           Litigation.  Except as set forth on Schedule 7.7, 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, against CONSOL or (b) to CONSOL’s Knowledge, pending or threatened against the Conveyed Interests, in each case, with respect to the ownership or operation of the Conveyed Interests.

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7.8     Material Contracts.  

(a)           Schedule 7.8(a) sets forth all Applicable Contracts of the type described below (collectively, the “Material Contracts”):

(i)          any Applicable Contract that can reasonably be expected to result in aggregate payments by CONSOL of more than $250,000 during the current or any subsequent calendar year or $500,000 in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(ii)         any Applicable Contract that can reasonably be expected to result in aggregate revenues to CONSOL of more than $250,000 during the current or any subsequent calendar year or $500,000 in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(iii)        any Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar Contract that is not terminable without penalty on 60 days or less notice;

(iv)        any indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bonds, letters of credit or similar financial Contract (a “Debt Instrument”);

(v)         any Applicable Contract that constitutes a lease under which CONSOL is the lessor or the lessee of personal property which lease (A) cannot be terminated by CONSOL without penalty upon 60 days or less notice and (B) involves an annual base rental of more than $500,000;

(vi)        any Applicable Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, CONSOL conducts business, including area of mutual interest Contracts;

(vii)       any Applicable Contract that contains calls upon or options to purchase production;

(viii)      any Applicable Contract that constitutes a Hedge Contract;

(ix)         any Applicable Contract that constitutes a partnership agreement, joint venture agreement or similar Contract (in each case, excluding any tax partnership);

(x)         any Applicable Contracts for the use or sharing of drilling rigs;

(xi)        any executory Applicable Contract that constitutes a pending farmout agreement, exploration agreement, participation agreement or other similar Contract where the primary obligation thereunder has not fully been performed;

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(xii)        any Applicable Contract that constitutes a joint operating agreement; and

(xiii)       any Applicable Contract with any Affiliate of CONSOL that will not be terminable by Noble within 30 days or less notice other than joint operating agreements and the Development Agreement.

(b)           With respect to the Material Contracts, except as set forth on Schedule 7.8(b):

(i)          there exists no default under any Material Contract by CONSOL or, to CONSOL’s Knowledge, by any other Person that is a party to such Material 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 Contract by CONSOL or, to CONSOL’s Knowledge, any other Person who is a party to such Material Contract;

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

(iii)        there are no purchase and sale agreements pursuant to which CONSOL or its Affiliates acquired (directly or indirectly) the Conveyed Interests that contain indemnity obligations that will be binding on Noble following Closing.

7.9     No Violation of Laws.  Except as set forth on Schedule 7.9 and except as would not have a Material Adverse Effect, CONSOL is not, and to CONSOL’s Knowledge no Third Party operator is, in violation of any applicable Laws with respect to the ownership or operation of the Conveyed Interests.  This Section 7.9 does not include any matters with respect to Environmental Laws which are exclusively covered in Section 7.19.

7.10   Preferential Purchase Rights.  Except as set forth on Schedule 7.10, 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 clause (a) and (b) above, that are applicable to the transfer of the Conveyed Interests in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

7.11   Payment of Royalties.  Except for such items that are being held in suspense as permitted pursuant to applicable Law or Contract, CONSOL has paid in all material respects all Burdens due by CONSOL with respect the Conveyed Interests or if not so paid, is contesting such Burdens in good faith in the normal course of business.

7.12   Imbalances.  There are no Well Imbalances and, to CONSOL’s Knowledge, Schedule 7.12 sets forth all Pipeline Imbalances, in each case, associated with the Oil and Gas Assets as of the Effective Time.

7.13  Current Commitments.  Schedule 7.13 sets forth, as of the date of this Agreement, all approved authorizations for expenditures and other approved capital commitments (“AFEs”) relating to the Properties to drill or rework wells or conduct other operations for which CONSOL had the right to consent or non-consent the operations to which such capital expenditures or commitments pertain (in each case) for which all of the activities anticipated in such AFEs have not been completed by the date of this Agreement.

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7.14   Asset Taxes.

(a)           Except as set forth on Schedule 7.14(a), all Asset Taxes with respect to the Oil and Gas Assets that have become due and payable by CONSOL prior to the Effective Time have been properly paid.

(b)           The adjusted tax bases of the Oil and Gas Assets contributed to the Tax Partnership by CONSOL (as described in Section 15.3) are (i) in the aggregate, not less than $2,000,000,000 as of the Closing Date, and (ii) in all material respects, as set forth in Schedule 7.14(b) and, in each case, as determined under federal income Tax principles.

7.15   Brokers’ 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.

7.16   Delivery of Hydrocarbons.  Except as set forth on Schedule 7.16 and for the rights of any lessor to take free gas under the terms of its Lease for its use on the lands covered by such Lease, CONSOL is not obligated by virtue of any take-or-pay payment, advance payment or other similar payment (other than gas balancing arrangements), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to the Conveyed Interests at some future time without receiving payment therefor at or after the time of delivery.  None of the revenues attributable to CONSOL’s interest in any producing Marcellus Well are being held in suspense.

7.17   Partnerships.  Except as set forth on Schedule 7.17, none of the Conveyed Interests are, or prior to Closing will be, subject to tax partnership reporting for federal or state income tax purposes.  Schedule 7.17 sets forth all of the Conveyed Interests that, prior to Closing, are deemed by agreement or applicable Law to be held by a partnership for federal or state income tax purposes, and, to the extent any of the Conveyed Interests are deemed by agreement or applicable Law to be held by a partnership for federal or state income tax purposes, each such partnership has or shall have in effect an election under Section 754 of the Code (and equivalent state income tax provision, if any) that will apply with respect to such portion of the Conveyed Interests.

7.18   Bonds and Credit Support.  Schedule 7.18 lists all bonds, letters of credit and other similar credit support instruments maintained by CONSOL with any Governmental Authority or other Third Party with respect to the Conveyed Interests for which Noble will be required to maintain from and after Closing.

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7.19   Environmental.  

(a)           With respect to the Conveyed Interests, 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) are in existence as of the date of this Agreement, (ii) are based on any Environmental Laws that relate to the present or future use of any of the Conveyed Interests and (iii) require any remediation or change in the present conditions of any of the Conveyed Interests.

(b)           Except as set forth on Schedule 7.19, as of the date of this Agreement, CONSOL has not received written notice from any Person of any release, spill, disposal, event, condition, circumstance, activity, practice or incident concerning any land, facility, asset or property included in the Conveyed Interests that:  (i) interferes with or prevents compliance by CONSOL with any Environmental Law or the terms of any license or permit issued pursuant thereto or (ii) gives rise to or results in any common Law or other liability of CONSOL to any Person.

(c)           To CONSOL’s Knowledge, as of the date hereof, CONSOL has provided Noble all material written reports prepared by a Third Party on behalf of CONSOL with respect to any of the Conveyed Interests.

7.20   Payout Status.  To CONSOL’s Knowledge, Schedule 7.20 sets forth the payout status as of the date set forth in such Schedule of each Marcellus Well and Lease subject to a reversion or other adjustment at some level of cost recovery or payout.

7.21  Permits.  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 Conveyed Interests, except where the failure to possess any such Permit would not have a Material Adverse Effect.  This Section 7.21 does not include any matters with respect to Environmental Laws, such matters being exclusively in Section 7.19.

7.22  Marcellus Wells.  To CONSOL’s Knowledge, as of the date hereof (a) all of the Marcellus Wells that have been drilled and completed have been so drilled and completed within the boundaries of the Leases and/or Units or as otherwise permitted by the Applicable Contracts and (b) there are no Marcellus Wells located on the Leases that are subject to any order from any Government Authority or written notice from any other Third Party requiring that such well be plugged and abandoned.

7.23   Suspense Accounts.  Except as set forth in Schedule 7.23, as of date set forth on such Schedule, CONSOL does not hold any material Third Party funds in suspense with respect to any of the Conveyed Interests.

7.24   Depletion.  Except as provided in Schedule 7.24, to CONSOL’s Knowledge, as of the date hereof, (a) no Marcellus Wells have watered out, (b) there is no collapsed casing in the Marcellus Wells and (c) there is no sand infiltration of any Marcellus Well.

7.25  Condemnation and Eminent Domain.  Except as provided in Schedule 7.25, to CONSOL’s Knowledge, as of the date hereof, no action for condemnation or taking under right of eminent domain is pending or threatened with respect to any Conveyed Interest or portion thereof.

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7.26  Mandatory Drilling Obligations.  Except as provided in Schedule 7.26 and except for those Leases that contain an optional right to drill to maintain acreage thereunder, to CONSOL’s Knowledge, no Lease contains any drilling obligations that would require the mandatory drilling of a Marcellus Well within one year of the Effective Time.

7.27   Offset Obligations.  Except as provided in Schedule 7.27, as of the date hereof, to CONSOL’s Knowledge, CONSOL is under no obligation to drill a well pursuant to any offset drilling obligations with respect to the Conveyed Interests or any obligation to pay compensatory royalties resulting from any offset drilling obligations.

7.28        Requisite Noteholders.  In order to obtain the consent or amendment more particularly described in Section 9.8 with respect to each CONSOL Indenture, the affirmative vote of the holders of at least a majority of the principal amount of the notes under such CONSOL Indenture (such percentage of noteholders, collectively, the “Requisite Noteholders”) would be required.

ARTICLE VIII

NOBLE’S REPRESENTATIONS AND WARRANTIES

Noble represents and warrants to CONSOL the following:

8.1     Organization; Existence.  Noble is a corporation, duly formed, validly existing and in good standing under the Laws of the state of its incorporation and has all requisite power and authority to own and operate its property 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.

8.2     Authorization.  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).

8.3     No Conflicts.  The execution, delivery and performance by Noble of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with, violate or result in a breach of any provisions of the organizational 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 note, bond, mortgage, indenture or license to which Noble is a party or by which Noble or any of its property may be bound or (c) violate any Law applicable to Noble or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a material adverse effect upon the ability of Noble to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

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8.4    Consents.  With the exception of any consent or approval required under the HSR Act, there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that would be applicable in connection with the consummation of the transactions contemplated by this Agreement by Noble.

8.5     Bankruptcy.  There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Noble’s knowledge, threatened against Noble or any Affiliate of Noble.

8.6     Litigation.  There is no investigation, lawsuit, action, or litigation by any Person by or before any Governmental Authority or arbitrator, and no legal, administrative, or arbitration proceedings pending, or to Noble’s knowledge, threatened against Noble, or to which Noble is a party, that would have a material adverse effect upon the ability of Noble to consummate the transactions contemplated in this Agreement.

8.7           Regulatory.  Noble is now, and hereafter shall continue to be, qualified per all regulations of Governmental Authorities and other applicable Laws to own the Conveyed Interests, and the consummation of the transactions contemplated in this Agreement will not cause Noble to be disqualified as such an owner or operator.  To the extent required by any applicable Laws, Noble currently has, and will hereafter continue to maintain, lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all applicable Laws governing the ownership of the Conveyed Interests and has filed any and all currently required reports necessary for such ownership with all Governmental Authorities having jurisdiction over such ownership.

8.8     Financing.  Noble has, and shall have as of the Closing Date, sufficient funds with which to pay the Closing Cash Payment and consummate the transactions contemplated by this Agreement and the Development Agreement.

8.9      Independent Evaluation.  Noble is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities.  In making its decision to enter into this Agreement and to consummate the transaction contemplated hereby, Noble (a) has relied or shall rely solely on its own independent investigation and evaluation of the Conveyed Interests and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors engaged by CONSOL, and (b) has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Conveyed Interests.

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8.10        Brokers’ 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 CONSOL’s Affiliates shall have any responsibility.

8.11   Accredited Investor.  Noble is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Conveyed Interests for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

8.12   Oil & Gas Interests.  Other than as contemplated by this Agreement and the Transaction Documents, Noble and its Affiliates have no interests in any, nor have they entered into any contracts or agreements to acquire any, oil, gas and/or mineral interests, subleases, fee mineral interests, royalties, overriding royalties, production payments, net profits interests, carried interests, reversionary interests and other interests in oil, gas and/or minerals in place in the Development Area.

ARTICLE IX

CERTAIN AGREEMENTS

9.1     Conduct of Business.  Except as (w) set forth on Schedule 9.1, (x) for the operations covered by the AFEs and other capital commitments described on Schedule 7.13, (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)           CONSOL agrees that from and after the date hereof until Closing, CONSOL will:

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

(iii)         maintain the books of account and records relating to the Conveyed Interests 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 Material Contract;

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(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 Conveyed Interests 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 Conveyed Interests.

(b)           CONSOL agrees that from and after the date hereof until Closing, CONSOL will not:

(i)           subject to the provisions of this Section 9.1(b)(i), propose or agree to participate in any operation with respect to the Conveyed Interests anticipated to cost in excess of $250,000 (net to the Conveyed Interests) without the prior written consent of Noble; provided that, with respect to each AFE proposed by a Third Party in excess of $50,000 (net to the Conveyed Interests) 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 Conveyed Interests that is anticipated to cost in excess of $250,000 per operation (net to the Conveyed Interests), 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.  If Noble affirmatively elects to non-consent to any such operation proposed by a Third Party that is anticipated to cost in excess of $250,000 (net to the Conveyed Interests), CONSOL shall nevertheless be entitled to consent to such operation and if CONSOL does consent to such operation, then the Conveyed Interests subject to such operation shall be excluded from the Conveyed Interests conveyed to Noble at Closing and shall be considered Excluded Assets for all purposes hereunder and the Closing Cash Payment shall be reduced by the Allocated Value of all such Conveyed Interests so excluded;

(ii)          enter into an Applicable Contract that if entered into on or prior to the date of this Agreement, would be required to be listed on Schedule 7.8(a);

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

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(iv)         settle any suit or litigation or waive any material claims or rights of material value, in each case, attributable to the Conveyed Interests and affecting the period after the Effective Time;

(v)          transfer, sell, mortgage, pledge or dispose of the Conveyed Interests 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 Conveyed Interests or for which replacement equipment of equal or greater value has been obtained;

(vi)         voluntarily relinquish its position as operator with respect to any Conveyed Interest that CONSOL operated as of (A) the date of this Agreement, or (B) the Closing Date; or

(vii)        commit to do any of the foregoing.

(c)           Noble acknowledges that CONSOL owns undivided interests in certain of the Conveyed Interests 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 of this Section 9.1, 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 9.1.

9.2     Governmental Bonds.  Noble acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by CONSOL or its Affiliates with Governmental Authorities and relating to the Conveyed Interests are transferable to Noble.  At or prior to Closing, Noble shall deliver to CONSOL evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements (if any) of such authorities to own the Conveyed Interests and, to the extent Noble will be designated as operator under the Development Agreement with respect to any Conveyed Interest, the operatorship of such Conveyed Interests.

9.3    HSR Act.  If applicable, within ten Business Days 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, subject to the terms of the Confidentiality Agreement, 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 9.3 shall be paid one-half by Noble and one-half by CONSOL.

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9.4          Additional Interests.  The Parties acknowledge that CONSOL or an Affiliate has acquired or may acquire additional oil and gas leases and oil and gas mineral fee interests in the Development Area from and after April 29, 2011 (CONSOL’s interest in such oil and gas leases and oil and gas mineral fee interests, excluding those acquired pursuant to Section 5.3(d)(iii) and Leases acquired by CONSOL from the Land Affiliates, the “Additional Interests”).  The Parties agree that any such Additional Interests shall be excluded from the transactions contemplated by this Agreement (and no adjustment shall be made to the Closing Cash Payment or the Carried Cost Obligation as a result thereof) and that CONSOL shall offer to Noble, within 15 days following Closing, Noble’s undivided 50% share of any such Additional Interests as either “Fill-In Interests” (as defined in the Development Agreement) or “Option Interests” (as defined in the Development Agreement) pursuant to the terms of Article V of the Development Agreement.

9.5     Non-Solicitation of Employees.  From and after the date of this Agreement until the date that is the earlier of (a) the Closing and (b) the one-year anniversary date of this Agreement, Noble and its Affiliates may not solicit or hire any officer or employee of CONSOL or its Affiliates without first obtaining the prior written consent of CONSOL; provided that this prohibition shall not apply to offers of employment made by Noble or its Affiliates pursuant to a general solicitation of employment to the public or the industry.

9.6     Gathering Assets.  Immediately following the execution of this Agreement and up to Closing, the Parties agree to use their commercially reasonable efforts to negotiate the terms by which (a) CONSOL would transfer, to a jointly owned and newly formed limited liability company (the “Gathering Company”), all of CONSOL’s interest in the existing compression equipment, flowlines, pipelines, separation and processing facilities and gathering systems (in each case) downstream from the tailgate of the lease separation and metering equipment of the Wells, which equipment, flowlines, pipelines, separation and processing facilities and gathering system are located in the Development Area and relate to the Marcellus Formation and Hydrocarbons produced therefrom, but including, for clarity, the gathering systems connected to the Legacy Wells (100% of such interest in such assets, the “Existing Gathering Assets”), and (b) Noble would contribute to the Gathering Company the Closing Funds, in each case, pursuant to a contribution agreement to be entered into at Closing (the “Contribution Agreement”).  The material terms of the Contribution Agreement, the limited liability company agreement of the Gathering Company and the gathering agreements pursuant to which the Gathering Company will provide gathering services to the Parties (collectively, the “Gathering JV Agreements”) are more particularly described in the Gathering Term Sheet.  In the event that the Parties are unable to agree upon the final forms of the Gathering JV Agreements on or prior to the Targeted Closing Date, the provisions of Schedule 9.6 shall be applicable.

9.7           Further Assurances. Noble and CONSOL agree to take such further actions and execute, acknowledge and deliver all such further documents as are reasonably requested by the other Party or Parties, as the case may be, for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement, including the Assignment.

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9.8     CONSOL Indentures.  CONSOL agrees to use its commercially reasonable efforts to obtain, prior to Closing, the consent of the Requisite Noteholders or an amendment to the CONSOL Indentures agreed to by the Requisite Noteholders, in either case, which clarifies that the transactions contemplated by this Agreement, the Development Agreement and the other Transaction Documents are permitted by the CONSOL Indentures.  CONSOL and its Affiliates will commence soliciting such consent or amendment on or prior to seven days following the date hereof.  For purposes of this Section 9.8, the Parties agree that the use of CONSOL’s “commercially reasonable efforts” shall not require CONSOL to pay more under the CONSOL Indentures than 0.50% of the total principal amount of the notes under each CONSOL Indenture to obtain such consent or amendment.

9.9     Secondees.  At or prior to Closing, Noble and CONSOL will each determine which of its employees, if any (but not to exceed five employees each), will be seconded into the organization of CONSOL or Noble, as applicable, and the Parties shall jointly agree on the positions that such secondees will have in such organizations.

9.10   Subsurface Access Easement.  At Closing, pursuant to the Assignment, CONSOL will grant to Noble a subsurface easement through the CONSOL Shallow Depths for the purposes of accessing the Marcellus Formation with respect to the Conveyed Interests (the “Subsurface Access Easement”).

9.11    Exclusivity.  Until the earlier of Closing or the termination of this Agreement pursuant to Section 14.1, (a) CONSOL shall (i) not, (ii) cause its Affiliates, and its and their respective directors, officers and employees, not to, and (iii) instruct its Representatives not to, in each case, take any action to, directly or indirectly, to (A) encourage, initiate or solicit any Alternate Transaction, (B) initiate or participate in any discussions (other than to respond negatively) or negotiations with any Third Party (other than the Noble Representatives) in connection with any Alternate Transaction or (C) enter into any agreement (including any letter of intent or confidentiality agreement) with respect to any Alternate Transaction, (b) CONSOL shall (i) make each of its Affiliates, and its and their respective directors, officers and employees, and each of its Representatives (in each case) aware of the covenants contained in this Section 9.11, and (ii) promptly notify Noble of the receipt by CONSOL or its Affiliates of any written inquiries or proposals from any Third Party relating to any potential Alternate Transaction, and (c) CONSOL shall not discuss any Alternate Transaction with its Representatives (other than conversations pursuant to which a Representative notifies CONSOL of an Alternative Transaction).

9.12   Downstream Contracts; Processing Contracts; Gathering Contracts.  The Parties will comply with the provisions set forth in (a) Section 2.10 of the Development Agreement regarding the assignment to Noble of certain rights under the Downstream Contracts and the Peoples Contract, (b) Schedule 9.12(a) regarding the assignment to Noble of certain rights under the Processing Contracts, and (c) Schedule 9.12(c) regarding the assignment to Noble of certain rights under the Gathering Contracts.

9.13         Development Plan and Annual Plan and Budget.  The Parties agree to use their commercially reasonable efforts to mutually agree upon a more detailed Development Plan (as such term is defined in the Development Agreement) and Annual Plan and Budget (as such term is defined in the Development Agreement) for calendar year 2012, in each case, prior to Closing.  If the Parties are able to reach such agreement, such agreed upon Development Plan and/or Annual Plan and Budget, as applicable, will replace the Development Plan attached to the Development Agreement as Exhibit E and/or the Annual Plan and Budget attached to the Development Agreement as Exhibit F, as applicable; provided that if the Parties are unable to reach such agreement, the Development Plan attached as of the date hereof to the Development Agreement as Exhibit E and/or the Annual Plan and Budget attached as of the date hereof to the Development Agreement as Exhibit F, as applicable, shall remain in effect.

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ARTICLE X

NOBLE’S CONDITIONS TO CLOSING

The obligations of Noble to consummate the acquisition of the Conveyed Interests 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:

10.1   Representations.  The representations and warranties of CONSOL set forth in Article VII shall be true and correct in all material respects (without regard to materiality qualifiers) as of the Closing Date as though made 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).

10.2   Performance.  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.

10.3   No 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.

10.4   Title Defects and Environmental Defects.  The sum of (a) all (i) Title Defect Amounts determined under Section 5.3(d)(i) prior to the Closing (or if not so determined prior to Closing, as determined by Noble in its reasonable, good faith opinion) with respect to Title Defects asserted by Noble prior to Closing, less (ii) the sum of all Title Benefit Amounts determined under Section 5.3(h) prior to Closing (or if not so determined prior to Closing, as determined by CONSOL in its reasonable, good faith opinion), plus (b) all Remediation Amounts for Environmental Defects determined under Section 6.1(b)(i) prior to the Closing (or if not so determined prior to Closing, as determined by Noble in its reasonable, good faith opinion), plus (c) all adjustments to the Closing Cash Payment made pursuant to Section 5.5(a)(i) as a result of un-obtained or un-waived Preferential Purchase Rights, plus (d) all adjustments to the Closing Cash Payment made pursuant to Section 5.5(b)(i) as a result of un-obtained Consents shall be less than 20% of the Total Amount.

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10.5   Certificate.  An authorized officer of CONSOL shall execute and deliver a certificate dated as of the Closing Date certifying on behalf of CONSOL that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled by CONSOL and, if applicable, any exceptions to such conditions that have been waived by Noble.

10.6   HSR 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.

10.7        Closing 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 12.3.

ARTICLE XI

CONSOL’S CONDITIONS TO CLOSING

The obligations of CONSOL to consummate the transfer of the Conveyed Interests 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:

11.1   Representations.  The representations and warranties of Noble set forth in Article VIII shall be true and correct in all material respects (without regard to materiality qualifiers) as of the Closing Date (except with respect to the representation and warranty set forth in Section 8.12, which shall be true in all respects) as though made 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).

11.2   Performance.  Noble shall have performed, observed or complied, in all material respects, with 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.

11.3   No 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.

11.4   Title Defects and Environmental Defects.  The sum of (a) all (i) Title Defect Amounts determined under Section 5.3(d)(i) prior to the Closing (or if not so determined prior to Closing, as determined by Noble in its reasonable, good faith opinion) with respect to Title Defects asserted by Noble prior to Closing, less (ii) the sum of all Title Benefit Amounts determined under Section 5.3(h) prior to Closing (or if not so determined prior to Closing, as determined by CONSOL in its reasonable, good faith opinion), plus (b) all Remediation Amounts for Environmental Defects determined under Section 6.1(b)(i) prior to the Closing (or if not so determined prior to Closing, as determined by Noble in its reasonable, good faith opinion), plus (c) all adjustments to the Closing Cash Payment made pursuant to Section 5.5(a)(i) as a result of un-obtained or un-waived Preferential Purchase Rights, plus (d) all adjustments to the Closing Cash Payment made pursuant to Section 5.5(b)(i) as a result of un-obtained Consents shall be less than 20% of the Total Amount.

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11.5   HSR 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.

11.6        Certificate.  An authorized officer of Noble shall execute and deliver a certificate dated as of the Closing Date certifying on behalf of Noble that the conditions set forth in Section 11.1 and Section 11.2 have been fulfilled by Noble and, if applicable, any exceptions to such conditions that have been waived by CONSOL.

11.7  Closing Deliverables.  Noble shall have delivered (or be ready, willing and able to deliver at Closing) to CONSOL the documents and other items, including the Closing Cash Payment, required to be delivered by Noble under Section 12.3.

11.8   Indenture.  CONSOL shall have received the consent of the Requisite Noteholders or the agreement by the Requisite Noteholders of an amendment to the CONSOL Indentures, in either case, which clarifies that the transactions contemplated by this Agreement, the Development Agreement and the other Transaction Documents are permitted under the CONSOL Indentures.

ARTICLE XII

CLOSING

12.1  Date of Closing.  Subject to the conditions stated in this Agreement, the transfer by CONSOL of the Conveyed Interests to Noble pursuant to this Agreement (the “Closing”) shall occur on or before September 30, 2011 (or the date by which such date is extended pursuant to the provisions of Schedule 9.6, if applicable), or if all conditions to Closing in Article XI have not yet been satisfied or waived by the Targeted Closing Date, then five Business Days after such conditions have been satisfied or waived, or such other date as Noble and CONSOL may agree upon in writing.  The date Closing occurs shall be the “Closing Date.”

12.2Place of Closing.  The Closing shall be held at the offices of Vinson & Elkins LLP, Suite 2500, 1001 Fannin Street, Houston, Texas 77002-1670 or such other location as Noble and CONSOL may agree upon in writing.

12.3  Closing 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:

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

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

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

(d)           Noble shall deliver, to the Cost Reconciliation Account as designated in the Preliminary Settlement Statement by CONSOL, by direct bank or wire transfer in same day funds, the Closing Cash Payment;

(e)           CONSOL and Noble shall execute and deliver the NAESB Agreement;

(f)           CNX Gas Corporation 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 Corporation for federal income tax purposes and (ii) CNX Gas Corporation is neither a disregarded entity nor a foreign person within the meaning of the Code and the Treasury Regulations promulgated thereunder;

(g)           CONSOL and Noble shall execute and deliver the Tax Partnership Agreement;

(h)           CONSOL and Noble shall execute and deliver the Development Agreement;

(i)           CONSOL and Noble shall execute and deliver the CONSOL Secondment Agreement;

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

(k)           CONSOL shall deliver a recordable release of any trust, mortgages, financing statements, fixture filings and security agreements (other than those provided for in any Third Party Operating Agreements) made by CONSOL affecting the Conveyed Interests;

(l)            if not previously executed and delivered by the Parties, CONSOL and Noble shall execute and deliver the Gathering JV Agreements;

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

(n)           CONSOL and Noble shall, and CONSOL shall cause its Affiliates that are a party thereto to, execute and deliver the Surface Use Agreement;

(o)           CONSOL and Noble shall, and CONSOL shall cause its Affiliates that are a party thereto to, execute and deliver the Water Use Agreement;

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(p)           CONSOL and Noble shall execute and deliver the Master JOA and each Unit JOA for those Drilling Units containing Marcellus Wells;

(q)           CONSOL and Noble shall (i) execute and deliver the Master JOA Memorandum and each Unit JOA Memorandum with respect to those Unit JOAs executed and delivered pursuant to Section 12.3(p), in each case, in sufficient counterparts to facilitate recording in the applicable counties covering the Conveyed Interests or the applicable Drilling Units, as applicable, and (ii) deliver the applicable UCC-1 Financing Statements relating to the Master JOA Memorandum and each such Unit JOA Memorandum;

(r)           if the condition in Section 11.8 is satisfied, CONSOL shall deliver evidence that the consent or agreement, as applicable, of the Requisite Noteholders has been obtained pursuant to Section 9.8; and

(s)           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.

12.4   Records.  

(a)           In addition to the obligations set forth under Section 12.3 above, no later than 90 days following the Closing Date, CONSOL shall deliver to Noble possession of the Records to which Noble is entitled pursuant to the terms of this Agreement.

(b)           Promptly following the date hereof, CONSOL shall make available to Noble true and complete copies of all Tax Returns that have been filed by or on behalf of CONSOL for tax periods beginning on or after January 1, 2010, with respect to any Asset Taxes imposed or based in whole or in part on CONSOL’s interest in the Conveyed Interests or Hydrocarbons produced from the Conveyed Interests.

ARTICLE XIII

ASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1   Assumption by Noble.  Without limiting Noble’s rights to indemnity under this Article XIII and Noble’s rights under any Title Indemnity Agreement or Environmental Indemnity Agreement, 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 the Conveyed Interests, 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 Conveyed Interests (all of said obligations and Liabilities, subject to the exclusions below, herein being referred to as the “Assumed Obligations”).

13.2  Indemnities of CONSOL.  Effective as of the Closing, subject to the limitations set forth in Section 13.4 and Section 13.8 and otherwise in this Agreement, 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:

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(a)           any breach by CONSOL of its representations or warranties contained in Article VII;

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

(c)           the payment, underpayment or nonpayment of Asset Taxes relating to the Conveyed Interests for periods prior to the Effective Time that CONSOL is responsible pursuant to Section 15.2(b);

(d)           the actions, suits or proceedings, if any, set forth on Schedule 7.7, except insofar and only insofar as they are attributable or relate to the ownership or operation of the Conveyed Interests for periods from and after the Effective Time;

(e)           personal injury, illness or death relating to the Conveyed Interests, to the extent such injury, illness or death (i) occurs both prior to the Effective Time and during CONSOL’s ownership of the Conveyed Interests, or (ii) arises from, results from or relates to events that occurred both prior to the Effective Time and during CONSOL’s ownership of the Conveyed Interests;

(f)           the gross negligence or willful misconduct of CONSOL in connection with its operations, prior to the Closing Date, of the Conveyed Interests in its capacity as operator thereof;

(g)           any Environmental Condition in existence as of the Closing Date that is attributable to, or that arose in connection with, any oil and gas operations conducted with respect to the CONSOL Shallow Depths but only to the extent such Environmental Conditions occurred during CONSOL’s period of ownership of such CONSOL Shallow Depths;

(h)           Hazardous Substances related or attributable to the Conveyed Interests that, prior to the Effective Time and during CONSOL’s ownership of the Conveyed Interests, were disposed of off-site at Third Party commercial disposal facilities;

(i)            the amounts payable to any Affiliate of CONSOL with respect to the Conveyed Interests and the period prior to the Effective Time; and

(j)            proceeds attributable to royalties, overriding royalties and other burdens payable to Third Parties out of production of Hydrocarbons from the Conveyed Interests 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 transferred to Noble, or under Noble’s control, at Closing.

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13.3   Indemnities of Noble.  Effective as of the Closing, Noble and its successors and assigns shall be responsible for, shall pay on a current basis and hereby agrees to Indemnify CONSOL and its Affiliates, and all of 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:

(a)           any breach by Noble of its representations or warranties contained in Article VIII;

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

(c)           the (i) Assumed Obligations; and (ii) any obligations attributable to the Assigned FT Interests and/or Assigned Processing Interests, to the extent such rights are acquired by Noble pursuant to the Development Agreement and/or Schedule 9.12(a), as applicable.

13.4   Limitation on Liability.  

(a)           CONSOL shall not have any liability for any indemnification under this Agreement unless (i) the individual amount of any Liability for which a Claim Notice is delivered by Noble to CONSOL under this Article XIII and for which CONSOL is liable exceeds $100,000 and (ii) the aggregate amount of all Liabilities for which CONSOL is liable under this Agreement exceeds 1% of the unadjusted Total Amount (the “Indemnity Deductible”) and then only to the extent such damages or costs exceed the Indemnity Deductible; provided, however, that (A) the covenants of the Parties under Section 2.3, (B) any adjustments to the Closing Cash Payment under Section 3.2 or the Carried Cost Obligation (as applicable) pursuant to Article V or Article VI, (C) the indemnities under Section 13.2(a) for a breach of any Fundamental Representation and (D) the indemnities under Section 13.2(c), Section 13.2(d), Section 13.2(g) and Section 13.2(i) (such foregoing items in this proviso, the “Limitation of Liability Exclusions”), in each case, shall not be limited by the provisions of this Section 13.4(a).

(b)           Notwithstanding anything to the contrary contained in this Agreement, except with respect to the Limitation of Liability Exclusions, CONSOL shall not be required to indemnify Noble for aggregate Liabilities in excess of 10% of the Total Amount.  Subject to Section 13.8(b)(iv), theLimitation of Liability Exclusions shall, in each case, be without limit.

13.5  Express Negligence. EXCEPT AS OTHERWISE PROVIDED IN SECTION 4.1(c) AND SECTION 4.3, 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.

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13.6   Exclusive Remedy.  Notwithstanding anything to the contrary contained in this Agreement and except for claims relating to any indemnity provided by CONSOL pursuant to Section 6.1(b)(ii), from and after Closing, Sections 4.1(c), 13.2 and 13.3 and any Title Indemnity Agreement or Environmental Indemnity Agreement entered into by the Parties 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 VII, Article VIII, Article IX and this Article XIII and the affirmations of such representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Section 10.5 or Section 11.6, as applicable.  Except for (a) the remedies contained in Sections 4.1(c), 13.2 and 13.3, (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 VII, Article VIII, Article IX and Article XIII, 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 10.5 or Section 11.6, 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 Conveyed Interests prior to the Closing, or the condition, quality, status or nature of the Conveyed Interests 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 CONSOL or any of its Affiliates (except as provided in Section 5.4).

13.7   Indemnification Procedures.  All claims for indemnification under Section 4.1(c), Section 13.2 and Section 13.3 shall be asserted and resolved as follows:

(a)           For purposes of Section 4.1(c) and this Article XIII, 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 Section 4.1(c) and this Article XIII, 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 Section 4.1(c) and this Article XIII.

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(b)           To make a claim for indemnification under Sections 4.1(c), 13.2 or 13.3, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 13.7, 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 13.7 shall not relieve the Indemnifying Party of its obligations under Sections 4.1(c), 13.2 or 13.3 (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 30 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 13.7(d).  An Indemnifying Party shall not, without the written consent of the Indemnified Party, (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 ten 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 (i) above.

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(f)           In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 30 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 30 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the amount of such Liabilities shall conclusively be deemed a liability of the Indemnifying Party hereunder.

13.8Survival.  

(a)           The representations and warranties of CONSOL in Article VII (other than the Fundamental Representations) and the covenants and agreements of CONSOL in Sections 9.1 and 12.4 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, and (ii) the special warranty of title contained in the Assignment shall survive the Closing without time limitation.  Subject to the foregoing and as set forth in Section 13.8(b), the remainder of this Agreement shall survive the Closing without time limit.  Any reference to a representation or warranty in this Section 13.8(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 13.2(a), 13.2(b), 13.3(a) and 13.3(b) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification.  Noble’s indemnities set forth in Section 4.1(c) and Section 13.3(c) shall survive the Closing without time limit.  CONSOL’s indemnities set forth in (i) Sections 13.2(c), 13.2(d) and 13.2(i) shall survive the Closing without time limit, (ii) Section 13.2(f) shall survive the Closing for a period of one year, (iii) Sections 13.2(e) and 13.2(j) shall survive the Closing for a period of two years, (iv) Section 13.2(g) shall survive the Closing for a period of five years, and (v) Section 13.2(h) shall survive the Closing for a period of five years.  Notwithstanding the foregoing, there shall be no termination of any bona fide claim asserted pursuant to the indemnities in Sections 13.2(a) through 13.2(j) or Sections 13.3(a) through 13.3(c), if such bona fide claim is assertedprior to the date of termination for the applicable indemnity.

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13.9  Non-Compensatory Damages.  None of the Noble Indemnified Parties nor CONSOL Indemnified Parties shall be entitled to recover from CONSOL or Noble, or their respective Affiliates, 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, except to the extent any such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder.  Subject to the preceding sentence, Noble, on behalf of each of the Noble Indemnified Parties, and CONSOL, on behalf of each of CONSOL Indemnified Parties, 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.

13.10Cooperation by Noble Concerning Retained Litigation.  Noble agrees to use reasonable efforts to cooperate with CONSOL in connection with CONSOL’s defense and other actions relating to or arising out of the litigation and claims set forth on Schedule 7.7.

13.11Waiver 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.

13.12Insurance.  The amount of any Liabilities for which any of the Noble Indemnified Parties is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds, from insurance policies carried by a Party, that are actually realized by such Party or that could reasonably be expected to be realized by such Party if a claim were properly pursued under the relevant insurance arrangements.

13.13Materiality. For purposes of this Article XIII, any Liability resulting from any breach or inaccuracy in the representations and warranties under this Agreement and the corresponding representations and warranties given in the certificates to be delivered by CONSOL at Closing pursuant to Section 10.5 shall be determined without regard to any materiality qualifiers in or affecting such representations or warranties.

ARTICLE XIV

TERMINATION, DEFAULT AND REMEDIES

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

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(a)           by CONSOL, at CONSOL’s option, if any of the conditions set forth in Article XI (other than the conditions set forth in Section 11.3, Section 11.4, Section 11.5, Section 11.6 and Section 11.8) have not been satisfied (or waived by CONSOL) on or before the Outside Termination Date (as such date may be extended by Noble pursuant to the terms hereof);

(b)           by Noble, at Noble’s option, if any of the conditions set forth in Article X (other than the conditions set forth in Section 10.3, Section 10.4, Section 10.5 and Section 10.6) have not been satisfied (or waived by Noble) on or before the Outside Termination Date (as such date may be extended by Noble pursuant to the terms hereof);

(c)           by either Party if any of the conditions set forth in Section 10.3, Section 10.4, Section 10.5, Section 10.6, Section 11.3, Section 11.4, Section 11.5 or Section 11.6 have not been satisfied (or waived by (i) CONSOL with respect to the conditions set forth in Section 10.3, Section 10.4, Section 10.5 and Section 10.6 or (ii) Noble with respect to the conditions set forth in Section 11.3, Section 11.4, Section 11.5 and Section 11.6) on or before the Outside Termination Date (as such date may be extended by Noble pursuant to the terms hereof);

(d)           by CONSOL, at CONSOL’s option, if the condition set forth in Section 11.8 has not been satisfied (or waived by CONSOL) on or before the Outside Termination Date (as such date may be extended by Noble pursuant to the terms hereof);

(e)           by either Party, at such Party’s option, at any time following ten days after the Outside Termination Date (as such date may be extended by Noble pursuant to the terms hereof); or

(f)           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), (c) or (d) above if such Party or its Affiliates are at such time in material breach of any provision of this Agreement.

14.2   Effect of Termination.  

(a)           If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 14.1 hereof, then, except for the provisions of Article I, Sections 4.1(c) through 4.1(e), 4.2, 4.3, 13.9, this Section 14.2, Article XV (other than Sections 15.2(b) through 15.2(e), 15.3, 15.4, 15.10 and 15.11) 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 14.1(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 (as such date may be extended by Noble pursuant to the terms hereof), (A) all of the conditions in Article X (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 12.3, 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 reasonable considering all of the circumstances existing as of the date hereof 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 14.2(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 14.1(a).

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(c)           If this Agreement is terminated by Noble pursuant to Section 14.1(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 (as such date may be extended by Noble pursuant to the terms hereof), (A) all of the conditions in Article XI (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 12.3, 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 reasonable considering all of the circumstances existing as of the date hereof 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 14.2(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 allege to suffer as a result of the termination of this Agreement pursuant to Section 14.1(b).

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

14.3Return of Documentation and Confidentiality.  Upon termination of this Agreement, Noble shall return to CONSOL or shall destroy all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other information furnished by CONSOL to Noble or prepared by or on behalf of Noble in connection with its due diligence investigation of the Conveyed Interests, in each case, in accordance with the Confidentiality Agreement (and subject to such retention rights as are provided in the Confidentiality Agreement) and an officer of Noble shall certify same to CONSOL in writing.

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ARTICLE XV

MISCELLANEOUS

15.1Appendices, 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.

15.2Expenses 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 the Conveyed Interests shall be borne by Noble.

(c)           CONSOL shall retain responsibility for, and shall bear and pay, (i) all federal income Taxes, state income Taxes, and other similar Taxes (including any applicable interest or penalties) incurred or imposed with respect to the transactions described in this Agreement, (ii) 50% of all Transfer Taxes incurred or imposed with respect to the transfer to Noble of the Conveyed Interests and (iii) 100% of the Transfer Taxes, if any, incurred with respect to the Oil and Gas Assets other than the Conveyed Interests.  Noble shall assume responsibility for, and shall bear and pay, 50% of all Transfer Taxes incurred or imposed with respect to the transfer to Noble of the Conveyed Interests.  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 Noble of the Conveyed Interests.

(d)           CONSOL shall retain responsibility for, and shall bear and pay, all Asset Taxes assessed with respect to the ownership and operation of the Conveyed Interests for (i) any period ending prior to the Effective Time and (ii) the portion of any Straddle Period ending immediately prior to the Effective Time.  All Asset Taxes with respect to the ownership or operation of the Conveyed Interests arising on or after the Effective Time (including all Straddle Period Taxes not apportioned to CONSOL) shall be allocated to and borne by Noble.  For purposes of allocation between the Parties of Asset Taxes that are payable with respect to Straddle Periods, the portion of any such Taxes that are attributable to the portion of the Straddle Period that ends immediately prior to the Effective Time shall (A) in the case of Asset Taxes that are based upon or related to revenues, income or receipts or imposed on a transactional basis such as severance or production Taxes, be allocated based on revenues from sales occurring before the Effective Time (which shall be CONSOL’s responsibility) and from and after the Effective Time (which shall be Noble’s responsibility); and (B) in the case of other Asset Taxes, be allocated pro rata per day between the period immediately prior to the Effective Time and the period beginning on the Effective Time.  For purposes of clause (A) of the preceding sentence, any exemption, deduction, credit or other item that is calculated on an annual basis shall be allocated pro rata per day between the period ending immediately prior to the Effective Time and the period beginning on the Effective Time.  To the extent the actual amount of Asset Taxes is not determinable at Closing, Noble and CONSOL shall utilize the most recent information available in estimating the amount of Asset Taxes for purposes of Sections 3.2(a)(iv) and 3.2(b)(v).  Upon determination of the actual amount of Asset Taxes, CONSOL shall pay to Noble to the extent not taken into account in the Final Settlement Statement any additional amount necessary to equal CONSOL’s share of the Asset Taxes.  In the event the amount of Asset Taxes paid by CONSOL or included as a reduction to the Closing Cash Payment pursuant to Section 3.2(b)(v) at Closing exceeds CONSOL’s share of Asset Taxes, Noble shall pay the amount of any such overage to CONSOL.  Any allocation of Asset Taxes between the Parties shall be in accordance with this Section 15.2(d).

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(e)           CONSOL shall prepare and file all Tax Returns with respect to Asset Taxes that are due on or prior to the Closing Date and, subject to the provisions of Sections 3.2(a)(iv), 3.2(b)(v) and 15.2 and Section 4(f) of the Services Agreement, pay all Asset Taxes shown to be due thereon.  With respect to Asset Taxes that are due after the Closing Date, each Party shall, subject to the provisions of Sections 3.2(a)(iv), 3.2(b)(v) and 15.2 and Section 4(f) of the Services Agreement, (i) pay (or cause to be paid) all such Asset Taxes for which such Party is responsible and (ii) prepare and file (or cause to be prepared and filed) all such Tax Returns for which such Party is responsible.  The Parties acknowledge that, to the extent any Party Operator (as defined in the Development Agreement) pays any such Asset Taxes on behalf of the non-operators under any Applicable Operating Agreement (as defined in the Development Agreement), such Asset Taxes shall be chargeable to the joint account and billable to the parties to such Applicable Operating Agreement pursuant to the terms of such Applicable Operating Agreement.

15.3   Tax Treatment.  The Parties intend and expect that the transactions contemplated by this Agreement, the Development Agreement and the Transaction Documents, taken together, will be treated, for purposes of federal income taxation and for purposes of certain state income Tax Laws that incorporate or follow federal income tax principles (“Tax Purposes”), as resulting in the creation of a partnership (the “Tax Partnership”) in which Noble and CONSOL are treated as partners.  Accordingly, for Tax Purposes (a) the Tax Partnership will be treated from and after Closing as (i) holding (A) 100% of the Parties' interests in the Oil and Gas Assets, (B) any other Subject Assets acquired by the Parties jointly pursuant to the Development Agreement, and (C) any cash held in any Tax Partnership Account and (ii) engaging in all activities of the Parties with respect to the aforementioned assets; (b) CONSOL will be treated as contributing to the Tax Partnership at Closing all of its interests in the Oil and Gas Assets and providing its undertaking to fund, when due, the costs and expenses allocable to it under the Development Agreement in exchange for an interest in the Tax Partnership; (c) Noble will be treated as contributing to the Tax Partnership at Closing (by deposit into the Cost Reconciliation Account) the Closing Cash Payment (as adjusted) and providing its undertaking to fund, when due the Post Closing Cash Payments and the costs and expenses allocable to it under the Development Agreement (including the Carried Cost Obligation) in exchange for an interest in the Tax Partnership; (d) upon any withdrawal by CONSOL (as and to the extent permitted by the Development Agreement) of the Total Cost Sharing Payments from the Cost Reconciliation Account, CONSOL will be treated as receiving a distribution from the Tax Partnership of the withdrawn amount (i) as a reimbursement of CONSOL’s preformation expenditures with respect to the Oil and Gas Assets within the meaning of Treasury Regulations Section 1.707-4(d) to the extent applicable and (ii) in a transaction subject to treatment under Section 707(a) of the Code and its implementing Treasury Regulations as in part a sale, and in part a contribution, of the Oil and Gas Assets to the Tax Partnership to the extent that Treasury Regulations Section 1.707-4(d) is inapplicable, and (e) from and after its commencement, the Tax Partnership will be treated as realizing all items of income or gain and incurring all items of cost or expense attributable to the ownership, operation or disposition of the Subject Assets, notwithstanding that such items are realized, paid or incurred by the Parties individually. The governing terms and conditions of the Tax Partnership (the “Tax Partnership Agreement”) are set forth in the form thereof to be executed at Closing, attached as Exhibit D hereto.

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15.4       Value Allocations for Tax Purposes.  CONSOL and Noble agree that the portion, if any, of the Total Cost Sharing Payments and the Assumed Obligations that could be treated for federal tax purposes as consideration for a sale transaction (collectively, the “Allocable Amount”) shall be allocated among the various Conveyed Interests for federal and state income tax purposes.  The initial draft of such allocations shall be prepared in a manner consistent with the Allocated Values by CONSOL in a manner consistent with Sections 3.7 and 15.3 and shall be provided to Noble concurrently with the delivery of the Final Settlement Statement. CONSOL and Noble shall then cooperate to prepare a final Schedule of any Allocable Amount among the Conveyed Interests, which shall also be materially consistent with the Allocated Values (as adjusted, the “Allocation Schedule”).  The Allocation Schedule shall be updated to reflect any adjustments to Allocable Amount. If agreed by the Parties, the allocation of the Allocable Amount shall be reflected on a completed Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which Form will be timely filed separately by CONSOL and Noble (and/or the Tax Partnership, as appropriate) with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code.  Each Party agrees not to (and to cause the Tax Partnership not to) take any position inconsistent with this Section 15.4 or the allocations set forth in the Allocation Schedule unless required by applicable Law or with the consent of the other Party.  The Parties further agree that the allocations set forth on the Allocation Schedule will represent reasonable estimates of the fair market values of the Conveyed Interests described therein.

15.5Dispute Resolution.  The procedures of Section 3.6 shall be applied in the event of a dispute for any item under Sections 15.2, 15.3 or 15.4.

15.6  Assignment.  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.

15.7        Preparation 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.

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15.8   Publicity.  CONSOL and Noble shall consult with each other with regard to all press releases or other public or private announcements 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 publicity 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 the 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 Conveyed Interests from CONSOL to Noble, (c) prevent Noble or CONSOL from making any disclosure of information relating to this Agreement if made in a manner, under conditions and to Persons that would be permitted under the Confidentiality Agreement so long as such Person continue to hold such information confidential on the same terms as set forth in this Section, and (d) prevent CONSOL from making disclosures in connection with complying with Preferential Purchase Rights and other transfer restrictions applicable to the transactions contemplated hereby.

15.9   Notices.  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:

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:         724-485-4163

Fax:                      724-485-4836

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and:

Vinson & Elkins LLP

1001 Fannin, Suite 2500

Houston, Texas 77002

Attention:           Jeff Munoz

Telephone:         713-758-3222

Fax:                      713-615-5191

and:

Wachtell, Lipton, Rosen & Katz

51 West 52nd Street

New York, NY 10019

Attention:           David A. Katz

Telephone:         212-403-1309

Fax:                      212-403-2309

If to Noble:

Noble Energy, Inc.

100 Glenborough Drive, Suite 100

Houston, Texas 77067

Attention:           Shawn Conner

Telephone:         281-872-3138

Fax:                      281-872-3358

with a copy to:

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 15.9.

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15.10Further 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 Conveyed Interests to Noble, to perfect Noble’s title thereto, and to accomplish the orderly transfer of the Conveyed Interests to Noble in the manner contemplated by this Agreement.

15.11Filings, Notices and Certain Governmental Approvals.  Promptly after Closing Noble shall (a) record the Assignments of the Conveyed Interests and all state/federal assignments 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 the Conveyed Interests to Noble and (c) actively pursue all other consents and approvals that may be required in connection with (i) the assignment of the Conveyed Interests to Noble, and CONSOL agrees to use its commercially reasonable efforts to cooperate with such pursuit, and (ii) the assumption of the liabilities assumed by Noble hereunder, in each case, that shall not have been obtained prior to Closing.  Noble 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.

15.12Entire Agreement; Conflicts.  THIS AGREEMENT, THE APPENDICES, EXHIBITS AND SCHEDULES HERETO, THE TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY AGREEMENT 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; (B) THE TERMS AND PROVISION OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT (OTHER THAN THE TAX PARTNERSHIP AGREEMENT), THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; OR (C) THE TERMS AND PROVISION OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF THE TAX PARTNERSHIP AGREEMENT, THE TERMS AND PROVISIONS OF THE TAX PARTNERSHIP 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 15.12.

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15.13Successors and Permitted Assigns.  This Agreement shall be binding upon and inure to the benefit of the Parties and their successors and permitted assigns.

15.14Parties in Interest.  Nothing in this Agreement shall entitle any Person other than the Parties, or the Parties’ respective related Indemnified Parties hereunder any claim, cause of action, remedy or right of any kind.

15.15Amendment.  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.

15.16Waiver; 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.

15.17Governing 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.  ALL OF THE PARTIES CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES FEDERAL DISTRICT COURTS LOCATED IN THE STATE 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 FEDERAL DISTRICT COURTS HAVING SITES IN PITTSBURGH, 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.

15.18Severability.  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.

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15.19Counterparts.  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 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 date first above written.

CONSOL:
CNX GAS COMPANY LLC
By:	/s/ Nicholas J. DeIuliis
Name:	Nicholas J. DeIuliis
Title:	President and Chief Executive Officer
NOBLE:
NOBLE ENERGY, INC.
By:	/s/ Shawn E. Conner
Name:	Shawn E. Conner
Title:	Vice President

[Signature Page to Asset Acquisition Agreement]

S-1

APPENDIX I

Definitions

“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 3.6.

“Additional Interests” has the meaning set forth in Section 9.4.

“Adjusted Closing Cash Payment” has the meaning set forth in Section 3.2.

“AFEs” has the meaning set forth in Section 7.13.

“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.

“Allocable Amount” has the meaning set forth in Section 15.4.

“Allocated Value” has the meaning set forth in Section 3.7.

“Allocation Schedule” has the meaning set forth in Section 15.4.

“Alternate Transaction” means (a) any sale or other disposition of, or a joint venture involving, any material portion of the Oil and Gas Assets to or with another Person (other than Noble or its Affiliates) or any other transaction or series of transactions with respect to the Oil and Gas Assets which has a substantially similar economic effect as the foregoing,or (b) any sale or similar disposition, directly or indirectly, of any material portion of the equity ownership of CONSOL (except to any Affiliate).

“Antero ORRI” means those certain royalty and overriding royalty payments due from Antero Resources Appalachian Corporation to CNX Gas Company LLC, under those certain Partial Assignment of Oil and Gas Leases dated September 29, 2008, effective September 30, 2008 and other instruments delivered pursuant to that Amended and Restated Farmout Acquisition Agreement dated September 23, 2008 by and among Dominion Exploration & Production, Inc., Dominion Appalachian Development LLC and Dominion Transmission Inc., predecessors to CNX Gas Company LLC, collectively as farmor, and Antero Resources Appalachian Corporation, as farmee.

“Applicable Contracts” means all Contracts to which CONSOL is a party by which any Conveyed Interest is bound and that will be binding on Noble after the Closing, including farmin and farmout agreements; bottomhole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements (including the Gathering Contracts); hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements (including the Processing Contracts); crossing agreements; saltwater disposal agreements; facilities or equipment leases; letters of objection; production handling agreements; and other similar contracts and agreements held by CONSOL and relating to the Conveyed Interests.

Appendix I

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“Area” means the CPA Dry Area, the SWPA Dry Area, the SWPA Wet Area or the WV Dry Area, as applicable.

“Asset Taxes” means ad valorem, property, excise, 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, but excluding, for the avoidance of doubt, income, capital gains and franchise Taxes.

“Assigned FT Interests” has the meaning set forth in the Development Agreement.

“Assigned Gathering Interests” has the meaning set forth in Schedule 9.12(c).

“Assigned Processing Interests” has the meaning set forth in Schedule 9.12(a).

“Assignment” means the Deed, Assignment and Bill of Sale from CONSOL to Noble, pertaining to the Conveyed Interests and the Subsurface Access Easement, substantially in the form attached to this Agreement as Exhibit E.

“Assumed Obligations” has the meaning set forth in Section 13.1.

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

“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.

“Carried Cost Balance Account” has the meaning set forth in the Development Agreement.

“Carried Cost Obligation” means $2,133,776,252 as such amount may be adjusted from time to time pursuant to Section 5.3(d) or otherwise pursuant to this Agreement.  “Cash Payment” means any cash payment due under Section 3.1.

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

“Claim Notice” has the meaning set forth in Section 13.7(b).

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“Closing” has the meaning set forth in Section 12.1.

“Closing Cash Payment” has the meaning set forth in Section 3.1(b).

“Closing Date” has the meaning set forth in Section 12.1.

“Closing Funds” has the meaning set forth in the Gathering Term Sheet.

“CNX Operated Area” has the meaning set forth in the Development Agreement.

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

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement between CONSOL Energy Inc. and Noble dated May 2, 2011.

“Consent” has the meaning set forth in Section 7.4.

“CONSOL” has the meaning set forth in the first paragraph herein.

“CONSOL Indemnified Parties” has the meaning set forth in Section 13.3.

“CONSOL Indentures” means, collectively, CONSOL Energy Inc.’s Indentures for its 8% Senior Notes due 2017, 8.25% Senior Notes due 2020, and 6.375% Senior Notes due 2021.

“CONSOL Secondment Agreement” means that Secondment Agreement by and between CONSOL and Noble substantially in the form attached hereto as Exhibit J.

“CONSOL Shallow 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 Exhibit A, insofar and only insofar as such leases and oil and gas mineral fee interests cover subsurface depths and formations above the Marcellus Formation.

“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 or evidencing an interest in the Conveyed Interests or any real or immovable property related to or used in connection with the operations of any Conveyed Interests.

“Contribution Agreement” has the meaning set forth in Section 9.6.

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“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.

“Conveyed Interests” has the meaning set forth in Section 2.1.

“COPAS Accounting Procedures” means the Counsel of Petroleum Accountants Societies, Inc. 2005 Accounting Procedures Joint Operations.

“Cost Reconciliation Account” has the meaning set forth in Section 3.1(a).

“CPA Dry Area” means, collectively, those counties in which the Leases that are marked as being located in the “CPA Dry” Area on Schedule 1.1 are located.

“Cure Period” has the meaning set forth in Section 5.3(c).

“Customary Post Closing Consents” means the consents and approvals from Governmental Authorities for the assignment of the Conveyed Interests to Noble that are customarily obtained after the assignment of properties similar to the Conveyed Interests.

“Debt Instrument” has the meaning set forth in Section 7.8(a)(iv).

“Defensible Title” means such title of CONSOL as of Closing with respect to the Leases and Marcellus Wells, as applicable, that, subject to the Permitted Encumbrances:

(a)           with respect to each Lease shown in Exhibit A and each Marcellus Well shown in Exhibit B,entitles CONSOL to receive not less than the Net Revenue Interest shown in such Exhibit for such Lease or Marcellus Well (as applicable) throughout the productive life of such Lease or Marcellus Well, except for (i) decreases in connection with those operations in which a CONSOL may from and after the date of this Agreement elect to be a non-consenting co-owner, (ii) decreases resulting from the establishment or amendment from and after the date of this Agreement 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 Noble, (v) decreases resulting from any reversion of interest to a co-owner with respect to operations in which such co-owner, after the date hereof, elects not to consent, and (vi) as otherwise stated in such Exhibit;

(b)           with respect to each Marcellus Well shown in Exhibit B, obligates CONSOL to bear a percentage of the costs and expenses for the development and maintenance of, and operations relating to, such Marcellus Well of not more than the Working Interest shown in Exhibit B for such Marcellus Well throughout the productive life of such Marcellus Well, except (i) increases resulting from contribution requirements with respect to defaulting co-owners from and after the date hereof under applicable operating agreements, (ii) increases to the extent that such increases are accompanied by a proportionate increase in CONSOL’s Net Revenue Interest, (iii) increases resulting from actions by Noble, and (iv) as otherwise stated in Exhibit B;

Appendix I

Page 4

(c)           with respect to each Area, entitles CONSOL to the Minimum Net Acres for such Area (based upon the aggregate Net Acres for the Leases that are included in such Area); and

(d)           with respect to each Lease and Marcellus Well, is free and clear of all Encumbrances.

“Development Agreement” means the Joint Development Agreement, substantially in the form of attached to this Agreement as Exhibit G.

“Development Area” has the meaning set forth in the Development Agreement.

“Dispute Notice” has the meaning set forth in Section 3.5.

“DOJ” means the Department of Justice.

“Downstream Contracts” has the meaning set forth in the Development Agreement.

“Drilling Unit” has the meaning set forth in the Development Agreement.

“Effective Time” means 7:00 a.m. (Central Time) on July 1, 2011.

“Encumbrance” means any lien, mortgage, security interest, defect, irregularity, pledge, charge or encumbrance.

“Environmental Arbitrator” has the meaning set forth in Section 6.1(e).

“Environmental Condition” means (a) a condition existing on the date of this Agreement with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes a Conveyed Interest (or CONSOL with respect to a Conveyed Interest) not to be in compliance with any Environmental Law or (b) the existence as of the date of this Agreement with respect to the Conveyed Interest or their operation thereof of any environmental pollution, contamination, degradation, damage or injury caused by or related to a Conveyed Interest for which remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws.

“Environmental Defect” means an Environmental Condition with respect to a Conveyed Interest.

“EnvironmentalDefect Claim Date” means on or before 5:00 p.m. (Central Time) on September 16, 2011.

“Environmental Defect Deductible” means 1.0% of the Total Amount.

“Environmental Defect Notice” has the meaning set forth in Section 6.1(a).

“Environmental Disputes” has the meaning set forth in Section 6.1(e).

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“Environmental Indemnity Agreement” has the meaning set forth in Section 6.1(b)(iii).

“Environmental Laws” means all applicable federal, state and local Laws in effect as of the date of this Agreement, 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.

“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 Conveyed Interests); (b) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Conveyed Interests with respect to any period of time prior to the Effective Time; (c) 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) subject to Section 5.4, all rights and interests of CONSOL (i) under any policy or agreement of insurance or indemnity, (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 Properties with respect to all periods prior to the Effective Time, other than those Hydrocarbons attributable to the Conveyed Interests and 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) Asset Taxes attributable to any period, or portion thereof, prior to the Effective Time, (ii) income or franchise Taxes or (iii) any Taxes attributable to the Excluded Assets; (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 Properties or the Personal Property; (j) all documents and instruments of CONSOL that may be protected by an attorney-client privilege;(k) all data and Contracts that cannot be disclosed to Noble as a result of confidentiality arrangements under agreements with Third Parties; (l) all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances assumed by Noble; (m) all geophysical and other seismic and related technical data and information relating to the Properties or other Conveyed Interests to the extent that such geophysical and other seismic and related technical data and information is not transferable without payment of a fee or other penalty (unless Noble agrees to, and does, pay such fees and penalties) or not otherwise set forth in Schedule 2.1;(n) documents prepared or received by CONSOL or its Affiliates with respect to (i) lists of prospective purchasers for such transactions compiled by CONSOL or its Affiliates, (ii) bids submitted by other prospective purchasers of the Conveyed Interests or any other interest in the Properties, (iii) analyses by CONSOL or its Affiliates of any bids submitted by any prospective purchaser, (iv) correspondence between or among CONSOL or its Affiliates or their respective representatives, and any prospective purchaser other than Noble and (v) correspondence between CONSOL or its Affiliates or any of their respective representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated in this Agreement; (o) all trucks, cars and drilling/workover rigs utilized by CONSOL or its Affiliates in connection with the ownership or operation of the Conveyed Interests; (p) all Hedge Contracts;(q) all proceeds and amounts held in suspense as of Closing that are attributable to the Hydrocarbons produced from the Properties; (r) Overhead Costs payable to CONSOL or any Affiliate of CONSOL as an Operator of the Conveyed Interests attributable to the period between the Effective Time and the Closing Date; (s) files and records attributable to the Conveyed Interests that are maintained by CONSOL that are not primarily used or held for use in connection with the operatorship or ownership of the Conveyed Interests; (t) any Conveyed Interests described in Section 2.1(b) that are not assignable; provided, however, that CONSOL shall have exercised commercially reasonable efforts to obtain any and all relevant consents; (u) any Retained Interest; (v) the Existing Gathering Assets; (w) the Antero ORRI; (x) all rights to coal and substances mined in connection therewith; (y) any Additional Interests acquired by CONSOL during the Interim Period in the Development Area with respect to which Noble elects not to acquire its participating share pursuant to the terms of the Development Agreement; (z) all water rights; (aa) notwithstanding the inclusion of any Downstream Contract, the Peoples Contract or the NJR Contracts on any disclosure Schedule to the representations of CONSOL under Article VII, the Downstream Contracts, the Peoples Contract and the NJR Contracts, subject to the provisions of Section 2.10 of the Development Agreement, if applicable; (bb) all Contracts which are held or to be held by CONSOL in its capacity as operator of the CNX Operated Area, including drilling Contracts and services Contracts; (cc) all Pipeline Imbalances; and (dd) the properties described in Exhibit F and all associated Conveyed Interests relating thereto.

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“Existing Gathering Assets” has the meaning set forth in Section 9.6.

“Final Settlement Statement” has the meaning set forth in Section 3.5.

“First Cash Payment” has the meaning set forth in Section 3.1(b).

“FTC” means the Federal Trade Commission.

“Fundamental Representations” means those representations and warranties of CONSOL set forth in Sections 7.1, 7.2, 7.5, 7.6, 7.14 and 7.15.

“GAAP” means generally accepted accounting principles as used in the United States of America.

“Gathering Company” has the meaning set forth in Section 9.6.

“Gathering Contracts” means those gathering Contracts set forth on Schedule 9.12(d).

“Gathering JV Agreements” has the meaning set forth on Section 9.6.

“Gathering Term Sheet” means the term sheet attached to this Agreement as Exhibit I.

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“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.

“Hazardous Substances” means any pollutants, contaminants, toxic or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds, or chemicals that are regulated by, or may form the basis of liability under, any Environmental Laws, including NORM and other substances referenced in Section 6.2.

“Hedge Contract” means any Contract to which CONSOL 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.

“Imbalances” means all Well Imbalances and Pipeline Imbalances.

“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 costs were incurred prior to, or on and after, the Effective Time shall be based upon when the services were rendered or the good delivered, as applicable

“Indemnify”means indemnify, defend (including the requirement to pay costs of litigation, dispute resolution and other legal costs and court fees) and hold harmless.

“Indemnified Party” has the meaning set forth in Section 13.7(a).

“Indemnifying Party” has the meaning set forth in Section 13.7(a).

“Indemnity Deductible” has the meaning set forth in Section 13.4(a).

“Individual Environmental Threshold” has the meaning set forth in Section 6.1(d).

“Individual Title Defect Threshold” has the meaning set forth in Section 5.3(i).

“Interim Period” means that period of time commencing with the Effective Time and ending immediately prior to Closing.

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“Invasive Activities” has the meaning set forth in Section 4.1(b).

“Knowledge” means with respect to (a) CONSOL, the actual knowledge (without investigation) of the following Persons:  Nicholas J. DeIuliis, William J. Lyons, Robert P. King, Randall M. Albert, Robert Belesky and William Hauck, and (b) Noble, the actual knowledge (without investigation) of the following Persons:  Shawn Conner and John Lewis.

“Land Affiliates” means Leatherwood, Inc., Braxton-Clay Land & Mineral, Inc., CNX Land Resources Inc., Conrhein Coal Company, Consol Pennsylvania Coal Company LLC, Consolidation Coal Company, Eighty-Four Mining Company, Island Creek Coal Company, McElroy Coal Company and Wolfpen Knob Development Company.

“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.

“Leases” has the meaning set forth in Section 2.1(a)(i).

“Legacy Wells” means those wells set forth on Annex 2 to Exhibit H.

“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 13.4(a).

“Marcellus Formation” means (a) in central Pennsylvania, specifically from the stratigraphic equivalent of the top of the Burkett in the DeArmitt #1 (API 37-129-27246) and 7000'MD through to the stratigraphic equivalent of the top of the Onondaga at 7530'MD and illustrated in the log attached on Exhibit A-1; (b) in southwest Pennsylvania, specifically from the stratigraphic equivalent of the top of the Burkett in the GH-10C-CV (API 37-059-25397) at 7600'MD through to the stratigraphic equivalent of the top of the Onondaga at 7900'MD and illustrated in the log attached on Exhibit A-1; and (c) 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 on Exhibit A-1.

“Marcellus Wells” has the meaning set forth in Section 2.1(a)(ii).

“MarkWest” has the meaning set forth in Schedule 9.12(b).

“Master JOA” has the meaning set forth in the Development Agreement.

“Master JOA Memorandum” has the meaning set forth in the Development Agreement.

“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 Conveyed Interests, taken as a whole as currently operated as of the date of this Agreement; 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 Conveyed Interests 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 Conveyed Interests 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 date of this Agreement; (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 date of this Agreement; and (m) natural declines in well performance.

Appendix I

Page 9

“Material Contracts” has the meaning set forth in Section 7.8(a).

“Minimum Net Acres” means, with respect to each Area, the Net Acres set forth for such Area in Schedule 1.2.

“NAESB Agreement” means that NAESB Agreement and related Transaction Confirmation by and between CONSOL and Noble pertaining to the Conveyed Interests, substantially in the form attached hereto as Exhibit O.

“Negotiation Period” has the meaning set forth in Schedule 9.12(a).

“Net Acre” means, as computed separately with respect to each Lease, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the undivided percentage interest in oil, gas and other minerals covered by such Lease in such lands, multiplied by (c) CONSOL’s Working Interest or undivided interest in such Lease; provided that if items (b) and/or (c) vary as to different areas of such lands (including depths) covered by such Lease in the Marcellus Formation, a separate calculation shall be done for each such area as if it were a separate Lease; provided further that (i) with respect to each Area, Net Acres shall mean the aggregate Net Acres for all of the Leases contained within such Area, and (ii) “Net Acres” shall not include net acres included in a production unit for any Marcellus Well.

“Net Acre Allocation” has the meaning set forth on Schedule 1.1.

“Net Revenue Interest” means, with respect to any Marcellus Well or Lease, the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Marcellus Well or Lease, after giving effect to all Burdens.

“NJR Contracts” means, collectively, the following Contracts (a) the Base Contract for Sale and Purchase of Natural Gas, between NJR Energy Services Company and CONSOL, dated September 11, 2006 and (b) all Transaction Confirmations subject to such Base Contract, including those dated October 17, 2008, March 23, 2010, March 25, 2010, April 5, 2010, March 9, 2011, March 17, 2011 and June 30, 2011.

Appendix I

Page 10

“Noble” has the meaning set forth in the first paragraph herein.

“Noble Indemnified Parties” has the meaning set forth in Section 13.2.

“Noble Representatives” has the meaning set forth in Section 4.1(a).

“Noble Secondment Agreement” means that Secondment Agreement by and between CONSOL and Noble, substantially in the form attached hereto as Exhibit K.

“NORM” means naturally occurring radioactive material.

“Oil and Gas Assets” mean the Conveyed Interests and, to the extent pertaining to the Marcellus Formation and operations relating thereto, the interests which are retained by CONSOL in the properties and assets underlying the Conveyed Interests.

“Outside Termination Date” means January 31, 2012; provided, however, that if the condition to Closing set forth in Section 11.8 has not been satisfied by CONSOL as of such specified date, Noble shall have the right, upon written notice to CONSOL, to elect to extend such specified date for up to six months from such specified date.

“Overhead Costs” means, with respect to those Conveyed Interests that are operated by CONSOL and are burdened by an existing joint operating agreement covering such Conveyed Interests, the amount representing the overhead or general and administrative fee that is charged to other working interest owners with interests in the related Conveyed Interests as set forth in the lease operating expenses statement, which amount is attributable to the Conveyed Interests during the Interim Period.

“Party” and “Parties” has the meaning set forth in the first paragraph herein.

“Peoples Contract” has the meaning set forth in the Development Agreement.

“Permits” has the meaning set forth in Section 7.21.

“Permitted Encumbrances” means:

(a)           the terms and conditions of all Contracts, Leases and all Burdens if the net cumulative effect of such Contracts, Leases and Burdens does not (i) operate to reduce the Net Revenue Interest of CONSOL with respect to any Lease or Marcellus Well to an amount less than the Net Revenue Interest set forth in Exhibit A or Exhibit B (as applicable) for such Lease or Marcellus Well, (ii) obligate CONSOL to bear a Working Interest with respect to any Marcellus Well in any amount greater than the Working Interest set forth in Exhibit B for such Marcellus Well (unless the Net Revenue Interest for such Marcellus Well is greater than the Net Revenue Interest set forth in Exhibit B, as applicable in the same proportion as any increase in such Working Interest), and (iii) reduce the Net Acres in any Area to less than the Minimum Net Acres for such Area;

Appendix I

Page 11

(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 or, if delinquent, that are being contested in good faith in the normal course of business;

(d)           Customary Post Closing Consents;

(e)           conventional rights of reassignment;

(f)           such Title Defects as Noble may have waived or is deemed to have waived pursuant to the terms of this Agreement;

(g)           all applicable Laws and all rights reserved to or vested in any Governmental Authority (i) to control or regulate any Lease or Marcellus Well in any manner or to assess Taxes with respect to any Lease or Marcellus 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 Lease or Marcellus 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 the Leases or Marcellus Wells to any Governmental Authority with respect to any franchise, grant, license or permit;

(h)           rights of a common owner of any interest in rights-of-way, permits or easements held by CONSOL and such common owner as tenants in common or through common ownership;

(i)           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 materially impair the operation or use of the Leases or Marcellus Wells as currently operated and used;

(j)           zoning and planning ordinances and municipal regulations;

(k)           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 or which are being contested in good faith by appropriate proceedings by or on behalf of CONSOL;

Appendix I

Page 12

(l)           liens created under Leases or Contracts or by operation of Law in respect of obligations that are not yet due or that are being contested in good faith by appropriate proceedings by or on behalf of CONSOL;

(m)           any Encumbrance affecting the Leases or Marcellus Wells that is discharged by CONSOL at or prior to Closing;

(n)           any matters set forth in Exhibit A or Exhibit B and all litigation set forth in Schedule 7.7;

(o)           calls on production under existing Contracts;

(p)           any lien, charge or other Encumbrance on or affecting the Conveyed Interests which is expressly bonded or paid by Noble at or prior to Closing;

(q)           limitations (including drilling and operating limitations) imposed on the Conveyed Interests by reason of the rights of subsurface owners or operators in a common property (including the rights of coal, utility and timber owners); and

(r)           all other Encumbrances, instruments, obligations, defects and irregularities affecting the Leases and Marcellus Wells that individually or in the aggregate that do not: (i) materially interfere with the operation or use of any of the Leases or Marcellus Wells (as currently operated and used), (ii) reduce the Net Revenue Interest of CONSOL with respect to any Lease or Marcellus Well to an amount less than the Net Revenue Interest set forth in Exhibit A or Exhibit B (as applicable) for such Lease or Marcellus Well, (iii) obligate CONSOL to bear a Working Interest with respect to any Marcellus Well in any amount greater than the Working Interest set forth in Exhibit B for such Marcellus Well (unless the Net Revenue Interest for such Marcellus Well is greater than the Net Revenue Interest set forth in Exhibit B in the same proportion as any increase in such Working Interest), (iv) reduce the Net Acres in any Area to less than the Minimum Net Acres for such Area, and (v) which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating similar oil and gas properties.

“Person” means any individual, corporation, company, partnership, limited partnership, limited liability company, trust, estate, Governmental Authority or any other entity.

“Personal Property” has the meaning set forth in Section 2.1(a)(v).

“Pipeline Imbalance” means any marketing imbalance between the quantity of Hydrocarbons attributable to the Oil and Gas Assets required to be delivered by CONSOL under any Contract relating to the purchase and sale, gathering, transportation, storage, processing (including any production handling and processing at a separation facility) or marketing of Hydrocarbons and the quantity of Hydrocarbons attributable to the Oil and Gas Assets actually delivered by CONSOL pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

Appendix I

Page 13

“Post Closing Cash Payments”has the meaning set forth in Section 3.1(b).

“Preferential Purchase Right” has the meaning set forth in Section 7.10.

“Preliminary Settlement Statement” has the meaning set forth in Section 3.4.

“Processing Contracts” means those processing Contracts set forth on Schedule 9.12(b).

“Producing Properties Cash Payment” has the meaning set forth in Section 3.1(a).

“Property” or “Properties” has the meaning set forth in Section 2.1(a)(iv).

“Property Expenses” means all property expenses (including costs of insurance and Asset Taxes) and capital expenditures incurred in the ownership and operation of the Conveyed Interests 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 the Conveyed Interests 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 Personal Property under applicable Environmental Laws, (d) obligations with respect to Imbalances, and (e) obligations to pay royalties, overriding royalties or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to the Conveyed Interests, including those held in suspense.  Notwithstanding anything to the contrary, Property Expenses do not include any costs incurred by CONSOL in connection with any obligation of CONSOL to pay, reimburse or Indemnify Noble hereunder, which costs shall be the sole obligation of CONSOL.

“Records” has the meaning set forth in Section 2.1(b)(iii).

“Remediation” means, with respect to an Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions required under Environmental Laws to correct or remove such Environmental Condition.

“Remediation Amount” means, with respect to an Environmental Condition, the present value as of the Closing Date of the cost (net to CONSOL’s interest) of the most cost effective Remediation of such Environmental Condition that is reasonably effective, appropriate and available.

“Representatives” means any financial advisor, investment banker or other similar representative, in each case, of CONSOL or its Affiliates.

“Requisite Noteholders” has the meaning set forth in Section 7.28.

“Retained Interest” means (a) all of CONSOL’s rights in and to the oil, gas and/or mineral leases and oil and gas mineral fee interests described in Exhibit A, insofar and only insofar as such leases and oil and gas mineral fee interests cover depths and formations outside of the Marcellus Formation, and (b) all rights to use the surface and install pipelines and gathering systems in connection with the ownership or operation of such leases and interests with respect to such depths and formations, and all wells to the extent associated therewith.

Appendix I

Page 14

“Rights-Of-Way” has the meaning set forth in Section 2.1(a)(iv).

“Second Cash Payment”has the meaning set forth in Section 3.1(b).

“Services Agreement” means that Services Agreement by and between CONSOL and Noble pertaining to the Conveyed Interests, substantially in the form attached hereto as Exhibit M.

“Straddle Period” means any tax period beginning before and ending after the Effective Time.

“Subject Assets” means the interests and other property rights in the Oil and Gas Assets and any other assets that both Parties own or acquire an interest in pursuant and subject to the Development Agreement.

“Subsurface Access Easement” has the meaning set forth in Section 9.10

“Surface Use Agreement” means that Surface Use Agreement by and among CONSOL, Noble and certain CONSOL Affiliates substantially in the form attached hereto as Exhibit N.

“SWPA Dry Area” means, collectively, those counties in which the Leases that are marked as being located in the “SWPA Dry” Area on Schedule 1.1 are located.

“SWPA Wet Area” means, collectively, those counties in which the Leases that are marked as being located in the “SWPA Wet” Area on Schedule 1.1 are located.

“Targeted Closing Date” has the meaning set forth in Schedule 9.6.

“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” has the meaning set forth in Section 15.3.

“Tax Partnership Account” means any deposit account identified or otherwise treated as being an asset of the Tax Partnership, with all interest accruing thereto reportable under the Tax Partnership’s taxpayer identification number, and shall include, without limitation, the Cost Reconciliation Account and any Carried Costs Balance Account.

Appendix I

Page 15

“Tax Partnership Agreement” has the meaning set forth in Section 15.3.

“Tax Purposes” has the meaning set forth in Section 15.3.

“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.

“Third Cash Payment”has the meaning set forth in Section 3.1(b).

“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 13.7(b).

“Third Party Operating Agreements” has the meaning set forth in the Development Agreement.

“Title Arbitrator” has the meaning set forth in Section 5.3(j).

“Title Benefit” means any right, circumstance or condition that operates to (a) increase the Net Revenue Interest of CONSOL in any Lease or Marcellus Well above that shown for such Lease or Marcellus Well in Exhibit A or Exhibit B (as applicable) to the extent the same does not cause a greater than proportionate increase in CONSOL’s Working Interest therein, (b) increase the Minimum Net Acres of CONSOL in any Area, or (c) decrease the Working Interest of CONSOL in any Marcellus Well below that shown for such Marcellus Well in Exhibit B to the extent the same causes a decrease in CONSOL’s Working Interest that is proportionately greater than the decrease in CONSOL’s Net Revenue Interest therein below that shown in Exhibit B.

“Title Benefit Amount” has the meaning set forth in Section 5.3(e).

“Title Benefit Notice” has the meaning set forth in Section 5.3(b).

“Title Benefit Property” has the meaning set forth in Section 5.3(b).

“Title Defect” means any Encumbrance or other matter that causes CONSOL not to have Defensible Title (or would cause CONSOL not to have Defensible Title as of Closing unless curative action is taken prior to Closing) in and to the Leases or Marcellus Wells; provided that the following shall not be considered Title Defects:

(a)           defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Noble provides affirmative evidence that such failure or omission results in another Person’s superior claim of title to the relevant Lease or Marcellus Well;

Appendix I

Page 16

(b)           defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(c)           defects arising out of lack of corporate or other entity authorization, unless such lack of authorization results in Third Party’s actual and superior claim of title to the relevant property;

(d)           defects based on a gap in CONSOL’s chain of title to any Lease in the applicable federal, state or county records existing prior to 1960 and, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in a Title Defect Notice, all other defects based on a gap in CONSOL’s chain of title to any Lease in the applicable federal, state or county records;

(e)           defects that have been cured by applicable Laws of limitations or prescription;

(f)           defects based upon the exercise of any Preferential Purchase Right;

(g)           defects that cause CONSOL to have less Net Acres for any Lease than the Net Acres set forth in Exhibit A with respect to such Lease unless if, after accounting for any such deficit in the Net Acres for any Lease, the actual aggregate Net Acres in the Area in which such Lease is located would be less than the Minimum Net Acres for such Area;

(h)           any Encumbrance or loss of title resulting from CONSOL’s conduct of business after the date hereof in compliance with this Agreement;

(i)            defects based solely on: (i) lack of information in CONSOL's files; (ii) references to an unrecorded document(s) to which neither CONSOL or any Affiliate is a party, if such document is dated earlier than January 1, 1960 and is not in CONSOL’s files; or (C) Tax assessment, Tax payment or similar records (or the absence of such activities or records);

(j)            defects as a consequence of cessation of production, insufficient production or failure to conduct operations during any period after the completion of a Well capable of production in paying quantities on any of the Leases held by production, or lands pooled or unitized therewith, except to the extent the cessation of production is affirmatively shown to exist such that it would give rise to a right to terminate the Lease, which document shall be included in the Title Defect Notice; and

(k)           defects arising from any change in Laws after the date hereof or from the outcome of any minimum royalty or related litigation.

“Title Defect Amount” has the meaning set forth in Section 5.3(g).

“TitleDefect Claim Date” means on or before 5:00 p.m. (Central Time) on the date that is 18 months after the Closing Date, or if such day is not a Business Day, on the first Business Day following such date.

Appendix I

Page 17

“Title Defect Deductible” means 1.0% of the Total Amount.

“Title Defect Notice” has the meaning set forth in Section 5.3(a).

“Title Defect Notice Date” has the meaning set forth in Section 5.3(c).

“Title Defect Property” has the meaning set forth in Section 5.3(a).

“Title Disputes” has the meaning set forth in Section 5.3(j).

“Title Dispute Date” means, with respect to any Title Dispute, the date that is 60 days following the date upon which the Title Defect Notice or Title Benefit Notice that relates to the Title Defect or Title Benefit (or the amount thereof) that is the subject of the dispute has been received.

“Title Indemnity Agreement” has the meaning set forth in Section 5.3(d)(iii).

“Total Amount” means the Total Cost Sharing Payments together with the Carried Cost Obligation.

“Total Cost Sharing Payments” means the sum of the Closing Cash Payment and the Post Closing Cash Payments.

“Transaction Documents” means those documents executed and/or delivered on or prior to Closing pursuant to or in connection with this Agreement.

“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 when, or with respect to, the transfer of property, 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.

“Units” has the meaning set forth in Section 2.1(a)(iii).

“Unit JOA” has the meaning set forth in the Development Agreement.

“Unit JOA Memorandum” has the meaning set forth in the Development Agreement.

“Water Use Agreement” means that Water Use Agreement by and among CONSOL, Noble and certain CONSOL Affiliates substantially in the form attached hereto as Exhibit L.

“Wells” has the meaning set forth in Section 2.1(a)(ii).

Appendix I

Page 18

“Well Imbalance” means any imbalance at the wellhead between the amount of Hydrocarbons produced from a Marcellus Well and allocable to the interests of CONSOL therein and the shares of production from the relevant Marcellus Well to which CONSOL is entitled, together with any appurtenant rights and obligations concerning future in kind and/or cash balancing at the wellhead.

“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) 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 date hereof, or (c) such Party willfully and intentionally causes any 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 Lease or Marcellus Well, means the interest in and to such Lease or Marcellus 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 Lease or Marcellus Well, but without regard to the effect of any Burdens.

“WV Dry Area” means, collectively, those counties in which the Leases that are marked as being located in the “WV Dry” Area on Schedule 1.1 are located.

Appendix I

Page 19

EX-10.1

Exhibit 10.1

JOINT DEVELOPMENT AGREEMENT

BY AND AMONG

CNX GAS COMPANY LLC,

and

NOBLE ENERGY, INC.

DATED September 30, 2011

TABLE OF CONTENTS

		Page
ARTICLE I	DEFINITIONS AND INTERPRETATION	1
1.1	Defined Terms	1
1.2	References and Rules of Construction	1
ARTICLE II	SCOPE; PARTICIPATING INTERESTS; OPERATIONS	2
2.1	Scope	2
2.2	Participating Interests	2
2.3	Operations; Development Area	2
2.4	Operating Agreements	4
2.5	Operator	5
2.6	Liability of Operator	7
2.7	Rentals, Shut-in Well Payments and Royalties	8
2.8	Insurance	8
2.9	Reports	9
2.10	Marketing	10
2.11	Development Services; Overhead Rates; and Marketing Fees.	15
2.12	Contracts; Use of Affiliates	15
2.13	Non-Solicitation	16
2.14	Conflict of Interest Policy	16
2.15	Secondment	16
ARTICLE III	JOINT DEVELOPMENT COMMITTEE; DEVELOPMENT PLAN; ANNUAL PLANS AND BUDGETS	16
3.1	Joint Development Committee	16
3.2	Development Plan	19
3.3	Annual Plan and Budgets	20
3.4	AFEs	25
3.5	Non-Consent Years	25
ARTICLE IV	TRANSFER RESTRICTIONS	27
4.1	Restrictions on Transfer	27
4.2	Documentation for Transfers	29
4.3	Maintenance of Uniform Interest	29
4.4	Right of First Offer	30
ARTICLE V	AREA OF MUTUAL INTEREST	31
5.1	Creation of Area of Mutual Interest	31
5.2	Acquisition of Fill-In Interests for Drilling Units in the Development Area	31
5.3	Acquisition of Option Interests in the Development Area	32
5.4	Exceptions	33

i

ARTICLE VI	TAXES	35
6.1	Tax Partnership	35
6.2	Tax Information	36
6.3	Responsibility for Taxes	36
ARTICLE VII	CERTAIN PAYMENT OBLIGATIONS	36
7.1	Payment of Development Costs and Carried Costs	36
7.2	Payment Procedures	37
7.3	Carried Costs Balance Payment	38
7.4	Post Closing Cash Payments	38
7.5	Certain Order of Payments	38
7.6	Total Cost Sharing Payments	38
ARTICLE VIII	DEFAULTS	39
8.1	Defaults	39
8.2	Certain Automatic Remedies for a Default	39
8.3	Certain Other Remedies for a Default	41
8.4	Cumulative and Additional Remedies	42
ARTICLE IX	LAND AND GEOSCIENCE DATA; DISCLAIMERS	42
9.1	Land and Geoscience Data	42
9.2	Disclaimers	42
ARTICLE X	TERM	43
10.1	Termination	43
10.2	Effect of Termination	43
ARTICLE XI	MISCELLANEOUS	44
11.1	Relationship of the Parties	44
11.2	Notices	44
11.3	Expenses	47
11.4	Waivers; Rights Cumulative	47
11.5	Entire Agreement; Conflicts	47
11.6	Amendment	48
11.7	Governing Law; Disputes	48
11.8	Publicity	49
11.9	Parties in Interest	49
11.10	Successors and Permitted Assigns	49
11.11	Preparation of Agreement	49
11.12	Severability	49
11.13	Counterparts	50
11.14	Excluded Assets	50

ii

LIST OF APPENDICES AND EXHIBITS

Appendices
Appendix I	―	Definitions
Exhibits
Exhibit A-1	―	Development Area and Area of Mutual Interest
Exhibit A-2	―	CNX Operated Area
Exhibit A-3	―	NBL Operated Area
Exhibit B-1	―	Master JOA
Exhibit B-2	―	Noble Master JOA Memorandum
Exhibit B-3	―	CONSOL Master JOA Memorandum
Exhibit C	―	Insurance
Exhibit D-1	―	Unit JOA
Exhibit D-2	―	Noble Unit JOA Memorandum
Exhibit D-3	―	CONSOL Unit JOA Memorandum
Exhibit E	―	Development Plan
Exhibit F	―	Annual Plan and Budget
Exhibit G	―	Tax Partnership Agreement
Exhibit H	―	Marcellus Formation
Schedule
Schedule 2.3(c)	―	Expansion Counties
Schedule 2.10	―	Downstream Contracts and Hydrocarbon Sales Contract

iii

JOINT DEVELOPMENT AGREEMENT

THIS JOINT DEVELOPMENT AGREEMENT is made this 30th day of September, 2011 (the “Closing Date”) by and among CNX Gas Company LLC, a Virginia limited liability company(“CONSOL”), and Noble Energy, Inc., a Delaware corporation (“Noble”).  CONSOL and Noble shall sometimes be referred to herein together as the “Parties”, and individually as a “Party”.

Recitals

Pursuant to that certain Acquisition Agreement (as hereafter defined), CONSOL is transferring to Noble, and Noble is acquiring from CONSOL, certain undivided interests in the Oil and Gas Assets (as hereinafter defined) described therein;

The Parties desire to set forth their agreements for the joint exploration, development and operation of the Subject Assets (as hereinafter defined) in a coordinated manner using CONSOL Operator (as hereinafter defined) as operator of the CNX Operated Area (as hereinafter defined) and using Noble Operator (as hereinafter defined) as operator of the NBL Operated Area (as hereinafter defined);

This Agreement, the Acquisition Agreement and the Associated Agreements are parts of a single, integrated transaction; and

The Parties desire to set forth their respective rights and obligations with respect to all such arrangements.

NOW THEREFORE, in consideration of the mutual agreements contained herein, 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 I

DEFINITIONS AND INTERPRETATION

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

1.2          References and Rules of Construction.  All references in this Agreement to Exhibits, Appendices, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Appendices, 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 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 will have the meaning given to it under generally accepted accounting principles.  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.  References to any Law or agreement means such Law or agreement as it may be amended from time to time.

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ARTICLE II

SCOPE; PARTICIPATING INTERESTS; OPERATIONS

2.1Scope .  This Agreement shall govern the respective rights and obligations of the Parties with respect to the funding, exploration, development and operation of the Subject Assets, and the marketing and sale of Hydrocarbons produced therefrom.

2.2Participating Interests.

(a)As of the Closing Date, the Participating Interests of the Parties are as follows:

Party	Participating Interest
CONSOL	50%
Noble	50%

(b)If a Party Transfers all or any undivided percentage of its Joint Development Interest pursuant to the provisions of this Agreement, the Participating Interests of the Parties shall be revised accordingly.

2.3Operations; Development Area.

(a)Subject to Sections 2.3(c), 2.3(d), 2.5and 2.6 and the other terms of this Agreement, CONSOL Operator shall manage and control the participation of the Parties in all Development Operations and Area-Wide Operations relating to the portion of the Development Area described on Exhibit A-2 (as adjusted pursuant to Section 2.3(c), the “CNX Operated Area”) in accordance with the Development Plan and applicable Annual Plan and Budget and such other operating guidelines as the Joint Development Committee may establish, including proposing all Development Operations on behalf of the Parties under any Applicable Operating Agreement relating to such area, making all elections on behalf of the Parties under any Applicable Operating Agreement (other than elections with respect to operations proposed by a Third Party Operator or other Third Party under an Applicable Operating Agreement) relating to such area, and conducting all Area-Wide Operations on behalf of the Parties relating to such area.  In addition, subject to Sections 2.5 and 2.6, CONSOL Operator shall have such other powers and responsibilities as are set forth in this Agreement or as granted to it by the Joint Development Committee.

(b)Subject to Sections 2.3(c), 2.3(d), 2.5 and 2.6 and the other terms of this Agreement, Noble Operator shall manage and control the participation of the Parties in all Development Operations and Area-Wide Operations relating to the portion of the Development Area described on Exhibit A-3 (as adjusted pursuant to Section 2.3(c), the “NBL Operated Area”) in accordance with the Development Plan and applicable Annual Plan and Budget and such other operating guidelines as the Joint Development Committee may establish, including proposing all Development Operations on behalf of the Parties under any Applicable Operating Agreement relating to such area, making all elections on behalf of the Parties under any Applicable Operating Agreement (other than elections with respect to operations proposed by a Third Party Operator or other Third Party under an Applicable Operating Agreement) relating to such area, and conducting all Area-Wide Operations on behalf of the Parties relating to such area.  In addition, subject to Sections 2.5 and 2.6, Noble Operator shall have such other powers and responsibilities as are set forth in this Agreement or as granted to it by the Joint Development Committee.

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(c)CONSOL and Noble may adjust the allocation of the Operated Areas between the Party Operators by written agreement; provided that, at any time that Drilling Units have been designated covering at least 60% of the net acreage included in the Subject Assets within the NBL Operated Area and such Subject Assets covered by such Drilling Units have become or, within the following 24-months months are reasonably expected to become, Developed Assets or P&A/Condemned Assets, then upon written request from Noble to CONSOL (an “Expansion Request”), Noble and CONSOL shall meet (which meeting shall occur within 15 days of such request being received by CONSOL) and use their commercially reasonable efforts to agree upon expanding the NBL Operated Area (and, if applicable, reducing the CNX Operated Area) so that Noble Operator can continue conducting drilling and completion Development Operations to the same extent and at the same pace that it was conducting drilling and completion Development Operations prior to the Expansion Request.  If Noble and CONSOL are unable to so mutually agree upon an expansion of the NBL Operated Area within 45 days of CONSOL receiving an Expansion Request, then the NBL Operated Area shall automatically be expanded by one county (each, an “Expansion County”), which Expansion County shall be selected by Noble by choosing one of the counties listed on Schedule 2.3(c) that is not then a part of the NBL Operated Area (and, if applicable, the CNX Operated Area shall be reduced by excluding from such area such Expansion County, provided that, notwithstanding the foregoing, from and after the date of such expansion, the CNX Operated Area shall continue to include (and the NBL Operated Area shall not include) any Drilling Units within the Expansion County that were designated by CONSOL Operator prior to such expansion and on which any drilling and completion operations had been commenced or are reasonably expected to be commenced within six months following such expansion (the “Excluded Units”).  Unless otherwise agreed by the Parties, an Excluded Unit shall cease to be an Excluded Unit and operatorship of such Excluded Unit shall be transferred to Noble Operator promptly after all drilling and completion operations that caused such Drilling Unit to be an Excluded Unit have been concluded by CONSOL Operator.  Unless otherwise mutually agreed, the right to expand the NBL Operated Area shall automatically terminate at the time that all counties listed on Schedule 2.3(c) have become part of the NBL Operated Area (excluding any Excluded Units).

(d)Notwithstanding anything in the Agreement to the contrary, beginning on the Closing Date and ending on the date that is 90 days following the date on which CONSOL Operator receives written notice from Noble Operator that it is electing to assume operatorship of the NBL Operated Area, or such earlier date as CONSOL Operator and Noble Operator may mutually agree (the “Operatorship Transition Period”), the NBL Operated Area shall be deemed to be a part of the CNX Operated Area and CONSOL Operator shall serve as Party Operator of such Operated Area; provided that in the event that Noble Operator does not provide such notice to CONSOL Operator on or before December 31, 2012, then the Operatorship Transition Period shall terminate, the NBL Operated Area thereafter shall be deemed to cover none of the Development Area, the CONSOL Operated Area shall be deemed to cover both the area initially defined as the NBL Operated Area and the area initially defined as the CONSOL Operated Area and the provisions of Section 2.3(c) shall no longer be applicable.  During the Operatorship Transition Period, prior to commencing any Development Operation in the Operated Area that is described on Exhibit A-3, CONSOL Operator shall provide a copy of any AFE and any related drilling and completion plan for such Development Operation to Noble Operator and thereafter meet with Noble Operator to discuss and review such AFE and/or related drilling and completion plan.  At the end of the Operatorship Transition Period, CONSOL Operator shall use its commercially reasonable efforts to assist Noble Operator in taking over as operator in the NBL Operated Area.

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2.4Operating Agreements.

(a)Except for any Unit JOAs that are executed and delivered by the Parties on the Closing Date, all Leases and related assets in the Development Area:  (i) in which only the Parties hold interests as of the Closing Date, or (ii) in which the Parties hereafter both acquire interests, shall be deemed to be subject to and governed by an operating agreement in the form attached hereto as Exhibit B-1 (the “Master JOA”); provided that with respect to those Subject Assets that are subject to any Third Party Operating Agreement, only the lien provisions of the Master JOA shall be applicable to such Subject Assets.   On the Closing Date, the Master JOA shall be executed by the Parties and shall cover all such Subject Assets (including those Subject Assets that are subject to a Third Party Operating Agreement), excluding, however, those Subject Assets that are covered by a Unit JOA.  All Leases and related assets in the Development Area in which the Parties hereafter both acquire interests that are not subject to a Third Party Operating Agreement, shall automatically become subject to the Master JOA and, within 30 days following the end of each calendar quarter, the Parties shall supplement and/or amend each applicable Master JOA Agreement to reflect the addition of such Leases and related assets; provided that to the extent that such Leases and related assets are Developed Assets and not subject to a Third Party Operating Agreement at the time of acquisition, then such Leases and related assets shall become subject to a Unit JOA to be executed by the Parties at the time of the acquisition of such Leases and related assets.  For those Subject Assets that are subject to a Third Party Operating Agreement, such Third Party Operating Agreement shall govern the operations thereon; provided that if such Subject Assets as of the Closing Date are not Developed Assets, then the lien provisions of the Master JOA shall be applicable to such Subject Assets.

(b)On the Closing Date, the Parties shall execute and file a separate Memorandum of Operating Agreement, Lien and Financing Statement, in the case of Noble, in the form attached hereto as Exhibit B-2 (the “Noble Master JOA Memorandum”), and , in the case of CONSOL, in the form attached hereto as Exhibit B-3 (the “CONSOL Master JOA Memorandum” and, together with the Noble Master JOA Memorandum, the “Master JOA Memoranda”) and related financing statements for the Master JOA and, within 30 days of the Closing Date, the Parties will file such Master JOA Memoranda in the real property records of each county in which the Subject Assets that are covered by the Master JOA are located and such financing statements in the proper office under the Uniform Commercial Code in the states in which such Subject Assets are located.

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(c)From and after the Closing Date, if a Drilling Unit is designated by CONSOL Operator or Noble Operator to cover a specified portion of the Subject Assets covered by the Master JOA that is not also covered by a Third Party Operating Agreement and such portion of the Subject Assets covered by such Drilling Unit become Developed Assets, then the Master JOA shall automatically be deemed to not cover such portion of the Subject Assets and a separate operating agreement in the form attached hereto as Exhibit D-1 (each, a “Unit JOA”), with CONSOL Operator or Noble Operator serving as operator (as applicable pursuant to Section 2.3) shall be deemed to cover such portion of the Subject Assets with respect to such Drilling Unit.   Further, from and after the Closing Date, if any portion of the Subject Assets that are subject to a Third Party Operating Agreement become Developed Assets, then the Master JOA shall automatically be deemed to not cover such portion of the Subject Assets and only such Third Party Operating Agreement shall cover such portion of the Subject Assets.

(d)  Within 30 days following the end of each calendar quarter, the Parties shall (i) modify or amend the Master JOA and each Master JOA Memoranda and related financing statements (including making any filings necessary to reflect such modifications or amendments in the applicable real property and other public records) to reflect any Subject Assets that have become subject to, or removed from, the Master JOA during the previous calendar quarter, (ii) execute and deliver separate Unit JOAs to cover any Subject Assets that have been deemed to have become subject to a Unit JOA during the previous calendar quarter and (iii) execute and file a separate Memorandum of Operating Agreement, Lien and Financing Statement, in the case of Noble, in the form attached hereto in Exhibit D-2 (the “Noble Unit JOA Memorandum”), and , in the case of CONSOL, in the form attached hereto in Exhibit D-3 (the “CONSOL Unit JOA Memorandum” and, together with the Noble Unit JOA Memorandum, the “Unit JOA Memoranda”) and related financing statements for each Unit JOA that is being executed and delivered pursuant to clause (ii) above and file such Unit JOA Memoranda in the real property records of each county in which the Subject Assets that are covered by the applicable Unit JOA are located and in the proper office under the Uniform Commercial Code in the states in which such Subject Assets are located.

(e)In addition, subject to Section 2.4(a), the Parties agree to use their respective commercially reasonable efforts to have the form of the Unit JOA adopted as the operative operating agreement by all Working Interest owners for any Drilling Unit in the Development Area in which Persons other than the Parties hold Working Interests.

(f)As between the Parties, each Applicable Operating Agreement shall be subject to the provisions of the Tax Partnership Agreement unless and until the applicability of such provisions to the Subject Assets subject to each such Applicable Operating Agreement terminates in accordance with the terms of the Tax Partnership Agreement.

2.5Operator.

(a)CONSOL Operator.

(i)CONSOL Operator is hereby designated and agrees to serve as operator under each Joint Development Operating Agreement relating to the CNX Operated Area.  In addition, to the extent requested by CONSOL Operator, the Parties agree to use their respective commercially reasonable efforts to support CONSOL Operator in any vote with respect to becoming or remaining as operator under each other Applicable Operating Agreement relating to the CNX Operated Area.

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(ii)CONSOL Operator (1) may be removed or resign as operator under an Applicable Operating Agreement pursuant to the relevant provisions of such Applicable Operating Agreement or (2) may be removed as operator under all Applicable Operating Agreements pursuant to Section 8.3(c)(ii).  In the event that CONSOL Operator is removed or resigns as operator under an Applicable Operating Agreement relating to the CNX Operated Area or is removed as CONSOL Operator pursuant to Section 8.3(c)(ii), Noble shall have the right, which shall be exercisable by written notice to CONSOL Operator within 15 days following such removal or resignation, to have Noble Operator named as operator of the CNX Operated Area to the extent it relates to such removal or resignation with respect to any Joint Development Operating Agreement or have CONSOL vote its interest under any Third Party Operating Agreement for Noble Operator to be named the operator under any such Third Party Operating Agreement (and if so exercised, such area shall be removed from the CNX Operated Area and added to the NBL Operated Area).

(b)    Noble Operator.

(i)Noble Operator is hereby designated and agrees to serve as operator under each Joint Development Operating Agreement relating to the NBL Operated Area.  In addition, to the extent requested by Noble Operator, the Parties agree to use their respective commercially reasonable efforts to support Noble Operator in any vote with respect to becoming or remaining as operator under each other Applicable Operating Agreement relating to the NBL Operated Area.

(ii)  Noble Operator (1) may be removed or resign as operator under an Applicable Operating Agreement pursuant to the relevant provisions of such Applicable Operating Agreement or (2) may be removed as operator under all Applicable Operating Agreements pursuant to Section 8.3(c)(i).  In the event that Noble Operator is removed or resigns as operator under an Applicable Operating Agreement relating to the NBL Operated Area or is removed as Noble Operator pursuant to Section 8.3(c)(i), CONSOL shall have the right, which shall be exercisable by written notice to Noble Operator within 15 days following such removal or resignation, to have CONSOL Operator named as operator of the NBL Operated Area to the extent it relates to such removal or resignation with respect to any Joint Development Operating Agreement or have Noble vote its interest under any Third Party Operating Agreement for CONSOL Operator to be named the operator under any such Third Party Operating Agreement (and if so exercised, such area shall be removed from the NBL Operated Area and added to the CNX Operated Area).

 (c)         HSE Standards.

(i)Each Party Operator shall be required to maintain health, safety and environmental policies and programs covering Development Operations and Area-Wide Operations conducted by such Party Operator in its Operated Area (as amended and modified from time to time, an “HSE Program”).  Each Party Operator shall conduct (i) regular audits and reviews of its HSE Program and (ii) an annual review of its HSE Program.  Prior to conducting an annual review of its HSE Program, each Party Operator shall give each other Party reasonable advance notice of such annual review and an opportunity to reasonably participate in such annual review.

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(ii)Each Party Operator shall submit to the HSE Committee, promptly after such annual review is completed, a written description describing in reasonable detail the results and findings of such annual review.  Each Party Operator shall meet at least quarterly with the HSE Committee to review and discuss such Party Operator’s HSE Program and its compliance therewith.

2.6Liability of Operator.

(a)Subject to the rights of a Party to remove any Party acting as operator under any Applicable Operating Agreement in accordance with the terms hereof or thereof, in no event shall any Party serving as a Party Operator have any liability as a Party Operator to another Party or its Affiliates under this Agreement, under any Applicable Operating Agreement or Law or common law (including on account of its marketing of any Party’s production pursuant to this Agreement) for any claim, damage, loss or liability sustained or incurred in connection with its operations with respect to any Development Operation or Area-Wide Operation (including its activities to market any Party’s production pursuant to Section 2.10) or any breach of any provision regarding the standard of performance of an operator in performing operations under any Applicable Operating Agreement, EVEN IF SUCH CLAIM, DAMAGE, LOSS OR LIABILITY AROSE IN WHOLE OR IN PART FROM THE ACTIVE, PASSIVE, SOLE OR CONCURRENT NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF SUCH PARTY, ANY OF ITS AFFILIATES OR ANY OFFICER, PARTNER, MEMBER, DIRECTOR, AGENT OR EMPLOYEE OF SUCH PARTY, OTHER THAN IF SUCH CLAIM, DAMAGE, LOSS OR LIABILITY AROSE FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH PARTY, ANY OF ITS AFFILIATES OR ANY OFFICER, PARTNER, MEMBER, DIRECTOR OR EMPLOYEE OF SUCH PARTY; provided that no Party Operator shall be released and/or exonerated from liability for a material breach of any financial, administrative or procedural (such as providing notices and voting) obligation of such Person under this Agreement or (if a Party Operator) under any Applicable Operating Agreement; and provided further that each Party acknowledges that any such claim, damage, loss or liability (other than that caused by the gross negligence or willful misconduct of a Party, its Affiliates or any officer, partner, member, director, agent or employee of a Party or any of its Affiliates or the material breach of any financial, administrative or procedural (such as providing notices and voting) obligation of a Party Operator), shall be borne severally by the Parties (including such operator) in proportion to their interests in the operations or activities giving rise to such claim, damage, loss or liability.

(b)Any Party serving as a Party Operator shall bear sole liability on behalf of the Parties for any claim, damage, loss or liability sustained or incurred in connection with any Development Operation or Area-Wide Operation or any other operation or activity prescribed hereunder or any breach of any provision regarding the standard of performance of an operator in performing operations under any Applicable Operating Agreement to the extent such claim, damage, loss or liability arose in whole or in part from the gross negligence or willful misconduct of such Party or any of its Affiliates or any officer, partner, member, director, agent or employee of such Party or Affiliate of such Party.

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(c)          Notwithstanding anything to the contrary herein or in any Applicable Operating Agreement, no Party Operator shall be liable for the gross negligence or willful misconduct of a secondee of another Party, nor shall the gross negligence or willful misconduct of any such secondee be grounds for removal of a Party Operator pursuant to Section 2.5.

2.7         Rentals, Shut-in Well Payments and Royalties.  Each Party Operator shall be responsible for paying, on behalf of each Party, such Party’s share of (a) all rentals, shut-in well payments and minimum royalties required to be paid to lessors under the Leases included in the Subject Assets in such Party Operator’s Operated Area and (b) all valid and subsisting royalties, overriding royalties and other burdens required to be paid to lessors and holders of overriding royalties and other burdens on the Leases included in the Subject Assets in such Party Operator’s Operated Area; provided that, subject to this Section 2.7, a Party Operator may determine, in its reasonable discretion as a reasonable prudent operator (after consulting with Noble, in the case that CONSOL is the Party Operator, or CONSOL, in the case that Noble is the Party Operator), not to renew, maintain or extend any such Lease in its Operated Area.  A Party Operator shall be entitled to contract with Third Parties to provide the foregoing services (including in the case of Noble Operator, contracting with CONSOL and its Affiliates in accordance with and subject to the terms of the Services Agreement (as defined in the Acquisition Agreement) during the term thereof).  If a Party Operator (after consulting with the applicable Party) determines not to renew, maintain or extend any of the Leases included in the Subject Assets in its Operated Area, such Party Operator will provide each other Party with no less than 30 days (to the extent reasonably possible) notice of such determination in writing prior to the expiration of such portion of such Lease, and each other Party will have the right (in the proportion that the participating Party’s undivided interest in such Lease bears to all other participating Parties’ undivided interest in such Lease) to pay the rental, shut-in well payment, minimum royalty, lease renewal or other payment and receive an assignment from the non-participating Parties of their respective interests in such Lease (in the proportion that the participating Party’s undivided interest in such Lease bears to all other participating Parties’ undivided interest in such Lease).  Thereafter, notwithstanding anything contained in this Agreement to the contrary, such Lease shall be deemed to be excluded from the terms and conditions of this Agreement.  A Party Operator may invoice the other Parties up to 30 days prior to the date any rental, shut-in payment, minimum royalty or any other lease renewal or maintenance payment shall become due, and each Party shall pay such invoice in accordance with Section 7.2.  NO PARTY OPERATOR WILL BE LIABLE TO ANY PARTY FOR ANY NEGLIGENCE, ACT, ERROR, MISTAKE OR OMISSION PERTAINING TO THE PERFORMANCE OF ITS OBLIGATIONS UNDER THIS SECTION 2.7 OR ANY LOSS RESULTING FROM SUCH NEGLIGENCE (WHETHER ACTIVE, PASSIVE, SOLE OR CONCURRENT) ACT, ERROR, MISTAKE OR OMISSION UNLESS SUCH NEGLIGENCE, ACT, ERROR, MISTAKE OR OMISSION CONSTITUTES GROSS NEGLIGENCE OR WILLFUL MISCONDUCT BY SUCH PARTY OPERATOR.

2.8Insurance.  

(a)Each Party Operator shall use its commercially reasonable efforts to carry insurance for the benefit of the joint account of the Parties as outlined in Exhibit C (or at such other insurance level as the Joint Development Committee may approve) for those Subject Assets for which it serves as operator.  Each Party Operator shall provide copies of such policies to the Parties covered by such policies upon request, and shall notify all Parties to be covered by such policies if it has been unable to obtain or maintain any of such policies.  Except for worker’s compensation policies, each Party Operator shall use its commercially reasonable efforts to arrange for each of the Parties, according to their respective interests, to be named as additional insureds on the relevant policies, with waivers of subrogation in favor of all Parties with respect to their interests under this Agreement or such Applicable Operating Agreement where such Party Operator is the operator, as applicable.  Each Party Operator shall use commercially reasonable efforts to duly file any relevant claims and to collect for the account of the relevant Parties any proceeds under such policies.

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(b)Notwithstanding the foregoing, any Party may obtain such insurance as it deems advisable for its own account at its own expense.  Such insurance shall, in so far as it relates to Development Operations or Area-Wide Operations, contain a waiver of subrogation by the insurers in favor of each of the other Parties.  Each Party Operator shall reasonably cooperate and assist such insurers in the investigation of insurance claims made by a Party in connection with the operations performed hereunder.

2.9Reports.

(a)Unless otherwise prohibited by the terms of an Applicable Operating Agreement or (subject to Section 2.9(d) below) confidentiality obligation under any other applicable contract or agreement or by applicable Law, each Party Operator shall provide the following data and reports, as they are produced or compiled after the date hereof (unless otherwise provided below), for each Development Operation for which it serves as operator and each Area-Wide Operation in its Operated Area to the other Parties that participate in such Development Operation or Area-Wide Operation:

(i)    copies of all logs or surveys, including in digitally recorded format if such exists;

(ii)daily drilling and production reports;

(iii)copies of all tests and core data and analysis reports;

(iv)  final well recap reports, including well bore diagrams;

(v)copies of all plugging reports;

(vi)as requested by a Party, copies of current geological and geophysical maps, seismic sections and shot point location maps;

(vii)development schedules and annual progress reports on development projects;

(viii) field and well performance reports;

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(ix)copies of written notices provided by any Third Party regarding violations or potential violations of applicable Law (including any applicable health, safety or environmental Laws);

 (x)copies of all material reports provided to any Governmental Authority;

(xi)   as requested by a Party, copies of any material correspondence between such operator and any Governmental Authority;

(xii)copies of all title opinions, including drill site title opinions and division order title opinions;

(xiii)copies of all post-fracing flowback reports;

(xiv)  such other information as may be reasonably requested by a Party; and

(xv)   such other reports as may be directed by the Joint Development Committee.

(b)Notwithstanding the foregoing, but without limiting the information required to be provided by a Party Operator pursuant to an Applicable Operating Agreement, a Party Operator will not be obligated to provide to any Party copies of: (i) any of its own independent reserve reports or evaluations or reservoir studies; or (ii) any data or report to the extent such data or report is generated, assembled or prepared by a Third Party and the Party requesting such data or report has not paid its Share of Development Costs relating to such data or report.

(c)          To the extent that a Party is responsible for any portion of the liability associated therewith, each Party Operator shall promptly notify such Party of any Third Party written claim or suit arising from Development Operations or Area-Wide Operations in its Operated Area of which such Party Operator becomes aware that exceeds (or is reasonably expected to exceed) $50,000, and, upon request of such Party from time to time, shall further provide, in a timely manner, the then current information in its possession regarding the progress and status of any such claims or suits.

(d)          Each Party Operator shall use its commercially reasonable efforts obtain a waiver of any confidentiality obligation under an applicable contract or agreement that prevents such Party Operator from providing to the other Parties the data and reports required by Section 2.9(a).

2.10Marketing.

(a)Production.  Each Party retains and reserves the right to take-in-kind all of its Production in the CNX Operated Area and the Noble Operated Area subject to the terms of this Section 2.10.

(b)Gas Production.

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(i)For the Interim Marketing Period, Noble hereby designates CONSOL Operator as marketer of Noble’s Gas Production (“Marketer”), in the CNX Operated Area and in the Noble Operated Area, produced during the Interim Marketing Period in accordance with and subject to the following terms of this Section 2.10.  During the Interim Marketing Period and subject to the remaining provisions of this Section 2.10, Marketer shall have authority and responsibility to market and sell such Gas Production (but not hedge such Gas Production) and to enter into sales, transportation, gathering and treatment agreements with respect to such Gas Production on behalf of the Party that owns the same (a “Marketing Transaction”); provided that Marketer shall not enter into a Marketing Transaction that (i) has a noncompetition provision, area of mutual interest restriction, preferential purchase right, or dedication of properties or (ii) a term that extends beyond March 31, 2013, in each case, that is binding upon a Party without the prior written consent of such Party.  For each Marketing Transaction, Noble’s Gas Production in an Operated Area shall be marketed on terms at least as favorable as terms received by Marketer for its share of Gas Production during the Interim Marketing Period and Marketer will market all Gas Production on market-based terms as reasonably determined in good faith by Marketer.  Unless Noble otherwise consents to the same in writing, none of Noble’s Gas Production may be marketed to Marketer itself or any Affiliate of Marketer.  During the Interim Marketing Period, title to Noble’s Gas Production will pass to (A) with respect to all processed natural gas liquids, condensate or other processed products from such Gas Production (“Processed Gas Production”), to the processor at the point at which title is required to be transferred to such processor under the applicable processing agreement and (B) with respect to all other such Gas Production (“Residual Gas Production”), to Marketer at the first delivery point location into an interstate natural gas pipeline system.  During the Interim Marketing Period, all Residual Gas Production shall be sold under the NAESB Agreement and the related transaction confirmations.  Furthermore, during the Interim Marketing Period, title to Noble’s Gas Production shall at all times remain with Noble until such time as title is passed to another Person as described above, such that all products, both volume and value, sold on behalf of Noble or directly by Noble is to be reported as production volume, sales and revenue, by Noble.  During the Interim Marketing Period, the Parties will cause their Gas Production to be delivered pursuant to the Processing Agreements, as required.

(ii)During the Interim Marketing Period, Marketer will make all nominations that are required under the terms of any of its Marketing Transactions.  As requested by Marketer from time to time, Noble will reasonably cooperate and coordinate with Marketer in order to permit Marketer to perform under the terms of each of its Marketing Transaction with respect to Noble’s Gas Production and Noble shall indemnify, defend and hold Marketer harmless from any breach of any Marketing Transaction to the extent arising from Noble’s failure to so reasonably cooperate and coordinate.

(iii)Subject to Section 8.3(a), during the Interim Marketing Period Marketer shall remit to Noble all amounts due to Noble under the NAESB Agreement as and when due under the NAESB Agreement.

(iv)At the end of the Interim Marketing Period, each Party will take-in-kind any and all of its Gas Production in the CNX Operated Area and the Noble Operated Area and provide its own full marketing services.

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(c)Transportation and Processing.

(i)  After the Interim Marketing Period, subject to Section 2.10(c), each Party shall be responsible for obtaining their own gathering, processing and transportation agreements with respect to their Gas Production.  Prior to the end of the Interim Marketing Period and, if and to the extent required by Schedule 2.10(a), thereafter, each Party will comply with the terms of Schedule 2.10(a) with respect to the Downstream Contracts and the Peoples Contract.

(ii)During the Interim Marketing Period and for so long thereafter as CONSOL holds any of the Downstream Contracts for the benefit of Noble pursuant to Schedule 2.10(a), Noble shall be responsible for, and shall pay in accordance with Section 7.2, all demand charges and tariffs required to be paid by CONSOL with respect to such Downstream Contracts to the extent applicable to the Assigned FT Interests.  During the Interim Marketing Period, Noble shall be responsible for, and shall pay in accordance with Section 7.2, in addition to any other amounts set forth herein, in the NAESB Agreement or any related transaction confirmations, a daily reservation fee of $2,700.  During the Interim Marketing Period, with respect to that amount of Noble’s and its Affiliates’ Gas Production that is delivered to the Texas Eastern Transmission interstate pipeline in Marshall, West Virginia, Green, Pennsylvania, Fayette, Pennsylvania, Westmoreland, Pennsylvania, or Indiana, Pennsylvania, that is in excess of 54,000 MMBtu per day but less than 104,001 MMBtu per day (the “Excess Gas Production”), CONSOL shall purchase such Excess Gas Production under the terms of the NAESB Agreement and the related transaction confirmations at the inlet meter of the Texas Eastern Transmission interstate pipeline and, notwithstanding anything in this Section 2.10, the NAESB Agreement or any related transaction confirmation to the contrary, pay Noble and its Affiliates in respect of such Excess Gas Production as and when required under the terms of the NAESB Agreement an amount equal to (x) the first of the month Platts Inside F.E.R.C’s Gas Market Report, “Price of Spot Gas Delivered to Pipelines,” for deliveries at Appalachian Lebanon Hub for the calendar month in which such Excess Gas Production is so delivered multiplied by (y) the amount of Excess Gas Production delivered during such calendar month.

(iii)For purposes of flow assurance for each Party’s share of Gas Production, it is the intent of the Parties to participate equally in any future processing agreements for Gas Production obtained by either Party after the Closing Date.  If either Party desires to acquire additional processing capacity, then prior to entering into negotiations for a new processing agreement, such Party shall provide written notice to the Joint Development Committee, which shall include, the general deal parameters and the portion or portions of the Subject Assets within the Development Area that would be affected by such new processing agreement (a “Proposed Processing Agreement”).  At the next meeting of the Joint Development Committee following such submission, the Joint Development Committee shall vote to authorize or not authorize a Party (the “Negotiating Party”) to negotiate the Proposed Processing Agreement on behalf of the Parties.  Any members of the Joint Development Committee appointed by the Party (or its Affiliates) that submits a proposal for a Proposed Processing Agreement shall be deemed to have voted to authorize a Negotiating Party to negotiate the terms of a Proposed Processing Agreement on behalf of the Parties in accordance with this Section 2.10(b)(iii).  If the Joint Development Committee fails to authorize a Negotiating Party to negotiate a Proposed Processing Agreement on behalf of the Parties, then the Party making the proposal to acquire additional processing capacity may enter into a processing agreement covering the subject matter of the proposal for the Proposed Processing Agreement (with such revisions as are necessary to account for only such Party’s Gas Production being subject to such agreement).  If the Joint Development Committee authorizes a Negotiating Party to negotiate the Proposed Processing Agreement on behalf of the Parties, then, for a period of 90 days following the date of such authorization, such Negotiating Party shall have the exclusive right to negotiate such Proposed Processing Agreement on behalf of the Parties and no other Party shall negotiate or enter into any processing agreement relating to the subject matter of such Proposed Processing Agreement; provided that if such Negotiating Party fails to negotiate such Proposed Processing Agreement within such 90-day period, then such Negotiating Party will no longer have the right to negotiate such Proposed Processing Agreement (and until it resubmits a written notice to the Joint Development Committee to obtain the Joint Development Committee’s authorization of another Proposed Processing Agreement in accordance with the provisions of this Section 2.10(b)(iii)).  In negotiating any Proposed Processing Agreement, the Negotiating Party shall use its commercially reasonable efforts to negotiate any processing agreement or agreements on market based terms and to negotiate separate processing agreements for each Party (with the same terms and other than revisions necessary to account for each Party’s separate Gas Production).  Upon completion of such negotiations, if applicable, the Negotiating Party shall submit the final Proposed Processing Agreement or agreements to the Joint Development Committee.  At the next meeting of the Joint Development Committee following such submission, the Joint Development Committee shall vote to approve or disapprove such agreement or agreements.  If the Joint Development Committee approves such agreement or agreements, then each Party shall promptly execute and deliver such agreement or, if applicable, its respective agreement.  If the Joint Development Committee fails to approve a Proposed Processing Agreement or Proposed Processing Agreements after such agreement(s) has been negotiated by the Negotiating Party, then the Party whose members of the Joint Development Committee voted to approve such final Proposed Processing Agreements or agreements may enter into a processing agreement covering the subject matter of the Proposed Processing Agreement (with such revisions as are necessary to account for only such Negotiating Party’s Gas Production being subject to such agreement).

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(iv)Upon mutual agreement of the Parties, the Parties shall have the right, prior to September 25, 2011, to unwind the production dedication under the Processing Agreements in accordance with the terms of the Processing Agreements.

(d)          Hedging.  Each Party will be responsible for conducting (for its own account) any hedging activities with respect to its Production from the Subject Assets.

(e)Administrative Services and Reporting.  Each Party or Party Operator conducting marketing activities under this Section 2.10 on behalf of another Party shall also be responsible for providing any accounts receivable, collection, revenue accounting, system balancing and other back office marketing services necessary to market such Production.  Each Party or Party Operator conducting marketing activities under this Section 2.10 on behalf of another Party shall provide to such other Party the following reports and information as such data and reports are produced or compiled (unless otherwise provided below) relating to the Production being marketed hereunder on behalf of such other Party:

(i)counterparty credit exposure reports, as amended from time to time, which reports shall include a list of counterparties with to which the Parties have credit exposure, the maximum amount of potential credit exposure to each such counterparty for a 60-day period (regardless of any outstanding credit extensions to such counterparty at the time of such report) and any outstanding credit extensions to such counterparty at the time of such report;

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(ii)prior to the first day of each calendar month, a listing on anticipated sales and volumes by counterparty for the production of such Party being sold during such relevant calendar month;

(iii)copies of all transaction confirmations entered into under any NAESB agreement or similar agreement to which such Party or Party Operator is a party; and

(iv) any other data or information that a Party whose production is being marketed hereunder may reasonably request relating to its Production.

(f)Wellhead Condensate Production. From and after the Closing Date, each Party Operator shall have exclusive authority and responsibility to market and sell all of the Wellhead Condensate Production of the Parties in the Operated Area in which it operates (but not hedge such Wellhead Condensate Production), and to enter into any necessary marketing agreements for such Wellhead Condensate Production.  A Party Operator shall not enter into any marketing agreement that has a noncompetition provision, area of mutual interest restriction, preferential purchase right or dedication of properties that is binding upon a Party without the prior written consent of such Party.  Each Party’s Wellhead Condensate Production in an Operated Area shall be marketed by the applicable Party Operator on market-based terms at least as favorable as terms received by the applicable Party Operator for its share of Wellhead Condensate Production and the applicable Party Operator will market all Wellhead Condensate Production on market-based terms as reasonably determined in good faith by the applicable Party Operator.  Unless a Party otherwise consents to the same in writing, none of such Party’s Wellhead Condensate Production may be marketed to the Party Operator marketing such Wellhead Condensate Production or any Affiliate of such Party Operator.  Title to a Party’s Wellhead Condensate Production will remain in such Party until such time as title to such Wellhead Condensate Production is required to be transferred to the purchasing counterparty under the terms of the applicable sales contract.  As requested by a Party Operator from time to time, each Party will reasonably cooperate and coordinate with such Party Operator in order to permit such Party Operator to market such Party’s Wellhead Condensate Production.  All net proceeds from a Party’s Wellhead Condensate Production received by a Party Operator shall be held for the account of such Party and delivered by such Party Operator no later than the 25th day of the calendar month following receipt thereof by such Party Operator to an account designated by the applicable Party.

(g)Drip Condensate Production.  From and after the Closing Date, each Party’s Drip Condensate Production will be handled by the gatherer of any applicable gathering agreement.  Title to a Party’s Drip Condensate Production will remain in such Party until such time as title to such Drip Condensate Production is required to be transferred to the gatherer under the terms of the applicable gathering agreement.

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2.11Development Services; Overhead Rates; and Marketing Fees.

(a)Development Services.

(i)   Each Party Operator shall be entitled to perform Development Services required in connection with Development Operations and Area-Wide Operations conducted by such Party Operator.

(ii)Subject to Section 2.11(d), with respect to Development Services performed by a Party Operator hereunder, each Party shall pay to the applicable Party Operator its Participating Interest share of (A) those Services Costs incurred by such Party Operator in performing such Development Services and (B) all Third Party expenses incurred by such Party Operator in performing such Development Services (except to the extent such expenses are paid pursuant to and under an Applicable Operating Agreement), in each case, in accordance with Section 7.2.

(b)Overhead Rates.  With respect to Development Operations conducted by a Party Operator under an Applicable Operating Agreement, each Party shall pay to such Party Operator such Party’s Working Interest share of the producing well and/or drilling well overhead rates specified in such Applicable Operating Agreement in accordance with Section 7.2 for such Development Operations with respect to which it participates.

(c)Marketing Fee.  Subject to Section 2.11(d), during the Interim Gas Marketing Period, Noble shall pay or reimburse CONSOL Operator a monthly marketing fee equal to $0.02  for each MMBtu of Noble’s Gas Production that is purchased by CONSOL Operator from Noble pursuant to the NAESB Agreement (the “Marketing Fee”), in accordance with Section 7.2.

(d)Periodic Review.  On or before August 31 in the calendar year immediately preceding the relevant calendar year, the Joint Development Committee shall review the calculation of Services Costs being charged by each Party Operator pursuant to the then current Annual Plan and Budget and the amount of the Marketing Fees chargeable by CONSOL and vote to approve the calculation of such Services Costs and the amount of such Marketing Fee for the following year (each of which may be modified by the Joint Development Committee).  If the Joint Development Committee fails to approve the calculation of such Services Costs or the amount of such Marketing Fee (with any modifications that the Joint Development Committee may approve) for such following year, then any Party may submit such matter to an expert in accordance with Section 11.7(b)and such expert shall adjust such calculation and/or fees so that the amount of Services Costs and/or Marketing Fees chargeable to the Parties under this Section 2.11 equals in such expert’s opinion a market rate for fees being charged for similar services by other Persons in the Development Area at the time of such adjustment.

2.12Contracts; Use of Affiliates.

(a)Except as provided in Section 2.12(c), each Party Operator may enter into contracts and other agreements on customary terms and conditions in connection with any Development Operations or any Area-Wide Operations conducted by or at the direction of such Party Operator.

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(b)Except as provided in Section 2.12(c), each Party Operator may contract with its Affiliates and related parties to provide services and materials in connection with Development Operations or Area-Wide Operations.  All services performed and materials supplied by any such Affiliates or related parties shall be performed or supplied at arm’s length and on competitive rates, pursuant to written agreements, and in accordance with customs and standards prevailing in the industry.

(c)Notwithstanding Sections 2.12(a)or2.12(b) or any Applicable Operating Agreement to the contrary, unless either (i) such contract has been approved by the Joint Development Committee or (ii) such contract is expressly contemplated by an Annual Plan and Budget, a Party Operator shall not enter into an Affiliate Contract or a contract or agreement that contains a confidentiality obligation that would prevent such Party Operator from providing to the other Parties the data and reports required by Section 2.9(a).

2.13      Non-Solicitation.

(a)During the term of this Agreement and for a period of 12 calendar months thereafter, Noble and its Affiliates may not solicit or hire any officer or employee of CONSOL or its Affiliates without first obtaining the prior written consent of CONSOL; provided that this prohibition shall not apply to offers of employment made by Noble or its Affiliates pursuant to a general solicitation of employment to the public or the industry.

(b)During the term of this Agreement and for a period of 12 calendar months thereafter, CONSOL and its Affiliates may not solicit or hire any officer or employee of Noble or its Affiliates without first obtaining the prior written consent of Noble; provided that this prohibition shall not apply to offers of employment made by CONSOL or its Affiliates pursuant to a general solicitation of employment to the public or the industry.

2.14Conflict of Interest Policy

.  CONSOL Operator and Noble Operator shall develop and implement a policy regarding required disclosure of conflicts of interest that any officer, director or key employee of that Party or Affiliate of that Party may have with the interest of any of the Parties in connection with the conduct of Development Operations.

2.15Secondment.  From time to time after the Closing Date, each of CONSOL or Noble may second certain of their (or their Affiliates’) employees into the organization of the other Party pursuant to the terms of the CONSOL Secondment Agreement or the Noble Secondment Agreement, as applicable.  From time to time the Joint Development Committee may increase or decrease the number of secondees and change or modify their positions in the other Party’s organization.

ARTICLE III

JOINT DEVELOPMENT COMMITTEE;

DEVELOPMENT PLAN; ANNUAL PLANS AND BUDGETS

3.1Joint Development Committee.  

(a)To facilitate the creation, approval and amendment of the Development Plan and each Annual Plan and Budget, to approve or disapprove the other matters set forth in Section 3.1(h) and to provide (directly or through a subcommittee) advice and recommendations for the conduct of Development Operations and Area-Wide Operations, there is hereby established a joint development committee composed of representatives of CONSOL and Noble (the “Joint Development Committee”).  CONSOL shall be entitled to appoint three representatives to the Joint Development Committee and Noble shall be entitled to appoint three representatives to the Joint Development Committee.  The initial representatives to the Joint Development Committee for CONSOL shall be Randall M. Albert, M. Charles Hardoby and Stephen W. Johnson and the initial representatives to the Joint Development Committee for Noble shall be Barry Shelden, John Lewis and Aaron Carlson.  Each Party shall have the right to change its representatives at any time by giving notice of such change to the other Parties.

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(b)         The Joint Development Committee shall have only the powers and duties expressly ascribed to it in this Agreement.

(c)The representatives of a Party shall be authorized to represent and bind such Party with respect to any matter that is within the powers of the Joint Development Committee hereunder and is properly brought before the Joint Development Committee.  On all matters coming before the Joint Development Committee, the representatives of each of CONSOL and Noble shall have an aggregate vote equal to the Participating Interest of the Person (and its Affiliates) that appointed such representatives divided by the aggregate Participating Interests of all Persons (and their Affiliates) with representatives on the Joint Development Committee.  Any representative of a Party that is present or otherwise available to vote or consent on an action of the Joint Development Committee shall have the authority to cast all of the votes or consents allocated to all of the representatives of such Party.  In addition to the representatives, each Party may also send such advisors as it may deem appropriate to any Joint Development Committee meetings.

(d)Unless otherwise agreed to by the members of the Joint Development Committee, the Joint Development Committee shall meet once (and no more than once unless otherwise mutually agreed) per calendar month to review and discuss reports concerning the Development Plan, Annual Plan and Budget and the drilling schedule, relevant geoscience and other data relating to Subject Assets and such other matters as may be reasonably proposed by a Party Operator or members of the Joint Development Committee.  Meetings of the Joint Development Committee may be called by either CONSOL Operator or NBL Operator by giving notice to the members of the Joint Development Committee at least 5 days in advance of such meeting, along with a proposed agenda for such meeting (which shall include any items that a member of the Joint Development Committee or a Party Operator may request to have included on such agenda).  All meetings shall be held during normal business hours at a time and place agreed to by CONSOL Operator and NBL Operator, or failing to reach such agreement, meetings occurring in even numbered months shall be held in a location selected by NBL Operator and meetings held in odd numbered months shall be held in a location selected by CONSOL Operator; provided that members of the Joint Development Committee shall be allowed to participate telephonically (or, to the extent available, by video conference) in any such meeting.

(e)All decisions, approvals and other actions of the Joint Development Committee shall be decided by the affirmative vote of members of the Joint Development Committee holding collectively at least two-thirds of the votes eligible to vote on such proposals (which eligible votes, for the avoidance of doubt, shall not include any votes by the representatives of any Defaulting Party in accordance with Section 8.2(a)).  The Joint Development Committee shall keep a written record of all meetings and actions taken by the Joint Development Committee or any of its subcommittees.  To the fullest extent permitted by Law and notwithstanding any provision of this Agreement or any Associated Agreement to the contrary, no member of the Joint Development Committee, in his or her capacity as a member of the Joint Development Committee, shall have any duty, fiduciary or otherwise, to the Parties that did not appoint such member in connection with any act or omission by such member under this Agreement or any Associated Agreement.  Each Party agrees and acknowledges that each member of the Joint Development Committee shall be entitled to determine whether or not to take any action under this Agreement or any Associated Agreement by only considering the interests of the Party that designated such member to the Joint Development Committee and not the interests of the other Party.

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(f)In lieu of a meeting, any Party Operator may submit any proposal that is within the Joint Development Committee’s powers to approve or disapprove (including any amendment to the then existing Development Plan or Annual Plan and Budget) to the Joint Development Committee for a vote by written notice.  Such Party Operator shall provide a copy of any such proposal by written notice to the members of the Joint Development Committee.  The members of the Joint Development Committee shall communicate their votes on the proposal by written notice to the submitting Party Operator within 14 days after receipt of the proposal from such Party Operator.  If none of the representatives of a Party communicates their collective votes in a timely manner to such Party Operator, such representatives shall be deemed to have voted against such proposal.  Promptly following the expiration of the relevant time period, the submitting Party Operator shall give each member of the Joint Development Committee a confirmation notice stating the tabulation and results of the vote on such proposal.

(g)The Joint Development Committee may establish such subcommittees as it may deem appropriate, including a technical committee (whose purpose would be to advise the Party Operators with respect to the development of the Subject Assets, the coordination of Development Services, the selection of Third Party contractors, the terms of contracts for Development Operations and such other matters as the Joint Development Committee may direct).  The functions of such subcommittees shall be to serve in an advisory capacity only.  CONSOL and Noble shall each have the right to appoint an equal number of representatives to each subcommittee.  The Joint Development Committee is hereby deemed to have established a HSE Committee (the “HSE Committee”) whose purpose shall be to (A) review violations of applicable health, safety and environmental Law by a Party Operator and (B) collaborate with each Party Operator to develop additional health, safety and environmental policies and programs in its Operated Area.

(h)Notwithstanding anything else to the contrary in this Agreement, each of the following actions shall require the approval of the Joint Development Committee:

(i)   any amendment, modification or supplement to the Development Plan as provided in Section 3.2;

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(ii)the adoption of any Annual Plan and Budget and any amendment, modification or supplement to any Annual Plan and Budget as provided in Section 3.3;

(iii)any allocation of, and any amendment, modification or supplement to the allocation of, Development Services to be provided by the Party Operators as provided in Section 2.11;

(iv) any Affiliate Contract or a contract or agreement that contains a confidentiality obligation that would prevent such Party Operator from providing to the other Parties the data and reports required by Section 2.9(a), in each case, to be entered into by a Party Operator as provided in Section 2.12(c);

(v)subject to Section 2.11(d), approval or modification to the calculation of Services Costs or the amount of the Marketing Fee as provided in Section 2.11(d);

(vi)formation or dissolution of any subcommittee of the Joint Development Committee;

(vii)approval of, and any amendment, modification or supplement to any previously approved, operating guidelines to be followed by the Party Operators in conducting Development Operations or Area-Wide Operations;

(viii)any amendment, modification or supplement to the insurance standards required to be maintained by each of the Party Operators as provided in Section 2.8 or the reports to be provided by each of the Party Operators as provided in Section 2.9; and

(ix) any modification to the number of secondees or the positions of such secondees under either the CONSOL Secondment Agreement or the Noble Secondment Agreement as applicable.

(i)          Each Party will designate a representative (the “Party Representative”) who will be the primary, but not exclusive, day-to-day point of contact for the other Party with respect to safety, operational, technical, production, financial, land, permitting, marketing and other matters under this Agreement and any Applicable Operating Agreement.  Each Party Representative shall meet with the Party Representatives of the other Parties on a regular basis in person or by telephone to (i) discuss the status of such matters, (ii) identify and seek to resolve any issues that may arise with respect to such matters, and (iii) seek to enhance the safety, compliance, continuous improvement, production and costs of operations under this Agreement and any Applicable Operating Agreement.  The initial Party Representative of CONSOL shall be J. Michael Onifer and the initial Party Representative of Noble shall be Barry Shelden, each of whose contact information is set forth in Section 11.2; provided that any Party may change its Party Representative or the contact information for its Party Representative by giving notice to the other Parties in accordance with Section 11.2.

3.2Development Plan.  

(a)Attached hereto as Exhibit E is a multi-year development plan for Development Operations and Area-Wide Operations which the Parties currently anticipate to be conducted by the Party Operators through calendar year 2020 (as hereafter amended, modified or supplemented, the “Development Plan”).  The Joint Development Committee shall have the sole right to amend, modify and supplement the Development Plan.

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(b)Each Development Plan shall, to the extent possible, include:

(i)a forecast of the number of active rigs, the drilling days from spud to rig release including the expected time from rig release to first production, including estimates for stimulation/completion days and a forecast of all relevant capital and operational costs related to the foregoing;

(ii)the sequence of development of the applicable Operated Area, to the extent known;

(iii)a forecast of future production in four categories: (A) wells already on stream, (B) wells stimulated but not on stream, (C) wells drilled but not stimulated, and (D) wells to be drilled (wells on stream shall be forecasted on an individual performance basis (individual decline analysis) and all other wells shall be forecasted on an area basis based on expected performance for the relevant locations (pro-forma curves)).

(c)Commencing in 2017 or earlier if the Parties mutually agree, on or before August 31 of each calendar year, each Party Operator shall, with respect to its Operated Area, prepare and submit to the Joint Development Committee an amendment to the portion of the then existing Development Plan covering such Operated Area, which amendment sets forth the Development Operations and Area-Wide Operations reasonably expected to be carried out during the following three calendar years in such Operated Area.  Following distribution of all amendments to the Development Plan from each of the Party Operators, the representatives of the Joint Development Committee shall have 30 days to furnish to the other members of the Joint Development Committee any proposed revisions they desire to make to the proposed amendments to the Development Plan.  Promptly following the Joint Development Committee’s 30-day review process, the Joint Development Committee shall meet to consider the amendments to the Development Plan and any recommendations made with respect thereto by any member of the Joint Development Committee and approve or reject such amendments to the Development Plan and such recommendations.  In addition, the Joint Development Committee shall annually review the Development Plan in connection with its annual review and approval of the Annual Plan and Budget for the following calendar year and may from time to time amend or modify the Development Plan.

(d)For the avoidance of doubt, any reference in this Agreement to the Development Plan shall mean the Development Plan attached hereto as Exhibit E, as such Development Plan may be amended from time to time by the Joint Development Committee pursuant to the terms hereof.

3.3Annual Plan and Budgets.  

(a)Attached hereto as Exhibit F is an annual development plan and budget for Development Operations and Area-Wide Operations which the Parties currently anticipate to be conducted by the Party Operators through calendar year 2012(as hereafter amended, modified or supplemented, the “Annual Plan and Budget”).  Each Party Operator shall, with respect to its Operated Area, be responsible for conducting the Development Operations and Area-Wide Operations that are contemplated by, and in accordance with, the then applicable Annual Plan and Budget covering such Operated Area.  The Joint Development Committee shall have the sole right to amend, modify and supplement any Annual Plan and Budget.

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(b)        Other than with respect to calendar year 2011,on or before August 31 in the calendar year immediately preceding the relevant calendar year, each Party Operator shall, with respect to its Operated Area, prepare and submit to the Joint Development Committee that portion of a proposed Annual Plan and Budget for such relevant calendar year that pertains to such Operated Area.  In preparing such portion of such proposed Annual Plan and Budget, each Party Operator shall prepare such Annual Plan and Budget in a manner consistent with the then current Development Plan for such relevant calendar year.  Each such portion of such proposed Annual Plan and Budget submitted by a Party Operator shall contain at least the following with respect to the Operated Area of such Party Operator:

(i)    all Development Operations and Area-Wide Operations that are expected to be conducted by such Party Operator in its Operated Area during such calendar year;

(ii)all lease maintenance costs and expenditures required under the terms of existing Leases or existing Third Party contracts held by a Party Operator for the benefit of Development Operations and Area-Wide Operations (including each Party’s share thereof);

(iii)  itemized estimates of the Development Costs (including each Party’s share thereof including Carried Costs, separately stated, in the case of Noble) for Development Operations and Area-Wide Operations covered by the proposed Annual Plan and Budget by budget category containing sufficient detail, if available, to afford the ready identification of the nature, scope and duration of the activity in question;

(iv) the number of wells proposed to be drilled as part of the Development Operations and Area-Wide Operations during such calendar year, the areas for drilling groups of wells and proposed locations of such wells (to the extent reasonably ascertainable at the time such Annual Plan and Budget is proposed), and the estimated Development Costs (including each Party’s share thereof) associated therewith;

(v)estimates of the schedule pursuant to which the Parties’ Share of Development Costs for Development Operations and Area-Wide Operations included in the Annual Plan and Budget are anticipated to be incurred by the Parties;

(vi)estimated production for the applicable calendar year; and

(vii) any other information that a member of the Joint Development Committee reasonably requests to have included in such portion of such proposed Annual Plan and Budget.

Each Party Operator shall also provide to the Joint Development Committee any technical and interpretive data to support its proposed portion of the Annual Plan and Budget that any member of the Joint Development Committee may reasonably request.

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(c)Following distribution of the applicable portion of the proposed Annual Plan and Budget from each of the Party Operators, the representatives of the Joint Development Committee shall have 30 days to furnish to the other members of the Joint Development Committee any proposed revisions they desire to make to such proposed Annual Plan and Budget.  Promptly following the Joint Development Committee’s 30-day review process, the Joint Development Committee shall meet to consider the proposed Annual Plan and Budget and any recommendations made with respect thereto by any member of the Joint Development Committee and approve or reject the proposed Annual Plan and Budget and such recommendations.  In addition to annually submitting an Annual Plan and Budget to the Joint Development Committee, commencing in 2012, on or prior to June 30 of each calendar year, each Party Operator shall meet with the Joint Development Committee to review the then current Annual Plan and Budget to discuss any potential amendments or modifications to such Annual Plan and Budget for the remaining portion of such calendar year that may be proposed by the members of the Joint Development Committee or such Party Operator.

(d)Inclusion of an operation in an approved Annual Plan and Budget shall (unless and until such operation is removed from such Annual Plan and Budget pursuant to an amendment thereof):  (i) bind all Parties to participate in such operation, and no Party shall have the right to make any nonconsent election under an Applicable Operating Agreement with respect to such operation;and (ii) subject to an occurrence of a Force Majeure Event affecting such operation, authorize the applicable Party Operator to propose and conduct such operation for the account of all of the Parties under the relevant Applicable Operating Agreement (provided that, to the extent any Third Party is a party to such Applicable Operating Agreement, a Party Operator shall propose such operation to such Third Party in accordance with the terms of such Applicable Operating Agreement, though, for the avoidance of doubt, such Party Operator need not re-propose such operation to the Parties but the Party Operator shall provide any AFEs required by the terms of the Applicable Operating Agreement to such Party, which shall be for informational purposes only) or under this Agreement in the case of an Area-Wide Operation.

(e)Subject to a Force Majeure Event that affects such Development Operations, each Party Operator shall be responsible for proposing, and shall conduct, Development Operations relating to its Operated Area that are contemplated in an Annual Plan and Budget under the Applicable Operating Agreement; provided that, notwithstanding anything to the contrary in this Agreement, no Party Operator shall have any liability for failing to commence operations to drill all of the wells set forth in the applicable Annual Plan and Budget for any year for its Operated Area so long as such Party Operator proposes and commences the drilling of at least 95% of the wells contemplated to be drilled in an Annual Plan and Budget for its Operated Area for such year.  Other than as provided in the preceding sentence or as provided in Section 3.3(g), no Party or its Affiliates (including any Party Operator) shall propose Development Operations under any Applicable Operating Agreement.  Other than with respect to Development Operations proposed by a Third Party Operator or a Third Party under an Applicable Operating Agreement, each Party hereby authorizes each Party Operator on its behalf to provide such notices, make such elections and take such actions as may reasonably be required under any Applicable Operating Agreement or any other Associated Agreement to implement the operations and activities contemplated by an approved Annual Plan and Budget in such Party Operator’s Operated Area.  In the event that an operation that is included in an approved Annual Plan and Budget is proposed by a Party Operator under an Applicable Operating Agreement and a Third Party to such Applicable Operating Agreement non-consents such proposal, then (i) if the Working Interest of the non-consenting Third Party with respect to such proposed operation is less than 50%, each Party shall be required to participate for its full Working Interest share of the Working Interest of such non-consenting Third Party and the applicable Party Operator shall make such elections, on behalf of each Party, as is necessary to implement the same and (ii) if the Working Interest of the non-consenting Third Party with respect to such proposed operation is 50% or more, each Party shall have the right to elect to participate for its full Working Interest share of the Working Interest of such non-consenting Third Party in accordance with the terms of the Applicable Operating Agreement; provided that if any Party elects not to participate for its full Working Interest share of the Working Interest of such non-consenting Third Party, the Party Operator shall have the option to withdraw its proposal for such Development Operation (and if the Party Operator withdraws such proposal, such Development Operation shall be deemed to have been removed from the Annual Plan and Budget).

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(f)Each Party shall have the right to elect to participate or not to participate in any Development Operations proposed by a Third Party Operator or other Third Party pursuant to an Applicable Operating Agreement.  Any such Development Operation in which less than all of such Parties elect to participate as permitted hereunder may be conducted by the Parties electing to participate in such Development Operation under the terms of the relevant Applicable Operating Agreement.  Except as provided in Section 3.5 with respect to a Non-Consent Year, Noble’s obligation to pay the Carried Costs on behalf of CONSOL in accordance with Section 7.1 shall not apply to Development Operations proposed by a Third Party Operator or other Third Parties pursuant to an Applicable Operating Agreement unless Noble is a participating party in such Development Operation.

(g)        In the event that the Joint Development Committee fails to approve an Annual Plan and Budget for a particular calendar year on or prior to December 15 of the year preceding such particular calendar year (for purposes of this Section 3.3(g), such particular year for which the Joint Development Committee fails to approve an Annual Plan and Budget, the “relevant calendar year”),the Joint Development Committee shall be deemed to have approved an Annual Plan and Budget for such relevant calendar year that includes the following:  (i) all Development Operations and Area-Wide Operations that were previously commenced pursuant to an approved Annual Plan and Budget in a prior calendar year and not completed in such prior calendar year; (ii) the wells scheduled to be drilled during the relevant calendar year as set forth in the Development Plan, if any, and the associated Development Costs reasonably expected to be required to implement such Development Operations (regardless of estimated amounts set forth in the Development Plan); (iii) all actual Operating Expenses relating to the Subject Assets and incurred during the relevant calendar year; (iv) Services Costs and overhead rates and Marketing Fees (and related Third Party expenses) in accordance with Section 2.11 (provided that if the Services Costs or Marketing Fee (as applicable) are not then approved by the Joint Development Committee or determined by an expert pursuant to Section 2.11(d), then until so approved or determined, such cost or fee shall be equal to the Services Costs or Marketing Fee (as applicable) for the preceding calendar year); (v) existing payment commitments to Third Parties under Leases and binding contracts with respect to the Subject Assets; and (vi) taxes payable with respect to the Subject Assets by a Party Operator under the terms of any Applicable Operating Agreement.  In the event that any Development Operation scheduled to be performed during any calendar year is not commenced during such calendar year, then the Development Plan shall automatically be amended to add such Development Operation to the Development Plan to be conducted in the year following the year in which the Development Plan would have otherwise expired and the Development Plan shall be automatically extended for such period of time as is reasonably necessary for the applicable Party Operator to conduct such Development Operation.

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(h)Subject to Section 7.1 and subject to the applicable Annual Plan and Budget (as modified by Section 3.3(i)), each Party shall be responsible for such Party’s Share of Development Costs, including its Share of Development Costs for operations conducted by a Party Operator in accordance with Section 3.3(j).  Subject to Section 7.1, each Party shall pay or advance its Share of Development Costs in accordance with Section 7.2.  For the avoidance of doubt, no Party shall be obligated to participate in acquisitions of Leases included in an Annual Plan and Budget (other than Fill-In Interests), if any, but instead shall have the right but not the obligation to participate in such acquisitions pursuant to ARTICLE V.

(i)Approval by the Joint Development Committee of an Annual Plan and Budget shall constitute the Joint Development Committee’s deemed approval for any Party Operator to expend up to 20% in excess of the authorized amount applicable to its operations in its Operated Area within each Annual Plan and Budget category, not to exceed in the aggregate 10% of the aggregate amount applicable to such operations in such Annual Plan and Budget.  Each Party Operator shall promptly notify the Joint Development Committee of any expenditure made by it in the exercise of its rights pursuant to this Section 3.3(i).  The deemed approval levels set forth in this Section 3.3(i) shall be calculated with respect to the original amount of an Annual Plan and Budget or, once amended, the amended amount of the Annual Plan and Budget, provided that no expenditures incurred pursuant to Section 3.3(j) shall be deemed to be included in an approved Annual Plan and Budget for purposes of calculating the deemed approval levels pursuant to this Section 3.3(i), nor shall any such expenditures be considered to be amounts expended in excess of the authorized amount of any Annual Plan and Budget for purposes of calculating the deemed approval levels set forth in this Section 3.3(i).

(j)Notwithstanding anything to the contrary in this Agreement, each Party Operator is expressly authorized to make expenditures and incur liabilities when it reasonably determines that such expenditures or incurrences are necessary or advisable to deal with emergencies, including well blowouts, fires, oil spills, or any other similar event, which may endanger property, lives, or the environment.  Each Party Operator shall as soon as practicable report to the Parties the nature of any such emergency which arises, the measures it intends to take or has taken in respect of such emergency and the estimated related expenditures.

(k)To the extent reasonably within the control of any Party Operator conducting any Development Operation and subject to any Force Majeure Event affecting such Development Operation, each Development Operation shall be conducted at approximately the time prescribed in the applicable Annual Plan and Budget.

(l)For the avoidance of doubt, any reference in this Agreement to an Annual Plan and Budget in connection with any operations, rights or obligations shall mean an Annual Plan and Budget that is approved or deemed to have been approved by the Joint Development Committee, including all amendments to such Annual Plan and Budgets that are approved (or deemed approved) by the Joint Development Committee pursuant to the terms hereof.

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3.4AFEs.  Prior to any Party Operator (a) spudding any well included in the Annual Plan and Budget, or (b) making any expenditure that is included in the Annual Plan and Budget and that is estimated to cost in excess of $500,000, such Party Operator shall submit an AFE to the Parties covering such well or expenditure for information purposes only.

3.5Non-Consent Years.  Notwithstanding any other provision in this Agreement to the contrary, subject and pursuant to the terms and provisions of this Section 3.5, each of Noble and CONSOL shall have the right (the “Non-Consent Right”) to elect to non-consent all (but not less than all) wells to be drilled in the Development Area under the Annual Plan and Budget deemed approved pursuant to Section 3.3(g) during a Non-Consent Year in the event that the Joint Development Committee fails to approve an Annual Plan and Budget for such Non-Consent Year.

(a)Non-Consent Right.

(i)Commencing in calendar year 2013, on or prior to December 20 of any calendar year, either Noble or CONSOL may exercise its Non-Consent Right with respect to the following calendar year (such following calendar year, the “Non-Consent Year”) by giving written notice of the same to all other Parties.  For clarity, no calendar year prior to 2014 can be a Non-Consent Year.  For clarity, a Party electing to exercise the Non-Consent Right shall be entitled to elect to participate in any wells that are not included in the Annual Plan and Budget for the Non-Consent Year (being the Annual Plan and Budget deemed approved pursuant to Section 3.3(g)) proposed to be drilled by a Third Party Operator or Third Party under any Applicable Operating Agreement in the Non-Consent Year on a well-by-well basis.

(ii)If either Noble or CONSOL (the “Non-Consenting Party”) exercises its Non-Consent Right for a Non-Consent Year, then (A) such Non-Consenting Party shall not be entitled or obligated to conduct, propose or otherwise participate in any wells included in the Annual Plan and Budget for the Non-Consent Year (being the Annual Plan and Budget deemed approved pursuant to Section 3.3(g)) for which drilling operations are commenced in the Development Area during the Non-Consent Year and (B) the other Party (the “Electing Party”) shall have the right (but not the obligation, notwithstanding anything herein to the contrary) to propose and drill each of the wells scheduled pursuant to the Development Plan to be drilled during such Non-Consent Year (such wells proposed where drilling operations are commenced, the “Non-Consent Wells”).  For clarity, the Electing Party shall not be required to drill any or all of the Non-Consent Wells and it can choose which Non-Consent Well(s) to drill during such Non-Consent Year and when such Non-Consent Wells should be drilled.

(iii)The Electing Party will have the right to become operator with respect to any Non-Consent Wells commenced during the Non-Consent Year (including becoming operator with respect to any Non-Consent Wells commenced in the Non-Consenting Party’s Operated Area).  The Non-Consenting Party will use commercially reasonable efforts to assist the Electing Party to become operator with respect to such Non-Consent Wells.  The Non-Consenting Party will also serve as a contract operator for the Electing Party, if the Electing Party is unable to takeover as operator with respect to any Non-Consent Well where the Non-Consenting Party is already designated as operator.  The Non-Consenting Party will transfer to the Electing Party those agreements that the Electing Party needs to operate such Non-Consent Wells or, if such agreements are not transferable, hold such agreements for the benefit of the Electing Party.

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(iv) With respect to each Non-Consent Well that is commenced during the Non-Consent Year, the non-consent penalties set forth in the Applicable Operating Agreement for such Non-Consent Well shall be applicable to the Non-Consenting Party.

(v)The Non-Consenting Party shall be solely responsible for any payment requirements (the “Non-Terminable Contract Obligations”) resulting from the Parties not satisfying their obligations under any non-terminable (without fee payment) contract relating to the Subject Assets during the Non-Consent Year (the “Non-Terminable Contracts”); provided that if in connection with its Development Operations during the Non-Consent Year the Electing Party does not actually incur at least an amount equal to 67% of the actual costs and expenses relating to drilling and completing wells that such Electing Party was projected to incur (after taking into account Noble’s obligation to pay the Carried Costs for such wells) pursuant to the Annual Plan and Budget for such Non-Consent Year (being the Annual Plan and Budget deemed approved pursuant to Section 3.3(g)), then, within 15 days following the end of such Non-Consent Year, the Electing Party shall reimburse the Non-Consent Party for its Participating Interest share of all actual amounts paid by the Non-Consenting Party with respect to the Non-Terminable Contract Obligations and shall thereafter be responsible for paying its Participating Interest share of all Non-Terminable Contract Obligations.  During a Non-Consent Year, the Parties shall each use their commercially reasonable efforts to mitigate any payment requirements under any Non-Terminable Contracts at the sole cost and expense of the Non-Consent Party; provided that the Electing Party shall not be required to conduct any Development Operations to satisfy its obligations to mitigate such payment requirements.

(vi)In the event that any wells scheduled pursuant to the Development Plan for such Non-Consent Year are not Non-Consent Wells, then the Development Plan shall automatically be amended to add such wells that are not Non-Consent Wells to the Development Plan to be conducted in the year following the year in which the Development Plan would have otherwise expired and the Development Plan shall be automatically extended for such period of time as is reasonably necessary for the applicable Party Operator to conduct such Development Operation.

(b)Carried Costs.  If Noble is the Non-Consenting Party, then:

(i)On or prior to January 1 of the Non-Consent Year, Noble must advance to the Tax Partnership Account designated and controlled (subject to the obligation of CONSOL to withdraw such funds only to pay for specific costs of the Non-Consent Year’s drilling program) by CONSOL (the “Non-Consent Account”) the total amount of the Carried Costs that are contemplated by the Development Plan for the Non-Consent Year (the “Carried Costs Amount”), which funds may thereafter be solely utilized for the purposes described in Section 3.5(b)(ii) or 3.5(c)(ii).  The Parties acknowledge that such funds in the Non-Consent Account discharge Noble’s obligations to pay Carried Costs during such Non-Consent Year.  Notwithstanding the fact that Noble has no right to the return of such funds once they are paid into such Non-Consent Account, interest in such funds shall be allocated and distributed 50% to CONSOL and 50% to Noble.  Except for payment under this Section 3.5(b) of the Carried Costs Amount, Noble shall have no other obligation to pay any Carried Costs during the Non-Consent Year.

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(ii)  With respect to any Non-Consent Well or any other well proposed by a Third Party under an Applicable Operating Agreement that is actually spudded during the Non-Consent Year in which CONSOL participates, notwithstanding anything in Section 7.1(b) to the contrary, CONSOL shall pay out of the Non-Consent Account (until expended) two-thirds of CONSOL’s Working Interest share of all Drilling and Completion Costs with respect to such wells (and all such Drilling and Completion Costs that are funded pursuant to this Section 3.5(b)(ii) shall be deemed to be Carried Costs for all purposes hereunder).

(iii)The provisions of Section 7.1(d) shall not be applicable during any Non-Consent Year.

(c)Following a Non-Consent Year.

(i)To the extent that any Non-Consent Wells were commenced by the Electing Party in the Operated Area of the Non-Consenting Party, then the Non-Consenting Party will take over as operator with respect to each such Non-Consent Well as promptly as practicable following the later to occur of (A) the end of such Non-Consent Year and (B) the date upon which all drilling and completion operations with respect to such Non-Consent Well have been completed, and the Electing Party will use commercially reasonable efforts to assist the Non-Consenting Party to become operator with respect to each such Non-Consent Well.

(ii)  If any portion of the Carried Costs Amount is not fully used to pay the costs set forth in Section 3.5(b) during the Non-Consent Year, then following such Non-Consent Year the funds remaining in the Non-Consent Account shall be used to satisfy Noble’s obligation to pay Carried Costs and Noble shall not have any obligation to pay any additional amounts in respect of the Carried Costs incurred in following years until all such funds have been so expended.

(d)Limited Right.  Neither Noble nor CONSOL may exercise its Non-Consent Right if such Party also exercised its Non-Consent Right with respect to the calendar year immediately preceding the Non-Consent Year.  A Party shall only be permitted to exercise the Non-Consent Right twice during the term of this Agreement.

ARTICLE IV

TRANSFER RESTRICTIONS

4.1Restrictions on Transfer.  

(a)Transfers by CONSOL and its Affiliates.

(i)   Subject to Sections 4.1(c) through (f), 4.2, 4.3 and 4.4, prior to the thirty-month anniversary of the Closing Date, CONSOL shall not, and shall cause any of its Affiliates holding any Joint Development Interest not to, Transfer all or any portion of their Joint Development Interests (other than a Transfer of an Immaterial Interest) or undergo a Change in Control without the prior written consent of Noble (which may be granted or withheld in Noble’s sole discretion).

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(ii)Subject to Sections 4.1(c) through (f), 4.2, 4.3 and 4.4, from and after the thirty-month anniversary of the Closing Date, CONSOL and its Affiliates holding any Joint Development Interest shall be permitted to Transfer all or any undivided portion of their Joint Development Interests to any Person that as of the date of such Transfer has the financial ability to perform the future payment obligations hereunder and under the Associated Agreements with respect thereto, or undergo a Change in Control; provided that upon a Transfer where CONSOL intends that the transferee will become CONSOL Operator or upon such a Change in Control, Noble Operator shall be entitled to take over as CONSOL Operator under this Agreement and each Applicable Operating Agreement unless such transferee establishes to Noble’s reasonable satisfaction that it has the technical ability and experience to serve as CONSOL Operator.

(b)Transfers by Noble and its Affiliates.

(i)Subject to Sections 4.1(c) through (f), 4.2, 4.3 and 4.4,prior to the later to occur of: (A) the thirty-month anniversary of the Closing Date and (B) the Carry Termination Event Noble shall not, and shall cause any of its Affiliates holding any Joint Development Interest not to, Transfer all or any portion of their Joint Development Interests (other than a Transfer of an Immaterial Interest) and Noble shall not permit any of its Affiliates holding any Joint Development Interest to undergo a Change in Control unless the prior written consent of CONSOL to such otherwise prohibited Transfer or Change in Control (which may be granted or withheld in CONSOL’s sole discretion) is first obtained.

(ii)Subject to Sections 4.1(c) through (f), 4.2, 4.3 and 4.4, from and after the later to occur of: (A) the thirty-month anniversary of the Closing Date and (B) the Carry Termination Event, Noble and its Affiliates holding any Joint Development Interest shall be permitted to Transfer all or any undivided portion of their Joint Development Interests to any Person that as of the date of such Transfer has the financial ability to perform the future payment obligations hereunder and under the Associated Agreements with respect thereto, or undergo a Change in Control; provided that upon a Transfer where Noble intends that the transferee will become Noble Operator or upon such a Change in Control, CONSOL Operator shall be entitled to take over as Noble Operator under this Agreement and each Applicable Operating Agreement unless such transferee establishes to CONSOL’s reasonable satisfaction that it has the technical ability and experience to serve as Noble Operator.

(c)         Permitted Transfers.  Notwithstanding the restrictions on Transfer set forth in Sections 4.1(a)or 4.1(b), but subject to the requirements of Sections 4.1(e) and 4.2, (i) any Party and its Affiliates may Transfer all or an undivided portion of their Joint Development Interests (including the Tax Partnership) to any Affiliate of any Party (provided such Affiliate will be bound by all the provisions hereof as if it was the original party hereto), (ii) CONSOL and its Affiliates may encumber all or a portion of their Joint Development Interests solely for financing purposes and (iii) Noble and its Affiliates may encumber all or a portion of their Joint Development Interests that have become Developed Assets solely for financing purposes; provided, however, that no such Transfer of any Joint Development Interests as permitted under this Section 4.1(c) shall relieve such transferring Person of any of its or its Affiliates’ obligations under this Agreement or, unless specifically provided otherwise, any Associated Agreement (whether accruing prior to or after the date of such Transfer).  Notwithstanding Sections 4.1(a), 4.1(b) or 4.1(d) to the contrary, any Transfer by a Party to an Affiliate of such Party shall be deemed pursuant to and subject to this Section 4.1(c).

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(d)        Liability of Transferor/Transferee. No Transfer of any Joint Development Interests as permitted under Section 4.1(a)or4.1(b) shall relieve the transferring Person of any of its or its Affiliates’ obligations under this Agreement or any Associated Agreement except to the extent of obligations incurred from and after such Transfer under this Agreement and all Associated Agreements to the extent related to the interests transferred to such Person, which obligations such transferring Person shall be released from to the extent assumed by such transferee unless, in the case of the Associated Agreements, otherwise specifically provided therein.

(e)Transfers by Defaulting Parties.  No Defaulting Party may, and any Defaulting Party shall cause its Affiliates not to, Transfer all or any part of its Joint Development Interest or undergo a Change in Control unless and until the Total Amount in Default is paid by such Defaulting Party or its transferee or any other Person on behalf of such Defaulting Party and then further subject to compliance with the other provisions of this ARTICLE IV.

(f)Transfers in Violation of this ARTICLE IV.  Any Transfer or attempted Transfer or Change in Control in violation of this ARTICLE IV shall be, and is hereby declared, null and void ab initio.

4.2       Documentation for Transfers.  Any Transfer (other than a Transfer of an Immaterial Interest or a Transfer permitted under Section 4.1(c)(i)) by any Party that is otherwise permitted pursuant to Section 4.1 shall not be effective unless and until the other Parties have received a document executed by both the transferring Party (or its legal representative) and the permitted transferee (or its legal representative) that includes: (a) the notice address of the permitted transferee; (b) such permitted transferee’s express agreement in writing to (i) be bound by all of the terms and conditions of this Agreement and any applicable Associated Agreement and (ii) assume an undivided interest (in an amount equal to the Participating Interest being Transferred to the permitted transferee) of all of the liabilities and obligations of the transferring Party under this Agreement and any applicable Associated Agreements (which may be limited to the liabilities and obligations arising from and after the effective time of the assignment); (c) a description of the Participating Interests in the Subject Assets being Transferred by the transferring Party and the permitted transferee immediately following the Transfer; and (d) representations and warranties to the other Parties from both the transferring Party and the permitted transferee that the Transfer was made in accordance with applicable Law (including state and federal securities Law) and the terms and conditions of this Agreement and any applicable Associated Agreements.  Each permitted Transfer shall be effective against the other Parties as of the first Business Day of the calendar month immediately following the other Parties’ receipt of the document required by this Section 4.2.

4.3Maintenance of Uniform Interest.  For the purpose of maintaining uniformity of ownership in the Development Area as among the Parties, from and after the Closing Date during the term of this Agreement, no Party shall Transfer any portion of its Joint Development Interest (other than a Transfer of an Immaterial Interest or a Transfer permitted under Section 4.1(c)(i)) unless such Transfer covers the entirety of such Party’s Joint Development Interest, or an undivided percentage thereof.  Any Transfer of an undivided portion of a Party’s Joint Development Interest shall also include a proportionate share of the transferring Party’s rights and obligations in and under this Agreement and any applicable Associated Agreement.

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4.4Right of First Offer.

(a)Subject to Section 4.1, if a Party or any of its Affiliates (each such Person, a “Transferor”) desires to Transfer to a Third Party (either directly or indirectly through a Change in Control but excluding Transfers of the types described in Section 4.1(c) and a Transfer of an Immaterial Interest) all or any portion of the Transferor’s Joint Development Interest, the Transferor shall give to the other Parties (the “ROFO Parties”) written notice (“ROFO Notice”) stating the Transferor’s desire to effect such Transfer, the Joint Development Interest to be Transferred (the “Offered Interest”) and the terms and conditions on which the Transferor proposes to Transfer the Offered Interest; provided, however, that if the consideration set forth in such ROFO Notice contemplates any non-cash consideration, the ROFO Parties shall be entitled to pay in lieu of such non-cash consideration, cash in an amount equal to the Fair Market Value of such non-cash consideration unless the ROFO Parties and Transferor agree to some other form of consideration.  The ROFO Parties shall have the right but not the obligation to elect to acquire such Offered Interest on the terms and conditions set forth in the ROFO Notice.  The ROFO Notice shall constitute a binding offer (the “ROFO Offer”) by the Transferor to Transfer to the ROFO Parties the Offered Interest at the price and upon the terms specified in the ROFO Notice and such offer shall be irrevocable for 30 days following receipt by the ROFO Parties.  Any ROFO Party may accept such ROFO Offer and acquire all but not less than all of the Offered Interest by giving written notice of the same to the Transferor within such 30-day period; provided that if more than one ROFO Party accepts such ROFO Offer then, unless such ROFO Parties otherwise agree, each ROFO Party shall acquire a pro rata portion of the Offered Interest based on the relative Participating Interests of each accepting ROFO Party.  The failure by any ROFO Party to so notify the Transferor within such 30-day period shall be deemed an election by such ROFO Party not to accept such ROFO Offer.

(b)If one or more ROFO Parties accepts the ROFO Offer, then the Transferor and such accepting ROFO Parties shall cooperate together to consummate the Transfer of the Offered Interest to the ROFO Parties as promptly as practicable following such acceptance.

(c)         If none of the ROFO Parties accepts the ROFO Offer, then the Transferor may Transfer all but not less than all of the Offered Interest at any time within 180 days following the end of the 30-day period that the ROFO Parties had to accept the ROFO Offer.  Any such Transfer shall be at a price not less than the price set forth in the ROFO Notice and on such other terms and conditions not more favorable in any material respect to the acquiring party than those specified in the ROFO Notice.  If the Transferor does not affect such Transfer within such 180-day period, the Transfer of the Offered Interest shall again become subject to the right of first offer set forth in this Section 4.4.

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ARTICLE V

AREA OF MUTUAL INTEREST

5.1Creation of Area of Mutual Interest.  Subject to Section 10.2(5), the Parties agree that for a period beginning on the Closing Date and ending on the 25th anniversary thereof, the Development Area shall be an area of mutual interest as described in Exhibit A-1.  For clarity, in general this Agreement only applies to Subject Assets covering depths within the Marcellus Formation, but with respect to any Fill-In Interest or Option Interest to be acquired pursuant to this ARTICLE V, such Fill-In Interest and/or Option Interest shall include all depths that have been or are being acquired by the acquiring Party or Acquiring Party, as applicable.  In the event a Fill-In Interest or an Option Interest is acquired pursuant to this ARTICLE V, only the portion of such Fill-In Interest or Option Interest that covers depths within the Marcellus Formation shall thereafter be subject to the terms and provisions of this Agreement and the depths outside the Marcellus Formation shall not be subject to the terms of this Agreement.  Further for clarity, if a Party or any of its Affiliates, directly or indirectly, acquires a Lease or related asset in the Development Area that does not cover any depths within the Marcellus Formation, then such acquisition shall not be subject to the terms of this ARTICLE V or the other terms of this Agreement.

5.2Acquisition of Fill-In Interests for Drilling Units in the Development Area.  Although it is anticipated that only a Party Operator will acquire Fill-In Interests in such Party Operator’s Operated Area, if, after the date hereof, any Party or any of its Affiliates, directly or indirectly (including by merger, acquisition of equity or otherwise), acquires any additional Leases and related assets within the Development Area covering at least depths within the Marcellus Formation that completes or increases their Working Interest in a Drilling Unit covering existing Subject Assets (a “Fill-In Interest”), then such Party will promptly provide written notice to the other Parties of such acquisition, including the material terms and conditions of such acquisition (excluding any terms dealing solely with assets not within the Development Area).  Within 30 days after such notice is delivered to the other Parties, such other Parties shall purchase their individual Participating Interest share of such Fill-In Interests from such acquiring Party or its Affiliate.  At the closing of such purchase, (a) each purchasing Party will be required to (i) except for obligations assumed pursuant to clause (ii) below, pay in cash to the acquiring Party (or its Affiliate) its Participating Interest share of the Acquisition Costs that the acquiring Party (or its Affiliate) incurred in acquiring such Fill-In Interest, together with interest thereon at the Agreed Rate from the date on which the acquiring Party (or its Affiliate) acquired the Fill-In Interest to the date of such payment and (ii) if the Fill-In Interest is acquired pursuant to a farmout agreement or similar agreement requiring the drilling of a well or the performance of other similar obligations, subject to Section 7.1, assume its Participating Interest share of all obligations required to be performed by the applicable acquiring Party or its Affiliates to earn such Fill-In Interest and (b) the acquiring Party (or its Affiliate) shall deliver to such other Parties their respective individual Participating Interest share of the Fill-In Interests on the same terms and conditions as the acquiring Party (or its Affiliate) acquired the Fill-In Interests (with such changes as may be necessitated by the differences in the parties, the transfer of only the Fill-In Interests and, if applicable, the payment of the Fair Market Value in lieu of other consideration or the apportionment of rights from a Package Sale); provided that, except for a special warranty of title covering the acquiring Party’s (or its Affiliate’s) period of ownership, the acquiring Party shall in no event have any liability to the other Parties for representations, warranties or indemnities with respect to the Fill-In Interest in excess of the Parties’ Participating Interest shares of amounts that the acquiring Party (or its Affiliate) actually recovers from the Person from whom it acquired the Fill-In Interest.  The costs of recording the assignment of each Party’s interest in Fill-In Interests in the real property records of the appropriate county or township as applicable shall be chargeable to the joint account under the Applicable Operating Agreement.

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5.3Acquisition of Option Interests in the Development Area.  

(a)If, after the date hereof, a Party or any of its Affiliates, directly or indirectly (including by merger, acquisition of equity or otherwise), acquires or seeks to acquire any additional Leases and related assets within the Development Area covering at least depths within the Marcellus Formation (other than any Fill-In Interest) (such Person, the “Acquiring Party”), then the Acquiring Party (i) will in the case of any acquisition that has already taken place and (ii) may in the case of any proposed acquisition promptly provide written notice (the “Acquisition Notice”) to the other Parties (the “Non-Acquiring Parties”) of such acquisition or proposed acquisition, as applicable, including the material terms and conditions (excluding any terms dealing solely with assets not within the Development Area) of such acquisition and a description of the Leases and related assets that are being or has been acquired (the “Option Interests”).  Within 30 days after such Acquisition Notice is delivered to the Non-Acquiring Parties (the “Election Period”), the Non-Acquiring Parties will have the option to acquire (i) all, but not less than all, of their Participating Interest share of such Option Interests and (ii) all, but not less than all, of their Participating Interest share of any portion of the Option Interests that any Non-Acquiring Parties elect not to acquire in accordance with this Section 5.3(a), in each case, on the same terms and conditions on which the Acquiring Party acquired or will acquire the Option Interests by providing written notice of such election to the Acquiring Party.  If a Non-Acquiring Party fails to exercise its option within such 30-day period, such Non-Acquiring Party shall be deemed to have made an election not to participate.

(b)If any of the Non-Acquiring Parties elect to participate in accordance with Section 5.3(a), such Non-Acquiring Parties shall purchase their share of the Option Interests from the Acquiring Party within 30 days of its election in the case of any acquisition that has already taken place, or in the case of a proposed acquisition, at the closing of such acquisition (or as promptly as practicable thereafter as the Acquiring Party may reasonably determine) (such date, the “Payment Date”).  At the closing of such purchase (an “AMI Purchase Date”), (i) such Non-Acquiring Parties will be required to (A) except for obligations assumed pursuant to clause (B) below, pay to the Acquiring Party (or to such other Person as the Acquiring Party may designate) its share of the Acquisition Costs in proportion to the interest in the Option Interests it is acquiring in cash, together with interest thereon at the Agreed Rate from the date on which the Acquiring Party acquired the Option Interests (if earlier than the Payment Date) to the Payment Date and (B) if the Option Interest is acquired pursuant to a farmout agreement or similar agreement requiring the drilling of a well or the performance of other similar obligations, subject to Section 7.1, assume its share of all obligations required to be performed by the Acquiring Party or its Affiliates to earn such Option Interest and (ii) the Acquiring Party shall deliver to such Non-Acquiring Parties their respective interests in the Option Interests on the same terms and conditions as such Acquiring Party is or has acquired its interest in the Option Interests (with such changes as may be necessitated by the differences in the parties, the transfer of only the Option Interests and, if applicable, the payment of the Fair Market Value in lieu of other consideration or the apportionment of rights from a Package Sale); provided that, except for a special warranty of title covering the Acquiring Party’s period of ownership, the Acquiring Party shall in no event have any liability to the Non-Acquiring Parties for representations, warranties or indemnities with respect to the Option Interest in excess of the Non-Acquiring Parties’ Participating Interest shares of amounts that the Acquiring Party actually recovers from the Person from whom it acquired the Option Interest.  Each Non-Acquiring Party will be responsible for and will pay the costs of recording the assignment of its interest in the Option Interests in the real property records of the appropriate county or township as applicable.

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(c)         If all of the Non-Acquiring Parties elect not to participate in accordance with Section 5.3(a), the Acquiring Party will retain 100% of the Option Interests and such Option Interests will be excluded from the Development Area and will not be governed by the terms of this Agreement or any Applicable Operating Agreement.

(d)         If an Acquiring Party acquires or seeks to acquire any Lease that lies partially within and partially outside of the Development Area, then the entirety of such Lease shall be deemed to be an Option Interest and if one or more Non-Acquiring Parties elects to acquire an interest in such Lease, the Development Area (and the applicable Operated Area to which such Lease relates) shall automatically be amended to include the entirety of such Lease.  The Parties shall memorialize in writing any such amendment to the Development Area and any Operated Area.

(e)For avoidance of doubt, the Additional Interests shall be treated as “Fill-In Interests” or “Option Interests,” as applicable, for purposes of this Agreement in accordance with the Acquisition Agreement, and CONSOL shall offer the Additional Interests to Noble within 15 days following the Closing Date in accordance with the terms of this Section 5.3.

(f)Each Party shall cause its Affiliates to comply with the terms of this ARTICLE V.

5.4Exceptions.

(a)Notwithstanding anything in this ARTICLE V to the contrary, the provisions of this ARTICLE V shall not apply to (i) any acquisition of a Lease or related asset by CONSOL or its Affiliates for the purpose of curing a title defect in accordance with the Acquisition Agreement or (ii) any indirect acquisition by a Party or its Affiliates of any Lease and related assets by the acquisition of an entity having at least 75% (by Fair Market Value) of its assets outside of the Development Area; provided that such indirect acquisition of such Lease(s) and related assets is not made with the intention of circumventing the provisions of this ARTICLE V.

(b)Notwithstanding anything in this ARTICLE V to the contrary, in the event that, during the period in which the provisions of this ARTICLE V are applicable to the Parties, a Party or its Affiliates acquires more than $50,000,000 (by Fair Market Value) of Option Interests, in a single transaction or series of related transactions, in exchange for cash or assets and the Acquiring Party specifies in its Acquisition Notice that such Acquiring Party is acquiring such Option Interest through a like kind exchange (as provided for under Section 1031 of the Internal Revenue Code of 1986, as amended and the regulations thereto), then the following provisions of this Section 5.4(b) shall also apply to such acquisition (and to the extent of any conflict between Section 3.5 and this Section 5.4(b), this Section 5.4(b) shall control):

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(i)The Election Period shall not begin until the Acquiring Party provides the Non-Acquiring Parties with written notice in accordance with this Section 5.4(b)(i), which the Acquiring Party shall be required to provide to the Non-Acquiring Parties within 5 Business Days following the end of the 3-month anniversary of the date on which such Party and/or Affiliate completes such like kind exchange.  Such notice from the Acquiring Party to the Non-Acquiring Parties shall include (A) the material terms and conditions (excluding any terms dealing solely with assets not within the Development Area) of such acquisition, (B) a description of the Option Interests, (C) a description of all drilling, completing, deepening, sidetracking, reworking and plugging and abandoning operations that have been conducted with respect to the Option Interests since the Acquiring Party acquired such Option Interests or are contemplated to be completed through the end of the Election Period, (D) copies of all written notices of claims made by or against the Acquiring Party relating to the Option Interests, (E) copies of all environmental assessment in the possession of or under the control of the Acquiring Party relating to the Option Interests and (F) an estimated preliminary settlement statement reflecting the Acquisition Costs of the Option Interests (as adjusted pursuant to Section 5.4(b)(ii).

(ii)If the Non-Acquiring Parties elect to participate in accordance with Section 5.3(a), then on the AMI Purchase Date, (A) such Non-Acquiring Parties will be required to pay to the Acquiring Party (or to such other Person as the Acquiring Party may designate) its share of the Acquisition Costs in proportion to the interest in such Option Interests it is acquiring in cash (with such adjustments to such Acquisition Costs (including capital expenditures and lease operating expenses) as may be necessitated by the fact that development and other operations may have occurred with respect to such Option Interests since the date such Option Interests were acquired by the Acquiring Party) and (B) the Acquiring Party shall deliver to such Non-Acquiring Parties their respective interests in such Option Interests with special warranty of title by, through and under the Acquiring Party and otherwise on the same terms and conditions as such Acquiring Party is or has acquired its interest in such Option Interests (with such changes as may be necessitated by the differences in the parties, the fact that operations have occurred with respect to such Option Interests, the transfer of only such Option Interests and, if applicable, the payment of the Fair Market Value in lieu of other consideration or the apportionment of rights from a Package Sale).

(iii)  The Non-Acquiring Parties shall not be charged any interest on the Acquisition Costs.

(iv)  Beginning on the date that such Option Interests are acquired by the Acquiring Party until the earlier of (A) the AMI Purchase Date and (B) the date upon which the Non-Acquiring Party elects (or is deemed to have elected) not to participate (the “Restricted Period”), each Non-Acquiring Party shall be entitled to receive the same reports and information relating to, and shall have the same access to, such Option Interests as if such Option Interests were Subject Assets hereunder and such Non-Acquiring Party held an interest therein (including all AFEs required by Section 3.4).

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(v)   During the Restricted Period, except as permitted under this ARTICLE V, the Acquiring Party shall not, and shall cause its Affiliates not to, Transfer all or any portion of the Option Interests to any Person.

(vi)During the Restricted Period, the Acquiring Party shall, and shall cause its Affiliates to, consult with the Non-Acquiring Party prior to conducting any drilling operations on the Option Interests (other than drilling operations that have been commenced prior to the Acquiring Party’s acquisition of the Option Interests).

(vii) For clarity, the “Option Interests” as used in this Section 5.4(b) shall include any improvements made to, or equipment or other property acquired by, such Acquiring Party in connection with any operations conducted upon the Leases included in the Option Interests after the date the original Option Interests are acquired by such Acquiring Party.

(viii)Unless and until the AMI Purchase Date occurs, only the Acquiring Party (and not the Non-Acquiring Parties) shall be entitled to the benefits and burdens of the Option Interests.

ARTICLE VI

TAXES

6.1Tax Partnership.  The Parties intend and expect that the transactions contemplated by the Acquisition Agreement, this Agreement and the Associated Agreements, taken together, will be treated, for purposes of federal income taxation and for purposes of certain state income tax laws that incorporate or follow federal income tax principles (“Tax Purposes”), as resulting in the creation of a partnership (the “Tax Partnership”) in which Noble and CONSOL are treated as partners.  Accordingly, for Tax Purposes, (a) the Tax Partnership will be treated as (i) holding (A) the Parties’ interests in Oil and Gas Assets, (B) any other Subject Assets and (C) any cash held in any account identified or otherwise treated as being an asset of the Tax Partnership resulting from production or contribution pursuant to the Asset Acquisition Agreement or this Agreement and (ii) engaging in all activities of the Parties with respect to the Subject Assets, (b) CONSOL will be treated as contributing to the Tax Partnership at Closing of the Oil and Gas Assets and its undertaking to fund, when due, the costs and expenses allocable to it under this Agreement in exchange for an interest in the Tax Partnership; (c) Noble will be treated as contributing to the Tax Partnership at Closing (by deposit into the Cost Reconciliation Account) the Closing Cash Payment (as adjusted), its undertaking to fund, when due, the Post Closing Cash Payments and the costs and expenses allocable to it under this Agreement (including the Carried Costs, any Carried Costs Amount and any Carried Costs Balance Payments) in exchange for an interest in the Tax Partnership; (d) upon any withdrawal by CONSOL (as and to the extent permitted under Section 7.6 hereof) of the Total Cost Sharing Payments from the Cost Reconciliation Account, CONSOL will be treated as receiving distributions from the Tax Partnership of the withdrawn amounts (i) as a reimbursement of CONSOL’s preformation expenditures with respect to the Oil and Gas Assets within the meaning of Treasury Regulations Section 1.707-4(d) to the extent applicable and (ii) in a transaction subject to treatment under Section 707(a) of the Internal Revenue Code of 1986, as amended, and its implementing Treasury Regulations as in part a sale, and in part a contribution, of the Oil and Gas Assets to the Tax Partnership to the extent that Treasury Regulations Section 1.707-4(d) is inapplicable, and (e) from and after its commencement, the Tax Partnership will be treated as realizing all items of income or gain and incurring all items of cost or expense attributable to the ownership, operation or disposition of the Subject Assets, notwithstanding that such items are realized, paid or incurred by the Parties individually. The governing terms and conditions of the Tax Partnership are set forth in Exhibit G hereto.

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6.2Tax Information.  Each Party Operator shall provide the TRP (as defined in the Tax Partnership Agreement) or each Party, as applicable, in a timely manner and at each Party’s sole expense, with information with respect to Development Operations and Area-Wide Operations conducted by such Party Operator as the TRP or such Party may reasonably request for preparation of its tax returns, responding to any audit or tax proceeding with respect to Asset Taxes or complying with the reporting obligations in the Tax Partnership Agreement.

6.3Responsibility for Taxes.  Each Party shall be responsible for reporting and discharging its own tax measured by the income of the Party and the satisfaction of such Party’s share of all contract obligations under this Agreement, the Associated Agreements and the Tax Partnership Agreement.  Each Party shall protect, defend, and indemnify each other Party from and against any and all losses, costs, and liabilities arising from the indemnifying Party’s failure or refusal to report and discharge such taxes or satisfy such obligations.

ARTICLE VII

CERTAIN PAYMENT OBLIGATIONS

7.1Payment of Development Costs and Carried Costs.

(a)Subject to the other terms of this Agreement including Section 7.1(b) and subject to the applicable Annual Plan and Budget, (i) Noble shall pay its Share of Development Costs and (ii) CONSOL shall pay its Share of Development Costs.

(b)In addition to paying for its Share of Development Costs, unless the following obligation is temporarily suspended pursuant to Section 7.1(d), during the Carry Period (notwithstanding the terms of any Applicable Operating Agreement to the contrary) Noble shall pay, on behalf of CONSOL and its Affiliates, one-third of all Drilling and Completion Costs that CONSOL would otherwise be required to pay as its Share of Development Costs under Section 7.1(a) (all such Drilling and Completion Costs that Noble is obligated to pay pursuant to this Section 7.1(b) and subject to Section 3.5, the “Carried Costs”). For clarity, the Parties intend that Noble shall pay its Share of Development Costs plus all Carried Costs until the Carry Termination Event, and that CONSOL shall pay its Share of Development Costs less all Carried Costs until the Carry Termination Event.

(c)Until the Carry Termination Event, all Carried Costs shall be paid by Noble in the same manner and at the same time it pays or advances its Share of Development Costs pursuant to Section 7.2.

(d)Unless otherwise agreed by Noble in writing and except as provided in Section 3.5(b)(iii), Noble’s obligation to pay, on behalf of CONSOL and its Affiliates, the Carried Costs shall be temporarily suspended (i) during any period beginning on the first date in any calendar year that the Carried Costs paid by Noble for Drilling and Completion Costs incurred in such calendar year exceeds $400,000,000 and ending on the last day of such calendar year and (ii) during any period (A) beginning on the first day of the month following the month in which the average midpoint price per MMBtu of natural gas (as reported by Platts Gas Daily for natural gas delivered at Henry Hub for each such day) for a calendar month and the preceding two calendar months before such month is less than $4.00/MMBtu and (B) ending on the first day of the month following the month in which the average midpoint price per MMBtu of natural gas (as reported by Platts Gas Daily for natural gas delivered at Henry Hub for each such day) for a calendar month and the preceding two calendar months before such month equals or exceeds $4.00/MMBtu.

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(e)Under no circumstance shall Noble be permitted to offset any amounts owed by CONSOL to Noble against Noble’s obligation to pay the Carried Costs or the Post Closing Cash Payments.

7.2Payment Procedures.

(a)Each Party Operator, at its option, may issue statements and invoices to any Party for such Party’s Share of Development Costs (after giving effect to Section 7.1(b)) and, in the case of Noble, the Carried Costs that such Party Operator incurs in connection with Development Operations or may issue a request to any Party to advance such Party’s Share of Development Costs and, in the case of Noble, the Carried Costs that such Party Operator reasonably anticipates to be incurred in the future in connection with Development Operations; provided that no Party shall be obligated to advance any monies hereunder to such Party Operator for costs more than 30 days before such Development Costs are reasonably anticipated to be incurred by such Party Operator.

(b)Subject to the proviso in Section 7.2(a), in response to each statement or invoice for Development Costs issued by a Party Operator pursuant to Section 7.2(a), each Party shall pay or advance its Share of Development Costs and, in the case of Noble, the Carried Costs within 15 days of receiving such statement or invoice.

(c)In response to each statement or invoice for Development Costs issued by a Third Party Operator under an Applicable Operating Agreement (to the extent a Party Operator has not previously issued a statement or invoice for such Development Costs), subject to the applicable Annual Plan and Budget, each Party shall pay its Share of Development Costs (after giving effect to Section 7.1(b)).  In the event that a Party Operator has issued a statement or invoice for Development Costs and a Third Party Operator under an Applicable Operating Agreement issues a statement or invoice for the same Development Costs, (i) subject to the applicable Annual Plan and Budget (as modified by Section 3.3(i)), each Party shall pay or advance its Share of Development Costs (after giving effect to Section 7.1(b)) by the earlier of (x) the date such amounts are required to be paid or advanced pursuant to such Party Operator’s statement or invoice and (y) one Business Day prior to the date such amounts are required to be paid or advanced pursuant to such Third Party Operator’s statement or invoice and (ii) upon receipt of such payment or advance, such Party Operator shall pay, on behalf of each Party, such operator for such Development Costs.

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(d)Each Party shall have the right to audit each Party Operator’s and its Affiliates’ accounts with respect to Development Operations and Area-Wide Operations in which it participates on the same basis as is provided in Exhibit “C” to the Master JOA.

7.3Carried Costs Balance Payment.  At any time from and after the thirty-month anniversary of the Closing Date until the Carry Termination Event, Noble, upon five Business Days written notice to CONSOL (the “Balance Election Notice”), shall have the right (but not the obligation) to elect to pay the Carried Costs Balance as a lump sum payment, as applicable (such payment, the “Carried Costs Balance Payment”).  Promptly following the delivery of the Balance Election Notice by Noble, but in any event within five Business Days following such delivery, Noble shall pay the Carried Costs Balance Payment by wire transfer of immediately available funds to the Carried Cost Balance Account designated and controlled (subject to the obligations of CONSOL to withdraw such funds solely for the purpose hereafter described) by CONSOL promptly following CONSOL’s receipt of the Balance Election Notice.Upon CONSOL’s receipt of the Carried Costs Balance Payment, Noble’s and its Affiliates’ obligation to pay Carried Costs shall be deemed to be fully satisfied, the Carry Termination Event shall be deemed to have occurred and Noble shall have no right to the return of the Carried Cost Balance.  Notwithstanding anything in this Agreement to the contrary, any funds held in the Carried Costs Balance Account (exclusive of interest, which notwithstanding the fact that the payment of the requisite funds into the Carried Costs Balance Account, shall be allocated and distributed 100% to Noble) shall, prior to the termination of the Tax Partnership pursuant to Section 7.1 of the Tax Partnership Agreement, be used solely to pay Drilling and Completion Costs of CONSOL incurred pursuant to Development Operations and Area-Wide Operations in the same amount and manner as the funds provided by Noble to pay Carried Costs in accordance with Section 7.1(b) would have been used pursuant to this Agreement had the Carried Costs Balance Payment not been made and the Carry Termination Event not occurred.

7.4Post Closing Cash Payments.  Noble shall pay to CONSOL the Post Closing Cash Payments as and when required under the Acquisition Agreement.

7.5Certain Order of Payments.  Notwithstanding anything in this Agreement to the contrary, each Party hereby agrees that with respect to any outstanding payment obligation of Noble, all monies received by CONSOL and all recoveries realized in connection with any of the remedies hereunder for a default by Noble shall first be applied towards any portion of the Post Closing Cash Payments that are then due and payable by Noble to CONSOL, second, be applied towards any Carried Costs that are then due and payable by Noble, and third, be applied pro rata amongst the Parties towards any other payment obligations of Noble.

7.6Total Cost Sharing Payments.  Noble shall pay the Total Cost Sharing Payments into the Cost Reconciliation Account designated and controlled (subject to the obligations of CONSOL to withdraw such funds solely for the purposes specified in this Section 7.6) by CONSOL as and when required under the Acquisition Agreement.  The funds (other than interest accruing thereon) held from time to time in the Cost Reconciliation Account shall not be withdrawn or applied for the benefit of either Party for 30 days after the date on which such funds are deposited into the Cost Reconciliation Account  (with respect to such funds, the “Lockup Termination Date”), provided that CONSOL shall be entitled to borrow any portion of the principal balance of the Cost Reconciliation Account prior to the relevant Lockup Termination Date applicable to the funds at an arm’s-length interest rate and on other commercially reasonable terms for similar loans.  The Parties acknowledge that the funds in the Cost Reconciliation Account discharge Noble’s obligation to make Total Cost Sharing Payments dollar for dollar.  Notwithstanding the fact that Noble has no right to the return of the Total Cost Sharing Payments paid into the Cost Reconciliation Account, any interest earned on the Cost Reconciliation Account (or loans made therefrom) shall be allocated and distributed to the Parties based on their respective Participating Interests periodically.  Following the relevant Lockup Termination Date, the principal balance of the Cost Reconciliation Account shall be withdrawn by, and transferred to, CONSOL as reimbursement of costs funded by CONSOL in respect of the Oil and Gas Assets prior to the Closing Date (and not theretofore reimbursed from the Total Cost Sharing Payments).

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ARTICLE VIII

DEFAULTS

8.1Defaults.

(a)In the event that any Party fails to pay any of its Share of Development Costs (other than with respect to operational expenses, excluding Carried Costs, that are being disputed by a Party in good faith in an aggregate amount not to exceed $1,000,000) or Noble fails to pay any Carried Costs, in each case, on or before the Initial Default Date, or Noble fails to make any payment in respect of the Post Closing Cash Payments as and when required by Section 7.4 and under the Acquisition Agreement (such Party, a “Defaulting Party” and each such failure, a “Payment Default”), then (i) the other Parties (the “Non-Defaulting Parties”) shall provide written notice of such Payment Default (a “Default Notice”) to such Defaulting Party within 10 days after the Initial Default Date (provided any failure by the Non-Defaulting Parties to give such notice within such time period shall not affect any rights or remedies of the Non-Defaulting Parties in this Agreement, the Acquisition Agreement or any Associated Agreement, but shall be a covenant for the benefit of the Defaulting Party solely for the purpose of allowing the Defaulting Party to assert a claim in the event the Defaulting Party incurs damages caused by the Non-Defaulting Party’s failure to give any such notice within such period) and (ii) in addition to (A) the remedies available to any Non-Defaulting Party under any Associated Agreements, (B) those remedies that occur automatically pursuant to Section 8.2, (C) in the case Noble is the Defaulting Party with respect to its payment obligations for the Post Closing Cash Payments, the remedies available to CONSOL under the Acquisition Agreement, and (D) any and all other rights and remedies under this Agreement or at Law or in equity, the applicable Non-Defaulting Parties shall be entitled to exercise, in their sole discretion, any one or more of the remedies set forth in Section 8.3 during the period of time beginning on the Initial Default Date until the date upon which the Total Amount in Default has been fully cured (the “Default Period”).

(b)All amounts in default and not paid when due under this Agreement shall bear interest at the Agreed Rate from the due date to the date of payment.

8.2Certain Automatic Remedies for a Default.  

(a)General Remedies.  Unless a majority of the Non-Defaulting Parties (based on their relative Participating Interests) elect in writing to waive or extend the time period for any or all of the following, then, for a period (1) beginning on the earlier of (x) the 10th day after the date on which the Defaulting Party receives the Default Notice and (y) 20 days after the Initial Default Date and (2) ending upon the expiration of the Default Period, the Defaulting Party shall automatically not be entitled to:

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(i)     make or elect to participate in any proposal under this Agreement or any Applicable Operating Agreement;

(ii) vote on any matter with respect to which approval is required under the express terms of this Agreement or any Associated Agreement (excluding any amendment or waiver of the terms of any such agreement and any amendment or modification to the Development Plan);

(iii )  call any Joint Development Committee meeting;

(iv )  send its representatives or advisors to any meeting of the Joint Development Committee (and such members shall not be eligible to vote on any matters brought before the Joint Development Committee);

(v)access any data or information relating to any operation conducted under this Agreement or any Associated Agreement (except to the extent that the Defaulting Party is a Party Operator, in which case such Defaulting Party shall be entitled to such data and information as may be necessary to perform its responsibilities in such capacity);

(vi)Transfer all or any part of its Joint Development Interest or any other Subject Asset, undergo a Change in Control or encumber all or any part of its Joint Development Interest or any other Subject Assets, except in a case of a Transfer of a Joint Development Interest to, or a Change in Control with, a Person or encumbrance in favor of a Person who simultaneously with such Transfer, Change in Control or encumbrance satisfies in full the Total Amount in Default;

(vii) elect to acquire any Offered Interest pursuant to Section 4.4; or

(viii)elect to acquire any Option Interests pursuant to Section 5.3.

(b)Certain Remedies.  If Noble is a Defaulting Party with respect to the Total Amount (a “NBL Payment Default”), then unless CONSOL elects in writing to waive or extend the time period for the following, as of the earlier to occur of (x) the 110th day after the date on which Noble, as the Defaulting Party, receives the Default Notice for such NBL Payment Default and (y) 120 days after the Initial Default Date for such NBL Payment Default (the “NBL Acceleration Trigger”), Noble shall be required to pay the NBL Balance as a lump sum payment, as applicable (such payment, the “NBL Balance Payment”).  Promptly following the NBL Acceleration Trigger, but in any event within five Business Days following the date of such NBL Acceleration Trigger, Noble shall pay to CONSOL the NBL Balance Payment by wire transfer of immediately available funds as follows:  (i) the amount of the Carried Costs Balance shall be paid to the Carried Costs Balance Account specified by CONSOL in writing to Noble promptly following the NBL Acceleration Trigger and (ii) the amount of the Post Closing Cash Payments Balance shall be paid to a Tax Partnership Account specified by CONSOL in writing to Noble promptly following the NBL Acceleration Trigger.Upon CONSOL’s receipt of the NBL Balance Payment, (a) Noble and its Affiliates shall be deemed to no longer be in default of the obligation to pay the Total Amount in accordance with this Agreement and the Acquisition Agreement,(b) such obligation to pay Total Amount shall be deemed to be fully satisfied, and (c) the Carry Termination Event shall be deemed to have occurred.  Notwithstanding anything in this Agreement to the contrary, any funds held in the Carried Costs Balance Account (exclusive of interest, which shall be allocated and distributed 50% to CONSOL and 50% to Noble) shall, prior to the termination of the Tax Partnership pursuant to Section 7.1 of the Tax Partnership Agreement, be used solely to pay Drilling and Completion Costs incurred pursuant to Development Operations and Area-Wide Operations in the same amount and manner as the funds provided by Noble to pay Carried Costs would have been used pursuant to this Agreement had the NBL Balance Payment not been made and the Carry Termination Event not occurred.

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8.3Certain Other Remedies for a Default.

(a)Right to Entitlements.  From and after the 30th day after the Initial Default Date, a Defaulting Party shall have no right to receive its Entitlement from the Subject Assets and the Non-Defaulting Parties shall have the right to collect such Entitlement; provided that, in the case that (i) Noble is the Defaulting Party, the proceeds from all such Entitlements shall be used to pay the Total Amount in Default and shall be deemed, first, to apply to the portion of the Total Amount in Default that relates to any portion of the Post Closing Cash Payments that are then due and payable by Noble to CONSOL, second, and only to the extent that all Payment Defaults have been cured with respect to the Post Closing Cash Payments, to apply to the portion of the Total Amount in Default that relates to any Carried Costs and, third, and only to the extent that all Payment Defaults have been cured with respect to the Post Closing Cash Payments and the Carried Costs, proportionately to the remainder of the Total Amount in Default and (ii) CONSOL is the Defaulting Party, the proceeds from all such Entitlements shall be used to pay the Total Amount in Default and shall be deemed to apply proportionately to the Total Amount in Default.

(b)Specific Performance.  Any Non-Defaulting Party shall be entitled to seek specific performance of any of the Defaulting Party’s obligations under this Agreement or any Associated Agreement.

(c)Removal of Party Operator.

(i)   In addition to the other remedies available hereunder to CONSOL, if Noble Operator or any of its Affiliates is a Defaulting Party, from and after the 30th day after the Initial Default Date, then, and so long as Noble Operator or any of its Affiliates is in a Payment Default, CONSOL may deliver to Noble Operator a notice that it is electing to remove Noble Operator as operator of the NBL Operated Area, effective as of the date of such notice (or such later date as CONSOL shall specify in such notice), and Noble Operator shall be replaced in accordance with Section 2.5(b)(ii).

(ii)  In addition to the other remedies available hereunder to Noble, if CONSOL Operator or any of its Affiliates is a Defaulting Party, from and after the 30th day after the Initial Default Date, then, and so long as CONSOL Operator or any of its Affiliates is in a Payment Default, Noble may deliver to CONSOL Operator a notice that it is electing to remove CONSOL Operator as operator of the CNX Operated Area, effective as of the date of such notice (or such later date as Noble shall specify in such notice), and CONSOL Operator shall be replaced in accordance with Section 2.5(a)(ii).

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(d)Offset.  Except as provided in Section 7.1(e), any Non-Defaulting Party and its Affiliates shall be permitted to offset any amounts owed to it by a Defaulting Party or its Affiliates.

8.4        Cumulative and Additional Remedies.  The rights and remedies granted to Non-Defaulting Parties in this ARTICLE VIII shall be cumulative, not exclusive, and shall be in addition to any other rights and remedies that may be available to the Non-Defaulting Parties, at Law, in equity or otherwise.  Each right and remedy available to a Non-Defaulting Party may be exercised from time to time and so often and in such order as may be considered expedient by a Non-Defaulting Party in its sole discretion.

ARTICLE IX

LAND AND GEOSCIENCE DATA; DISCLAIMERS

9.1Land and Geoscience Data.  To the extent that a Party is neither prohibited nor required to make payment of a fee pursuant to any Third Party agreement or applicable Law, each Party will make available to any other Party, upon request, (a) all existing leasehold documentation developed or obtained by such Party in connection with the acquisition of Subject Assets within the Development Area, including all lease, land, title and division order files (including any available abstracts of title, title opinions and reports, and title curative documents), contracts, accounting records, correspondence, permitting, engineering, production, and well files (including any well logs) and (b) all seismic and geological data and other similar information, including drainage data, seismic surveys, information regarding fracing of wells and related information regarding the development and operation of the Subject Assets, in each case, that such Party may possess.  The Party holding such data and information, as the case may be, will use its commercially reasonable efforts to obtain the consent of the applicable party to disclose any such data to such other Parties (to the extent applicable to such Parties’ interest in the Subject Assets at such time) if such disclosure is otherwise prohibited without such consent.  Other than with respect to amounts required to be paid to obtain any necessary consent to share any information that was held by CONSOL Operator prior to the Closing Date and amounts being paid by Noble to CONSOL pursuant to the Acquisition Agreement, the costs of acquiring, transferring or sharing any such data and information (including any fee amounts required to be paid to obtain any necessary consents) for any Subject Assets will be Development Costs to be borne and paid by the Parties in relation to their Participating Interests.  With respect to amounts required to be paid to obtain any necessary consent to share any information that was held by CONSOL Operator prior to the Closing Date, such amount shall be paid by the Party requesting the sharing of such information.

9.2Disclaimers. EACH PARTY MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AS TO THE ACCURACY AND COMPLETENESS OF MATERIALS, DOCUMENTS AND OTHER INFORMATION MADE AVAILABLE BY SUCH PARTY IN CONNECTION WITH THE PERFORMANCE OF THIS AGREEMENT AND SUCH PARTY EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO EACH OTHER PARTY OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO SUCH OTHER PARTIES, INCLUDING PURSUANT TO SECTION 9.1).  EACH PARTY EXPRESSLY AGREES THAT ANY RELIANCE UPON OR CONCLUSIONS DRAWN FROM ANY MATERIALS, DOCUMENTS AND OTHER INFORMATION PROVIDED BY ANOTHER PARTY SHALL BE AT ITS OWN RISK TO THE MAXIMUM EXTENT PERMITTED BY LAW AND SHALL NOT GIVE RISE TO ANY LIABILITY OF OR AGAINST THE PROVIDING PARTY.  EACH PARTY HEREBY WAIVES AND RELEASES ANY CLAIMS ARISING UNDER THIS AGREEMENT, COMMON LAW OR ANY STATUTE ARISING OUT OF ANY MATERIALS, DOCUMENTS OR INFORMATION PROVIDED BY ANOTHER PARTY TO SUCH PARTY.  EACH PARTY AGREES THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 9.2 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

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ARTICLE X

TERM

10.1Termination.  This Agreement shall terminate upon the earlier to occur of (“Termination Date”):

(a)the date that is 60 days after the occurrence of the Carry Termination Event; or

(b)the mutual agreement of CONSOL and Noble.

10.2Effect of Termination.  Upon the Termination Date, (a) this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder and (b) to the extent not previously completed, (i) CONSOL Operator and Noble Operator shall each, as promptly as practicable, designate Drilling Units for any portion of the Subject Assets that are not already included in a Drilling Unit or covered by a Third Party Operating Agreement, (ii) execute and deliver separate Unit JOAs to cover any such Drilling Unit and (iii) execute and file separate Unit JOA Memoranda and related financing statements for each such Unit JOA and file such Unit JOA Memoranda in the real property records of each county in which the Subject Assets that are covered by the applicable Unit JOA are located and such financing statements in the proper office under the Uniform Commercial Code in the states in which such Subject Assets are located.  Upon completion of the requirements set forth in the preceding sentence, the Master JOA shall automatically be deemed to have terminated and the Parties shall take all action as is necessary to reflect such termination, including filing a release of each Master JOA Memoranda that is on file in the real property records and a termination of all related financing statements.  Notwithstanding the foregoing, (1) the termination of this Agreement or any provision thereof shall not relieve any Party from any expense, liability or other obligation or remedy therefor which has accrued or attached prior to the date of such termination, (2) as among the Parties (but not as to any successor or assign of such Party following the termination of this Agreement), the provisions of Section 6.1 and Exhibit G shall survive such termination and remain in full force and effect until the Tax Partnership is terminated in accordance with the terms of the Tax Partnership Agreement, (3) the provisions of Section 2.6 and ARTICLE XI (other than Section 11.8) shall survive such termination and remain in full force and effect indefinitely, (4) the provisions of Section 2.13 shall survive such termination and remain in full force and effect in accordance with its terms, and (5) the provisions of ARTICLE V and this clause (5) shall survive the termination of this Agreement until the 25th anniversary of the Closing Date; provided that with respect to this clause (5), from and after the termination of this Agreement, (x) Section 5.2 shall terminate and any Fill-In Interests acquired by any Party shall be deemed to be an Option Interest subject to Section 5.3, (y) either Party can terminate the provisions of ARTICLE V with respect to all or any portion of the Development Area prior to the 25th anniversary of the Closing Date by giving 6 months prior written notice of the same to the other Parties and (z) upon the sale of any Lease and/or well by any Party to a Third Party, the provisions of ARTICLE V with respect to such Lease and/or well and all related assets with respect thereto shall terminate.

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ARTICLE XI

MISCELLANEOUS

11.1Relationship of the Parties.  The rights, duties, obligations and liabilities of the Parties under this Agreement shall be individual, not joint or collective. It is not the intention of the Parties to create, nor shall this Agreement be deemed or construed to create, a mining or other partnership (other than the Tax Partnership created pursuant to Section 6.1 for federal and state income tax purposes only), joint venture or association or a trust.  This Agreement shall not be deemed or construed to authorize any Party to act as an agent, servant or employee for any other Party for any purpose whatsoever except as explicitly set forth in this Agreement.  In their relations with each other under this Agreement, the Parties shall not be considered fiduciaries.

11.2Notices.  

(a)Generally.  Subject to Section 11.2(b), 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) or (only with respect to purposes set forth in Section 11.2(b)) by electronic mail with a PDF of the notice or other communication attached (provided that any such electronic mail is confirmed either by written confirmation, facsimile transmission or U.S. Express Mail), in each case, addressed to the appropriate Person at the address for such Person shown below:

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If to CONSOL, its representatives on the Joint Development Committee or CONSOL Operator:

CNX Gas Company LLC

2481 John Nash Blvd

Bluefield, WV 24701

Attention:  Randall M. Albert

Telephone: 304-323-6501

Fax: 304-323-6615

Email: RandyAlbert@cnxgas.com

CNX Gas Company LLC

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA  15317

Attention:  Charles Hardoby

Telephone:  (724) 485-4166

Fax:  (724) 485-4836

Email: ChuckHardoby@consolenergy.com

CNX Gas Company LLC

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA  15317

Attention:  Stephen W. Johnson

Telephone:  (724) 485-4163

Fax:  (724) 485-4836

Email: SteveJohnson@consolenergy.com

If to CONSOL’s Party Representative:

CNX Gas Company LLC

2481 John Nash Blvd

Bluefield, WV 24701

Attention:  Michael Onifer

Telephone:  (304) 323-6502

Fax:  (304) 323-6549

Email: MikeOnifer@cnxgas.com

In each case, with a copy to:

Wachtell, Lipton, Rosen & Katz

51 West 52nd Street

New York, NY  10019-6150

Attention:  David A. Katz

Telephone:  (212) 403-1309

Email:  dakatz@wlrk.com

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If to Noble or its representatives on the Joint Development Committee or Noble Operator:

Noble Energy, Inc.

100 Glenborough Drive, Suite 100

Houston, Texas 77067

Attention:  Barry Shelden

Telephone:   281-872-3100

Fax:                281-872-3111

Email:  bshelden@nobleenergyinc.com

Noble Energy, Inc.

100 Glenborough Drive, Suite 100

Houston, Texas 77067

Attention: John Lewis

Telephone:    281-872-3100

Fax:                 281-872-3111

Email: jlewis@nobleenergyinc.com

Noble Energy, Inc.

100 Glenborough Drive, Suite 100

Houston, Texas 77067

Attention: Aaron Carlson

Telephone:   281-872-3100

Fax:                281-872-3111

Email:

If to Noble’s Party Representative:

Noble Energy, Inc.

100 Glenborough Drive, Suite 100

Houston, Texas 77067

Attention:  Barry Shelden

Telephone:    281-872-3100

Fax:                 281-872-3111

Email:  bshelden@nobleenergyinc.com

Any notice given in accordance herewith shall be deemed to have been given when (i) delivered to the addressee in person or by courier, (ii) transmitted by facsimile transmission or electronic communications during normal business hours, or if transmitted after normal business hours, on the next Business Day, or (iii) 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.

(b)          Notices.  With respect to any notices and communications required or permitted to be given pursuant to ARTICLE II, ARTICLE III, ARTICLE VII, or ARTICLE IX, such notices and communications shall be sufficient in all respects if given in accordance with Section 11.2(a) or if such notice is delivered by email to the address specified for a Person in Section 11.2(a); provided that, in each case, copies of such notices and communications shall not be required to be given to any law firm representing such Party.  Any notice given by email shall be deemed to have been given on the Business Day such email was sent, if sent during normal business hours, and on the Business Day following such email being sent, if sent at a time other than normal business hours.

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(c)Any Person may change their contact information for notice by giving written notice to the other Parties in the manner provided in Section 11.2(a).

11.3       Expenses.  Except as otherwise specifically provided, all fees, costs and expenses incurred by the Parties in negotiating this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

11.4Waivers; Rights Cumulative.  Any of the terms, covenants, 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 their respective officers, employees, agents, or representatives, nor any 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 or covenant 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 or covenant.  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.

11.5Entire Agreement; Conflicts.  THIS AGREEMENT, THE EXHIBITS HERETO, THE ACQUISITION AGREEMENT (INCLUDING ALL TRANSACTION DOCUMENTS) AND THE ASSOCIATED AGREEMENTS 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 HEREOF.  THERE ARE NO WARRANTIES, REPRESENTATIONS, OR OTHER AGREEMENTS AMONG THE PARTIES RELATING TO THE SUBJECT MATTER HEREOF EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT, THE EXHIBITS HERETO, THE ACQUISITION AGREEMENT (INCLUDING ALL TRANSACTION DOCUMENTS) AND THE ASSOCIATED AGREEMENTS, 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 EXHIBIT HERETO (OTHER THAN THE TAX PARTNERSHIP AGREEMENT); OR (B) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY ASSOCIATED AGREEMENT (INCLUDING ANY THIRD PARTY JOINT OPERATING AGREEMENT, BUT EXCLUDING THE TAX PARTNERSHIP AGREEMENT), THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL, PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE EXHIBITS HERETO OR ANY ASSOCIATED AGREEMENT 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 11.5.

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11.6     Amendment.  This Agreement may be amended only by an instrument in writing executed by CONSOL and Noble and expressly identified as an amendment or modification.

11.7Governing Law; Disputes.  

(a)GENERALLY.  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.  ALL OF THE PARTIES HERETO CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES FEDERAL DISTRICT COURTS LOCATED IN THE STATE OF PENNSYLVANIA FOR ANY ACTION ARISING OUT OF THIS AGREEMENT, THE ASSOCIATED AGREEMENTS 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 ASSOCIATED AGREEMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY SHALL BE EXCLUSIVELY LITIGATED IN THE UNITED STATES FEDERAL DISTRICT COURTS HAVING SITES IN PITTSBURGH, PENNSYLVANIA (AND ALL APPELLATE COURTS HAVING JURISDICTION THEREOVER).  EACH PARTY HERETO 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 ASSOCIATED AGREEMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY.

(b)         Expert Proceedings.  For any decision referred to an expert under this Agreement as expressly provided herein, the Parties hereby agree that such decision shall be conducted expeditiously by an expert (who shall have at least 10 years of oil and gas exploration and development experience in the Development Area and with respect to the subject matter giving rise to the underlying dispute) selected unanimously by the Parties to such dispute.  The expert is not an arbitrator of the dispute and shall not be deemed to be acting in an arbitral capacity.  The Party desiring an expert determination shall give the other Party written notice of the request for such determination.  If the Parties are unable to agree upon an expert within 10 days after receipt of the notice of request for an expert determination, then, upon the request of any of the Parties, the Pittsburgh, Pennsylvania office of the American Arbitration Association shall appoint such expert.  The expert, once appointed, shall have no ex parte communications with the Parties concerning the expert determination or the underlying dispute.  All communications between any Party and the expert shall be conducted in writing, with copies sent simultaneously to the other Party in the same manner, or at a meeting to which all Parties have been invited and of which such Parties have been provided at least 5 Business Days notice.  Within 30 days after the expert’s acceptance of its appointment, the Parties shall provide the expert with a report containing their proposal for the resolution of the matter and the reasons therefor, accompanied by all relevant supporting information and data.  Within 60 days of receipt of the above-described materials and after receipt of additional information or data as may be required by the expert, the expert shall select the proposal which it finds more consistent with the terms of this Agreement.  The expert may not propose alternate positions or award damages, interest or penalties to any Party with respect to any matter.  The expert’s decision shall be final and binding on the Parties.  Any Party that fails or refuses to honor the decision of an expert shall be in default under this Agreement.

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(c)Damages.  None of the Parties shall be entitled to recover from any other Party, or such Parties respective Affiliates, any indirect, consequential, punitive or exemplary damages or damages for lost profits of any kind arising under or in connection with this Agreement, the Associated Agreements or the transactions contemplated hereby or thereby, except to the extent any such Party suffers such damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending of such damages) to a Third Party, which damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder.  Subject to the preceding sentence, each Party, on behalf of itself and each of its Affiliates, waive any right to recover punitive, special, exemplary and consequential damages, including damages for lost profits, arising in connection with or with respect to this Agreement, the Associated Agreements or the transactions contemplated hereby and thereby.

11.8Publicity.

(a)No Party will issue any Press Release with respect to this Agreement, the Associated Agreements or the activities contemplated hereby or thereby without providing the text of such Press Release to the other Party at least 24 hours prior to release, except where such releasing Party in good faith determines that such Press Release is required to be released immediately by Law or under the rules and regulations of a recognized stock exchange on which shares of such Party or any of its Affiliates are listed in which case the releasing Party shall promptly thereafter provide each Party with a copy of such Press Release.

(b)Notwithstanding anything to the contrary in Section 11.8(a), in the event of any emergency endangering property, lives or the environment, Party Operator may issue such Press Releases or other public announcements as it deems necessary in light of the circumstances and shall promptly thereafter provide each Party with a copy of any such Press Release or other public statement.

11.9Parties in Interest.  Nothing in this Agreement shall entitle any Person other than the Parties to any claim, cause of action, remedy or right of any kind.

11.10Successors and Permitted Assigns.  This Agreement shall be binding upon and inure to the benefit of the Parties and their successors and permitted transferees and assigns.

11.11Preparation 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.

11.12Severability.  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.

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11.13Counterparts.  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 shall constitute for all purposes one agreement.  Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

11.14Excluded Assets.  For the avoidance of doubt and notwithstanding anything herein to the contrary, no Excluded Asset shall be subject to the terms of this Agreement or any Associated Agreement.

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

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IN WITNESS WHEREOF, the Parties have executed this Agreement by their duly authorized representatives on and as of the Closing Date.

CNX GAS COMPANY LLC
By:	/s/ Stephen W. Johnson
Name:  Stephen W. Johnson
Title:	Vice President and Secretary
NOBLE ENERGY, INC.
By:	/s/ Shawn E. Conner
Name: Shawn E. Conner
Title:	Vice President

[SIGNATURE PAGE TO JOINT DEVELOPMENT AGREEMENT]

APPENDIX I

DEFINITIONS

“Acquiring Party” has the meaning set forth in Section 5.3(a).

“Acquisition Agreement” means that certain Asset Acquisition Agreement by and between CONSOL and Noble, dated August 17, 2011, as amended in writing from time to time.

“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 Party in acquiring any Fill-In Interests or Option Interests along with any adjustments required by Section 5.4(b)(ii); provided, however, that (a) if Fill-In Interests or Option Interests were acquired by the Party Operator or an Acquiring Party, as applicable, as part of a Package Sale or as part of an acquisition of an entity with assets and properties that are not within the Development Area, then the amount of the Acquisition Costs for such Fill-In Interests or Option Interests shall be deemed to be the lesser of (1) the value allocated to such Fill-In Interests or Option Interests in the transaction in which the Party Operator or Acquiring Party, as applicable, acquired such interests or (2) the Fair Market Value of the Fill-In Interests or Option Interests and (b) if the consideration paid by such Party Operator or such Acquiring Party, as applicable, includes any non-cash consideration, then the value of such non-cash consideration shall be deemed to be the lesser of (x) the value allocated to such non-cash consideration in the transaction in which the Party Operator or Acquiring Party, as applicable, acquired such interests or (y) the Fair Market Value of such non-cash consideration.

“Acquisition Notice” has the meaning set forth in Section 5.3(a).

“Active Rig” means a drilling rig capable of drilling a horizontal well to a depth within the Marcellus Formation with a minimum lateral of 4,500 feet.

“Additional Interests” has the meaning set forth in the Acquisition Agreement.

“AFE” means authority for expenditure.

“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.

“Affiliate Contract” means any contract or other agreement entered into by a Party Operator, on the one hand, and any of its Affiliates, on the other, in connection with any Development Operations or any Area-Wide Operations that would reasonably be expected to involve aggregate payments by such Party Operator that, taken in the aggregate with all payments under all other contracts or agreements between the Party Operator and its Affiliates for similar goods and services, would be in excess of $500,000 in any 12-month period; provided that the Surface Use Agreement and the Water Use Agreement (each as defined in the Acquisition Agreement) shall not be deemed to be Affiliate Contracts.

Appendix I - 1

“Agreed Rate” means the Prime Rate (as published in the “Money Rates” table of The Wall Street Journal, eastern edition) plus an additional two percentage points applicable on the first Business Day prior to the due date of payment and thereafter on the first Business Day of each succeeding calendar month (or, if such rate is contrary to any applicable usury Law, the maximum rate permitted by such applicable Law).

“Agreement” means this Joint Development Agreement, as amended in writing from time to time.

“AMI Purchase Date” has the meaning set forth in Section 5.3(b).

“Annual Plan and Budget” has the meaning set forth in Section 3.3(a).

“Applicable Operating Agreements” means, collectively, the Joint Development Operating Agreements and all Third Party Operating Agreements, and “Applicable Operating Agreement” means any of them.

“Area-Wide Operation” means a seismic or other geophysical data acquisition operation, or other similar operation, including geophysical surveys, microseismic monitoring and core sampling and analysis conducted by the Parties in accordance with this Agreement with respect to the Development Area and covering areas subject to more than one Applicable Operating Agreement.

“Asset Taxes” means ad valorem, property, excise, 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 Subject Assets or the production of hydrocarbons therefrom, but excluding, for the avoidance of doubt, income, capital gains and franchise taxes.

“Assigned FT Interests” has the meaning set forth in Schedule 2.10(a).

“Associated Agreements” means, collectively, the Applicable Operating Agreements and any other agreements entered into by a Party and any third parties in furtherance of the conduct of Development Operations or Area-Wide Operations (including the Surface Use Agreement, the Noble Secondment Agreement, the CONSOL Secondment Agreement, the Services Agreement and the Water Use Agreement (each as defined in the Acquisition Agreement)), and “Associated Agreement” means any of them.

“Balance Election Notice” has the meaning set forth in Section 7.3.

“Business Day” means a day (other than a Saturday or Sunday) on which commercial banks in Pennsylvania and Houston are generally open for business.

“Carried Cost Obligation” means $2,133,776,252, as may be adjusted pursuant to the Acquisition Agreement.

“Carried Costs” has the meaning set forth in Section 7.1(b).

Appendix I - 2

“Carried Costs Balance” means, as of any time, the difference between the Carried Costs Obligation and the aggregate amount of Carried Costs actually paid by Noble or funded into a Tax Partnership Account by Noble, in each case, in accordance with the terms hereof, Noble as of such time.

“Carried Costs Balance Account” means the Tax Partnership Account to which the Carried Costs Balance Payment is made pursuant to Section 7.3 or Section 8.2(b).

“Carried Costs Balance Payment” has the meaning set forth in Section 7.3.

“Carried Costs Amount” has the meaning set forth in Section 3.5(b)(i).

“Carry Period” means the period beginning on the Closing Date and ending at the Carry Termination Event.

“Carry Termination Event” means the time at which (a) the aggregate amount of Carried Costs actually paid by Noble or funded into a Tax Partnership Account by Noble, in each case, in accordance with the terms hereof equals (b) the Carried Cost Obligation.

“Change in Control” means any direct or indirect change in control of a Person (whether through merger, sale of shares or other equity interests, or otherwise), through a single transaction or series of related transactions, from one or more transferors to one or more transferees; provided, however, that for purposes hereof, a “Change in Control” shall not include a change in control of a Party (a) resulting in ongoing control by an Affiliate that is wholly-owned by the ultimate parent company of such Party, (b) created by a change in control of CONSOL Energy Inc. (or its successor) or Noble Energy, Inc. (or its successor) or (c) solely with respect to Section 4.4, created by a change in control of any entity directly or indirectly holding all of CONSOL’s and its Affiliates’ Joint Development Interest and all or substantially all of CONSOL’s and its Affiliates’ other oil and gas assets (other than coalbed methane assets) that is effected through (i) the distribution of the equity interests in such entity to the public stockholders of CONSOL Energy Inc. (or its successor) in proportion to the respective stock ownership of CONSOL Energy Inc. (or its successor), (ii) an initial public offering of equity ownership interests in such entity, in either case as a result of which such entity becomes a publicly-held company subject to the reporting requirements of  Section 15(d) of the Securities Act of 1933 or Section 13 of the Securities Exchange Act of 1934 and would qualify for initial listing and quotation on the New York Stock Exchange or any other national securities exchange in the United States, or (iii) a Transfer of the equity interests in such entity in a transaction having the purpose of separating CONSOL Energy Inc.’s (or its successor) coal business from its oil and gas exploration and development business.

“Closing Cash Payment” has the meaning set forth in the Acquisition Agreement.

“Closing Date” has the meaning set forth in the Preamble.

“CNX Operated Area” has the meaning set forth in Section 2.3(a), subject to the provisions of Section 2.3(c), Section 2.3(d) and Section 5.3(d).

“CONSOL” has the meaning set forth in the Preamble.

Appendix I - 3

“CONSOL Master JOA Memorandum” has the meaning set forth in Section 2.4(b).

“CONSOL Operator” means CONSOL or any Affiliate of CONSOL designated by CONSOLor, to the extent permitted by Section 4.1(a)(ii), any transferee that upon consummation of such Transfer will hold at least a 25% Participating Interest.

“CONSOL Secondment Agreement” has the meaning set forth in the Acquisition Agreement.

“CONSOL Unit JOA Memorandum” has the meaning set forth in Section 2.4(d).

“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.

“Cost Reconciliation Account” has the meaning set forth in the Acquisition Agreement.

“Defaulting Party” has the meaning set forth in Section 8.1(a).

“Default Notice” has the meaning set forth in Section 8.1(a).

“Default Period” has the meaning set forth in Section 8.1(a).

“Developed Assets” means all Subject Assets included within a Drilling Unit in which at least one well in which the Parties hold an economic interest has been spudded.

“Development Area” means the area described on Exhibit A-1, as may be expanded pursuant to Section 5.3(d), and includes the CNX Operated Area and the NBL Operated Area, provided that the Development Area shall not include any Lease or other property (or portion thereof) to the extent that it is an Excluded Asset or that is otherwise excluded from this Agreement pursuant to ARTICLE V.

“Development Costs” means costs and expenses incurred in the conduct of Development Operations or Area-Wide Operations, and all other fees, costs and expenses chargeable to the Parties under this Agreement or any Associated Agreement, including the fees, costs and expenses chargeable under Section 2.11.

“Development Operation” means any operation with respect to the Subject Assets or lands pooled thereunder conducted pursuant to any Applicable Operating Agreement.

“Development Plan” has the meaning set forth in Section 3.2(a).

“Development Services” means the services described in the introductory paragraphs of Section III of Exhibit “C” to the Master JOA; provided, however, Development Services shall not include those services specifically covered by the fixed rates as set forth in Exhibit “C” to the Master JOA.

Appendix I - 4

“Drilling and Completion Costs” means all of CONSOL’s and its Affiliates’ Share of Development Costs, attributable to (a) examining title and preparing locations for wells, (b)  the drilling, testing, completing, deepening, recompleting, sidetracking, reworking and plugging back of wells, (c) the plugging and abandoning of dry holes or wells no longer capable of producing in paying quantities, (d) the equipping of wells for production (including costs of mobilizing and demobilizing drilling and workover rigs to and from the well-site) and construction of infrastructure and facilities in order to transport the Hydrocarbons produced from any wells part of the Subject Assets to the lease tank or gathering system, (e) permitting, (f)  reclamation and related costs and (g) drilling overhead chargeable under the Applicable Operating Agreement.  For the avoidance of doubt, Drilling and Completion Costs shall not include (i) the costs of construction and operation of gathering and transportation systems, central delivery facilities or pipelines, (ii) any remedial operations (including sidetracking, deepening, reworking or plugging back operations) that are taken with respect to a well after the well has been drilled and initially completed, (iii) lease operating expenses, or (iv) costs of acquiring Fill-In Interests or Option Interests.

“Drilling Unit” means the area fixed for the drilling of one well by order or rule of any applicable Governmental Authority.  If a Drilling Unit is not fixed by any such rule or order, then a “Drilling Unit” shall be the drilling unit as reasonably established by the pattern of drilling in the applicable Operated Area unless otherwise agreed by the Parties.

“Drip Condensate Production” means, with respect to a Party, such Party’s and its Affiliates’ respective share of condensate collected from its Production by a gatherer in or from such gatherer’s gathering system.

“Electing Party” has the meaning set forth in Section 3.5(a)(ii).

“Election Period” has the meaning set forth in Section 5.3(a).

“Entitlement” means that quantity of Hydrocarbons produced from the Subject Assets for which a Party has the right to take delivery pursuant to the terms of any Applicable Operating Agreement, any other applicable agreement or applicable Law.

“Excess Gas Production” has the meaning set forth in Section 2.10(c)(ii).

“Excluded Asset” has the meaning set forth in the Acquisition Agreement.

“Excluded Units” has the meaning set forth in Section 2.3(c).

“Expansion County” has the meaning set forth in Section 2.3(c).

“Expansion Request” has the meaning in Section 2.3(c).

“Fair Market Value” means the fair market value (expressed in U.S. dollars) of all or a portion of the assets and properties subject to such determination that a willing buyer would pay a willing seller in an arm’s length transaction.  Fair Market Value shall be agreed upon in good faith by the Parties to whom such determination relates; provided that if the Parties are unable to agree upon a determination of Fair Market Value, any such Party may have such matter determined by an expert in accordance with Section 11.7(b).

Appendix I - 5

“Fill-In Interest” has the meaning set forth in Section 5.2.

“Force Majeure Event” means any (i) act of God, (ii) change in Law (or administrative action or inaction in respect of Law), or (iii) with respect to a given Party, a breach of an Associated Agreement by another Party or its Affiliates (other than a Third Party), that in any such case prevents a Party from complying with its respective obligations (other than obligations relating to the payment of monies when due), but only insofar as and only for so long as such event prevents such compliance.

“Gas Production” means, with respect to a Party, such Party’s and its Affiliates’ respective share of Production (other than Wellhead Condensate Production and Drip Condensate Production).

“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 entitle 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.

“HSE Committee” has the meaning set forth in Section 3.1(g).

“HSE Program” has the meaning set forth in Section 2.5(c)(i).

“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.

“Immaterial Interest” means, with respect to any Party, any overriding royalty interest, production payment, net profits interest or similar interest that is carved out of such Party’s interests in the Subject Assets, the Transfer of which interest would not convey a material portion of the value of the Party’s interest in the Subject Assets.

“Initial Default Date” means the date on which a Party is obligated to pay or advance its Share of Development Costs or, in the case of Noble, the Carried Costs pursuant to Section 7.2or the Post Closing Cash Payments as provided in Section 7.4.

“Interim Marketing Period” means the period beginning on the date hereof and ending on (a) if Noble in its sole discretion gives CONSOL Operator written notice on or prior to January 30, 2012 that it is terminating the Interim Gas Marketing Period, then March 31, 2012, (b) if Noble in its sole discretion gives CONSOL Operator written notice on or prior to August 31, 2012 that it is terminating the Interim Gas Marketing Period, then October 31, 2012, and (c) in all other situations, March 31, 2013.

“Joint Development Committee” means the committee created pursuant to Section 3.1(a).

Appendix I - 6

“Joint Development Interest” means, with respect to a Party, all of such Party’s leasehold, working and mineral fee interest and obligations with respect to Subject Assets within the Development Area.

“Joint Development Operating Agreement” each of the Master JOA and each Unit JOA.

“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.

“Lease” means any oil, gas and mineral lease or sublease, royalty in oil and gas, overriding royalty in oil and gas, production payment in oil and gas, oil and gas mineral fee interest or other right to oil and gas in place.  For clarity, the term “Lease” shall not include any rights or interests in coal or coalbed methane.

“Lockup Termination Date” has the meaning set forth in Section 7.6.

“Marcellus Formation” means, (a) in central Pennsylvania, specifically from the top of the Burkett in the DeArmitt #1 (API 37-129-27246) and 7000'MD through to the top of the Onondaga at 7530'MD and illustrated in the log attached on Exhibit H; (b) in southwest Pennsylvania, specifically from the top of the Burkett in the GH-10C-CV (API 37-059-25397) at 7600'MD through to the top of the Onondaga at 7900'MD and illustrated in the log attached on Exhibit H; and (c) in West Virginia, specifically from the top of the Burkett in the DEPI #14815 (API 47-001-02850) at 7350'MD through to the top of the Onondaga at 7710'MD and illustrated in the log attached on Exhibit H.

“Marketer” has the meaning set forth in Section 2.10(b)(i).

“Marketing Fee” has the meaning set forth in Section 2.11(c).

“Marketing Transaction” has the meaning set forth in Section 2.10(b)(i).

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

“Master JOA” has the meaning set forth in Section 2.4(a).

“Master JOA Memoranda” has the meaning set forth in Section 2.4(b).

“MMBtu” means one million British thermal units.

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

“NBL Acceleration Trigger” has the meaning set forth in Section 8.2(b).

“NBL Balance” means the sum of the Carried Costs Balance and the Post Closing Cash Payments Balance.

“NBL Balance Payment” has the meaning set forth in Section 8.2(b).

Appendix I - 7

“NBL Operated Area” has the meaning set forth in Section 2.3(b), subject to the provisions of Section 2.3(c), Section 2.3(d) and Section 5.3(d).

“NBL Payment Default” has the meaning set forth in Section 8.2(b).

“Negotiating Party” has the meaning set forth in Section 2.10(c)(iii).

“Noble” has the meaning set forth in the Preamble.

“Noble Master JOA Memorandum” has the meaning set forth in Section 2.4(b).

“Noble Operator” means Noble or any Affiliate of Noble designated by Noble or, to the extent permitted by Section 4.1(b)(ii), any transferee that upon consummation of such Transfer will hold at least a 25% Participating Interest.

“Noble Secondment Agreement” has the meaning set forth in the Acquisition Agreement.

“Noble Unit JOA Memorandum” has the meaning set forth in Section 2.4(d).

“Non-Acquiring Parties” has the meaning set forth in Section 5.3(a).

“Non-Consent Account” means the Tax Partnership Account to which the Carried Costs Amount is made pursuant to Section 3.5(b)(i).

“Non-Consent Right” has the meaning set forth in Section 3.5.

 “Non-Consent Wells” has the meaning set forth in Section 3.5(a)(ii).

“Non-Consent Year” has the meaning set forth in Section 3.5(a)(i).

“Non-Consenting Party” has the meaning set forth in Section 3.5(a)(ii).

“Non-Defaulting Parties” has the meaning set forth in Section 8.1(a).

“Non-Terminable Contracts” has the meaning set forth in Section 3.5(a)(v).

“Non-Terminable Contract Obligations” has the meaning set forth in Section 3.5(a)(v).

“Offered Interest” has the meaning set forth in Section 4.4(a).

“Oil and Gas Assets” has the meaning set forth in the Acquisition Agreement.

“Operated Area” means the CNX Operated Area when used in reference to CONSOL Operator and the NBL Operated Area when used in reference to Noble Operator.

 “Operating Expenses” means costs and expenses reasonably necessary to continue operating, maintaining and producing wells and related surface equipment included in the Subject Assets in a manner consistent with past practices, industry standards and applicable Law.

Appendix I - 8

 “Operatorship Transition Period” has the meaning set forth in Section 2.3(d).

“Option Interests” has the meaning set forth in Section 5.3(a).

“P&A/Condemned Assets” means all Subject Assets (i) included within a Drilling Unit in which at least one well in which the Parties hold an economic interest has been drilled and plugged and abandoned or (ii) that have been condemned for drilling by agreement of the Parties or the Joint Development Committee.

“Package Sale” means an acquisition covering assets within the Development Area together with other assets outside of the Development Area as part of a wider transaction.

“Participating Interest” means the percentage set forth next to such Party’s name in Section 2.2(a), as adjusted pursuant to Section 2.2(b) to reflect each Party’s undivided share of the aggregate rights and obligations of the Parties under the terms of (a) this Agreement and (b) each Applicable Operating Agreement.

“Party” or “Parties” has the meaning set forth in the Preamble.

“Party Operator” means CONSOL Operator and/or Noble Operator, as appropriate.

“Party Representative” has the meaning set forth in Section 3.1(i).

“Payment Date” has the meaning set forth in Section 5.3(b).

“Payment Default” has the meaning set forth in Section 8.1(a).

“Peoples Contract” means that Base Contract for the Sale and Purchase of Natural Gas - Market Area, between Dominion Exploration & Production (as Seller) and The Peoples Natural Gas Company (as Buyer), dated May 9, 2001.

“Person” means any individual, corporation, company, partnership, limited partnership, limited liability company, trust, estate, Governmental Authority or any other entity.

“Post Closing Cash Payments” has the meaning set forth in the Acquisition Agreement.

“Post Closing Cash Payments Balance” means, as of any time, the difference between the Post Closing Cash Payments and that portion of the Post Closing Cash Payments (including the Closing Cash Payment) previously paid by Noble as of such time.

“Press Release” means any press release or other public statement that is released by a Party on PR Newswire, Business Wire or another similar national media distribution outlet, other than (x) any press release or other public statement that contains non-public financial information concerning the issuing Party not related to the activities contemplated hereby or (y) any press release or other public statement relating to an earnings release.

“Processed Gas Production” has the meaning set forth in Section 2.10(b)(i).

“Processing Agreements” has the meaning set forth in the Acquisition Agreement.

Appendix I - 9

“Production” means, with respect to a Party, such Party’s and its Affiliates’ respective share of Hydrocarbon production from any of their interests in the Subject Assets.

“Proposed Processing Agreement” has the meaning set forth in Section 2.10(c)(iii).

“Residual Gas Production” has the meaning set forth in Section 2.10(b)(i).

“Restricted Period” has the meaning set forth in Section 5.4(b)(iv).

“ROFO Notice” has the meaning set forth in Section 4.4(a).

“ROFO Offer” has the meaning set forth in Section 4.4(a).

“ROFO Parties” has the meaning set forth in Section 4.4(a).

“Services Costs” means the costs attributable to Development Services provided by each Party Operator as set forth in the Annual Plan and Budget or as determined pursuant to Section 2.11(d).

“Share of Development Costs” means, with respect to any Party, (i) such Party’s Working Interest share of Development Costs to the extent such Development Costs relate to such Party’s Working Interest in any Subject Asset and (ii) such Party’s Participating Interest share of Development Costs in all other cases.

“Subject Assets” means all right, title and interest of the Parties within the Development Area in and to the Oil and Gas Assets and any Leases and related assets acquired under ARTICLE V, insofar and only insofar as such Leases and related assets cover or relate to depths within the Marcellus Formation, in each case, in which two or more non-Affiliated Parties hold an interest.  For clarity, except as expressly provided in ARTICLE V, all Leases and related assets owned by one or more Parties within the Development Area that cover depths outside the Marcellus Formation shall not be Subject Assets or subject to this Agreement.

“Tax Partnership” has the meaning set forth in Section 6.1.

“Tax Partnership Account” has the meaning set forth in the Acquisition Agreement.

“Tax Partnership Agreement” has the meaning set forth in the Acquisition Agreement.

“Tax Purposes” has the meaning set forth in Section 6.1.

“Termination Date” has the meaning set forth in Section 10.1.

“Third Party” or “Third Parties” means any Person not a Party or an Affiliate of a Party.

“Third Party Operating Agreement” means an operating agreement to which there are Persons other than (or in addition to) the Parties and a Party Operator that are parties and that burden certain of the Subject Assets within the Development Area.

Appendix I - 10

“Third Party Operator” means a Third Party under a Third Party Operating Agreement that is not a Party Operator.

“Total Amount” has the meaning set forth in the Acquisition Agreement.

“Total Amount in Default” means, as of any time, the following amounts:  (a) the amounts that the Defaulting Party has failed to pay under the terms of this Agreement (including, in the case of Noble, any amounts relating to a failure to pay the Total Amount) and the Associated Agreements as of such time; (b) all reasonable attorneys’ fees and other reasonable costs sustained in the collection of amounts owed by the Defaulting Party and (c) any interest at the Agreed Rate accrued on the amounts set forth in clauses (a) and (b).

“Total Cost Sharing Payments” means the sum of the Closing Cash Payment and the amounts described in Sections 3.1(b)(ii) and 3.1(b)(iii) of the Acquisition Agreement.

“Transfer(s)” or “Transferred” means any sale, assignment, pledge, encumbrance or other disposition by a Party of all or any part of its Joint Development Interest or the granting of any overriding royalty interest, production payment, net profits interest or other similar interest covering all or any part of a Party’s interest in the Subject Assets.

“Transferor” has the meaning set forth in Section 4.4(a).

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Internal Revenue Code of 1986, as amended.  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.

“Unit JOA” has the meaning set forth in Section 2.4(c).

“Unit JOA Memoranda” has the meaning set forth in Section 2.4(d).

“Wellhead Condensate Production” means, with respect to a Party, such Party’s and its Affiliates’ respective share of wellhead condensate produced and separated from any of their interests in the Subject Assets at the wellhead.

“Working Interest” means, with respect to any unit, well or lease, the interest that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such unit, well or lease, but without regard to the effect of any royalties, overriding royalties, production payments, net profits interests and other similar burdens upon, measured by, or payable out of production therefrom.

Appendix I - 11

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, Charles D. Davidson, 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 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:	October 20, 2011
/s/ Charles D. Davidson
Charles D. Davidson
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 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:	October 20, 2011
/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, 2011 (the “Report”), I, Charles D. Davidson, 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	October 20, 2011	/s/ Charles D. Davidson
		Charles D. Davidson
		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, 2011 (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	October 20, 2011	/s/ Kenneth M. Fisher
		Kenneth M. Fisher
		Chief Financial Officer

XML

Comprehensive Income (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Notes to Financial Statements [Abstract]
Net Income	$ 441	$ 232	$ 749	$ 673
Oil and Gas Cash Flow Hedges [Abstract]
Realized Losses Reclassified Into Earnings	0	5	0	15
Less Tax Provision	0	(2)	0	(5)
Interest Rate Cash Flow Hedges [Abstract]
Unrealized Change in Fair Value	0	(47)	23	(141)
Less Tax Provision	0	16	(8)	49
Net Change in Other	1	1	4	2
Other Comprehensive Income (Loss)	1	(27)	19	(80)
Comprehensive Income	$ 442	$ 205	$ 768	$ 593

XML

Consolidated Balance Sheets (unaudited) (USD $) In Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and Cash Equivalents	$ 1,252	$ 1,081
Accounts Receivable, Net	546	556
Other Current Assets	279	201
Total Assets, Current	2,077	1,838
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	17,180	14,393
Property, Plant and Equipment, Other	277	263
Total Property, Plant and Equipment, Gross	17,457	14,656
Accumulated Depreciation, Depletion and Amortization	(4,945)	(4,392)
Total Property, Plant and Equipment, Net	12,512	10,264
Goodwill	696	696
Other Noncurrent Assets	548	484
Total Assets	15,833	13,282
Current Liabilities
Accounts Payable - Trade	1,132	927
Other Current Liabilities	826	495
Total Liabilities, Current	1,958	1,422
Long-Term Debt	3,507	2,272
Deferred Income Taxes, Noncurrent	2,235	2,110
Other Noncurrent Liabilities	551	630
Total Liabilities	8,251	6,434
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 $3.33 1/3 per share; 250 Million Shares Authorized; 196 Million and 195 Million Shares Issued, Respectively	655	651
Additional Paid in Capital	2,467	2,385
Accumulated Other Comprehensive Loss	(85)	(104)
Treasury Stock, at Cost; 19 Million Shares	(640)	(624)
Retained Earnings	5,185	4,540
Total Shareholders' Equity	7,582	6,848
Total Liabilities and Shareholders' Equity	$ 15,833	$ 13,282

XML

Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $) In Millions, except Per Share data	Sep. 30, 2011	Dec. 31, 2010
Shareholders' Equity
Preferred stock, par value per share (in dollars per share)	$ 1.00	$ 1.00
Preferred stock, shares authorized (in shares)	4	4
Common stock, par value per share (in dollars per share)	$ 3.333	$ 3.333
Common stock, shares authorized (in shares)	250	250
Common stock, shares issued (in shares)	196	195
Treasury stock, shares (in shares)	19	19

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Commitments and Contingencies

Note 16.  Commitments and Contingencies

Legal Proceedings  We are involved in various legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

See also Part II. Other Information, Item 1. Legal Proceedingsfor further information on pending cases.

Marcellus Shale Joint Venture Partnership See Note 3. Acquisitions and Dispositions for a description of the CONSOL Carried Cost Obligation and  MARC.

XML

Document And Entity Information (USD $) In Billions, except Share data	9 Months Ended
	Sep. 30, 2011	Oct. 06, 2011	Jun. 30, 2010
Entity Registrant Name	NOBLE ENERGY INC
Entity Central Index Key	0000072207
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 10.4
Entity Common Stock, Shares Outstanding		176,645,583
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011

XML

Basic and Diluted Earnings Per Share (Details) (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Basic and Diluted Earnings Per Share [Abstract]
Net Income	$ 441		$ 232		$ 749		$ 673
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust	(12)	[1]	0	[1]	(10)	[1]	3	[1]
Net Income Used for Diluted Earnings Per Share Calculation	$ 429		$ 232		$ 739		$ 676
Weighted Average Number of Shares Outstanding, Basic (in shares)	177		175		176		175
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust (in shares)	3		2		3		3
Weighted Average Number of Shares Outstanding, Diluted (in shares)	180		177		179		178
Earnings Per Share, Basic (in dollars per share)	$ 2.50		$ 1.33		$ 4.25		$ 3.86
Earnings Per Share, Diluted (in dollars per share)	$ 2.39		$ 1.31		$ 4.12		$ 3.80
Number of antidilutive stock options and shares of restricted stock excluded from calculation above	1		2		2		2

[1] Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the NBL shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the three and nine months ended September 30, 2011 exclude deferred compensation gains, net of tax; and the diluted earnings per share calculation for the nine months ended September 30, 2010 excludes a deferred compensation loss, net of tax.

XML

Asset Impairments (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Asset Impairment Charges, Pre-tax (non-cash)

Pre-tax (non-cash) asset impairment charges were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
East Texas (Onshore US)	$	-	$	-	$	116	$	-
Iron Horse (Onshore US)		-		71		15		71
New Albany Shale (Onshore US)		-		19		-		19
Other		-		10		8		10
Total	$	-	$	100	$	139	$	100

XML

Stock-Based Compensation (Details) (USD $) In Millions, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Apr. 26, 2011
Stock-Based Compensation [Abstract]
Stock-Based Compensation Expense	$ 15	$ 13	$ 43	$ 40
Tax Benefit Recognized	$ (5)	$ (5)	$ (15)	$ (14)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Option and Restricted Stock Plan common stock authorized for issuance under the plan (in shares)					24,000,000
April 26, 2011 approved Stock Option and Restricted Stock Plan common stock authorized for issuance under the plan (in shares)					31,000,000
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock (in shares)			985,503
Weighted Average Fair Value of Restricted Stock (in dollars per share)			$ 30.18
Shares of Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock (in shares)			403,097
Weighted Average Fair Value of Restricted Stock (in dollars per share)			$ 90.34

XML

Debt

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Debt

Note 5. Debt

Our debt consists of the following:

	September 30,						December 31,
	2011						2010
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due December 9, 2012	$	400			0.56	%	$	350			0.57	%
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	%		-			-
FPSO Lease Obligation		351			-			295			-
5¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%
8¼% Senior Notes, due March 1, 2019		1,000			8.25	%		1,000			8.25	%
7¼% Notes, due October 15, 2023		100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%
6% Senior Notes, due March 1, 2041		850			6.00	%		-			-
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		3,891						2,279
Unamortized Discount		(29	)					(7	)
Total Debt, Net of Discount		3,862						2,272
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(322	)					-
FPSO Lease Obligation		(33	)					-
Long-Term Debt Due After One Year	$	3,507					$	2,272

CONSOL Installment Payments   On September 30, 2011, we closed an agreement with CONSOL for the development of Marcellus shale properties. In addition to the cash paid at closing, we agreed to make two installment payments of $328 million each on September 30, 2012 and 2013. The installment payments have been discounted at the prevailing market rates for similar debt instruments. The CONSOL installment loan is a non-cash financing activity.  See Note 3. Acquisitions and Divestitures and Note 7. Fair Value Measurements and Disclosures.

FPSO Lease Obligation   We have entered into an agreement to lease a floating production, storage and offloading vessel (FPSO) to be used in the development of the Aseng field, offshore Equatorial Guinea. The amount of the FPSO lease obligation is based on the discounted present value of future minimum lease payments and the percentage of construction activities completed as of the reporting dates, and therefore does not reflect future minimum lease payments. The increase in the FPSO lease obligation is a non-cash financing activity. Amounts due within one year equal the amount by which the FPSO lease obligation is expected to be reduced during the next 12 months as lease payments begin. We currently expect production to commence, and lease payments to begin, by year end 2011.

Issuance of 6% Senior Notes   On February 18, 2011, we closed an offering of $850 million senior unsecured notes receiving net proceeds of $836  million, after deducting discount and underwriting fees. The notes are due March 1, 2041, and pay interest semi-annually at 6%. Total debt issuance costs of approximately $9 million were incurred and are being amortized to expense over the term of the notes. Approximately $470 million of the net proceeds were used to repay outstanding indebtedness under our revolving credit facility and the balance of the proceeds will be used for general corporate purposes. The notes are senior unsecured debt and rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest. See Note 6. Derivative Instruments and Hedging Activities –Interest Rate Derivative Instrument.

Annual Debt Maturities and FPSO Lease Payments    Annual maturities of outstanding debt and estimated annual FPSO lease payments are as follows:

	Debt Principal Payments		FPSO Lease Payments
(millions)
September 30, 2011
2011	$	-	$	12
2012		728		72
2013		328		72
2014		200		72
2015		-		70
Thereafter		2,284		198
Total	$	3,540	$	496

New Credit Facility    On October 14, 2011, we entered into a credit agreement with certain commercial lending institutions (the Credit Agreement) which provides for a new $3.0 billion unsecured five-year revolving credit facility (the New Credit Facility). The New Credit Facility replaces our $2.1 billion credit facility maturing December 9, 2012. Also on October 14, 2011, we borrowed $400 million under the New Credit Facility, which was used to repay outstanding borrowings under and to terminate the $2.1 billion credit facility.

The New Credit Facility (i) provides for an initial commitment of $3.0 billion with an option to increase the overall commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, (ii) will mature on October 14, 2016, (iii) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (iv) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iv) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.

The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the New Credit Facility and require the immediate repayment of any outstanding advances under the New Credit Facility. The Credit Agreement does not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby.

The New Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

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Debt (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Debt

Our debt consists of the following:

	September 30,						December 31,
	2011						2010
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due December 9, 2012	$	400			0.56	%	$	350			0.57	%
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	%		-			-
FPSO Lease Obligation		351			-			295			-
5¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%
8¼% Senior Notes, due March 1, 2019		1,000			8.25	%		1,000			8.25	%
7¼% Notes, due October 15, 2023		100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%
6% Senior Notes, due March 1, 2041		850			6.00	%		-			-
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		3,891						2,279
Unamortized Discount		(29	)					(7	)
Total Debt, Net of Discount		3,862						2,272
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(322	)					-
FPSO Lease Obligation		(33	)					-
Long-Term Debt Due After One Year	$	3,507					$	2,272

Annual maturities of outstanding debt

Annual Debt Maturities and FPSO Lease Payments    Annual maturities of outstanding debt and estimated annual FPSO lease payments are as follows:

	Debt Principal Payments		FPSO Lease Payments
(millions)
September 30, 2011
2011	$	-	$	12
2012		728		72
2013		328		72
2014		200		72
2015		-		70
Thereafter		2,284		198
Total	$	3,540	$	496

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Fair Value Measurements and Disclosures (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	$ 101				$ 101				$ 112
Commodity Derivative Instruments	131				131				62
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	(6)				(6)				(75)
Interest Rate Derivative Instrument	0				0				(63)
Portion of Deferred Compensation Liability Measured at Fair Value	(152)				(152)				(178)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Impaired Oil and Gas Properties	0		100		139		100
Quoted Prices in Active Markets (Level 1) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	101	[1]			101	[1]			112	[1]
Commodity Derivative Instruments	0	[1]			0	[1]			0	[1]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	0	[1]			0	[1]			0	[1]
Interest Rate Derivative Instrument	0	[1]			0	[1]			0	[1]
Portion of Deferred Compensation Liability Measured at Fair Value	(152)	[1]			(152)	[1]			(178)	[1]
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Impaired Oil and Gas Properties	0		0		0		0
Significant Other Observable Inputs (Level 2) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[2]			0	[2]			0	[2]
Commodity Derivative Instruments	174	[2]			174	[2]			106	[2]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	(49)	[2]			(49)	[2]			(119)	[2]
Interest Rate Derivative Instrument	0	[2]			0	[2]			(63)	[2]
Portion of Deferred Compensation Liability Measured at Fair Value	0	[2]			0	[2]			0	[2]
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Impaired Oil and Gas Properties	0		0		0		0
Significant Unobservable Inputs (Level 3) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[3]			0	[3]			0	[3]
Commodity Derivative Instruments	0	[3]			0	[3]			0	[3]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	0	[3]			0	[3]			0	[3]
Interest Rate Derivative Instrument	0	[3]			0	[3]			0	[3]
Portion of Deferred Compensation Liability Measured at Fair Value	0	[3]			0	[3]			0	[3]
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Impaired Oil and Gas Properties	0		48		32		48
Fair Value Inputs Adjustment [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[4]			0	[4]			0	[4]
Commodity Derivative Instruments	(43)	[4]			(43)	[4]			(44)	[4]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	43	[4]			43	[4]			44	[4]
Interest Rate Derivative Instrument	0	[4]			0	[4]			0	[4]
Portion of Deferred Compensation Liability Measured at Fair Value	0	[4]			0	[4]			0	[4]
Net Book Value [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Impaired Oil and Gas Properties	0	[5]	148	[5]	171	[5]	148	[5]
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Net of Unamortized Discount	3,511	[6]			3,511	[6]			1,977	[6]
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Net of Unamortized Discount	$ 4,031	[6]			$ 4,031	[6]			$ 2,302	[6]

[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 master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.

[5] Amount represents net book value at date of assessment.

[6] Excludes FPSO lease obligation.

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Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Other Revenues [Abstract]
Electricity Sales	$ 0	[1]	$ 19	[1]	$ 32	[1]	$ 53	[1]
Other	0		(2)		1		(1)
Total	0		17		33		52
Production Expense [Abstract]
Lease Operating Expense	98		95		288		283
Production and Ad Valorem Taxes	38		29		108		96
Transportation Expense	17		17		53		51
Total	153		141		449		430
Other Operating (Income) Expense, Net [Abstract]
Deepwater Gulf of Mexico Moratorium Expense	(1)	[2]	0	[2]	18	[2]	27	[2]
Electricity Generation Expense	0	[1]	9	[1]	26	[1]	26	[1]
Loss on Involuntary Conversion	0	[3]	0	[3]	4	[3]	0	[3]
Other, Net	3		(5)		(3)		6
Total	2		4		45		59
Other Non-Operating (Income) Expense, Net [Abstract]
Deferred Compensation (Income) Expense	(18)	[4]	15	[4]	(15)	[4]	4	[4]
Interest Income	(2)		(1)		(7)		(4)
Other (Income) Expense, Net	4		(2)		6		(1)
Total	(16)		12		(16)		(1)
Accounts Receivable, Net [Abstract]
Commodity Sales	228				228				291
Joint Interest Billings	253				253				259
Other	73				73				33
Allowance for Doubtful Accounts	(8)	[5]			(8)	[5]			(27)	[5]
Total	546				546				556
Other Current Assets [Abstract]
Inventories, Current	120				120				112
Commodity Derivative Assets, Current	87				87				62
Deferred Income Taxes, Net, Current	15	[6]			15	[6]			8	[6]
Probable Insurance Claims	25	[6]			25	[6]			0	[6]
Prepaid Expenses and Other Assets, Current	32				32				19
Total	279				279				201
Other Noncurrent Assets [Abstract]
Equity Method Investments	339	[7]			339	[7]			285	[7]
Mutual Fund Investments	101				101				112
Commodity Derivative Assets, Noncurrent	44				44				0
Other Assets, Noncurrent	64				64				87
Total	548				548				484
Other Current Liabilities [Abstract]
Production and Ad Valorem Taxes	128				128				110
Commodity Derivative Liabilities, Current	6				6				24
Interest Rate Derivative Liability, Current	0				0				63
Income Taxes Payable	143				143				90
Asset Retirement Obligations, Current	45				45				45
Interest Payable	18				18				36
CONSOL Installment Payment	322	[8]			322	[8]			0	[8]
Current Portion of FPSO Lease Obligation	33				33				0
Other	131				131				127
Total	826				826				495
Other Noncurrent Liabilities [Abstract]
Deferred Compensation Liabilities, Noncurrent	210				210				229
Asset Retirement Obligations, Noncurrent	215				215				208
Accrued Benefit Costs, Noncurrent	63				63				76
Commodity Derivative Liabilities, Noncurrent	0				0				51
Other	63				63				66
Total	$ 551				$ 551				$ 630
Interest in CONE Gathering LLC	50.00%				50.00%

[1] Electricity sales include sales from the Machala power plant located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. See Note 3. Acquisitions and Divestitures.

[2] Amounts relate to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011 and costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the deepwater Gulf of Mexico drilling moratorium in 2010.

[3] The loss on involuntary conversion represents our insurance deductible related to the Leviathan-2 appraisal well control incident. We suspended operations on the Leviathan-2 well, offshore Israel, in May 2011 when we identified water flowing to the sea floor from the wellbore. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. See footnote (2) below.

[4] Amount represents increases (decreases) in the fair value of shares of our common stock held in a rabbi trust.

[5] The decrease in the allowance for doubtful accounts from December 31, 2010 is due primarily to the transfer of assets to the Ecuadorian government. See Note 3. Acquisitions and Divestitures.

[6] Amount represents the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible. See footnote (3) above.

[7] The increase in equity method investments from December 31, 2010 is due to our acquisition of a 50% interest in CONE Gathering LLC. See Note 3. Acquisitions and Divestitures.

[8] See Note 3. Acquisitions and Divestitures and Note 5. Debt.

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Purchase Price Allocation of Acquisition

As a result of the transaction, we recorded the following:

	September 30,
	2011
(millions)
Unproved Oil and Gas Properties	$	790
Proved Oil and Gas Properties		370
Investment in CONE Gathering LLC		73
Total Assets Acquired (1)	$	1,233

(1) Total reflects impact of discount on remaining installment payments. See Note 5. Debt.

Sale of Onshore US Assets

In August 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. Information regarding the sale is as follows:

	Nine Months Ended September 30,
	2010
(millions)
Cash Proceeds	$	552
Less
Net Book Value of Assets Sold		(394	)
Goodwill Allocated to Assets Sold		(61	)
Asset Retirement Obligations Associated with Assets Sold		10
Other Closing Adjustments		7
Gain on Asset Sale	$	114

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 10.   Employee Benefit Plans

We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. Net periodic benefit cost related to the retirement and restoration plans was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Service Cost	$	3		$	4		$	10		$	11
Interest Cost		3			3			10			10
Expected Return on Plan Assets		(4	)		(3	)		(11	)		(10	)
Other		2			1			5			4
Net Periodic Benefit Cost	$	4		$	5		$	14		$	15

During the nine months ended September 30, 2011, we made cash contributions of $23 million to the pension plan.

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Organization and Nature of Operations

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Organization and Nature of Operations

Note 1.  Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our key operating areas are onshore in the US, primarily in the DJ Basin and the Marcellus shale, in the deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Income tax provision (benefit)

The income tax provision consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Current	$	179		$	42		$	289		$	180
Deferred		102			24			147			109
Total Income Tax Provision	$	281		$	66		$	436		$	289
Effective Tax Rate		39	%		22	%		37	%		30	%

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Fair Value Measurements and Disclosures

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Fair Value Measurements and Disclosures

Note 7.  Fair Value Measurements and Disclosures

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

Mutual Fund Investments   Our mutual fund investments, which primarily include assets held in a rabbi trust, 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 consist of variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps. We estimate the fair values of these instruments based on 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 (for three-way collars) and the contract floors and ceilings (for two-way and three-way collars) using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 6. Derivative Instruments and Hedging Activities.

Interest Rate Derivative Instrument   We estimated the fair value of our forward starting swap based on published interest rate yield curves as of the date of the estimate. The fair values of interest rate derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of interest rate derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. 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.

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, 2011
Financial Assets
Mutual Fund Investments	$	101			$	-		$	-	$	-		$	101
Commodity Derivative Instruments		-				174			-		(43	)		131
Financial Liabilities
Commodity Derivative Instruments		-				(49	)		-		43			(6	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(152	)			-			-		-			(152	)
December 31, 2010
Financial Assets
Mutual Fund Investments	$	112			$	-		$	-	$	-		$	112
Commodity Derivative Instruments		-				106			-		(44	)		62
Financial Liabilities
Commodity Derivative Instruments		-				(119	)		-		44			(75	)
Interest Rate Derivative Instrument		-				(63	)		-		-			(63	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(178	)			-			-		-			(178	)

(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 master netting 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:

Asset Impairments   We determined that the carrying amounts of certain onshore US assets were not recoverable from future cash flows and, therefore, were impaired.  The assets were reduced to their estimated fair values. Information about the impaired assets is as follows:

	Fair Value Measurements Using
Description	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)
Three Months Ended September 30, 2011
Impaired Oil and Gas Properties	$	-	$	-	$	-	$	-	$	-
Three Months Ended September 30, 2010
Impaired Oil and Gas Properties		-		-		48		148		100
Nine Months Ended September 30, 2011
Impaired Oil and Gas Properties	$	-	$	-	$	32	$	171	$	139
Nine Months Ended September 30, 2010
Impaired Oil and Gas Properties		-		-		48		148		100

(1) Amount represents net book value atdate of assessment.

The fair values of the properties were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management's expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate. See Note 4. Asset Impairments.

Additional Fair Value Disclosures

Debt   The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues.  The carrying amounts of floating-rate debt approximate fair value because the interest rate paid on such debt was set for periods of three months or less. The carrying amounts of the CONSOL installment payments approximate fair value because they have been discounted at the prevailing market rates for similar instruments. See Note 5. Debt. Fair value information regarding our debt is as follows:

	September 30,				December 31,
	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	3,511	$	4,031	$	1,977	$	2,302

(1) Excludes FPSO lease obligation.

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Basic and Diluted Earnings Per Share

9 Months Ended

Sep. 30, 2011

Basic and Diluted Earnings Per Share [Abstract]

Basic and Diluted Earnings Per Share

Note 12.  Basic and Diluted Earnings Per Share

Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock may include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings per share:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
(millions, except per share amounts)
Net Income	$	441		$	232	$	749		$	673
Earnings Adjustment from Assumed Conversion of
Dilutive Shares of Common Stock in Rabbi Trust (1)		(12	)		-		(10	)		3
Net Income Used for Diluted Earnings Per Share Calculation	$	429		$	232	$	739		$	676
Weighted Average Number of Shares Outstanding, Basic		177			175		176			175
Incremental Shares from Assumed Conversion of
Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust		3			2		3			3
Weighted Average Number of Shares Outstanding, Diluted		180			177		179			178
Earnings Per Share, Basic	$	2.50		$	1.33	$	4.25		$	3.86
Earnings Per Share, Diluted		2.39			1.31		4.12			3.80
Number of antidilutive stock options and shares of restricted
stock excluded from calculation above		1			2		2			2

(1) Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the NBL shares held in the rabbi trust are included in the diluted share count.  For this reason, the diluted earnings per share calculations for the three and nine months ended September 30, 2011 exclude deferred compensation gains, net of tax; and the diluted earnings per share calculation for the nine months ended September 30, 2010 excludes a deferred compensation loss, net of tax.

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Capitalized Exploratory Well Costs

9 Months Ended

Sep. 30, 2011

Capitalized Exploratory Well Costs [Abstract]

Capitalized Exploratory Well Costs

Note 8.  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:

	Nine Months Ended September 30,
(millions)
Capitalized Exploratory Well Costs, Beginning of Period		$	466
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves			158
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1)			(55	)
Capitalized Exploratory Well Costs Charged to Expense			(15	)
Capitalized Exploratory Well Costs, End of Period		$	554

(1) Includes $13 million related to the Flyndre project in the North Sea.

The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	September 30,		December 31,
	2011			2010
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	196	$	166
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling		358		300
Balance at End of Period	$	554	$	466
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling		10		9

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of September 30, 2011:

			Suspended Since
	Total		2010		2009		2008 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	113	$	7	$	19	$	87
Offshore Cameroon
YoYo		39		1		2		36
Offshore Israel
Dalit		22		1		21		-
Deepwater Gulf of Mexico
Deep Blue		73		54		19		-
Gunflint		58		2		6		50
Redrock		21		1		2		18
North Sea
Selkirk		23		1		1		21
Other
3 projects of $10 million or less each		9		9		-		-
Total	$	358	$	76	$	70	$	212

Blocks O and I   Blocks O and I are crude oil, natural gas and natural gas condensate discoveries. During third quarter 2011 we continued to evaluate results of the appraisal well at the Carmen/Diega prospect.

YoYo   YoYo is a 2007 natural gas and condensate discovery.  We have acquired and processed additional 3-D seismic information.

Dalit   Dalit is a 2009 natural gas discovery. We are currently working with our partners on a cost-effective development plan.

Deep Blue   Deep Blue (Green Canyon Block 723) is an exploratory well which found hydrocarbon pay in multiple intervals. When the deepwater Gulf of Mexico moratorium was announced in May 2010, we were required to suspend sidetrack drilling activities.  During third quarter 2011, we obtained approval for a drilling permit and resumed exploration drilling.

Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. Our plans to conduct appraisal drilling activities in 2010 were delayed by the deepwater Gulf of Mexico moratorium. Once a drilling permit is approved, we plan to resume drilling activities. We are also reviewing host platform options.

Redrock   Redrock (Mississippi Canyon Block 204) is a 2006 natural gas/condensate discovery and is currently considered a co-development candidate with Raton South (Mississippi Canyon Block 292). We are in the process of developing Raton South as a subsea tieback to a host platform at Viosca Knoll Block 900.  We plan to develop Redrock after Raton South commences production, which is currently expected to occur by the end of 2011.

Selkirk   The Selkirk project is located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans [Abstract]

Net periodic benefit cost related to retirement and restoration plans

Net periodic benefit cost related to the retirement and restoration plans was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Service Cost	$	3		$	4		$	10		$	11
Interest Cost		3			3			10			10
Expected Return on Plan Assets		(4	)		(3	)		(11	)		(10	)
Other		2			1			5			4
Net Periodic Benefit Cost	$	4		$	5		$	14		$	15

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Derivative Instruments and Hedging Activities

Note 6.  Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   In order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, two-way and three-way collars, and basis swaps.

The fixed price swap, two-way collar, and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.

A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar.  We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.

Wealso enter into forward contracts or swap agreements to hedge exposure to interest rate risk.

While these instruments mitigate the cash flow risk of future reductions in commodity prices or increases in interest rates, they may also curtail benefits from future increases in commodity prices or decreases in interest rates.

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

Counterparty Credit Risk   Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of highly rated major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts 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 settled at the time of election.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties' creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices or higher interest rates, and could incur a loss.

Interest Rate Derivative Instrument   In January 2010, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on our anticipated debt issuance. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million. Approximately $26 million, net of tax, was recorded in accumulated other comprehensive loss (AOCL) and is being reclassified to interest expense over the term of the 6% senior notes. The ineffective portion of the interest rate swap was de minimis. See Note 5. Debt.

Unsettled Derivative Instruments As of September 30, 2011, we had entered into the following crude oil derivative instruments:  

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX WTI (1)		5,000	$	85.52	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX WTI		13,000		-		-		80.15		94.63
2011	Three-Way Collars	NYMEX WTI		12,000		-		58.33		78.33		100.71
2012	Swaps	NYMEX WTI		5,000		91.84		-		-		-
2012	Swaps	Dated Brent		8,000		89.06		-		-		-
2012	Three-Way Collars	NYMEX WTI		23,000		-		61.09		83.04		101.66
2012	Three-Way Collars	Dated Brent		3,000		-		70.00		95.83		105.00
2013	Swaps	Dated Brent		3,000		98.03		-		-		-
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		5,000		-		80.00		99.71		127.32
Instruments Entered Into During October 1-15, 2011
2013	Three-Way Collars	Dated Brent		5,000		-		90.00		102.00		128.15

(1) West Texas Intermediate

As of September 30, 2011, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX HH (1)		25,000	$	6.41	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX HH		140,000		-		-		5.95		6.82
2011	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.00		6.70
2012	Swaps	NYMEX HH		30,000		5.10		-		-		-
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.25		5.59

(1) Henry Hub

As of September 30, 2011, we had entered into the following natural gas basis swaps:

Period	Index	Index Less Differential	MMBtu Per Day	Weighted Average Differential
2011	IFERC CIG (1)	NYMEX HH	140,000	$	(0.70)
2012	IFERC CIG	NYMEX HH	150,000		(0.52)

(1) Colorado Interstate Gas – Northern System

Fair Value Amounts and Gains and Losses on Derivative Instruments   The fair values of derivative instruments in our consolidated balance sheets were as follows:

Fair Value of Derivative Instruments

	Asset Derivative Instruments						Liability Derivative Instruments
	September 30,			December 31,			September 30,			December 31,
	2011			2010			2011			2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
(millions)
Commodity Derivative Instruments (Not Designated as Hedging Instruments)	Current Assets	$	87	Current Assets	$	62	Current Liabilities	$	6	Current Liabilities	$	24
	Noncurrent Assets		44	Noncurrent Assets		-	Noncurrent Liabilities		-	Noncurrent Liabilities		51
Interest Rate Derivative Instruments (Designated as Hedging Instruments)	Current Assets		-	Current Assets		-	Current Liabilities		-	Current Liabilities		63
Total		$	131		$	62		$	6		$	138

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

Commodity Derivative Instruments Not Designated as Hedging Instruments

Amount of Gain on Derivative Instruments Recognized in Income

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Realized Mark-to-Market Gain	$	(22	)	$	(33	)	$	(39	)	$	(65	)
Unrealized Mark-to-Market Gain		(300	)		(5	)		(140	)		(215	)
Total Gain on Commodity Derivative Instruments	$	(322	)	$	(38	)	$	(179	)	$	(280	)

Derivative Instruments in Cash Flow Hedging Relationships

	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss						Amount of (Gain) Loss on Derivative Instruments Reclassified from  Accumulated Other Comprehensive Loss
		2011			2010		2011		2010
(millions)
Three Months Ended September 30,
Commodity Derivative Instruments in Previously Designated
Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	5
Natural Gas Derivative Instruments			-			-		-		-
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			-			47		-		-
Total		$	-		$	47	$	-	$	5
Nine Months Ended September 30,
Commodity Derivative Instruments in Previously Designated
Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	14
Natural Gas Derivative Instruments			-			-		-		1
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			(23	)		141		1		-
Total		$	(23	)	$	141	$	1	$	15

(1) Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.

AOCL at September 30, 2011 included deferred losses of $27 million, net of tax, related to interest rate derivative instruments. This amount will be reclassified to earnings as an adjustment to interest expense over the terms of our senior notes due April 2014 and March 2041.  Approximately $2 million of deferred losses (net of tax) will be reclassified to earnings during the next 12 months and will be recorded as an increase in interest expense.

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Consolidated Statements of Shareholders' Equity (unaudited) (USD $) In Millions	Total	Common Stock [Member]	Additional Paid in Capital [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock at Cost [Member]	Retained Earnings [Member]
Balance at Dec. 31, 2009	$ 6,157	$ 645	$ 2,260	$ (75)	$ (615)	$ 3,942
Net Income	673	0	0	0	0	673
Stock-based Compensation	40	0	40	0	0	0
Exercise of Stock Options	35	3	32	0	0	0
Tax Benefits Related to Exercise of Stock Options	19	0	19	0	0	0
Restricted Stock Awards, Net	0	2	(2)	0	0	0
Dividends	(95)	0	0	0	0	(95)
Changes in Treasury Stock, Net	(12)	0	0	0	(12)	0
Oil and Gas Cash Flow Hedges
Realized Amounts Reclassified Into Earnings	10	0	0	10	0	0
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value	(92)	0		(92)
Net Change in Other	2	0	0	2	0	0
Balance at Sep. 30, 2010	6,737	650	2,349	(155)	(627)	4,520
Balance at Dec. 31, 2010	6,848	651	2,385	(104)	(624)	4,540
Net Income	749	0	0	0	0	749
Stock-based Compensation	43	0	43	0	0	0
Exercise of Stock Options	32	2	30	0	0	0
Tax Benefits Related to Exercise of Stock Options	11	0	11	0	0	0
Restricted Stock Awards, Net	0	2	(2)	0	0	0
Dividends	(104)	0	0	0	0	(104)
Changes in Treasury Stock, Net	(16)	0	0	0	(16)	0
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value	15	0	0	15	0	0
Net Change in Other	4	0	0	4	0	0
Balance at Sep. 30, 2011	$ 7,582	$ 655	$ 2,467	$ (85)	$ (640)	$ 5,185

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Basis of Presentation

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Basis of Presentation

Note 2.  Basis of Presentation

Presentation   The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2011 and December 31, 2010 and for the three and nine months ended September 30, 2011 and 2010 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. Operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. 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, 2010.

Consolidation   Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries.  In addition, we use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.

Estimates   The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Other Revenues
Electricity Sales (1)	$	-		$	19		$	32		$	53
Other		-			(2	)		1			(1	)
Total	$	-		$	17		$	33		$	52
Production Expense
Lease Operating Expense	$	98		$	95		$	288		$	283
Production and Ad Valorem Taxes		38			29			108			96
Transportation Expense		17			17			53			51
Total	$	153		$	141		$	449		$	430
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	(1	)	$	-		$	18		$	27
Electricity Generation Expense (1)		-			9			26			26
Loss on Involuntary Conversion (3)		-			-			4			-
Other, Net		3			(5	)		(3	)		6
Total	$	2		$	4		$	45		$	59
Other Non-Operating (Income) Expense, Net
Deferred Compensation (Income) Expense (4)	$	(18	)	$	15		$	(15	)	$	4
Interest Income		(2	)		(1	)		(7	)		(4	)
Other (Income) Expense, Net		4			(2	)		6			(1	)
Total	$	(16	)	$	12		$	(16	)	$	(1	)

(1) Electricity sales include sales from the Machala power plant located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts.  See Note 3. Acquisitions and Divestitures.

(2) Amounts relate to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011 and costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the deepwater Gulf of Mexico drilling moratorium in 2010.

(3) The loss on involuntary conversion represents our insurance deductible related to the Leviathan-2 appraisal well control incident. We suspended operations on the Leviathan-2 well, offshore Israel, in May 2011 when we identified water flowing to the sea floor from the wellbore. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. See footnote (2) below.

(4) Amount represents increases (decreases) 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:

	September 30,			December 31,
	2011			2010
(millions)
Accounts Receivable, Net
Commodity Sales	$	228		$	291
Joint Interest Billings		253			259
Other		73			33
Allowance for Doubtful Accounts (1)		(8	)		(27	)
Total	$	546		$	556
Other Current Assets
Inventories, Current	$	120		$	112
Commodity Derivative Assets, Current		87			62
Deferred Income Taxes, Net, Current		15			8
Probable Insurance Claims (2)		25			-
Prepaid Expenses and Other Assets, Current		32			19
Total	$	279		$	201
Other Noncurrent Assets
Equity Method Investments (3)	$	339		$	285
Mutual Fund Investments		101			112
Commodity Derivative Assets, Noncurrent		44			-
Other Assets, Noncurrent		64			87
Total	$	548		$	484
Other Current Liabilities
Production and Ad Valorem Taxes	$	128		$	110
Commodity Derivative Liabilities, Current		6			24
Interest Rate Derivative Liability, Current		-			63
Income Taxes Payable		143			90
Asset Retirement Obligations, Current		45			45
Interest Payable		18			36
CONSOL Installment Payment (4)		322			-
Current Portion of FPSO Lease Obligation		33			-
Other		131			127
Total	$	826		$	495
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	210		$	229
Asset Retirement Obligations, Noncurrent		215			208
Accrued Benefit Costs, Noncurrent		63			76
Commodity Derivative Liabilities, Noncurrent		-			51
Other		63			66
Total	$	551		$	630

(1) The decrease in the allowance for doubtful accounts from December 31, 2010 is due primarily to the transfer of assets to the Ecuadorian government. See Note 3.  Acquisitions and Divestitures.

(2) Amount represents the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible. See footnote (3) above.

(3) The increase in equity method investments from December 31, 2010 is due to our acquisition of a 50% interest in CONE Gathering LLC. See Note 3. Acquisitions and Divestitures.

(4) See Note 3. Acquisitions and Divestitures and Note 5. Debt.

Recently Issued Accounting Standards Updates   In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position and results of operations.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05: Comprehensive Income (Topic 220): Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 provides that an entity that reports items of other comprehensive income has the option to present comprehensive income in either one continuous financial statement or two consecutive financial statements. ASU 2011-05 is effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of ASU 2011-05. We do not expect ASU 2011-05 to have any impact on our financial position and results of operations as it is a change in presentation only.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08: Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment (ASU 2011-08).ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. Under ASU 2011-08, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 is effective for annual periods beginning after December 15, 2011. We expect to adopt the provisions of ASU 2011-08 for our annual impairment test as of December 31, 2011. We do not expect ASU 2011-08 to have any impact on our financial position and results of operations as it is a change in application of the goodwill impairment test only.

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Asset Impairments (Details) (USD $) In Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Impaired Long-Lived Assets Held and Used [Line Items]
Total - Impairment of Oil and Gas Properties	$ 0	$ 100	[1]	$ 139	[1]	$ 100	[1]
East Texas [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Total - Impairment of Oil and Gas Properties	0	0		116		0
Iron Horse [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Total - Impairment of Oil and Gas Properties	0	71		15		71
New Albany Shale [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Total - Impairment of Oil and Gas Properties	0	19		0		19
Other Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Total - Impairment of Oil and Gas Properties	$ 0	$ 10		$ 8		$ 10

[1] See Note 4. Asset Impairments.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Changes in Asset Retirement Obligations

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

	Nine Months Ended September 30,
	2011			2010
(millions)
Asset Retirement Obligations, Beginning Balance	$	253		$	232
Liabilities Incurred		2			14
Liabilities Settled		(19	)		(35	)
Revision of Estimate		9			11
Accretion Expense		15			13
Asset Retirement Obligations, Ending Balance	$	260		$	235

XML

Segment Information (Details) (USD $) In Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Segment Reporting Information [Line Items]
Revenues from Third Parties	$ 874	$ 726		$ 2,632		$ 2,169
Reclassification from AOCL		(5)	[1]			(15)	[1]
Income from Equity Method Investees	50	34		146		85
Total	924	755		2,778		2,239
DD&A	225	231		681		662
Gain on Divestitures	0	(114)	[2]	(26)	[2]	(114)	[2]
Asset Impairments	0	100	[3]	139	[3]	100	[3]
(Gain) Loss on Commodity Derivative Instruments	(322)	(38)		(179)		(280)
Income (Loss) Before Income Taxes	722	298		1,185		962
Goodwill	696			696				696
Total Assets	15,833			15,833				13,282
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	520	458		1,578		1,425
Reclassification from AOCL		(5)	[1]			(15)	[1]
Income from Equity Method Investees	0	0		0		0
Total	520	453		1,578		1,410
DD&A	180	184		534		543
Gain on Divestitures		(114)	[2]	(1)	[2]	(114)	[2]
Asset Impairments		100	[3]	137	[3]	100	[3]
(Gain) Loss on Commodity Derivative Instruments	(213)	(49)		(163)		(277)
Income (Loss) Before Income Taxes	418	211		631		681
Goodwill	696			696				696
Total Assets	10,921			10,921				9,091
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	153	64		401		243
Reclassification from AOCL		0	[1]			0	[1]
Income from Equity Method Investees	50	34		146		85
Total	203	98		547		328
DD&A	13	10		30		28
Gain on Divestitures		0	[2]	0	[2]	0	[2]
Asset Impairments		0	[3]	0	[3]	0	[3]
(Gain) Loss on Commodity Derivative Instruments	(109)	11		(16)		(3)
Income (Loss) Before Income Taxes	270	64		460		258
Goodwill	0			0				0
Total Assets	2,544			2,544				2,270
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	108	63		236		144
Reclassification from AOCL		0	[1]			0	[1]
Income from Equity Method Investees	0	0		0		0
Total	108	63		236		144
DD&A	8	7		19		18
Gain on Divestitures		0	[2]	0	[2]	0	[2]
Asset Impairments		0	[3]	0	[3]	0	[3]
(Gain) Loss on Commodity Derivative Instruments	0	0		0		0
Income (Loss) Before Income Taxes	88	51		184		110
Goodwill	0			0				0
Total Assets	1,540			1,540				919
North Sea [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	45	99		271		227
Reclassification from AOCL		0	[1]			0	[1]
Income from Equity Method Investees	0	0		0		0
Total	45	99		271		227
DD&A	10	20		62		45
Gain on Divestitures		0	[2]	0	[2]	0	[2]
Asset Impairments		0	[3]	2	[3]	0	[3]
(Gain) Loss on Commodity Derivative Instruments	0	0		0		0
Income (Loss) Before Income Taxes	23	59		161		132
Goodwill	0			0				0
Total Assets	625			625				770
Other International And Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	48	42		146		130
Reclassification from AOCL		0	[1]			0	[1]
Income from Equity Method Investees	0	0		0		0
Total	48	42		146		130
DD&A	14	10		36		28
Gain on Divestitures		0	[2]	(25)	[2]	0	[2]
Asset Impairments		0	[3]	0	[3]	0	[3]
(Gain) Loss on Commodity Derivative Instruments	0	0		0		0
Income (Loss) Before Income Taxes	(77)	(87)		(251)		(219)
Goodwill	0			0				0
Total Assets	$ 203			$ 203				$ 232

[1] Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues. All hedge gains and losses had been reclassified to revenues by December 31, 2010.

[2] See Note 3. Acquisitions and Divestitures.

[3] See Note 4. Asset Impairments.

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Acquisitions and Divestitures

Note 3.   Acquisitions and Divestitures

Marcellus Shale Joint Venture Partnership On September 30, 2011, we closed an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) for the development of Marcellus shale properties in southwest Pennsylvania and northwest West Virginia. Under the agreement, we acquired  50% interests in 628,000 net undeveloped acres, existing Marcellus production, and existing infrastructure for approximately $1.2 billion. We and CONSOL formed CONE Gathering LLC, which we will account for using the equity method, to own and operate existing and future infrastructure.

We paid a total of $592 million in cash at the closing of the above transaction, funded with available cash and amounts drawn under our credit facility. In addition, we will make two additional installment payments of $328 million each, which will be paid September 30, 2012 and 2013.

In addition, we have agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, up to approximately $2.1 billion (CONSOL Carried Cost Obligation). The CONSOL Carried Cost Obligation is expected to extend over an eight-year period. It is capped at $400 million in each calendar year and will be suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Therefore, specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time. Amounts paid pursuant to the CONSOL Carried Cost Obligation will be recorded as increases in property, plant and equipment in our consolidated balance sheets and as investing activities in our consolidated statements of cash flows.

As a result of the transaction, we recorded the following:

	September 30,
	2011
(millions)
Unproved Oil and Gas Properties	$	790
Proved Oil and Gas Properties		370
Investment in CONE Gathering LLC		73
Total Assets Acquired (1)	$	1,233

(1) Total reflects impact of discount on remaining installment payments. See Note 5. Debt.

To estimate the fair value of the proved oil and gas properties as of the acquisition date, we used an income approach. We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:

· estimated quantities of crude oil and natural gas prepared by our qualified petroleum engineers;

· management's estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;

· estimated future production rates based on our experience with similar properties which we operate; and

· estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.

We discounted the resulting future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. The fair value of the proved producing properties is considered a Level 3 fair value measurement.

Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.

See Note 5. Debt and Note 7. Fair Value Measurements and Disclosures.

Gas Gathering Agreement with CONE Gathering LLC   On September 30, 2011, in connection with the Marcellus shale joint venture arrangement described above, we entered into a 50-year gathering and marketing agreement with CONE Gathering LLC. Under the terms of the gathering and marketing agreement, we will pay CONE Gathering LLC a minimum annual revenue commitment (MARC). The fee will be adjusted annually based on projected gathering volumes, operating expenses, capital expenditures, and other factors. We expect the MARC to total approximately $3 million in 2011 and $23 million in 2012. Amounts to be paid under the MARC for years beyond 2012 have not yet been determined.

We also have agreed to fund an annual work program for the construction of additional pipeline assets to receive and deliver production from future wells. Amounts to be contributed in future years to fund our proportionate share of the annual work program will be dependent upon anticipated production locations, volumes and other factors.  We will account for our 50% interest in CONE Gathering LLC using the equity method; therefore, our share of income will be reported as income from equity method investees in our consolidated statements of operations. Our investment in CONE Gathering LLC will be reported as investment in equity method investee in our consolidated balance sheets and will reflect our cash contributions to the entity.

Divestitures In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.  We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets and Block 3 production sharing contract (PSC), which was terminated by the government of Ecuador on November 25, 2010, and the assignment of the Machala Power Electricity concession and its associated assets. Our net book value for the assets had been reduced due to previous impairment charges, resulting in a gain of $26 million before tax. We did not consider the property disposition material for discontinued operations presentation.

In August 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. Information regarding the sale is as follows:

	Nine Months Ended September 30,
	2010
(millions)
Cash Proceeds	$	552
Less
Net Book Value of Assets Sold		(394	)
Goodwill Allocated to Assets Sold		(61	)
Asset Retirement Obligations Associated with Assets Sold		10
Other Closing Adjustments		7
Gain on Asset Sale	$	114

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Derivative Instruments and Hedging Activities (Details) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended						0 Months Ended	9 Months Ended					3 Months Ended				9 Months Ended															3 Months Ended				9 Months Ended				3 Months Ended		9 Months Ended										3 Months Ended		9 Months Ended						3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Feb. 15, 2011	Dec. 31, 2010	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Two Way Collar 1 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Swaps 1 [Member]		Sep. 30, 2011 Crude Oil Commodity Contract [Member] Swaps 2 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Swaps 3 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Swaps 4 [Member]	Oct. 15, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 1 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 1 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 2 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 3 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 4 [Member]	Sep. 30, 2011 Crude Oil Commodity Contract [Member] Three Way Collars 5 [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Crude Oil Commodity Contract [Member]		Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Crude Oil Commodity Contract [Member]		Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Crude Oil Commodity Contract [Member]		Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Crude Oil Commodity Contract [Member]		Sep. 30, 2011 Natural Gas Commodity Contract [Member] Two Way Collar 1 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Swaps 1 [Member]		Sep. 30, 2011 Natural Gas Commodity Contract [Member] Swaps 2 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Swaps 3 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Swaps 4 [Member]		Sep. 30, 2011 Natural Gas Commodity Contract [Member] Basis Swaps 5 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Three Way Collars 1 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Three Way Collars 2 [Member]	Sep. 30, 2011 Natural Gas Commodity Contract [Member] Three Way Collars 3 [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Natural Gas Commodity Contract [Member]		Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Natural Gas Commodity Contract [Member]		Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Natural Gas Commodity Contract [Member]		Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Natural Gas Commodity Contract [Member]		Sep. 30, 2011 Derivative Instruments Not Designated as Hedging Instruments [Member] Commodity derivative instruments [Member]	Sep. 30, 2010 Derivative Instruments Not Designated as Hedging Instruments [Member] Commodity derivative instruments [Member]	Sep. 30, 2011 Derivative Instruments Not Designated as Hedging Instruments [Member] Commodity derivative instruments [Member]	Sep. 30, 2010 Derivative Instruments Not Designated as Hedging Instruments [Member] Commodity derivative instruments [Member]	Sep. 30, 2011 Commodity derivative instruments [Member] Current Assets [Member]	Dec. 31, 2010 Commodity derivative instruments [Member] Current Assets [Member]	Sep. 30, 2011 Commodity derivative instruments [Member] Noncurrent Assets [Member]	Dec. 31, 2010 Commodity derivative instruments [Member] Noncurrent Assets [Member]	Sep. 30, 2011 Commodity derivative instruments [Member] Current Liabilities [Member]	Dec. 31, 2010 Commodity derivative instruments [Member] Current Liabilities [Member]	Sep. 30, 2011 Commodity derivative instruments [Member] Noncurrent Liabilities [Member]	Dec. 31, 2010 Commodity derivative instruments [Member] Noncurrent Liabilities [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Interest rate derivative instruments [Member]	Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Interest rate derivative instruments [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member] Interest rate derivative instruments [Member]	Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member] Interest rate derivative instruments [Member]	Sep. 30, 2011 Interest rate derivative instruments [Member] Current Assets [Member]	Dec. 31, 2010 Interest rate derivative instruments [Member] Current Assets [Member]	Sep. 30, 2011 Interest rate derivative instruments [Member] Current Liabilities [Member]	Dec. 31, 2010 Interest rate derivative instruments [Member] Current Liabilities [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member]	Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member]	Sep. 30, 2011 Derivative Instruments in Cash Flow Hedging Relationships [Member]	Sep. 30, 2010 Derivative Instruments in Cash Flow Hedging Relationships [Member]
Notes to Financial Statements [Abstract]
Net liability position of settled interest rate swap					$ 40,000,000
AOCL amount, net of tax, to be reclassified to interest expense over the life of the debt					26,000,000
Derivative [Line Items]
Period							2011	2011		2012	2012	2013	2013	2011	2012	2012	2013	2013									2011	2011		2012	2013	2011		2012	2011	2012	2013
Index							NYMEX WTI	NYMEX WTI	[1]	NYMEX WTI	Dated Brent	Dated Brent	Dated Brent	NYMEX WTI	NYMEX WTI	Dated Brent	NYMEX WTI	Dated Brent									NYMEX HH	NYMEX HH	[2]	NYMEX HH	NYMEX HH	IFERC CIG	[3]	IFERC CIG	NYMEX HH	NYMEX HH	NYMEX HH
Index Less Differential																																NYMEX HH		NYMEX HH
Volume Per Day							13,000	5,000		5,000	8,000	3,000	5,000	12,000	23,000	3,000	5,000	5,000									140,000	25,000		30,000	30,000	140,000		150,000	50,000	110,000	50,000
Weighted Average Fixed Price							0	85.52		91.84	89.06	98.03	0	0	0	0	0	0									0	6.41		5.10	5.25				0	0	0
Weighted Average Short Put Price							0	0		0	0	0	90.00	58.33	61.09	70.00	65.00	80.00									0	0		0	0				4.00	4.44	4.00
Weighted Average Floor Price							80.15	0		0	0	0	102.00	78.33	83.04	95.83	85.00	99.71									5.95	0		0	0				5.00	5.25	5.25
Weighted Average Ceiling Price							94.63	0		0	0	0	128.15	100.71	101.66	105.00	113.63	127.32									6.82	0		0	0				6.70	6.66	5.59
Weighted Average Differential																																(0.70)		(0.52)
Derivatives, Fair Value [Line Items]
Derivative Asset Not Designated as Hedging Instrument, Fair Value																																																		87,000,000	62,000,000	44,000,000	0
Derivative Asset Designated as Hedging Instrument, Fair Value																																																														0	0
Derivative Asset, Fair Value	131,000,000		131,000,000			62,000,000
Derivative Liability Not Designated as Hedging Instrument, Fair Value																																																						6,000,000	24,000,000	0	51,000,000
Derivative Liability Designated as Hedging Instrument, Fair Value																																																																0	63,000,000
Derivative Liability, Fair Value	6,000,000		6,000,000			138,000,000
Derivative Instruments, Gain (Loss) [Line Items]
Realized Mark-to-Market Gain																																														(22,000,000)	(33,000,000)	(39,000,000)	(65,000,000)
Unrealized Gain on Commodity Derivative Instruments			(140,000,000)	(215,000,000)																																										(300,000,000)	(5,000,000)	(140,000,000)	(215,000,000)
Total Gain on Commodity Derivative Instruments	(322,000,000)	(38,000,000)	(179,000,000)	(280,000,000)																																										(322,000,000)	(38,000,000)	(179,000,000)	(280,000,000)
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss																			0	[4]	0	[4]	0	[4]	0	[4]												0	[4]	0	[4]	0	[4]	0	[4]													0	47,000,000	(23,000,000)	141,000,000					0	47,000,000	(23,000,000)	141,000,000
Amount of (Gain) Loss on Derivative Instruments Reclassified from Accumulated Other Comprehensive Loss																			0	[4]	5,000,000	[4]	0	[4]	14,000,000	[4]												0	[4]	0	[4]	0	[4]	1,000,000	[4]													0	0	1,000,000	0					0	5,000,000	1,000,000	15,000,000
Amount of Deferred Losses Related to Interest Rate Derivative Instruments to be Amortized to Interest Expense Over the Life of the Related Debt Issuance	27,000,000		27,000,000
Amount of Deferred Losses Related to Interest Rate Derivative Instruments Currently Being Reclassified Into Earnings	$ 2,000,000		$ 2,000,000

[1] West Texas Intermediate

[2] Henry Hub

[3] Colorado Interstate Gas - Northern System

[4] Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Unsettled Derivative Instruments

As of September 30, 2011, we had entered into the following crude oil derivative instruments:  

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX WTI (1)		5,000	$	85.52	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX WTI		13,000		-		-		80.15		94.63
2011	Three-Way Collars	NYMEX WTI		12,000		-		58.33		78.33		100.71
2012	Swaps	NYMEX WTI		5,000		91.84		-		-		-
2012	Swaps	Dated Brent		8,000		89.06		-		-		-
2012	Three-Way Collars	NYMEX WTI		23,000		-		61.09		83.04		101.66
2012	Three-Way Collars	Dated Brent		3,000		-		70.00		95.83		105.00
2013	Swaps	Dated Brent		3,000		98.03		-		-		-
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		5,000		-		80.00		99.71		127.32
Instruments Entered Into During October 1-15, 2011
2013	Three-Way Collars	Dated Brent		5,000		-		90.00		102.00		128.15

(1) West Texas Intermediate

As of September 30, 2011, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
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
Instruments Entered Into as of September 30, 2011
2011	Swaps	NYMEX HH (1)		25,000	$	6.41	$	-	$	-	$	-
2011	Two-Way Collars	NYMEX HH		140,000		-		-		5.95		6.82
2011	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.00		6.70
2012	Swaps	NYMEX HH		30,000		5.10		-		-		-
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Three-Way Collars	NYMEX HH		50,000		-		4.00		5.25		5.59

(1) Henry Hub

As of September 30, 2011, we had entered into the following natural gas basis swaps:

Period	Index	Index Less Differential	MMBtu Per Day	Weighted Average Differential
2011	IFERC CIG (1)	NYMEX HH	140,000	$	(0.70)
2012	IFERC CIG	NYMEX HH	150,000		(0.52)

(1) Colorado Interstate Gas – Northern System

Fair Value of Derivative Instruments

The fair values of derivative instruments in our consolidated balance sheets were as follows:

Fair Value of Derivative Instruments

	Asset Derivative Instruments						Liability Derivative Instruments
	September 30,			December 31,			September 30,			December 31,
	2011			2010			2011			2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
(millions)
	Current Assets	$	87	Current Assets	$	62	Current Liabilities	$	6	Current Liabilities	$	24
Commodity Derivative Instruments (Not Designated as Hedging Instruments)	Noncurrent Assets		44	Noncurrent Assets		-	Noncurrent Liabilities		-	Noncurrent Liabilities		51
Interest Rate Derivative Instruments (Designated as Hedging Instruments)	Current Assets		-	Current Assets		-	Current Liabilities		-	Current Liabilities		63
Total		$	131		$	62		$	6		$	138

Effect of derivative instruments on consolidated statement of operations

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

Commodity Derivative Instruments Not Designated as Hedging Instruments

Amount of Gain on Derivative Instruments Recognized in Income

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Realized Mark-to-Market Gain	$	(22	)	$	(33	)	$	(39	)	$	(65	)
Unrealized Mark-to-Market Gain		(300	)		(5	)		(140	)		(215	)
Total Gain on Commodity Derivative Instruments	$	(322	)	$	(38	)	$	(179	)	$	(280	)

Derivative Instruments in Cash Flow Hedging Relationships

	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss						Amount of (Gain) Loss on Derivative Instruments Reclassified from  Accumulated Other Comprehensive Loss
		2011			2010		2011		2010
(millions)
Three Months Ended September 30,
Commodity Derivative Instruments in Previously Designated Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	5
Natural Gas Derivative Instruments			-			-		-		-
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			-			47		-		-
Total		$	-		$	47	$	-	$	5
Nine Months Ended September 30,
Commodity Derivative Instruments in Previously Designated Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-		$	-	$	-	$	14
Natural Gas Derivative Instruments			-			-		-		1
Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			(23	)		141		1		-
Total		$	(23	)	$	141	$	1	$	15

(1) Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2011

Stock-Based Compensation [Abstract]

Stock-based Compensation Expense

We recognized stock-based compensation expense as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Stock-Based Compensation Expense	$	15		$	13		$	43		$	40
Tax Benefit Recognized		(5	)		(5	)		(15	)		(14	)

Share-based Compensation Awards

During the nine months ended September 30, 2011, we granted stock options and awarded shares of restricted stock (subject to service conditions) as follows:

	Number Granted/Awarded		Weighted Average Fair Value
Stock Options		985,503	$	30.18
Shares of Restricted Stock		403,097	$	90.34

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Debt (Details) (USD $)	0 Months Ended			9 Months Ended		9 Months Ended				9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended	0 Months Ended
	Oct. 15, 2011	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Credit Facility due December 9 2012 [Member]	Dec. 31, 2010 Credit Facility due December 9 2012 [Member]	Sep. 30, 2011 CONSOL Installment Payments, due September 30, 2012 and 2013 [Member]	Dec. 31, 2010 CONSOL Installment Payments, due September 30, 2012 and 2013 [Member]	Sep. 30, 2011 FPSO Lease Obligation [Member]	Dec. 31, 2010 FPSO Lease Obligation [Member]	Sep. 30, 2011 Senior Notes due April 15, 2014 [Member]	Dec. 31, 2010 Senior Notes due April 15, 2014 [Member]	Sep. 30, 2011 Senior Notes due March 1, 2019 [Member]	Dec. 31, 2010 Senior Notes due March 1, 2019 [Member]	Sep. 30, 2011 Notes, due October 15, 2023 [Member]	Dec. 31, 2010 Notes, due October 15, 2023 [Member]	Sep. 30, 2011 Senior Notes due April 1, 2027 [Member]	Dec. 31, 2010 Senior Notes due April 1, 2027 [Member]	Sep. 30, 2011 Senior Notes due March 1, 2041 [Member]	Dec. 31, 2010 Senior Notes due March 1, 2041 [Member]	Sep. 30, 2011 Senior Notes due August 1, 2097 [Member]	Dec. 31, 2010 Senior Notes due August 1, 2097 [Member]	Sep. 30, 2011 CONSOL [Member]	Oct. 15, 2011 New Line of Credit [Member]
Debt Instrument [Line Items]
Debt		$ 3,891,000,000	$ 2,279,000,000	$ 400,000,000	$ 350,000,000	$ 656,000,000	$ 0	$ 351,000,000	$ 295,000,000	$ 200,000,000	$ 200,000,000	$ 1,000,000,000	$ 1,000,000,000	$ 100,000,000	$ 100,000,000	$ 250,000,000	$ 250,000,000	$ 850,000,000	$ 0	$ 84,000,000	$ 84,000,000
Interest rate (in hundredths)				0.56%	0.57%	1.76%	0.00%	0.00%	0.00%	5.25%	5.25%	8.25%	8.25%	7.25%	7.25%	8.00%	8.00%	6.00%	0.00%	7.25%	7.25%
Debt instrument, maturity date				Dec. 09, 2012						Apr. 15, 2014		Mar. 01, 2019		Oct. 15, 2023		Apr. 01, 2027		Mar. 01, 2041		Aug. 01, 2097
Debt instrument, maturity dates						September 30, 2012 and 2013
Unamortized discount		(29,000,000)	(7,000,000)
Total debt, net of discount		3,862,000,000	2,272,000,000
Less amounts due within one year						(322,000,000)	0	(33,000,000)	0
Long-Term Debt Due After One Year		3,507,000,000	2,272,000,000
Issuance of 6% Senior Notes [Abstract]
Debt offering face amount																		850,000,000
Debt offerings proceeds, net of discount and underwriting fees																		836,000,000
Total debt issuance costs																		9,000,000
Debt issuance proceeds used to repay outstanding indebtedness																		470,000,000
Debt offering closing date																		2011-02-18
CONSOL Installment Payments [Abstract]
Installment payment amount for joint venture partnership																						328,000,000
Debt Principal Payments [Abstract]
2011		0
2012		728,000,000
2013		328,000,000
2014		200,000,000
2015		0
Thereafter		2,284,000,000
Total		3,540,000,000
FPSO Lease Payments [Abstract]
2011		12,000,000
2012		72,000,000
2013		72,000,000
2014		72,000,000
2015		70,000,000
Thereafter		198,000,000
Total		496,000,000
Credit Facility [Abstract]
Credit Facility, description	(New Credit Facility On October 14, 2011, we entered into a credit agreement with certain commercial lending institutions the Credit Agreement which provides for a new 3.0 billion unsecured five-year revolving credit facility the New Credit Facility. The New Credit Facility replaces our 2.1 billion credit facility maturing December 9, 2012. Also on October 14, 2011, we borrowed 400 million under the New Credit Facility, which was used to repay outstanding borrowings under and to terminate the 2.1 billion credit facility. The New Credit Facility i provides for an initial commitment of 3.0 billion with an option to increase the overall commitment amount by up to an additional 1.0 billion, subject to the consent of any increasing lenders, ii will mature on October 14, 2016, iii provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, iv includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of 500 million under each sub-facility and iv provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 100 basis points to 145 basis points depending upon our credit rating.)
Credit facility initiation date																							2011-10-14
Revolving credit facility borrowing capacity				2,100,000,000																			3,000,000,000
New Credit Facility maturity date																							2016-10-31
Line of Credit Facility, option to increase, maximum																							1,000,000,000
Credit facility fee rate basis points, minimum (in hundredths)																							0.125%
Credit facility fee rate basis points, maximum (in hundredths)																							0.30%
Credit facility aggregate short-term loans and letters of credit, maximum																							500,000,000
Credit facility interest rate, Eurodollar rate plus, minimum (in hundredths)																							1.00%
Credit facility interest rate, Eurodollar rate plus, maximum (in hundredths)																							1.45%
New Credit Facility, covenant terms	(The Credit Agreement requires that our total debt to capitalization ratio as defined in the Credit Agreement, expressed as a percentage, not exceed 65 at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the New Credit Facility and require the immediate repayment of any outstanding advances under the New Credit Facility. The Credit Agreement does not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby.)
Credit facility covenant term debt to capitalization ratio maximum (in hundredths)																							65.00%
Credit facility draw down																							$ 400,000,000

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Capitalized Exploratory Well Costs (Tables)

9 Months Ended

Sep. 30, 2011

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:

	Nine Months Ended September 30,
(millions)
Capitalized Exploratory Well Costs, Beginning of Period		$	466
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves			158
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1)			(55	)
Capitalized Exploratory Well Costs Charged to Expense			(15	)
Capitalized Exploratory Well Costs, End of Period		$	554

(1) Includes $13 million related to the Flyndre project in the North Sea.

Aging of Capitalized Well Costs

The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	September 30,		December 31,
	2011			2010
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	196	$	166
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling		358		300
Balance at End of Period	$	554	$	466
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling		10		9

Aging of Exploratory Well Costs

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of September 30, 2011:

			Suspended Since
	Total		2010		2009		2008 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	113	$	7	$	19	$	87
Offshore Cameroon
YoYo		39		1		2		36
Offshore Israel
Dalit		22		1		21		-
Deepwater Gulf of Mexico
Deep Blue		73		54		19		-
Gunflint		58		2		6		50
Redrock		21		1		2		18
North Sea
Selkirk		23		1		1		21
Other
3 projects of $10 million or less each		9		9		-		-
Total	$	358	$	76	$	70	$	212

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2011

Stock-Based Compensation [Abstract]

Stock-Based Compensation

Note 11.   Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Stock-Based Compensation Expense	$	15		$	13		$	43		$	40
Tax Benefit Recognized		(5	)		(5	)		(15	)		(14	)

During the nine months ended September 30, 2011, we granted stock options and awarded shares of restricted stock (subject to service conditions) as follows:

	Number Granted/Awarded		Weighted Average Fair Value
Stock Options		985,503	$	30.18
Shares of Restricted Stock		403,097	$	90.34

On April 26, 2011, our stockholders approved the amendment and restatement of our 1992 Stock Option and Restricted Stock Plan to increase the number of shares of common stock authorized for issuance under the plan from 24 million to 31 million and modify certain plan provisions.

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Asset Impairments

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Asset Impairments

Note 4.  Asset Impairments

Pre-tax (non-cash) asset impairment charges were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
East Texas (Onshore US)	$	-	$	-	$	116	$	-
Iron Horse (Onshore US)		-		71		15		71
New Albany Shale (Onshore US)		-		19		-		19
Other		-		10		8		10
Total	$	-	$	100	$	139	$	100

2011   Due to field performance combined with a low natural gas price environment, we determined that the carrying amounts of certain of our onshore US developments, primarily in East Texas, were not recoverable from future cash flows and, therefore, were impaired at June 30, 2011.

2010   Due to declines in natural gas prices and drilling results, we determined that the carrying amounts of our Iron Horse development and certain other US properties were not recoverable from future cash flows and, therefore, were impaired at September 30, 2010. We also recorded an impairment related to non-core, New Albany shale assets which were held-for-sale at September 30, 2010.

Assets to be held and used were written down to their estimated fair values, which were determined using discounted cash flow models. Assets held for sale were reduced to expected sales proceeds less costs to sell. See Note 7. Fair Value Measurements and Disclosures.

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Comprehensive Income

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Comprehensive Income

Note 14.  Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholders' equity and classified as AOCL. Comprehensive income was calculated as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
(millions)
Net Income	$	441	$	232		$	749		$	673
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings		-		5			-			15
Less Tax Provision		-		(2	)		-			(5	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		(47	)		23			(141	)
Less Tax Provision		-		16			(8	)		49
Net Change in Other		1		1			4			2
Other Comprehensive Income (Loss)		1		(27	)		19			(80	)
Comprehensive Income	$	442	$	205		$	768		$	593

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Acquisitions and Divestitures (Details) (USD $)	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Significant Acquisitions and Disposals [Line Items]
Interest in joint venture partnership (in hundredths)	50.00%
Cash at closing of joint venture partnership	$ 592,000,000
Divestitures [Abstract]
Cash Proceeds			552,000,000
Less
Net Book Value of Assets Sold			(394,000,000)
Goodwill Allocated to Assets Sold			(61,000,000)
Asset Retirement Obligations Associated with Assets Sold			10,000,000
Other Closing Adjustments			7,000,000
Gain on Asset Sale			114,000,000
Total Purchase Price [Abstract]
Unproved Oil and Gas Properties	790,000,000
Proved Oil and Gas Properties	370,000,000
Investment in CONE Gathering LLC	73,000,000
Total Assets Acquired	1,233,000,000	[1]
CONSOL [Member]
Significant Acquisitions and Disposals [Line Items]
Interest in joint venture partnership (in hundredths)	50.00%
Undeveloped acres purchased (in acres)	628,000
Purchase price of joint venture partnership	1,200,000,000
Installments to purchase joint venture partnership	2
Installment payment amount for joint venture partnership	328,000,000
Funding agreement for future drilling and completion costs, description	we have agreed to fund one-third of CONSOL's 50 working interest share of future drilling and completion costs, up to approximately 2.1 billion CONSOL Carried Cost Obligation. The CONSOL Carried Cost Obligation is expected to extend over an eight-year period. It is capped at 400 million in each calendar year and will be suspended if average Henry Hub natural gas prices fall and remain below 4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above 4.00 per MMBtu for three consecutive months. Therefore, specific payment dates for the funding of the CONSOL Carried Cost Obligation cannot be determined at this time
Future drilling and completion costs, maximum	2,100,000,000
Cost Obligation expected term (in years)	8 Y
Calendar year funding of future drilling and completion costs, maximum	400,000,000
Natural gas price agreed upon benchmark, average (in MMBtu)	4.00
CONE Gathering LLC [Member]
Significant Acquisitions and Disposals [Line Items]
Interest in joint venture partnership (in hundredths)	50.00%
Total Purchase Price [Abstract]
Gathering and marketing agreement, term (in years)	50 Y
Minimum annual revenue commitment fee (MARC), projected 2011	3,000,000
Minimum annual revenue commitment fee (MARC), projected 2012	23,000,000
Ecuador Sale [Member]
Divestitures [Abstract]
Cash proceeds for transfer of assets	73,000,000
Less
Gain on Asset Sale	$ 26,000,000

[1] Total reflects impact of discount on remaining installment payments. See Note 5. Debt.

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Fair Value Measurements and Disclosures (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Assets and liabilities measured at fair value on a 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, 2011
Financial Assets
Mutual Fund Investments	$	101			$	-		$	-	$	-		$	101
Commodity Derivative Instruments		-				174			-		(43	)		131
Financial Liabilities
Commodity Derivative Instruments		-				(49	)		-		43			(6	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(152	)			-			-		-			(152	)
December 31, 2010
Financial Assets
Mutual Fund Investments	$	112			$	-		$	-	$	-		$	112
Commodity Derivative Instruments		-				106			-		(44	)		62
Financial Liabilities
Commodity Derivative Instruments		-				(119	)		-		44			(75	)
Interest Rate Derivative Instrument		-				(63	)		-		-			(63	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(178	)			-			-		-			(178	)

(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 master netting 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

 The assets were reduced to their estimated fair values. Information about the impaired assets is as follows:

	Fair Value Measurements Using
Description	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)
Three Months Ended September 30, 2011
Impaired Oil and Gas Properties	$	-	$	-	$	-	$	-	$	-
Three Months Ended September 30, 2010
Impaired Oil and Gas Properties	$	-	$	-	$	48	$	148	$	100
Nine Months Ended September 30, 2011
Impaired Oil and Gas Properties		-		-		32		171		139
Nine Months Ended September 30, 2010
Impaired Oil and Gas Properties		-		-		48		148		100

(1) Amount represents net book value atdate of assessment.

Additional fair value disclosures

Fair value information regarding our debt is as follows:

	September 30,				December 31,
	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	3,511	$	4,031	$	1,977	$	2,302

(1) Excludes FPSO lease obligation.

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Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Cash Flows From Operating Activities
Net Income	$ 749		$ 673
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	681		662
Asset Impairments	139		100
Dry Hole Cost	57		57
Deferred Income Taxes	147		109
Dividends (Income) from Equity Method Investees, Net	23		6
Unrealized Gain on Commodity Derivative Instruments	(140)		(215)
Gain on Divestitures	(26)	[1]	(114)	[1]
Other Adjustments for Noncash Items Included in Income	52		40
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable	(7)		(63)
(Increase) Decrease in Other Current Assets	(17)		18
Increase in Accounts Payable	131		214
Increase in Current Income Taxes Payable	52		20
(Decrease) in Other Current Liabilities	(25)		(17)
Other Operating Assets and Liabilities, Net	(31)		(38)
Net Cash Provided by Operating Activities	1,785		1,452
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,868)		(1,326)
Marcellus Shale Asset Acquisition	(519)		0
Central DJ Basin Asset Acquisition	0		(458)
Additions to Equity Method Investments	(73)		0
Proceeds from Divestitures	77		552
Net Cash Used in Investing Activities	(2,383)		(1,232)
Cash Flows From Financing Activities
Exercise of Stock Options	32		35
Excess Tax Benefits from Stock-Based Awards	11		19
Dividends Paid, Common Stock	(104)		(95)
Purchase of Treasury Stock	(16)		(12)
Proceeds from Credit Facilities	520		760
Repayment of Credit Facilities	(470)		(792)
Proceeds from Issuance of Senior Long-Term Debt, Net	836		0
Settlement of Interest Rate Derivative Instrument	(40)		0
Net Cash Provided By (Used In) Financing Activities	769		(85)
Increase in Cash and Cash Equivalents	171		135
Cash and Cash Equivalents at Beginning of Period	1,081		1,014
Cash and Cash Equivalents at End of Period	$ 1,252		$ 1,149

[1] See Note 3. Acquisitions and Divestitures.

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Segment Information

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Segment Information

Note 15.  Segment Information

We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Senegal and Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), and new ventures.

	Consolidated			United States			West Africa			Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended September 30, 2011
Revenues from Third Parties	$	874		$	520		$	153		$	108	$	45	$	48
Income from Equity Method Investees		50			-			50			-		-		-
Total Revenues		924			520			203			108		45		48
DD&A		225			180			13			8		10		14
Gain on Commodity Derivative Instruments		(322	)		(213	)		(109	)		-		-		-
Income (Loss) Before Income Taxes		722			418			270			88		23		(77	)
Three Months Ended September 30, 2010
Revenues from Third Parties	$	726		$	458		$	64		$	63	$	99	$	42
Reclassification from AOCL (1)		(5	)		(5	)		-			-		-		-
Income from Equity Method Investees		34			-			34			-		-		-
Total Revenues		755			453			98			63		99		42
DD&A		231			184			10			7		20		10
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
(Gain) Loss on Commodity Derivative Instruments		(38	)		(49	)		11			-		-		-
Income (Loss)  Before Income Taxes		298			211			64			51		59		(87	)
Nine Months Ended September 30, 2011
Revenues from Third Parties	$	2,632		$	1,578		$	401		$	236	$	271	$	146
Income from Equity Method Investees		146			-			146			-		-		-
Total Revenues		2,778			1,578			547			236		271		146
DD&A		681			534			30			19		62		36
Gain on Divestiture (2)		(26	)		(1	)		-			-		-		(25	)
Asset Impairments (3)		139			137			-			-		2		-
Gain on Commodity Derivative Instruments		(179	)		(163	)		(16	)		-		-		-
Income (Loss) Before Income Taxes		1,185			631			460			184		161		(251	)
Nine Months Ended September 30, 2010
Revenues from Third Parties	$	2,169		$	1,425		$	243		$	144	$	227	$	130
Reclassification from AOCL (1)		(15	)		(15	)		-			-		-		-
Income from Equity Method Investees		85			-			85			-		-		-
Total Revenues		2,239			1,410			328			144		227		130
DD&A		662			543			28			18		45		28
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
Gain on Commodity Derivative Instruments		(280	)		(277	)		(3	)		-		-		-
Income (Loss) Before Income Taxes		962			681			258			110		132		(219	)
September 30, 2011
Goodwill	$	696		$	696		$	-		$	-	$	-	$	-
Total Assets		15,833			10,921			2,544			1,540		625		203
December 31, 2010
Goodwill		696			696			-			-		-		-
Total Assets		13,282			9,091			2,270			919		770		232

(1) Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues. All hedge gains and losses had been reclassified to revenues by December 31, 2010.

(2) See Note 3. Acquisitions and Divestitures.

(3) See Note 4. Asset Impairments.

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Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs, Beginning of Period	$ 466
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	158
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	(55)	[1]
Capitalized Exploratory Well Costs Charged to Expense	(15)
Capitalized Exploratory Well Costs, End of Period	554
Flynde project in the North Sea, reclassification to well, facilities, and equipment based on determination of proved reserves	13
Exploratory Well Costs Capitalized for a Period of One Year or Less	196		166
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	358		300
Balance at End of Period	554
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling	10		9
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	76
Suspended Since 2009	70
Suspended Since 2008 & Prior	212
Total	358		300
Blocks O And I Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	113
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	7
Suspended Since 2009	19
Suspended Since 2008 & Prior	87
Total	113
YoYo Offshore Cameroon [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	39
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	1
Suspended Since 2009	2
Suspended Since 2008 & Prior	36
Total	39
Dalit Offshore Israel [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	22
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	1
Suspended Since 2009	21
Suspended Since 2008 & Prior	0
Total	22
Deep Blue Deepwater Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	73
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	54
Suspended Since 2009	19
Suspended Since 2008 & Prior	0
Total	73
Gunflint Deepwater Gulf Of Mexico [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	58
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	2
Suspended Since 2009	6
Suspended Since 2008 & Prior	50
Total	58
Redrock Deepwater Gulf Of Mexico [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	21
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	1
Suspended Since 2009	2
Suspended Since 2008 & Prior	18
Total	21
Selkirk North Sea [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	23
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	1
Suspended Since 2009	1
Suspended Since 2008 & Prior	21
Total	23
Other Projects [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	9
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended Since 2010	9
Suspended Since 2009	0
Suspended Since 2008 & Prior	0
Total	$ 9

[1] Includes $13 million related to the Flyndre project in the North Sea.

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Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2011

Notes to 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,
	2011			2010			2011			2010
(millions)
Other Revenues
Electricity Sales (1)	$	-		$	19		$	32		$	53
Other		-			(2	)		1			(1	)
Total	$	-		$	17		$	33		$	52
Production Expense
Lease Operating Expense	$	98		$	95		$	288		$	283
Production and Ad Valorem Taxes		38			29			108			96
Transportation Expense		17			17			53			51
Total	$	153		$	141		$	449		$	430
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	(1	)	$	-		$	18		$	27
Electricity Generation Expense (1)		-			9			26			26
Loss on Involuntary Conversion (3)		-			-			4			-
Other, Net		3			(5	)		(3	)		6
Total	$	2		$	4		$	45		$	59
Other Non-Operating (Income) Expense, Net
Deferred Compensation (Income) Expense (4)	$	(18	)	$	15		$	(15	)	$	4
Interest Income		(2	)		(1	)		(7	)		(4	)
Other (Income) Expense, Net		4			(2	)		6			(1	)
Total	$	(16	)	$	12		$	(16	)	$	(1	)

(1) Electricity sales include sales from the Machala power plant located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts.  See Note 3. Acquisitions and Divestitures.

(2) Amounts relate to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011 and costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the deepwater Gulf of Mexico drilling moratorium in 2010.

(3) The loss on involuntary conversion represents our insurance deductible related to the Leviathan-2 appraisal well control incident. We suspended operations on the Leviathan-2 well, offshore Israel, in May 2011 when we identified water flowing to the sea floor from the wellbore. The incident was a covered event under our well control insurance. At this time, we expect to recover most of the costs from insurance, subject to a deductible. The final amount to be recovered will be based on the cost to drill the Leviathan-3 replacement well down to the same depth at which the incident occurred, possible remediation activities and/or abandonment activities at the Leviathan-2 well, which have not yet been determined, and other factors. See footnote (2) below.

(4) Amount represents increases (decreases) 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:

	September 30,			December 31,
	2011			2010
(millions)
Accounts Receivable, Net
Commodity Sales	$	228		$	291
Joint Interest Billings		253			259
Other		73			33
Allowance for Doubtful Accounts (1)		(8	)		(27	)
Total	$	546		$	556
Other Current Assets
Inventories, Current	$	120		$	112
Commodity Derivative Assets, Current		87			62
Deferred Income Taxes, Net, Current		15			8
Probable Insurance Claims (2)		25			-
Prepaid Expenses and Other Assets, Current		32			19
Total	$	279		$	201
Other Noncurrent Assets
Equity Method Investments (3)	$	339		$	285
Mutual Fund Investments		101			112
Commodity Derivative Assets, Noncurrent		44			-
Other Assets, Noncurrent		64			87
Total	$	548		$	484
Other Current Liabilities
Production and Ad Valorem Taxes	$	128		$	110
Commodity Derivative Liabilities, Current		6			24
Interest Rate Derivative Liability, Current		-			63
Income Taxes Payable		143			90
Asset Retirement Obligations, Current		45			45
Interest Payable		18			36
CONSOL Installment Payment (4)		322			-
Current Portion of FPSO Lease Obligation		33			-
Other		131			127
Total	$	826		$	495
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	210		$	229
Asset Retirement Obligations, Noncurrent		215			208
Accrued Benefit Costs, Noncurrent		63			76
Commodity Derivative Liabilities, Noncurrent		-			51
Other		63			66
Total	$	551		$	630

(1) The decrease in the allowance for doubtful accounts from December 31, 2010 is due primarily to the transfer of assets to the Ecuadorian government. See Note 3.  Acquisitions and Divestitures.

(2) Amount represents the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible. See footnote (3) above.

(3) The increase in equity method investments from December 31, 2010 is due to our acquisition of a 50% interest in CONE Gathering LLC. See Note 3. Acquisitions and Divestitures.

(4) See Note 3. Acquisitions and Divestitures and Note 5. Debt.

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Consolidated Statements of Shareholders' Equity (unaudited) (Parenthetical) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Consolidated Statements of Shareholders' Equity (unaudited) [Abstract]
Cash dividends per share (in dollars per share)	$ 0.58	$ 0.54

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Asset Retirement Obligations

Note 9.  Asset Retirement Obligations

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

	Nine Months Ended September 30,
	2011			2010
(millions)
Asset Retirement Obligations, Beginning Balance	$	253		$	232
Liabilities Incurred		2			14
Liabilities Settled		(19	)		(35	)
Revision of Estimate		9			11
Accretion Expense		15			13
Asset Retirement Obligations, Ending Balance	$	260		$	235

Liabilities settled in 2011 related primarily to deepwater and shelf properties in the Gulf of Mexico. Liabilities settled in 2010 related to US onshore assets sold and a Gulf of Mexico shelf asset.

Liabilities incurred in 2010 were due primarily to the Central DJ Basin asset acquisition.

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

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Basic and Diluted Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Basic and Diluted Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings (Loss) Per Share

The following table summarizes the calculation of basic and diluted earnings per share:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
(millions, except per share amounts)
Net Income	$	441		$	232	$	749		$	673
Earnings Adjustment from Assumed Conversion of
Dilutive Shares of Common Stock in Rabbi Trust (1)		(12	)		-		(10	)		3
Net Income Used for Diluted Earnings Per Share Calculation	$	429		$	232	$	739		$	676
Weighted Average Number of Shares Outstanding, Basic		177			175		176			175
Incremental Shares from Assumed Conversion of
Dilutive Stock Options, Restricted Stock and Shares of Common Stock in Rabbi Trust		3			2		3			3
Weighted Average Number of Shares Outstanding, Diluted		180			177		179			178
Earnings Per Share, Basic	$	2.50		$	1.33	$	4.25		$	3.86
Earnings Per Share, Diluted		2.39			1.31		4.12			3.80
Number of antidilutive stock options and shares of restricted
stock excluded from calculation above		1			2		2			2

(1) Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the NBL shares held in the rabbi trust are included in the diluted share count.  For this reason, the diluted earnings per share calculations for the three and nine months ended September 30, 2011 exclude deferred compensation gains, net of tax; and the diluted earnings per share calculation for the nine months ended September 30, 2010 excludes a deferred compensation loss, net of tax.

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Income Taxes

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Income Taxes

Note 13.  Income Taxes

The income tax provision consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Current	$	179		$	42		$	289		$	180
Deferred		102			24			147			109
Total Income Tax Provision	$	281		$	66		$	436		$	289
Effective Tax Rate		39	%		22	%		37	%		30	%

Our effective tax rate increased for the first nine months of 2011 as compared with the first nine months of 2010. This was primarily due to the changes in Israeli and UK tax law discussed below and to a $16 million increase in the valuation allowance against our deferred tax asset for foreign tax credits.  Partially offsetting this increase was the impact of greater earnings from equity method subsidiaries in 2011, which has the effect of decreasing the rate when we have pre-tax income. In third quarter 2010, we reversed a $28 million valuation allowance which had been established against a deferred tax asset of the same amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations and recorded a corresponding reduction in income tax expense. Finally, the rate for the first nine months of 2010 was increased by a nondeductible allocation of goodwill to assets sold.

Changes in Israeli Tax Law   In March 2011, the Israeli government enacted the Oil Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs.  We expect these changes to increase our 2011 consolidated effective income tax rate by approximately two percentage points. We expect no remeasurement of our deferred tax assets or liabilities as of December 31, 2010.

Changes in UK Tax Law Also in March 2011, the UK government announced that the Finance Bill 2011 will increase the rate of the Supplementary Charge levied on oil and gas income in the UK from 20% to 32% effective March 24, 2011. This change, which became law on July 19, 2011, increased the tax rate on our UK oil and gas income from 50% to 62% and our 2011 consolidated effective income tax rate by approximately four percentage points. The change also resulted in a remeasurement of our UK deferred tax liability as of December 31, 2010 to reflect the higher effective rate. As a result, we recorded a $34 million increase in both our deferred income tax liability and deferred income tax expense during third quarter 2011. These changes are reflected in our balance sheet and results of operations at September 30, 2011.

Years Remaining Open to Examination   In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2006, Equatorial Guinea – 2007, Israel – 2008, UK – 2007, the Netherlands – 2009, and China – 2006.

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Consolidated Statements of Operations (unaudited) (USD $) In Millions, except Per Share data	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Revenues
Oil, Gas and NGL Sales	$ 874	$ 704		$ 2,599		$ 2,102
Income from Equity Method Investees	50	34		146		85
Other Revenues	0	17		33		52
Total	924	755		2,778		2,239
Costs and Expenses
Production Expense	153	141		449		430
Exploration Expense	57	35		195		167
Depreciation, Depletion and Amortization	225	231		681		662
General and Administrative	89	65		254		194
Gain on Divestitures	0	(114)	[1]	(26)	[1]	(114)	[1]
Asset Impairments	0	100	[2]	139	[2]	100	[2]
Other Operating (Income) Expense, Net	2	4		45		59
Total	526	462		1,737		1,498
Operating Income	398	293		1,041		741
Other (Income) Expense
Gain on Commodity Derivative Instruments	(322)	(38)		(179)		(280)
Interest, Net of Amount Capitalized	14	21		51		60
Other Non-Operating (Income) Expense, Net	(16)	12		(16)		(1)
Total	(324)	(5)		(144)		(221)
Income Before Income Taxes	722	298		1,185		962
Income Tax Provision	281	66		436		289
Net Income	$ 441	$ 232		$ 749		$ 673
Earnings Per Share, Basic (in dollars per share)	$ 2.50	$ 1.33		$ 4.25		$ 3.86
Earnings Per Share, Diluted (in dollars per share)	$ 2.39	$ 1.31		$ 4.12		$ 3.80
Weighted Average Number of Shares Outstanding, Basic (in shares)	177	175		176		175
Weighted Average Number of Shares Outstanding, Diluted (in shares)	180	177		179		178

[1] See Note 3. Acquisitions and Divestitures.

[2] See Note 4. Asset Impairments.

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Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Comprehensive Income (Loss)

Comprehensive income was calculated as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
(millions)
Net Income	$	441	$	232		$	749		$	673
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings		-		5			-			15
Less Tax Provision		-		(2	)		-			(5	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		(47	)		23			(141	)
Less Tax Provision		-		16			(8	)		49
Net Change in Other		1		1			4			2
Other Comprehensive Income (Loss)		1		(27	)		19			(80	)
Comprehensive Income	$	442	$	205		$	768		$	593

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Notes to Financial Statements [Abstract]
Current	$ 179	$ 42	$ 289	$ 180
Deferred	102	24	147	109
Total Income Tax Provision	281	66	436	289
Effective Tax Rate	39.00%	22.00%	37.00%	30.00%
Change in the valuation allowance			16	(28)
Expected percentage point change in future period consolidated effective tax rate due to changes in Israeli Oil Profits Taxation Law (in hundredths)			2.00%
UK supplementary charge levied on oil and gas income prior to March 2011 increase (in hundredths)			20.00%
UK supplementary charge levied on oil and gas income following March 2011 increase (in hundredths)			32.00%
UK oil and gas income expected tax rate prior to March 2011 (in hundredths)			50.00%
UK oil and gas income expected tax rate after March 2011 (in hundredths)			62.00%
Expected increase in consolidated effective income tax rate due to changes in tax laws in the UK (in hundredths)			4.00%
Years Remaining Open to Examination [Abstract]
Increase in UK deferred tax liability due to change in UK tax law	34
Increase in UK income tax expense due to change in UK tax law	$ 34
US [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2006
Equatorial Guinea [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2007
Israel [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2008
UK [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2007
Netherlands [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2009
China [Member]
Years Remaining Open to Examination [Abstract]
Earliest years remaining open to examinations			2006

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Asset Retirement Obligations (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Notes to Financial Statements [Abstract]
Asset Retirement Obligations, Beginning Balance	$ 253	$ 232
Liabilities Incurred	2	14
Liabilities Settled	(19)	(35)
Revision of Estimate	9	11
Accretion Expense	15	13
Asset Retirement Obligations, Ending Balance	$ 260	$ 235

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Employee Benefit Plans (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Employee Benefit Plans [Abstract]
Service Cost	$ 3	$ 4	$ 10	$ 11
Interest Cost	3	3	10	10
Expected Return on Plan Assets	(4)	(3)	(11)	(10)
Other	2	1	5	4
Net Periodic Benefit Cost	4	5	14	15
Cash contributions to pension plan			$ 23

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Notes to Financial Statements [Abstract]

Segment information

We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Senegal and Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (through May 2011), and new ventures.

	Consolidated			United States			West Africa			Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended September 30, 2011
Revenues from Third Parties	$	874		$	520		$	153		$	108	$	45	$	48
Income from Equity Method Investees		50			-			50			-		-		-
Total Revenues		924			520			203			108		45		48
DD&A		225			180			13			8		10		14
Gain on Commodity Derivative Instruments		(322	)		(213	)		(109	)		-		-		-
Income (Loss) Before Income Taxes		722			418			270			88		23		(77	)
Three Months Ended September 30, 2010
Revenues from Third Parties	$	726		$	458		$	64		$	63	$	99	$	42
Reclassification from AOCL (1)		(5	)		(5	)		-			-		-		-
Income from Equity Method Investees		34			-			34			-		-		-
Total Revenues		755			453			98			63		99		42
DD&A		231			184			10			7		20		10
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
(Gain) Loss on Commodity Derivative Instruments		(38	)		(49	)		11			-		-		-
Income (Loss)  Before Income Taxes		298			211			64			51		59		(87	)
Nine Months Ended September 30, 2011
Revenues from Third Parties	$	2,632		$	1,578		$	401		$	236	$	271	$	146
Income from Equity Method Investees		146			-			146			-		-		-
Total Revenues		2,778			1,578			547			236		271		146
DD&A		681			534			30			19		62		36
Gain on Divestiture (2)		(26	)		(1	)		-			-		-		(25	)
Asset Impairments (3)		139			137			-			-		2		-
Gain on Commodity Derivative Instruments		(179	)		(163	)		(16	)		-		-		-
Income (Loss) Before Income Taxes		1,185			631			460			184		161		(251	)
Nine Months Ended September 30, 2010
Revenues from Third Parties	$	2,169		$	1,425		$	243		$	144	$	227	$	130
Reclassification from AOCL (1)		(15	)		(15	)		-			-		-		-
Income from Equity Method Investees		85			-			85			-		-		-
Total Revenues		2,239			1,410			328			144		227		130
DD&A		662			543			28			18		45		28
Gain on Divestiture (2)		(114	)		(114	)		-			-		-		-
Asset Impairments (3)		100			100			-			-		-		-
Gain on Commodity Derivative Instruments		(280	)		(277	)		(3	)		-		-		-
Income (Loss) Before Income Taxes		962			681			258			110		132		(219	)
September 30, 2011
Goodwill	$	696		$	696		$	-		$	-	$	-	$	-
Total Assets		15,833			10,921			2,544			1,540		625		203
December 31, 2010
Goodwill		696			696			-			-		-		-
Total Assets		13,282			9,091			2,270			919		770		232

(1) Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues. All hedge gains and losses had been reclassified to revenues by December 31, 2010.

(2) See Note 3. Acquisitions and Divestitures.

(3) See Note 4. Asset Impairments.