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 March 31, 2012

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 April 6, 2012, there were 177,787,421 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 Statements of Comprehensive Income	4
Consolidated Balance Sheets	5
Consolidated Statements of Cash Flows	6
Consolidated Statements of Shareholders' Equity	7
Notes to Consolidated Financial Statements	8
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.  Controls and Procedures	36
Part II. Other Information	36
Item 1.  Legal Proceedings	36
Item 1A.  Risk Factors	36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3. Defaults Upon Senior Securities	37
Item 4. Mine Safety Disclosures	37
Item 5.  Other Information	37
Item 6.  Exhibits	37
Signatures	37
Index to Exhibits	38

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 March 31,
	2012			2011
Revenues
Oil, Gas and NGL Sales	$	1,112		$	830
Income from Equity Method Investees		53			48
Other Revenues		-			21
Total		1,165			899
Costs and Expenses
Production Expense		179			142
Exploration Expense		63			70
Depreciation, Depletion and Amortization		312			221
General and Administrative		98			83
Other Operating (Income) Expense, Net		12			36
Total		664			552
Operating Income		501			347
Other (Income) Expense
Loss on Commodity Derivative Instruments		96			286
Interest, Net of Amount Capitalized		32			16
Other Non-Operating (Income) Expense, Net		(1	)		8
Total		127			310
Income Before Income Taxes		374			37
Income Tax Provision		111			23
Net Income	$	263		$	14
Earnings Per Share, Basic	$	1.48		$	0.08
Earnings Per Share, Diluted		1.47			0.08
Weighted Average Number of Shares Outstanding, Basic		177			176
Weighted Average Number of Shares Outstanding, Diluted		180			178

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

3

Noble Energy, Inc.

Consolidated Statements of Comprehensive Income

(in millions)

(unaudited)

	Three Months Ended March 31,
	2012		2011
Net Income	$	263	$	14
Other Items of Comprehensive Income (Loss)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		23
Less Tax Provision		-		(8	)
Net Change in Other		2		2
Other Comprehensive Income		2		17
Comprehensive Income	$	265	$	31

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

4

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

(unaudited)

	March 31,			December 31,
	2012			2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,143		$	1,455
Accounts Receivable, Net		919			783
Other Current Assets		330			180
Total Current Assets		2,392			2,418
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)		18,527			17,703
Property, Plant and Equipment, Other		317			294
Total Property, Plant and Equipment, Gross		18,844			17,997
Accumulated Depreciation, Depletion and Amortization		(5,460	)		(5,215	)
Total Property, Plant and Equipment, Net		13,384			12,782
Goodwill		696			696
Other Noncurrent Assets		592			548
Total Assets	$	17,064		$	16,444
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,457		$	1,343
Other Current Liabilities		951			925
Total Current Liabilities		2,408			2,268
Long-Term Debt		4,088			4,100
Deferred Income Taxes, Noncurrent		2,216			2,059
Other Noncurrent Liabilities		819			752
Total Liabilities		9,531			9,179
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; 198 Million and 197 Million Shares Issued, Respectively		659			656
Additional Paid in Capital		2,549			2,497
Accumulated Other Comprehensive Loss		(98	)		(100	)
Treasury Stock, at Cost; 19 Million Shares		(651	)		(638	)
Retained Earnings		5,074			4,850
Total Shareholders’ Equity		7,533			7,265
Total Liabilities and Shareholders’ Equity	$	17,064		$	16,444

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

5

Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Three Months Ended March 31,
	2012			2011
Cash Flows From Operating Activities
Net Income	$	263		$	14
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		312			221
Dry Hole Cost		1			22
Deferred Income Taxes		32			11
Dividends (Income) from Equity Method Investees, Net		(29	)		(23	)
Unrealized Loss on Commodity Derivative Instruments		73			303
Other Adjustments for Noncash Items Included in Income		30			36
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable		(135	)		(9	)
(Increase) in Other Current Assets		(5	)		(17	)
Increase in Accounts Payable		190			28
Increase (Decrease) in Current Income Taxes Payable		5			(71	)
(Decrease) in Other Current Liabilities		(26	)		(54	)
Other Operating Assets and Liabilities, Net		30			23
Net Cash Provided by Operating Activities		741			484
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,018	)		(578	)
Additions to Equity Method Investments		(14	)		-
Proceeds from Divestitures		-			3
Net Cash Used in Investing Activities		(1,032	)		(575	)
Cash Flows From Financing Activities
Exercise of Stock Options		27			23
Excess Tax Benefits from Stock-Based Awards		12			8
Dividends Paid, Common Stock		(39	)		(32	)
Purchase of Treasury Stock		(13	)		(16	)
Proceeds from Credit Facilities		-			120
Repayment of Credit Facilities		-			(470	)
Proceeds from Issuance of Senior Long-Term Debt, Net		-			836
Settlement of Interest Rate Derivative Instrument		-			(40	)
Repayment of Capital Lease Obligation		(8	)		-
Net Cash Provided By (Used In) Financing Activities		(21	)		429
Increase (Decrease) in Cash and Cash Equivalents		(312	)		338
Cash and Cash Equivalents at Beginning of Period		1,455			1,081
Cash and Cash Equivalents at End of Period	$	1,143		$	1,419

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

6

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, 2011	$	656	$	2,497		$	(100	)	$	(638	)	$	4,850		$	7,265
Net Income		-		-			-			-			263			263
Stock-based Compensation		-		16			-			-			-			16
Exercise of Stock Options		2		25			-			-			-			27
Tax Benefits Related to Exercise of Stock Options		-		12			-			-			-			12
Restricted Stock Awards, Net		1		(1	)		-			-			-			-
Dividends (22 cents per share)		-		-			-			-			(39	)		(39	)
Changes in Treasury Stock, Net		-		-			-			(13	)		-			(13	)
Net Change in Other		-		-			2			-			-			2
March 31, 2012	$	659	$	2,549		$	(98	)	$	(651	)	$	5,074		$	7,533
December 31, 2010	$	651	$	2,385		$	(104	)	$	(624	)	$	4,540		$	6,848
Net Income		-		-			-			-			14			14
Stock-based Compensation		-		14			-			-			-			14
Exercise of Stock Options		2		21			-			-			-			23
Tax Benefits Related to Exercise of Stock Options		-		8			-			-			-			8
Restricted Stock Awards, Net		1		(1	)		-			-			-			-
Dividends (18 cents per share)		-		-			-			-			(32	)		(32	)
Changes in Treasury Stock, Net		-		-			-			(16	)		-			(16	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		-			15			-			-			15
Net Change in Other		-		-			2			-			-			2
March 31, 2011	$	654	$	2,427		$	(87	)	$	(640	)	$	4,522		$	6,876

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

7

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 1.  Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our core operating areas are onshore U.S., primarily in the DJ Basin and 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 March 31, 2012 and December 31, 2011 and for the three months ended March 31, 2012 and 2011 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 months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. 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, 2011.

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 March 31,
	2012			2011
(millions)
Other Revenues (1)	$	-		$	21
Production Expense
Lease Operating Expense	$	118		$	92
Production and Ad Valorem Taxes		38			32
Transportation and Gathering Expense		23			18
Total	$	179		$	142
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	-		$	18
Electricity Generation Expense (1)		-			17
Other, Net		12			1
Total	$	12		$	36
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense (3)	$	3		$	10
Interest Income		-			(3	)
Other (Income) Expense, Net		(4	)		1
Total	$	(1	)	$	8

(1) Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

(2) Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011. 

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

8

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Balance Sheet Information   Other balance sheet information is as follows:

	March 31,			December 31,
	2012			2011
(millions)
Accounts Receivable, Net
Commodity Sales	$	467		$	356
Joint Interest Billings		344			313
Other		117			123
Allowance for Doubtful Accounts		(9	)		(9	)
Total	$	919		$	783
Other Current Assets
Inventories, Current	$	77		$	78
Commodity Derivative Assets, Current		17			10
Deferred Income Taxes, Net, Current (1)		159			41
Probable Insurance Claims (2)		22			15
Prepaid Expenses and Other Current Assets, Current		55			36
Total	$	330		$	180
Other Noncurrent Assets
Equity Method Investments	$	376		$	329
Mutual Fund Investments		108			99
Commodity Derivative Assets, Noncurrent		22			37
Other Assets, Noncurrent		86			83
Total	$	592		$	548
Other Current Liabilities
Production and Ad Valorem Taxes	$	123		$	121
Commodity Derivative Liabilities, Current		119			76
Income Taxes Payable		131			127
Asset Retirement Obligations, Current		41			33
Interest Payable		41			56
CONSOL Installment Payment (3)		325			324
Current Portion of FPSO Lease Obligation		48			45
Other		123			143
Total	$	951		$	925
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	237		$	222
Asset Retirement Obligations, Noncurrent		350			344
Accrued Benefit Costs, Noncurrent		90			88
Commodity Derivative Liabilities, Noncurrent		29			7
Other		113			91
Total	$	819		$	752

 (1) Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.

 (2) Amounts represent the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible and insurance proceeds received to date.

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

Changes in Shareholders’ Equity   On April 24, 2012, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company’s common stock from $3.331/3 per share to $0.01 per share.

9

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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 and interim periods beginning after December 15, 2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial statements. The only impact was to our fair value disclosures.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.

Note 3.   Acquisitions

Marcellus Shale Joint Venture   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 a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We have paid a total of $596 million as of March 31, 2012, and, other than post-closing adjustments, the remainder will be paid in two annual installments. See Note 4. Debt.

As part of the joint venture transaction, we agreed to fund one-third of CONSOL’s 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over approximately eight years or more. The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices.

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

	March 31,
	2012
(millions)
Unproved Oil and Gas Properties	$	853
Proved Oil and Gas Properties		386
Investment in CONE Gathering LLC		69
Total Assets Acquired (1)	$	1,308

(1) Total reflects impact of $17 million imputed discount on CONSOL installment payments.

We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. 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 reserves 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 for proved oil and gas properties 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.

10

Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 4. Debt

Our debt consists of the following:

	March 31,						December 31,
	2012						2011
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due October 14, 2016 (1)	$	-			-		$	-			-
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	% (2)		656			1.76	% (2)
FPSO Lease Obligation		344			-			355			-
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	%
4.15% Senior Notes, due December 15, 2021		1,000			4.15	%		1,000			4.15	%
7¼% Senior 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	%		850			6.00	%
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		4,484						4,495
Unamortized Discount		(23	)					(26	)
Total Debt, Net of Discount		4,461						4,469
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(325	)					(324	)
FPSO Lease Obligation		(48	)					(45	)
Long-Term Debt Due After One Year	$	4,088					$	4,100

(1)  Our Credit Agreement provides for a $3.0 billion unsecured five-year revolving credit facility. The Credit Facility is available for general corporate purposes.

(2) Imputed rate.

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

Note 5.  Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   In order to mitigate the effect of 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.

We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.

11

Noble Energy, Inc.

Notes to Consolidated Financial Statements

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 6. 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 March 2011 debt issuance. During first quarter 2011, the fair value of the swap increased and we recognized a gain of $23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million at the time of settlement. 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 notes. The ineffective portion of the interest rate swap was de minimis.

Unsettled Derivative Instruments   As of March 31, 2012, we had entered into the following crude oil derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	Bbls Per Day		Weighted Average Fixed Price		Weighted Average  Short Put  Price		Weighted Average Floor Price		Weighted Average  Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX WTI  (1)		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	Two-Way Collars	NYMEX WTI		5,000		-		-		95.00		115.00
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		26,000		-		82.88		100.86		127.32
2014	Swaps	Dated Brent		3,000		107.15		-		-		-
2014	Three-Way Collars	Dated Brent		10,000		-		85.00		98.50		129.24

(1) West Texas Intermediate

As of March 31, 2012, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day		Weighted Average Fixed Price		Weighted Average Short Put  Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX HH (1)		30,000	$	5.10	$	-	$	-	$	-
2012	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2013	Three-Way Collars	NYMEX HH		100,000		-		3.88		4.75		5.63

(1) Henry Hub

12

Noble Energy, Inc.

Notes to Consolidated Financial Statements

As of March 31, 2012, we had entered into the following natural gas basis swaps:

Settlement Period	Index	Index Less Differential	MMBtu Per Day		Weighted Average Differential
2012	IFERC CIG (1)	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
	March 31,			December 31,			March 31,			December 31,
	2012			2011			2012			2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
(millions)
Commodity Derivative Instruments	Current Assets	$	17	Current Assets	$	10	Current Liabilities	$	119	Current Liabilities	$	76
	Noncurrent Assets		22	Noncurrent Assets		37	Noncurrent Liabilities		29	Noncurrent Liabilities		7
Total		$	39		$	47		$	148		$	83

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

	Three Months Ended March 31,
	2012		2011
(millions)
Realized Mark-to-Market (Gain) Loss	$	23	$	(17	)
Unrealized Mark-to-Market Loss		73		303
Total Loss on Commodity Derivative Instruments	$	96	$	286

AOCL at March 31, 2012 included deferred losses of $26 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 6.  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 5. Derivative Instruments and Hedging Activities.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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)
March 31, 2012
Financial Assets
Mutual Fund Investments	$	108		$	-		$	-	$	-		$	108
Commodity Derivative Instruments		-			105			-		(66	)		39
Financial Liabilities
Commodity Derivative Instruments		-			(214	)		-		66			(148	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(172	)		-			-		-			(172	)
December 31, 2011
Financial Assets
Mutual Fund Investments	$	99		$	-		$	-	$	-		$	99
Commodity Derivative Instruments		-			99			-		(52	)		47
Financial Liabilities
Commodity Derivative Instruments		-			(135	)		-		52			(83	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(162	)		-			-		-			(162	)

(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.

Additional Fair Value Disclosures

Debt   The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a level 1 measurement on the fair value hierarchy.  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. As such, we consider the fair value of our floating-rate debt and CONSOL installment payments to be level 2 measurements on the fair value hierarchy. See Note 4. Debt. Fair value information regarding our debt is as follows:

	March 31,				December 31,
	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	4,117	$	4,606	$	4,114	$	4,733

(1) Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2012 or December 31, 2011. See Note 4. Debt.

Note 7.  Capitalized Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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

		Three Months Ended March 31, 2012
(millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	696
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		93
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		-
Capitalized Exploratory Well Costs Charged to Expense		-
Capitalized Exploratory Well Costs, End of Period	$	789

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

	March 31,		December 31,
	2012		2011
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	345	$	318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling		444		378
Balance at End of Period	$	789	$	696
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement 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 commencement of drilling as of March 31, 2012:

			Suspended Since
	Total		2011		2010		2009 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	114	$	2	$	6	$	106
Offshore Cameroon
YoYo		41		1		2		38
Offshore Israel
Leviathan		86		45		41		-
Dalit		22		-		1		21
Deepwater Gulf of Mexico
Gunflint		70		11		3		56
Deep Blue		75		2		54		19
North Sea
Selkirk		22		-		1		21
Other
3 projects of $10 million or less each		14		6		8		-
Total	$	444	$	67	$	116	$	261

Blocks O and I   Blocks O and I are crude oil, natural gas and natural gas condensate discoveries.  During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.

YoYo   YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are continuing evaluations for future drilling potential.

Leviathan   Leviathan is a 2010 natural gas discovery. We are continuing to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal well. We will require an additional one or two appraisal wells to further define Leviathan’s natural gas areal extent in order to determine the best development option including subsea tieback to existing shallow water platform, semi-submersible platform, FPSO, or LNG. 

In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests are expected during the second quarter of 2012.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

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

Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. We are currently drilling the first of up to three appraisal wells that we anticipate drilling to fully evaluate the extent of the reservoir. We are also reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility.

Deep Blue   Deep Blue (Green Canyon Block 723) was a significant test well which began drilling in 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend side track drilling activities. We resumed drilling activities and found additional hydrocarbons in high quality reservoirs in 2011. We have completed the analysis of the data obtained from the side track well and are working with our existing and potential new partners regarding their participation in an appraisal well.

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 8.  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:

	Three Months Ended March 31,
	2012			2011
(millions)
Asset Retirement Obligations, Beginning Balance	$	377		$	253
Liabilities Incurred		6			1
Liabilities Settled		(2	)		(9	)
Revision of Estimate		3			4
Accretion Expense		7			5
Asset Retirement Obligations, Ending Balance	$	391		$	254

Liabilities settled in 2011 related primarily to Deepwater Gulf of Mexico and Gulf of Mexico shelf properties.

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

Note 9.  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 include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share:

	Three Months Ended March 31,
	2012		2011
(millions, except per share amounts)
Net Income	$	263	$	14
Weighted Average Number of Shares Outstanding, Basic		177		176
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock		3		2
Weighted Average Number of Shares Outstanding, Diluted		180		178
Earnings Per Share, Basic	$	1.48	$	0.08
Earnings Per Share, Diluted		1.47		0.08
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above		2		2

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

Note 10.  Income Taxes

The income tax provision consists of the following:

	Three Months Ended March 31,
	2012			2011
(millions)
Current	$	79		$	12
Deferred		32			11
Total Income Tax Provision	$	111		$	23
Effective Tax Rate		30	%		62	%

Our effective tax rate decreased for the first quarter of 2012 as compared with the first quarter of 2011. During the first quarter of 2011, we increased the valuation allowance against our deferred tax asset for foreign tax credits by $11 million resulting in a corresponding increase in income tax expense, which was primarily responsible for the difference in the quarterly effective tax rates.

Years Remaining Open to Examination   In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2008, Equatorial Guinea – 2007, Israel – 2008, UK – 2010, the Netherlands – 2009, and China – 2006.

Note 11.  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/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (in first quarter 2011), and new ventures.

	Consolidated		United States			West Africa		Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended March 31, 2012
Revenues from Third Parties	$	1,112	$	554		$	383	$	44	$	75	$	56
Income from Equity Method Investees		53		2			51		-		-		-
Total Revenues		1,165		556			434		44		75		56
DD&A		312		198			73		5		18		18
(Gain) Loss on Commodity Derivative Instruments		96		(9	)		105		-		-		-
Income (Loss) Before Income Taxes		374		193			227		32		40		(118	)
Three Months Ended March 31, 2011
Revenues from Third Parties	$	851	$	505		$	130	$	52	$	114	$	50
Income from Equity Method Investees		48		-			48		-		-		-
Total Revenues		899		505			178		52		114		50
DD&A		221		167			10		4		28		12
Loss on Commodity Derivative Instruments		286		192			94		-		-		-
Income (Loss)  Before Income Taxes		37		(37	)		74		39		68		(107	)
March 31, 2012
Goodwill	$	696	$	696		$	-	$	-	$	-	$	-
Total Assets		17,064		11,220			2,948		2,107		458		331
December 31, 2011
Goodwill		696		696			-		-		-		-
Total Assets		16,444		11,201			2,728		1,751		544		220

Note 12.  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.

17

Noble Energy, Inc.

Notes to Consolidated Financial Statements

During 2011, we received two Notices of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (COGCC) regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. At this time, the COGCC has not established a proposed penalty for either 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.

18

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

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management.  Our MD&A is presented in the following major sections:

● Executive Overview;

● Operating Outlook;

● Results of Operations; and

● Liquidity and Capital Resources.

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

EXECUTIVE OVERVIEW

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

Our financial results for first quarter 2012 included:

● net income of $263 million, as compared with $14 million for first quarter 2011;

● loss on commodity derivative instruments of $96 million (including unrealized mark-to-market loss of $73 million) as compared with a loss on commodity derivative instruments of $286 million (including unrealized mark-to-market loss of $303 million) for first quarter 2011;

● diluted earnings per share of $1.47, as compared with $0.08 for first quarter 2011;

● cash flow provided by operating activities of $741 million, as compared with $484 million for first quarter 2011;

● ending cash balance of $1.1 billion, as compared with $1.5 billion at December 31, 2011;

● capital spending, on a cash basis, of $1 billion, as compared with $578 million for first quarter of 2011; and

● ratio of debt-to-book capital of 37% as compared with 38% at December 31, 2011.

Operational events for first quarter 2012 included:   

Overall

● record total sales volume of 243 MBoe/d, up 10 MBoe/d over the fourth quarter of 2011; and

● liquids represent 47% of total sales volumes, up from 40% in the fourth quarter of 2011;

United States

● horizontal production from the DJ Basin averaged 18 MBoe/d net, or 25% of the total DJ Basin volumes;

● expanded the Northern Colorado acreage position by 48,000 net acres to 230,000 net acres, where recent Company horizontal Niobrara results indicate recoveries comparable to Wattenberg; and

● assumed operatorship in the wet gas area of the Marcellus Shale joint venture acreage;

International

● gross daily crude oil production from the Aseng field, offshore Equatorial Guinea, achieved 60 MBbl/d;

● signed a natural gas sales contract with Israel Electric Corporation Limited for 2.7 Tcf of natural gas; and

● announced the Tanin discovery offshore Israel.

19

Exploration Program Update

We have significant remaining exploration potential 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 March 31, 2012, such as Deep Blue and the deep crude oil test at Leviathan-1 (See Item 1. Financial Statements – Note 7. Capitalized Exploratory Well Costs), and we expect to continue an active exploratory drilling program during the remainder of 2012. We do not always find proved reserves through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a project is not economically or operationally viable. We are currently conducting, or planning to conduct, appraisal activities at several of our discoveries. In the event we conclude that one of our discoveries is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.  As a result, in a future period, dry hole cost could be significant.

Updates of our significant exploration activities are as follows:

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

Deep Blue (Deepwater Gulf of Mexico)   We have completed the analysis of the data obtained from the side track well and are working with our existing and potential new partners regarding their participation in an appraisal well.

Leviathan (Offshore Israel)   In late 2010, we announced a significant natural gas discovery at the Leviathan-1 well in the Levant Basin. Additionally, we will require one or two appraisal wells to further define Leviathan’s natural gas areal extent in order to determine the best development option. See Major Development Projects Update – Leviathan below.

In January 2012, we returned to drilling at the Leviathan-1 well, which was suspended during 2011, in order to evaluate additional intervals for the existence of crude oil. Although the geological likelihood of success is low, the drilling results, which are expected in the second quarter of 2012, will yield valuable information about this new basin.

Tanin 1 (Offshore Israel)   In February 2012 we announced a natural gas discovery at the Tanin prospect, approximately 13 miles northwest of the Tamar field.

Additionally, we have acquired approximately 330,000 net acres in the state of Nevada.  We are currently planning 3-D seismic testing in 2012 and exploration drilling in 2013.

Major Development Projects Update

During the first quarter of 2012, 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:

Horizontal Niobrara (Onshore US)  We have increased our horizontal drilling activity targeting the Niobrara formation, completing 30 horizontal wells during the quarter. We recently added another horizontal drilling rig to our program and are currently running six horizontal drilling rigs.

Marcellus Shale (Onshore US)   During the first quarter of 2012, we took over operatorship of our first rig in the wet gas area of the Marcellus Shale, bringing the total rig count operating in the joint venture properties to seven. We drilled five horizontal wells reaching target depth during the quarter. By the end of the year, we expect to operate three rigs in the wet gas area while our partner CONSOL expects to operate two rigs in the dry gas area.

Galapagos (Deepwater Gulf of Mexico)  Installation of topside equipment at the host facility and subsea tiebacks for Santa Cruz, Isabela and Santiago have been completed and we are working with the host platform operator to perform final commissioning work. We expect production to commence in the second quarter of 2012.

Gunflint (Deepwater Gulf of Mexico)   We are currently drilling an appraisal well at Gunflint.  We currently anticipate drilling up to two additional appraisal wells to fully evaluate the extent of the reservoir. We are also reviewing host platform options, including subsea tieback to an existing third-party host and construction of a new facility, which will likely lead to sanctioning of a development project.

Alen (Offshore Equatorial Guinea) All sub-sea trees have been installed and sub-sea fabrication is underway. The production and injection wells are also on schedule and first production is expected to commence in the fourth quarter of 2013.

Diega (Offshore Equatorial Guinea)   We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.

Carla (Offshore Equatorial Guinea)   In late 2011, we drilled the Carla well, a successful oil appraisal well in Block O, offshore Equatorial Guinea. We are evaluating drilling results from our Carla discovery well and reviewing development options and formulating a development plan for these areas.

Tamar (Offshore Israel) Tamar development drilling and platform fabrication are ongoing. Pipeline installation is essentially complete, and the project remains on schedule for commissioning beginning in late 2012 and first sales in the second quarter of 2013. We also finalized several natural gas sales and purchase agreements during the quarter. See Israel Delivery Commitments below.

Noa/Pinnacles (Offshore Israel)   The Noa field is being developed as a subsea tieback to the Mari-B platform. Two development wells have been drilled, FEED (front end engineering and design) work has been completed, and installation and fabrication are progressing on schedule. In addition to Noa, we drilled the Pinnacles-1 well and are currently in the process of completing and tying the well back to the Mari-B platform. Noa and Pinnacles will help meet Israeli natural gas demands until the Tamar field begins producing. We expect production from both Noa and Pinnacles to commence in the third quarter of 2012. See Israel Delivery Commitments below.

20

Leviathan (Offshore Israel)   We have project and commercial teams in place and are considering our natural gas commercialization options. Due to the size of the field, economic viability depends on the ability to export via pipeline or LNG. Engineering design and planning work are currently underway for a potential first phase of development; however, we have not yet sanctioned a development project.

Block 12 (Offshore Cyprus) We are in the process of evaluating our commercialization options, including LNG, for the Block 12 natural gas discovery.

Northern Region Transportation Curtailments

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, mechanical or other reasons. In addition, continued drilling activity in concentrated areas, such as the DJ Basin and Marcellus Shale, can result in production growth outstripping available transportation and gathering capacity.

Due to both scheduled and unscheduled curtailments of third party pipeline services for significant equipment repairs and upgrades, we expect our Wattenberg area production to be impacted for the second quarter of 2012.

Recent Developments in the Marcellus Shale

Well Impact Fee    During the first quarter of 2012, the Pennsylvania legislature enacted an annual well impact fee which will be used by local governments, counties and state agencies to support the infrastructure and regulatory framework necessary to sustain effective development of natural gas resources in the Marcellus Shale. The well impact fee is a variable rate based on natural gas prices and the year a well is drilled. Due to the early stage of our Marcellus Shale development activities, the fee did not have a significant impact on our results of operations for the first quarter of 2012.

Butler v. Powers    On September 7, 2011, an intermediate appellate court (Superior Court) in Pennsylvania issued an opinion in Butler v. Powers regarding the interpretation 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 raised by the case 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 shale gas is contained inside non-porous shale rock. An appeal of the decision was subsequently filed with the Pennsylvania Supreme Court. The Pennsylvania Supreme Court recently announced its decision to hear the appeal. Written arguments in the case are due by May 15, 2012.

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 our initial review, we believe that any adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL and our Marcellus Shale joint venture operations.

Recent Developments Onshore US

Researchers from the U.S. Geological Survey recently reported that they have observed an increase in seismic activity in the Midcontinent region and have indicated that the seismic activity may be attributable to injection wells that handle wastewater from oil and gas drilling activities. The researchers cite a series of examples for which an uptick in seismic activity is observed in areas where the disposal of wastewater through deep-well injection increased significantly. Regulators in Ohio and Arkansas are also looking at a possible connection between minor seismic events and disposal of wastewater in injection wells.

Minor and imperceptible seismic activity is extremely common in areas of oil and gas development. Historically, such activity has rarely caused damage. In addition, there are safeguards in place to reduce the likelihood of seismic activity caused by oil and gas drilling activities, including the disposal of wastewater. For example, we study the seismicity of the areas where we operate and design plans for each well based on our understanding of the specific geology.  Steps taken to prevent seismic events include limiting increases in well pressure by reducing either the volume of wastewater pumped into the wells or the rate at which it is pumped. We also comply with requirements for injection well construction, operation, and closure set by the Underground Injection Control (UIC) Program, which was established under the provisions of the Safe Drinking Water Act of 1974.

Recent Developments Offshore France

We and our partner have applied to the French government for an extension of our offshore exploratory license until November 2015.  The French government has thus far not responded officially to this application, even though the regulatory period for reply has passed. The current political climate is not favorable to our application, and we are unable to predict the ultimate outcome. Regardless of the final result, any curtailment of exploration activities offshore France would have no material impact on our financial position or results of operations.

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Recent Developments in West Africa

We currently have an interest in the AGC Profond block covering 2.4 million gross (724,000 net) undeveloped acres offshore Senegal/Guinea-Bissau. On March 26, 2012, a new president of Senegal was elected in a peaceful, democratic election. Conversely, on April 13, 2012, the interim government of Guinea-Bissau was deposed by military forces. The military and the opposition subsequently agreed to form a transitional council, but have not announced specific plans. We will continue to monitor these developments, and we currently cannot predict the impact these events may have on our future exploration plans in this area.

Israel Delivery Commitments

During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at very high rates to support Israel’s growing natural gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B, which is nearing the end of its expected production life, to prudently manage the reservoir. We are currently working closely with our Israeli customers to manage demand from the Mari-B field and continue production from it while wells from Noa and Pinnacles are drilled, completed and tied back to the Mari-B platform. We expect production to commence from Noa and Pinnacles during the third quarter of 2012 and the Tamar field during the second quarter of 2013.

On March 14, 2012, we and our Tamar partners entered into a Gas Sale and Purchase Agreement (GSPA) with the Israel Electric Corporation Limited (IEC). Under the terms of the GSPA, we have agreed to sell approximately 2.7 Tcf of natural gas produced from the Tamar field to IEC over an approximate 15-year period. At IEC’s option, this amount can be increased to 3.5 Tcf, under certain conditions. The term of the GSPA begins upon commissioning of the Tamar project. The sales price is based on an initial base price and will be subject to an inflation adjustment. The GSPA is attached as Exhibit 10.1 to this Quarterly Report on Form 10-Q.

As of April 15, 2012, we and our partners have also signed GSPAs with other Israeli customers, including independent power, cogeneration and manufacturing companies, to supply approximately 1.3 Tcf of natural gas over a 16 to 17 year period beginning in late 2013. These contracts provide for an initial base price, subject to an inflation adjustment, and some of the contracts provide for increases or decreases in total quantities. We continue to negotiate additional GSPAs with other potential customers.

Sales Volumes

On a BOE basis, total sales volumes were 13% higher for the first quarter of 2012 as compared with the first quarter of 2011, and our mix of sales volumes was 47% global liquids, 23% international natural gas, and 30% US natural gas. US sales volumes increased due to continued acceleration of our horizontal drilling programs in Wattenberg along with our Marcellus Shale program, which began at the end of the third quarter of 2011. International crude oil sales volumes were higher in Equatorial Guinea due to the commencement of crude oil production at Aseng in the fourth quarter of 2011. Israel natural gas sales volumes were lower as we have reduced the rate of production from the Mari-B field in order to manage the reservoir. See Israel Delivery Commitments above and Results of Operations – Revenues below.

Commodity Price Changes and Hedging

Total consolidated average realized crude oil prices for the first three months of 2012 increased 14% as compared with the first three months of 2011. The increase was driven by the continued global economic recovery and continued threats to the global oil supply system.

US natural gas prices remain weak. Average realized natural gas prices for the first three months of 2012 decreased 36% as compared with the first three months of 2011 primarily due to abundant supply and above average levels of natural gas in storage. As long as US natural gas development activity continues at, or near, the current level and there is no significant increase in demand, production growth will continue to outstrip growth in transportation and storage capacity, likely resulting in downward pressure on natural gas prices (See Potential for Future Asset Impairments below).

We have hedged approximately 41% of our expected global crude oil production and 39% of our expected domestic natural gas production for the remainder of 2012. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities.

OPERATING OUTLOOK

Our expected crude oil, natural gas and NGL production for 2012 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, in the North Sea and the Mari-B field in Israel, where we reduced production to manage the reservoir (See Israel Delivery Commitments, above);

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

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● 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 and commencement of production from the Noa field and Pinnacles project, offshore Israel;

● variations in West Africa and 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 (see Northern Region Transportation Curtailments above);

● potential drilling and/or hydraulic fracturing permit delays due to future regulatory changes;

● potential purchases of producing properties and/or divestments of non-core operating assets; and

● potential shut-in of US producing properties if storage capacity becomes unavailable.

2012 Capital Investment Program

Our total capital investment program for 2012 is estimated at $3.5 billion. The capital investment program allocates approximately 50% to onshore US and the remainder to offshore deepwater Gulf of Mexico, Eastern Mediterranean, and West Africa. Exploration and appraisal activity within these geographic areas is expected to receive approximately 20% of total capital.

We expect that the 2012 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 an issuance of long-term debt. Funding may also be provided by proceeds from divestment of non-core assets. See Liquidity and Capital Resources – Financing Activities below.

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

● commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;

● cash flows from operations;

● operating and development costs and possible inflationary pressures;

● permitting activity in the deepwater Gulf of Mexico;

● drilling results;

● CONSOL Carried Cost Obligation (See Contractual Obligations below);

● property acquisitions and divestitures;

● availability of financing;

● potential legislative or regulatory changes regarding the use of hydraulic fracturing;

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

● impact of new laws and regulations, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, on our business practices.

Marketing of North Sea and Onshore US Assets

We occasionally divest non-core, non-strategic properties from our portfolio to generate organizational and operational efficiencies as well as cash for use in our capital investment program. We are in the process of marketing our North Sea properties along with certain non-core onshore US properties and are currently soliciting bids. However, at this time, the Board of Directors and management have not committed to any specific plans to sell the assets, individually or as packaged groups. See Potential for Future Asset Impairments below.

Potential for Future Asset Impairments

The US natural gas market remains weak. A decrease from the March 31, 2012 forward natural gas prices could result in impairment charges. Certain of our onshore US properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These properties 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, 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 an impairment of properties that are sensitive to declines in natural gas prices.

Additionally, we are currently marketing certain non-core onshore US properties. If the properties are reclassified as assets held for sale, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell.

The onshore US properties discussed above have a combined net book value of approximately $1 billion at March 31, 2012.

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Israeli Interministerial Committee

In 2011, the Interministerial Committee to Examine Government Policy Regarding the Natural Gas Industry in Israel (the Committee) was charged with the task of proposing a government policy for developing the natural gas economy. Objectives include the following:

● ensuring energy security in the economy;

● providing a framework for substantial resource exports;

● designating a certain percentage of production from each field for the domestic natural gas market;

● maintaining competition in the different sectors of the local economy;

● maximizing economic and political benefits; and

● leveraging environmental advantages with respect to the use of natural gas.

The Committee was also asked to examine, among other items, the desired policy to maintain reserves to supply local demand and export of natural gas. The Committee issued Interim Recommendations on April 5, 2012, which included, among others:

● requiring a minimum 25-year supply of gas to the domestic market;

● allowing for a redetermination of market needs after the year 2018;

● requiring regulatory approval for export;

● determining that an Israeli natural gas export facility be under Israeli control and within the jurisdiction of Israel’s economic waters;

● taking steps to increase competition in the natural gas market; and

● requiring infrastructure redundancy, physical connection of all reservoirs to the domestic market, third party access to infrastructure, and the development of statutory procedures to define infrastructures.

The Committee's timeline includes a public hearing on May 20, 2012 and submission of a final report on June 7, 2012.We are participating in the process and monitoring the activities of the Committee and the impact of its Interim Recommendations. However, at this time, we cannot predict the ultimate outcome of the Committee’s Interim Recommendations or the possible impact any resulting laws or regulations could have on our business. Certain changes in Israel’s market, fiscal, and/or regulatory regimes occurring as a result of the Committee’s recommendations could delay or reduce the profitability of our Tamar and/or Leviathan development projects and render future exploration and development projects uneconomic.

EPA Final Emissions Standards

On April 18, 2012, the U.S. Environmental Protection Agency (EPA) announced that it has finalized standards related to emissions associated with crude oil and natural gas production, including natural gas wells that are hydraulically fractured. The required technologies and processes, while reducing emissions, will also enable companies to collect additional natural gas that can be sold. The EPA’s final standards also address emissions from storage tanks and other equipment.

The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology.  During the first phase, until January 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions,” technologies that are already widely deployed at wells. In 2015, all newly fractured wells will be required to use green completions.

We are currently evaluating the EPA’s final rules and assessing the impact on our business. The reduction of greenhouse gas emissions (GHG) is already one of our Company's priorities and we have been working to improve our methods to reduce GHGs through operational and business practices.  We use green completions or flaring on a number of our wells to comply with COGCC rules.  Additionally we've undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture gas that would otherwise be flared on a substantial number of our tank batteries.

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, fire, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals, any of which could result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities and other property, environmental pollution, injury to persons, or loss of life. 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. We have limited or no insurance coverage for certain risks such as war or political risk. In addition, coverage is generally limited or not available to us for pollution events that are considered gradual.

In certain international locations (including Israel and Equatorial Guinea) 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.

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In the Gulf of Mexico, we self-insure for windstorm related exposures. 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 is customary with industry practice, crude oil and natural 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 US and international drilling contracts contain such indemnification clauses. In addition, crude oil and natural 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 $550 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 coverage for cleanup and consequential damages would cover a gross loss of at least $876 million depending on our ownership interest and subject to reduction for claims related to well control and third-party damages.

We have contracts with third-party service providers to perform hydraulic fracturing operations for us. The master service agreements signed by hydraulic fracturing providers contain indemnification provisions similar to those noted above. Our liability insurance policies do not contain any specific exclusions for liabilities from hydraulic fracturing operations and we believe our policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. We do not have insurance for gradual pollution nor do we have coverage for penalties or fines that may be assessed by a governmental authority.

We expect the future availability and cost of insurance to be impacted by the various catastrophic events which occurred in 2011. 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 ongoing changes in the types of coverage available in the insurance market may result in lower effective coverages and/or the incurrence of higher premiums to achieve past levels of coverage.

We continue to monitor the legislative and regulatory response to the Deepwater Horizon Incident and other recent international incidents in Brazil and the North Sea, and their impact on the insurance market and our overall risk profile. We anticipate that, at a minimum, less effective liability coverage will be available at a higher cost. 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.

Insurance Recoveries   In May 2011, we ended drilling operations at the Leviathan-2 appraisal well offshore Israel when we identified water flowing to the sea floor from the wellbore. We are continuing to monitor the wellbore and there are no indications of any hydrocarbons in the produced water. Drilling did not reach the depth of the targeted gas intervals discovered in the Leviathan-1 well. We are working with the Israeli government to determine appropriate abandonment activities.

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. Our partners have insurance coverage, but may not have sufficient coverage to cover all possible outcomes and may have to rely on other financial resources. We do not expect any delays in our 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.

Our business 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 robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial condition, results of operations and cash flows.

Recently Issued Accounting Standards Update

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

RESULTS OF OPERATIONS

Revenues

Revenues were as follows:

					Increase
					(Decrease)
	2012		2011		from Prior Year
(millions)
Three Months Ended March 31,
Oil, Gas and NGL Sales	$	1,112	$	830		34	%
Income from Equity Method Investees		53		48		10	%
Other Revenues		-		21		(100	%)
Total	$	1,165	$	899		30	%

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Changes in revenues are discussed below.

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 March 31, 2012
United States		42		433		17		131	$	101.21	$	2.62	$	41.62
Equatorial Guinea (2)		35		230		-		73		118.04		0.27		-
Israel		-		108		-		18		-		4.51		-
North Sea		6		5		-		7		122.44		7.88		-
China		5		-		-		5		126.10		-		-
Total Consolidated Operations		88		776		17		234		110.80		2.22		41.62
Equity Investees (3)		2		-		7		9		110.09		-		68.02
Total Operations		90		776		24		243	$	110.78	$	2.22	$	49.34
Three Months Ended March 31, 2011
United States		37		382		14		114	$	92.25	$	4.07	$	47.80
Equatorial Guinea (2)		13		248		-		55		103.49		0.27		-
Israel		-		140		-		23		-		4.19		-
North Sea		11		8		-		12		106.26		7.30		-
China		4		-		-		4		95.28		-		-
Total Consolidated Operations		65		778		14		208		97.15		2.91		47.80
Equity Investees (3)		2		-		5		7		103.93		-		75.71
Total Operations		67		778		19		215	$	97.32	$	2.91	$	55.43

(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.

If the realized gains and losses on commodity derivative instruments, which are included in 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)
	2012					2011
	Crude Oil & Condensate			Natural Gas		Crude Oil & Condensate			Natural Gas
	(Per Bbl)			(Per Mcf)		(Per Bbl)			(Per Mcf)
Three Months Ended March 31,
United States	$	(2.40	)	$	0.28	$	(2.75	)	$	0.76
Equatorial Guinea		(7.84	)		-		-			-
Total Consolidated Operations		(4.26	)		0.16		(1.56	)		0.37
Total Operations		(4.17	)		0.16		(1.52	)		0.37

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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 March 31, 2011	$	569	$	203		$	58		$	830
Changes due to
Increase in Sales Volumes		211		2			16			229
Increase (Decrease) in Sales Prices		110		(48	)		(9	)		53
Three Months Ended March 31, 2012	$	890	$	157		$	65		$	1,112

Crude oil and condensate sales – Revenues from crude oil and condensate sales increased during the first three months of 2012 as compared with 2011 due to the following:

● increases in average realized prices;

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

● higher sales volumes in Equatorial Guinea due to the commencement of oil production at Aseng during fourth quarter 2011, which impacted our sales volumes by approximately 18 MBbl/d in the first three months of 2012 as compared with 2011;

partially offset by:

● lower sales volumes in non-core onshore US and deepwater Gulf of Mexico areas due to natural field decline; and

● lower North Sea sales volumes due to maintenance downtime at the Dumbarton field.

Natural gas sales – Revenues from natural gas sales decreased during the first three months of 2012 as compared with 2011 due to the following:

● a 24% decrease in total consolidated average realized prices (36% decrease in US average realized prices) primarily due to oversupply and above average levels of natural gas in storage;

● lower sales volumes in non-core onshore US and deepwater Gulf of Mexico areas due to natural field decline;

● decrease in sales volumes in Israel due to a reduction in the rate of production from the Mari-B field in order to manage the reservoir ; and

● lower sales volumes in the North Sea due to maintenance downtime at the Dumbarton field;

partially offset by:

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

● sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and which added 68 MMcf/d to our first quarter 2012 sales volumes.

NGL sales – Most of our US NGL production is from the Wattenberg area. NGL sales revenues increased during the first three months of 2012 as compared with 2011 primarily due to the continued acceleration of our horizontal drilling programs. US NGL average realized sales prices declined by 13%, due primarily to higher supplies of NGLs resulting from increased wet gas drilling activities.

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. We also have a 50% interest in CONE Gathering LLC (CONE) which owns and operates the infrastructure associated with our Marcellus Shale joint venture. During first quarter 2012, we contributed $14 million to CONE.

Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, our share of dividends is reported within cash flows from operating activities and our share of investments is reported within cash flows from investing activities.

The increase in income from equity method investees for the first three months of 2012 as compared with 2011 was due to increases in condensate, LPG and methanol sales volumes, offset by a 10% decrease in average realized liquids prices.

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Methanol sales volumes and prices were as follows:

	Three Months Ended March 31,
	2012		2011
Methanol Sales Volumes (Mmgal)		41		40
Methanol Sales Prices (per gallon)	$	1.04	$	1.03

Operating Costs and Expenses

Operating costs and expenses were as follows:

	Three Months Ended				Increase
	March 31,				(Decrease)
	2012		2011		from Prior Year
(millions)
Production Expense	$	179	$	142		26	%
Exploration Expense		63		70		(10	%)
Depreciation, Depletion and Amortization		312		221		41	%
General and Administrative		98		83		18	%
Other Operating (Income) Expense, Net		12		36		(67	%)
Total	$	664	$	552		20	%

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 March 31, 2012
Lease Operating Expense (2)	$	5.53	$	118	$	71	$	23	$	4	$	13		$	7
Production and Ad Valorem Taxes		1.76		38		26		-		-		-			12
Transportation and Gathering Expense		1.10		23		21		-		-		1			1
Total Production Expense	$	8.39	$	179	$	118	$	23	$	4	$	14		$	20
Three Months Ended March 31, 2011
Lease Operating Expense (2)	$	4.89	$	92	$	62	$	9	$	3	$	12		$	6
Production and Ad Valorem Taxes		1.71		32		25		-		-		-			7
Transportation and Gathering Expense		0.94		18		16		-		-		2			-
Total Production Expense	$	7.54	$	142	$	103	$	9	$	3	$	14		$	13

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

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

For the first three months of 2012, total production expense increased as compared with 2011 due to the following:

● an increase in US lease operating, transportation and gathering expenses due to higher sales volumes from the Wattenberg area due to ongoing development activities and new production from the Marcellus Shale joint venture;

● an increase in Equatorial Guinea lease operating expense associated with the Aseng field which began producing in November 2011; and

● an increase in China production and ad valorem taxes due to increases in sales volumes and prices.

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Exploration Expense   Components of 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 March 31, 2012
Dry Hole Cost	$	1	$	-	$	1	$	-	$	-	$	-
Seismic		28		26		-		-		-		2
Exploration Expense		27		4		2		1		3		17
Other		7		6		1		-		-		-
Total Exploration Expense	$	63	$	36	$	4	$	1	$	3	$	19
Three Months Ended March 31, 2011
Dry Hole Cost	$	22	$	22	$	-	$	-	$	-	$	-
Seismic		26		16		-		-		-		10
Exploration Expense		18		5		1		-		-		12
Other		4		4		-		-		-		-
Total Exploration Expense	$	70	$	47	$	1	$	-	$	-	$	22

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

(2) Eastern Mediterranean includes Israel and Cyprus.

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

Exploration expense for the first three months of 2012 included the following:

● acquisition of seismic information for the deepwater Gulf of Mexico; and

● staff expense associated with new ventures and corporate expenditures.

Exploration expense for the first three months of 2011 included the following:

● dry hole cost associated with exploratory drilling in the US Rocky Mountain area;

● acquisition of seismic information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, and international new ventures; and

● staff expense associated with new ventures and corporate expenditures.

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

	Three Months Ended March 31,
	2012		2011
DD&A Expense (millions) (1)	$	312	$	221
Unit Rate per BOE (2)	$	14.60	$	11.81

(1)For DD&A expense by geographical area, see Item 1. Financial Statements – Note 11. Segment Information.

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

Total DD&A expense for the first three months of 2012 increased as compared with 2011 due to the following:

● an increase of approximately $33 million due primarily to higher sales volumes in the DJ Basin onshore US and the addition of DD&A expense related to the Marcellus Shale joint venture;

● an increase of approximately $61 million due to the startup of the Aseng field which includes the Aseng FPSO in its depreciation base; and

● the impact of negative reserves revisions at December 31, 2011, due to revised performance expectations in the North Sea and China;

 partially offset by:

● lower sales volumes in non-core onshore US and deepwater Gulf of Mexico areas resulting from natural field decline; and

● lower North Sea sales volumes.

Changes in the unit rate per BOE for the first three months of 2012 as compared with 2011 were due to changes in the mix of production, primarily due to volumes from the start-up of the Aseng field, which has a higher DD&A rate.

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

	Three Months Ended March 31,
	2012		2011
G&A Expense (millions)	$	98	$	83
Unit Rate per BOE (1)	$	4.60	$	4.43

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

G&A expense for the first three months of 2012 increased as compared with 2011 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and increased exploration activities.

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

	Three Months Ended March 31,
	2012		2011
(millions)
Deepwater Gulf of Mexico Moratorium Expense	$	-	$	18
Electricity Generation Expense		-		17
Other, Net		12		1
Total	$	12	$	36

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

Other (Income) Expense

Other (income) expense was as follows:

	Three Months Ended March 31,
	2012			2011
(millions)
Loss on Commodity Derivative Instruments	$	96		$	286
Interest, Net of Amount Capitalized		32			16
Other Non-Operating (Income) Expense, Net		(1	)		8
Total	$	127		$	310

Loss on Commodity Derivative Instruments     Loss on commodity derivative instruments is a result of mark-to-market accounting.   See Item 1. Financial Statements – Note 5.  Derivative Instruments and Hedging Activities and Note 6.  Fair Value Measurements and Disclosures.

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

	Three Months Ended March 31,
	2012			2011
(millions, except unit rate)
Interest Expense	$	69		$	41
Capitalized Interest		(37	)		(25	)
Interest Expense, Net	$	32		$	16
Unit Rate per BOE (1)	$	1.49		$	0.86

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

Interest expense prior to the reduction for capitalized interest increased for the first three months of 2012 as compared with 2011. The increase mainly resulted from our November 2011 debt issuance, an additional month of interest for our February 2011 debt issuance and interest related to our Aseng FPSO lease obligation.

The increase in capitalized interest is mainly due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, West Africa, and Israel.

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

30

Income Tax Provision

See Item 1. Financial Statements – Note 10. Income Taxes for a discussion of the change in our effective tax rate for the first three months of 2012 as compared with 2011.

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 sufficient 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 debt and capital markets may also provide cash to support opportunities.

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.

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

	March 31,			December 31,
	2012			2011
(millions, except percentages)
Cash and Cash Equivalents	$	1,143		$	1,455
Amount Available to be Borrowed Under Credit Facility (1)		3,000			3,000
Total Liquidity	$	4,143		$	4,455
Total Debt (2)	$	4,484		$	4,495
Total Shareholders' Equity		7,533			7,265
Ratio of Debt-to-Book Capital (3)		37	%		38	%

(1) See Credit Facility below.

(2) Total debt includes Aseng 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 $1.1billion in cash and cash equivalents at March 31, 2012, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $760 million of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently expect to use a significant amount of cash during 2012 to fund international projects, including the planned developments in West Africa and the Eastern Mediterranean.

Credit Facility   We have an unsecured revolving credit facility that matures on October 14, 2016. The commitment is $3.0 billion through the maturity date of the credit facility. See Financing Activities – Long-Term Debt below.

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 have also used 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. However, we currently have no such instruments.

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 March 31, 2012, the fair value of our commodity derivative assets was $39 million and the fair value of our commodity derivative liabilities was $148 million (after consideration of netting agreements).  See Item 1. Financial Statements – Note 5.  Derivative Instruments and Hedging Activities for a discussion of derivative counterparty credit risk and Note 6.  Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of derivative instruments.

31

European Debt CrisisThe debt crisis is ongoing and continues to have a negative impact on the European economy, with risks to the global banking system and overall global economy and financial system. During the first quarter of 2012, Moody's Investors Service announced rating actions affecting numerous financial institutions, and the ratings of a number of European banks were placed on review for downgrade.

Some of our commodity derivatives counterparties, as well as some of our lenders in our $3.0 billion Credit Facility, are international banks.  These institutions could potentially be affected by the European debt crisis and be unable to participate in our drawdowns. In addition, credit downgrades of these institutions could result in a change in our counterparties with whom we execute hedging transactions according to our internal risk guidelines.

We believe our current balance sheet and financial flexibility enhance our ability to react to Eurozone events as they unfold.

Accounts Receivable   Some of our purchasers and joint venture partners are not as creditworthy as we are and may experience credit downgrades or liquidity problems.  For example, Standard & Poor’s Ratings Services recently placed IEC’s credit rating on CreditWatch negative.

Counterparty liquidity problems could result in a delay in our receiving proceeds from commodity sales or reimbursement of joint venture costs. A partner’s inability to obtain financing could result in a delay of one of our joint development projects. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser; however, not all of our trade credit is protected through guarantees or credit support.  Nonperformance by a trade creditor or joint venture partner could result in significant financial losses.

Contractual Obligations

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 eight years or more. It is capped at $400 million in each calendar year and is 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. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices. Based on the March 31, 2012 Henry Hub natural gas price curve, we forecast our CONSOL Carried Cost Obligation will be suspended throughout the remainder of the 2012 fiscal year.

Cash Flows

Cash flow information is as follows:

	Three Months Ended March 31
	2012			2011
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	741		$	484
Investing Activities		(1,032	)		(575	)
Financing Activities		(21	)		429
Increase (Decrease) in Cash and Cash Equivalents	$	(312	)	$	338

Operating Activities   Net cash provided by operating activities for the first three months of 2012 increased as compared with 2011 primarily due to higher revenues, which benefitted from increases in crude oil prices and production. The increase in cash flow was partially offset by lower natural gas prices, increases in production expenses, 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 $440 million during the first three months of 2012 as compared with 2011, primarily due to increased major project development activity in the Wattenberg area, the Marcellus Shale, offshore West Africa, and offshore Israel. We also invested $14 million in CONE during first quarter 2012.

32

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 three months of 2012, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($39 million). We used cash to pay dividends on our common stock ($39 million), make principal payments related to the Aseng FPSO capital lease obligation ($8 million) and repurchase shares of our common stock ($13 million).

In comparison, during the first three months of 2011, funds were provided by net cash proceeds from borrowings under our revolving credit facility ($120 million) and the issuance of 6% senior notes due 2041 ($836 million). Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($31 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 ($32 million) and repurchase shares of our common stock ($16 million)

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

Investing Activities

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

	Three Months Ended March 31,
	2012		2011
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition	$	73	$	15
Exploration		129		122
Development		735		374
Corporate and Other		12		34
Total	$	949	$	545
Other
Investment in Equity Method Investee	$	14	$	-
Increase in FPSO Lease Obligation		-		34

2012   Unproved property acquisition costs were mainly related to an acquisition that strengthened our position in the DJ Basin along with other miscellaneous onshore US lease acquisitions. The increase in development costs is due to increased capital spending on major development projects located in the DJ Basin, Marcellus Shale, offshore Equatorial Guinea and offshore Israel.

2011    Unproved property acquisition costs for the first three months of 2011 related to onshore US lease acquisitions.

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

Financing Activities

Long-Term Debt   Our principal source of liquidity is an unsecured revolving credit facility that matures October 14, 2016. We did not engage in any activities under the Credit Facility, or other short-term borrowing arrangements during the first quarter of 2012.

The 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 (v) 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.

At March 31, 2012, there were no borrowings outstanding under the Credit Facility, leaving $3.0 billion available for use. We expect to use the Credit Facility to fund our capital investment program, and we periodically borrow amounts under provision (iv) above for working capital purposes. See Item 1. Financial Statements – Note 4. Debt.

Our outstanding fixed-rate debt, including the remaining CONSOL installment payments, totaled almost $4.1 billion at March 31, 2012. The weighted average interest rate on fixed-rate debt was 5.56%, with maturities ranging from 2012 to 2097. Approximately 21% of our fixed rate debt will mature within the next five years.

33

Our ratio of debt-to-book capital was 37% at March 31, 2012 as compared with 38% at December 31, 2011. We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

Dividends   We paid total cash dividends of 22 cents per share of our common stock during the first three months of 2012 and 18 cents per share during the first three months of 2011. 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 $27 million during the first three months of 2012 and $23 million during the first three months of 2011.

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 131,868 shares with a value of $13 million during the first three months of 2012 and 178,499 shares with a value of $16 million during the first three months of 2011. 

34

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes   We areexposed to market risk in the normal course of business operations, and the 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 March 31, 2012, 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 payable position with a fair value of $109 million. Based on the March 31, 2012 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative payable by approximately $20 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative payable by approximately $5 million.  Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities.

Interest Rate Risk

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

At March 31, 2012, we had approximately $4.1 billion (excluding the Aseng FPSO lease obligation and unamortized debt discount) of long-term debt outstanding. All debt outstanding was fixed-rate debt with a weighted average interest rate of 5.56%. 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 4. 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 March 31, 2012, AOCL included $26 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 5. 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 March 31, 2012, our cash and cash equivalents totaled approximately $1.1 billion, approximately 83% 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 March 31, 2012 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.

35

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 Annual Report on Form 10-K for the year ended December 31, 2011, 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, 2011 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

During 2011, we received two Notices of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (COGCC) regarding the reporting of the presence of hydrogen sulfide to the COGCC and local government designee within certain areas of our Piceance Basin and Grover field operations. At this time, the COGCC has not established a proposed penalty for either 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 1. Financial Statements – Note 12. 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 Annual Report on Form 10-K for the year ended December 31, 2011.

36

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

The following table sets forth, for the periods indicated, the Company’s share repurchase activity:

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
							(in thousands)
01/01/12 - 01/31/12		68,223	$	100.13		-		-
02/01/12 - 02/29/12		57,994		101.25		-		-
03/01/12 - 03/31/12		5,651		99.74		-		-
Total		131,868	$	100.61		-		-

(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.

Item 4. Mine Safety Disclosures

Not applicable.

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	April 26, 2012	/s/ Kenneth M. Fisher
		Kenneth M. Fisher Senior Vice President, Chief Financial Officer

37

Index to Exhibits

Exhibit
Number	Exhibit
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	Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean Ltd. and Isramco Negev 2 Limited Partnership, Delek Drilling Limited Partnership, Avner Oil Exploration Limited Partnership, and Dor Gas Exploration Limited Partnership (Sellers) and The Israel Electric Corporation Limited (Purchaser), filed herewith. (1)
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

(1) Pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission.

38

EX-10.1

Exhibit 10.1

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL

TREATMENT FOR THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL

HAS BEEN SEPARATELY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION,

AND THE REDACTED TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH

TWO ASTERISKS (**)

NOBLE ENERGY MEDITERRANEAN LTD.

DELEK DRILLING LIMITED PARTNERSHIP

ISRAMCO NEGEV 2 LIMITED PARTNERSHIP

AVNER OIL EXPLORATION LIMITED PARTNERSHIP

DOR GAS EXPLORATION LIMITED PARTNERSHIP

and

THE ISRAEL ELECTRIC CORPORATION LIMITED

GAS SALE AND

PURCHASE AGREEMENT

DATED March 14, 2012

INDEX

Article	Title	Page
‎Article 1	Definitions	6
‎Article 2	Period of Agreement and Commissioning	23
‎Article 3	Agreement for Sale and Purchase	30
‎Article 4	Warranties, Covenants and Taxes	31
‎Article 5	Sellers’ Rights/Commingling and Unitization	38
‎Article 6	Quantities and Nominations	39
‎Article 7	Facilities	50
‎Article 8	Exchange of Information	51
‎Article 9	Take or Pay	55
‎Article 10	Price, Price Review and Adjustment	59
‎Article 11	Billing and Payment	68
‎Article 12	Quality	74
‎Article 13	Delivery Point	76
‎Article 14	Pressure	77
‎Article 15	Measurement	78
‎Article 16	Force Majeure	80
‎Article 17	Default	84
‎Article 18	Assignment and Security Interests	89

2

‎Article 19	Governing Law and Dispute Resolution	95
‎Article 20	Security and Credit Cover	104
‎Article 21	Relationship and Sellers’ Coordinator	106
‎Article 22	Immunity	109
‎Article 23	Miscellaneous Provisions	110

Schedules

1	Sellers' Petroleum Rights
2	Sellers’ Percentages and Sellers' Interest
3	Sellers' Agreements
4	List of Charges on Sellers' Petroleum Rights
5	Specification
6	Corporate Guarantee
7	Bank Guarantee
8	Letter of Credit
9	Delivery Point Diagram (**)
10	Form of Buyer's Consent (**)

3

THIS AGREEMENT is entered into on the 14th day of March 2012

BETWEEN

(1) Noble Energy Mediterranean Ltd., a Cayman Islands company that has limited liability, registered in Israel as a foreign company No. 560017162, having its principal place of business at 12 Abba Eban Boulevard, Herzlia, 46725 Israel;

Delek Drilling Limited Partnership, an Israeli Limited Partnership having its principal place of business at 12 Abba Eban Boulevard, Herzlia, 46725 Israel;

Isramco Negev 2 Limited Partnership, an Israeli limited partnership having its principal place of business at 8 Granit Street, Petach Tikva, 49222, Israel;

Avner Oil Exploration Limited Partnership, an Israeli Limited Partnership having its principal place of business at 12 Abba Eban Boulevard, Herzlia, 46725 Israel; and

Dor Gas Exploration Limited Partnership, an Israeli limited partnership having its principal place of business at France Building, Europark, P.O. Box 10, Yakum, 60972, Israel;

(each a "Seller" and together the "Sellers") of the one part; and

(2) The Israel Electric Corporation Limited, an Israeli Company having its principal place of business at 1 Nativ Haor Street, Haifa, 31000 Israel (the "Buyer") of the other part.

The Sellers on the one part and the Buyer on the other part are a "Party" to this Agreement and the Sellers and the Buyer are collectively "Parties" to this Agreement.

WHEREAS

(A) The Sellers' Petroleum Rights have been granted to the Sellers and the Sellers have entered into the Sellers' Agreements.

(B) Under and by virtue of the Sellers' Petroleum Rights and the Sellers' Agreements:

(1) Operations have been carried out by the Sellers and as a result accumulations of Natural Gas currently estimated to be in excess of two hundred and fifty Billion Cubic Meters (250 BCM) (Proved and Probable reserves) have been discovered within the Reservoir; and

(2) The Sellers are the owners of the Sellers' Interest and parties to the Sellers’ Agreements.

4

(C) The Sellers desire to sell to the Buyer and the Buyer desires to buy from the Sellers, at the Delivery Point Natural Gas during the Contract Period, upon and subject to the terms and conditions herein contained.

NOW IT IS HEREBY AGREED AS FOLLOWS

5

ARTICLE 1

Definitions

1.1 Defined Terms

Except where the context otherwise indicates or requires the following terms in this Agreement shall have the following meanings:

1.1.1 "Act of Insolvency" means, if, as to any Person, an order is made by a court or an effective resolution is passed for the reorganization under any bankruptcy law, dissolution, liquidation, administration or winding up of such Person; an application for the dissolution, liquidation, administration or winding up of such Person is submitted to the courts and is not withdrawn or dismissed within ninety (90) days; such Person dissolves, liquidates, is wound up, or otherwise terminates its existence; such Person becomes insolvent, bankrupt or makes an assignment for the benefit of creditors (other than an assignment permitted under Article ‎18.6 of this Agreement); or a receiver or administrator is appointed for a substantial part of such Person's assets and such appointment is not withdrawn or cancelled within thirty (30) days.

1.1.2 "Actual Increase Date" means the date upon which the Sellers notify the Buyer that they have completed the commissioning and testing of the facilities contemplated by the Sellers' Additional Development Plan but not later than ninety (90) days following the Additional Flow Date.

1.1.3 "Additional Delay Period" has the meaning set out in Article ‎6.4.11.

1.1.4 "Additional Delivery Point" has the meaning set out in Article ‎13.1.

1.1.5 "Additional Flow Date" means the date on which the Sellers' Additional Facilities are completed to the extent required in order to enable Sellers to deliver Gas at the Delivery Point in accordance with the Buyer's Proper Nominations following the coming into effect of the increased MaxHQ as a consequence of the Buyer's exercise of the Increase Option.

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1.1.6 "Adjusted Annual Contract Quantity" or "Adjusted ACQ" has the meaning set out in Article ‎9.1.2.

1.1.7 "Affected Party" has the meaning set out in Article ‎16.8.

1.1.8 "Affiliate" means a company, partnership or other legal entity, which controls, is controlled by, or which is controlled by an entity that controls, any of the Sellers or the Buyer. Control means the ownership, directly or indirectly, of fifty percent (50%) or more of the voting rights, and/or the power to appoint half or more of the directors, in a company, partnership or other legal entity. With respect to any of the Sellers that are limited partnerships, Affiliates shall include the general partner of such limited partnership, and any company, partnership or other legal entity, which controls, or which is controlled by an entity that controls the general partner.

1.1.9 "Annual Contract Quantity" or "ACQ" has the meaning set out in Article ‎6.1.

1.1.10 "Annual Reconciliation Statement" has the meaning set out in Article ‎11.2.1.

1.1.11 "Annual Take or Pay Quantity" has the meaning set out in Article ‎9.3.1.

1.1.12 "Anti-trust Consent" means any consent or approval required under the Israel Restrictive Trade Practices Law 1988 in relation to this Agreement to be granted by the appropriate authority or court, such consent or approval to be final and unconditional or, if not, then subject to conditions which have been agreed to by the Party or Parties to whom such conditions apply.

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1.1.13 "Approval Date" means forty five (45) Days following the Effective Date.

1.1.14 "Ashdod Delivery Point" has the meaning set out in Article ‎13.1.

1.1.15 "Banks" has the meaning set out in Article ‎18.6.1.

1.1.16 "Bar" means pressure equal to one hundred thousand (100,000) Pascals (Pascal: as defined in ISO 1000:1981(E)).

1.1.17 "BTU" means an amount of heat equal to one thousand and fifty-five decimal zero six (1,055.06) Joules (Joules: as defined in ISO 1000:1981(E)).

1.1.18 "Business Day" means any day except a Friday, a Saturday and a day on which banks are closed for business in Israel.

1.1.19 "Buyer's Actual Generation" means the aggregate gross quantity of electricity generated in any Contract Year by the Buyer (in TWH) from all types of fuels, including (**).

1.1.20 "Buyer's Capacity Notice" has the meaning set out in Article ‎17.3.3(c).

1.1.21 "Buyer's Facilities" means the equipment installed by or on behalf of the Buyer at the entry to the Downstream System for the purposes of enabling the Buyer to receive Specification Gas to be delivered under this Agreement at the Delivery Point.

1.1.22 "Buyer's Stations" means the gas fired power stations and all related equipment and machinery, owned or operated by the Buyer, as are necessary from time to time to generate and distribute electricity.

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1.1.23 "Calendar Year" means a period beginning at 0600 on the first day of January in any calendar year and ending at 0600 on the first day of January of the next succeeding calendar year.

1.1.24 "Carry Forward" has the meaning set out in Article ‎9.2.1.

1.1.25 "Carry Forward Aggregate" has the meaning set out in Article ‎9.2.2.

1.1.26 "Charged Assets" has the meaning set out in Article ‎18.6.3.

1.1.27 "Cold Start" means recommencement of supply of Specification Gas through Sellers’ Facilities after the Sellers’ Facilities did not supply Specification Gas to any purchasers for a period of at least one (1) Hour which resulted in a shut-down of the Sellers’ Facilities.

1.1.28 "Commencement Date"means the first Day immediately following the last day of the Commissioning Period.

1.1.29 "(**)" has the meaning set out in Article 17.3.1.

1.1.30 "Commissioning Period" has the meaning set out in Article ‎2.4.1.

1.1.31 "Contract Period" means the period mentioned in Article ‎2.1.1.

1.1.32 "Contract Price" means the amount, in US Dollars, calculated in accordance with Article ‎10.1.

1.1.33 "Contract Year" means the following periods (as applicable):

(a) the period beginning at 0600 on the Commencement Date and ending at 0600 on the immediately following first day of January; and

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(b) the period beginning at 0600 on the first day of January immediately after the Commencement Date and ending at the same hour on the first day of January in the immediately succeeding Calendar Year and thereafter during the Contract Period any successive period of twelve (12) consecutive Months commencing at 0600 on the first day of January in each Calendar Year except for the Calendar Year in which the Contract Period ends; and

(c) in the year in which the Contract Period ends, the period beginning at 0600 on the first day of January and ending at 0600 on the last Day of the Contract Period.

1.1.34 "CPI" has the meaning set out in Article ‎10.1.3.

1.1.35 "Credit Cover" means any of the following forms of guarantee: (i) a corporate guarantee substantially in the form set out in Schedule 6 ("Corporate Guarantee"), provided by Alon Natural Gas Exploration Ltd. for Dor Gas Exploration Limited Partnership; or (ii) a bank guarantee substantially in the form set out in Schedule 7 ("Bank Guarantee"); or (iii) a Letter of Credit substantially in the form set out in Schedule 8 ("Letter of Credit"), issued by one of the top three (3) Israeli Banks or issued by a non Israeli Bank whose Credit Rating is at least S&P’s rating group "A" or Moody’s rating "A2".

1.1.36 "Cubic Meter" or "m3" means when applied to gas that quantity of gas which at fifteen (15) degrees Celsius and at an absolute pressure of one decimal zero one three two five (1.01325) Bar and the gas being free of water vapor, occupies the volume of one (1) cubic meter, being a meter as defined in ISO 1000: 1981(E).

1.1.37 "Daily Delivery Tolerance" has the meaning set out in Article ‎6.7.1(b).

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1.1.38 "Daily Contract Quantity" or "DCQ" has the meaning set out in Article ‎6.2.1.

1.1.39 "Day" means a period of twenty-four (24) hours beginning at 0600 on any day and ending at 0600 on the following day.

1.1.40 "Deemed Increase Date" means the Day immediately prior to the fourth (4th) anniversary of the Sellers' Additional Conditions Date (if applicable).

1.1.41 "Delivery Point" has the meaning set out in Article ‎13.1.

1.1.42 "Delivery Pressure" has the meaning set out in Article ‎14.1.1.

1.1.43 "Delivery Tolerances" has the meaning set out in Article ‎6.7.1.

1.1.44 "Disclosed Information" has the meaning set out in Article ‎8.5.1.

1.1.45 "Dispute" has the meaning set out in Article ‎19.2.

1.1.46 "Downstream System" means the pipelines, installations and other facilities owned and/or operated by the Transporter downstream of the Delivery Point necessary for the transportation of Gas from the Delivery Point to Buyer’s Stations.

1.1.47 "Effective Date" means the date of execution of this Agreement.

1.1.48 "Excess Gas" has the meaning set out in Article ‎6.9.3.

1.1.49 "Expert" means any Person appointed from time to time under and subject to the provisions of Article ‎19.3.

1.1.50 "Extended Contract Period" has the meaning set out in Article ‎2.1.2.

1.1.51 "First Period" means the period Commencing on the Commencement Date and ending on the earlier of: (i) the Increase Date (if applicable); and (ii) the last Day of the Contract Period.

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1.1.52 "Flow Date" has the meaning set out in Article ‎2.2.1.

1.1.53 "Force Majeure" has the meaning set out in Article ‎16.1.

1.1.54 "Gas" means Natural Gas, Specification Gas or both, as the context may permit or require.

1.1.55 "Gauge" means the pressure in excess of one decimal zero one three two five (1.01325) Bar (which is one (1) standard atmosphere).

1.1.56 "Governmental Approval" means the consent or approval of the Government of Israel pursuant to section 11(A)(9A) of the Government Companies Law, 5735-1975 in relation to this Agreement, such consent or approval to be final and unconditional or, if not, then subject to conditions which have been agreed to by the Party or Parties to whom such conditions apply.

1.1.57 "Higher Heating Value" means the superior (higher) real calorific value as described in ISO: 6976:1995 (E) of one Cubic Meter of Natural Gas at the reference condition of 15/15 Degrees Celsius and 1.01325 Bar (a) for the actual natural gas in the real state.

1.1.58 "Hour" means a period of sixty (60) minutes beginning on the hour.

1.1.59 "Hourly Delivery Tolerance" has the meaning set out in Article ‎6.7.1(a).

1.1.60 "IF" has the meaning set out in Article ‎10.1.3.

1.1.61 "Increase Date" means the Actual Increase Date or the Deemed Increase Date, as determined in accordance with Article ‎6.4.10.

1.1.62 "Increase Notice" has the meaning set out in Article ‎6.4.1.

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1.1.63 "Increase Option" means the option for the Buyer in accordance with Article ‎6.4 to increase the MaxHQ to (**) MMBTU together with a corresponding increase of the DCQ to (**) MMBTU.

1.1.64 "Initial Quota" has the meaning set out in Article ‎9.4.1.

1.1.65 "Installed Capacity" means (i) with respect to Sellers' Fueled Electricity Producer's production units that are supplied exclusively by the Sellers, the aggregate electricity production capacity (in MW) stipulated in the nameplate of such units; and (ii) with respect to Sellers' Fueled Electricity Producer's production units that are supplied by the Sellers on a non-exclusive basis, a proportionate part of the aggregate electricity production capacity (in MW) stipulated in the nameplate of such units calculated based on the ratio of: (i) the annual contract quantity of gas to be supplied by the Sellers to such Sellers' Fueled Electricity Producer; and (ii) the aggregate quantity of gas to be supplied to such Sellers' Fueled Electricity Producer from Sellers and from other sources.

1.1.66 "LCIA" means the London Court of International Arbitration.

1.1.67 "LIBOR" means London Interbank Offered Rate for three (3) month maturities, for US Dollar deposits, as published on the first banking day following any relevant due date for payment under this Agreement by the Wall Street Journal or if not so published, then by the Financial Times of London.

1.1.68 "Maintenance" has the meaning set out in Article ‎6.11.1.

1.1.69 "Maintenance Period" has the meaning set out in Article ‎6.11.1.

1.1.70 "Make-Up Aggregate" has the meaning set out in Article ‎9.3.4.

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1.1.71 "Maximum Hourly Quantity" or "MaxHQ" has the meaning set out in Article ‎6.3.

1.1.72 "Minimum Bill Quantity" or "MBQ" has the meaning set out in Article ‎9.1.3.

1.1.73 "MMBTU" means one million (1,000,000) BTUs.

1.1.74 "Month" means a period beginning at 0600 on the first day of any calendar month and ending at 0600 on the first day of the next succeeding calendar month.

1.1.75 "Monthly Statement" has the meaning set out in Article ‎11.1.1.

1.1.76 "MW" means one million watts.

1.1.77 "Nameplate Capacity of Sellers' Facilities" means the expected maximum capacity of the Sellers' Facilities as determined in the design basis of such facilities.

1.1.78 "Natural Gas" means any hydrocarbons (or mixture of hydrocarbons and other gases consisting primarily of methane) which at fifteen (15) Degrees Celsius and atmospheric pressure are or is in the gaseous state.

1.1.79 "Net Annual TOP Quantity" has the meaning set out in Article ‎9.3.2(a).

1.1.80 "New Producers Adjustment Quantity" has the meaning set out in Article ‎9.4.1(a).

1.1.81 "Non-Interruptible Gas Sales Agreements" means agreements entered into by the Sellers in which the Sellers undertook to deliver Gas to a purchaser at the Delivery Point through Sellers' Facilities, but excluding any agreement pursuant to which the Sellers have the right to curtail supply of gas in circumstances of insufficient capacity in Sellers' Facilities.

1.1.82 "Off-Spec Gas" means Natural Gas that does not conform to the Specification.

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1.1.83 "Over Deliveries" has the meaning set out in Article ‎6.10.

1.1.84 "Period Shortfall" has the meaning set out in Article ‎17.1.6.

1.1.85 "Person" includes any person, firm, partnership, association, company, body corporate, or individual.

1.1.86 "Petroleum Law" means the Israel Petroleum Law 5712-1952.

1.1.87 "Price Adjustment" has the meaning set out in Article ‎10.7.1.

1.1.88 "Price Adjustment Date" has the meaning set out in Article ‎10.7.1.

1.1.89 "Price Adjustment Notice" has the meaning set out in Article ‎10.7.1.

1.1.90 "Price Control Event" means the issuance, imposition or enactment of a decree, ruling, declaration, regulation, order, directive, instruction or other legal instrument, pursuant to the Israeli Prices of Commodities and Services (Supervision) Law, 5756-1996 or to any other law or regulation, the effect of which is the reduction of the amount to be received by Sellers for Gas to be delivered to the Buyer pursuant to this Agreement.

1.1.91 "Price Period" means a Calendar Year.

1.1.92 "Proper Nomination" has the meaning set out in Article ‎6.9.1.

1.1.93 "Properly Nominated" has the meaning set out in Article ‎6.9.1.

1.1.94 "Proved and Probable Reserves" means the sum of Proved Reserves and Probable Reserves as these terms are defined in the 2007 Petroleum Resource Management System (PRMS) approved by the Society of Petroleum Engineers (SPE).

1.1.95 "Provisional Contract Price" has the meaning set out in Article ‎10.6.1(a).

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1.1.96 "PUA Approval" means any consent or approval required in relation to this Agreement to be granted by the Israeli Public Utilities Authority- Electricity, such consent or approval to be final and unconditional or, if not, then subject to conditions which have been agreed to by the Party or Parties to whom such conditions apply.

1.1.97 "Reasonable and Prudent Operator" means a Person seeking in good faith to perform its contractual obligations and in so doing and in the general conduct of its undertaking exercising that degree of skill, diligence, prudence and foresight which would reasonably and ordinarily be expected from a skilled and experienced operator complying with the applicable law and industry standards engaged in the same type of undertaking under the same or similar circumstances and conditions.

1.1.98 "Representative Rate" means the representative rate of exchange of the New Israeli Shekel against the US Dollar, as published by the Bank of Israel.

1.1.99 "Reservoir" means that reservoir (currently known as the Tamar field) covered by Petroleum Lease I/12"Tamar" and which is more particularly identified in Schedule 1.

1.1.100 "Reservoir Event" has the meaning set out in Article ‎16.2.1.

1.1.101 "Review Month" has the meaning set out in Article ‎10.1.1.

1.1.102 "Sanction Notice" has the meaning set out in Article ‎6.4.2(b).

1.1.103 "Sanction of the Additional Development" means the approval by the Sellers under the Sellers' Agreements of a program and budget for the Sellers' Additional Development Plan.

1.1.104 "Second Period" means the period commencing on the Increase Date (if applicable) and ending on the last Day of the Contract Period.

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1.1.105 "Sellers' Additional Conditions" has the meaning set out in Article ‎6.4.4.

1.1.106 "Sellers' Additional Conditions Date" means the date on which the Sellers' Additional Conditions are satisfied or waived by the Sellers.

1.1.107 "Sellers' Additional Development Plan" means the plan for the construction and installation by or on behalf of the Sellers of additional facilities including the Sellers' Additional Pipeline and if applicable the Sellers' Additional Receiving Facilities and gas storage facilities in the Mari-B reservoir, as may be required for the increase of the total capacity of the Sellers' Facilities to enable delivery of Gas to the Ashdod Delivery Point and/or the Additional Delivery Point (as applicable), at cumulative peak rates of at least (**) MMBTU per (**) and (**) MMBTU per (**), for the purposes of fulfilling the Sellers' obligations to deliver Specification Gas in response to the Buyer's Proper Nominations in the case of an increase of the MaxHQ pursuant to the provisions of Article ‎6.4. It is clarified that the Sellers will not be required to increase the maximum rate of production from the Reservoir to more than (**) MMBTU per (**).

1.1.108 "Sellers' Additional Facilities" means the Sellers' Additional Pipeline and, if applicable, the Sellers' Additional Receiving Facilities.

1.1.109 "Sellers' Additional Pipeline" means a new pipeline, owned or operated by or on behalf of the Sellers, connecting the new platform to be installed by the Sellers in the area of the "Ashkelon" I/10 Lease to the Sellers' Additional Receiving Facilities (if applicable) or to the Yam Tethys Facilities.

1.1.110 "Sellers' Additional Receiving Facilities" means the new facilities, to be owned or operated by or on behalf of the Sellers, for the receipt, pressure reduction, processing, treatment, measurement and/or delivery of Gas that will be transported from the Sellers' Petroleum Rights through the Sellers' Additional Pipeline to the Ashdod Delivery Point or the Additional Delivery Point.

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1.1.111 "Sellers' Agreements" means the agreements or arrangements between the Sellers, listed in Schedule 3.

1.1.112 "Sellers' Capacity Increase Notice" has the meaning set out in Article ‎17.3.3(b).

1.1.113 "Sellers’ Coordinator" has the meaning set out in Article ‎21.2.1.

1.1.114 "Sellers' Delay Period" has the meaning set out in Article ‎2.3.2.

1.1.115 "Sellers’ Facilities" means such platforms, wells, pipelines, installations and other equipment, installed or to be installed by or on behalf of the Sellers, as are necessary from time to time to produce, process, transport, measure and deliver Specification Gas at the Delivery Point pursuant to this Agreement including the Yam-Tethys Facilities and if applicable, the Sellers' Additional Facilities.

1.1.116 "Sellers' Fueled Electricity Producers" means any Private Electricity Producer, as defined in the Electricity Sector Law 5756-1996, that is (**).

1.1.117 "Sellers' Interest" means the aggregate total of the Seller’s Percentages.

1.1.118 "Sellers' Lenders" has the meaning set out in Article ‎18.6.4.

1.1.119 "Sellers' (**)" means Sellers having entered into (**).

1.1.120 "Sellers' Petroleum Rights" means those petroleum rights in relation to the Reservoir under the Petroleum Law, to which the Sellers are party and which are set out in Schedule 1.

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1.1.121 "Seller's Percentage" means the respective interests of the Sellers, expressed as a percentage, in the Sellers' Petroleum Rights as set out in Schedule 2.

1.1.122 "Shortfall Aggregate" has the meaning set out in Article ‎17.2.1.

1.1.123 "Shortfall Gas" has the meaning set out in Article ‎17.1.1.

1.1.124 "Shortfall Price" has the meaning set out in Article ‎10.8.3.

1.1.125 "Specification" has the meaning set out in Article ‎12.1.1.

1.1.126 "Specification Gas" means Natural Gas that complies with the Specification and any Off-Spec Gas that the Buyer takes in accordance with the terms of Article ‎12.2.4.

1.1.127 "Spot Sales Customer" has the meaning set out in Article ‎9.4.1(b).

1.1.128 "Take or Pay Period" means the period commencing on the later of the Commencement Date and (**) and ending at the end of the Contract Period.

1.1.129 "Target Completion Date" has the meaning set out in Article ‎6.4.11.

1.1.130 "Technical MinHQ" means (**) MMBTU.

1.1.131 "Three Month Window" has the meaning set out in Article ‎6.4.10.

1.1.132 "Total Contract Quantity" (or "TCQ") means a quantity of Gas equal to two billion and seven hundred and sixty million (2,760,000,000) MMBTU, and upon the Actual Increase Date (if applicable) the TCQ shall be increased to three billion five hundred and thirty six million (3,536,000,000) MMBTU.

1.1.133 "Transportation Agreement" means the agreement dated 13th January 2009 between Buyer and the Transporter.

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1.1.134 "Transporter" means the Person granted the license to transport Gas from the Delivery Point to Buyer’s Stations, currently Israel Natural Gas Lines Ltd.

1.1.135 "Twelve Month Window" has the meaning set out in Article ‎6.4.9.

1.1.136 "TWH" means one trillion watt hours.

1.1.137 "Week" means a period of seven (7) days beginning at 0600 on a Sunday and ending at 0600 on the following Sunday.

1.1.138 "Weekly Delivery Tolerance" has the meaning set out in Article ‎6.7.1(c).

1.1.139 "Yam-Tethys Agreements" means the agreement(s) to be entered into by and between the Sellers and the Yam-Tethys Partners providing for the transportation and processing within the Yam-Tethys Facilities and delivering to the Buyer at the Delivery Point, of Gas from the Reservoir pursuant to this Agreement.

1.1.140 "Yam-Tethys Facilities" means such platform, wells, pipelines, installations and other equipment, installed or to be installed by or on behalf of the Yam-Tethys Partners (and constituting part of the Sellers' Facilities) to the extent such are used from time to time to store, process, transport and deliver Gas from the Reservoir to the Buyer at the Delivery Point pursuant to this Agreement.

1.1.141 "Yam-Tethys Partners" means the owners of interests in the "Ashkelon" I/10 Lease granted pursuant to the Petroleum Law that covers the Mari-B gas reservoir offshore Israel.

1.1.142 "YT GSPA" means the gas sale and purchase agreement dated June 25, 2002 by and between the Buyer and the Yam-Tethys Partners (as amended) and the Agreed Principles dated July 2, 2009 (as amended).

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1.2 Interpretation

In this Agreement, Article headings and the index are inserted for convenience only and do not affect the interpretation of this Agreement; and unless the context indicates a contrary intention:

1.2.1 the term "Agreement" includes the Schedules to this Agreement and any amendments to this Agreement;

1.2.2 references to Articles or Schedules shall be deemed to be references to Articles of or Schedules to this Agreement;

1.2.3 the singular shall be deemed to include the plural and vice versa except with respect to the Sellers or to a Seller;

1.2.4 references in this Agreement to any law, decree or statutory provision shall be deemed to include references to any regulations and orders made thereunder;

1.2.5 references in this Agreement to any law shall include references to such law as it may, after the Effective Date, from time to time be amended, supplemented or re-enacted;

1.2.6 references to time shall be construed as a reference to whatever time shall be statutorily in force in Israel;

1.2.7 the words and phrases "other", "including" and "in particular" shall not limit the generality of any preceding words or be construed as being limited to the same class as the preceding words where a wider construction is possible;

1.2.8 where a word or phrase is defined, its other grammatical forms shall have corresponding meanings;

1.2.9 references to "writing" include any mode of representing or reproducing words, numbers, symbols or drawing in a visible form and includes by facsimile or by electronic mail;

1.2.10 references to any decision, determination, election, discretion or act of the Sellers under this Agreement, mean any decision, determination, election, discretion or act exercised or made unanimously or carried out jointly by the Sellers or, if applicable, by the Sellers’ Coordinator on behalf of all Sellers;

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1.2.11 for the purposes of this Agreement, the energy content of Gas delivered hereunder shall be calculated in accordance with its Higher Heating Value;

1.2.12 the words "shall" and "will" shall be construed to have the same meaning and effect.

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ARTICLE 2

Period of Agreement and Commissioning

2.1 Commencement and Period

2.1.1 The Contract Period: This Agreement shall come into force on the Effective Date and subject to Article ‎2.1.3 shall continue until the earlier of:

(a) the fifteenth (15th) anniversary of the Commencement Date ; and

(b) the date of delivery by the Sellers under this Agreement of an aggregate quantity of Gas equal to the Total Contract Quantity;

unless terminated earlier by either Party in accordance with the terms of this Agreement or extended in accordance with the provisions of Articles ‎2.1.2 and ‎9.5.6 ("Contract Period").

2.1.2 Extended Contract Period: In the event that by the thirteenth (13th) anniversary of the Commencement Date, the Buyer notifies the Sellers in writing that it reasonably anticipates that it will not be able to take from the Sellers an aggregate quantity of Specification Gas equal to the Total Contract Quantity by the fifteenth (15th) anniversary of the Commencement Date, and that it requests an extension of the Contract Period, then the Contract Period will be automatically extended by an additional period commencing on the fifteenth (15th) anniversary of the Commencement Date and ending on the earlier of: (i) the seventeenth (17th) anniversary of the Commencement Date; and (ii) the date by which the Buyer will have taken from the Sellers under this Agreement an aggregate quantity of Gas equal to the Total Contract Quantity (the period from the date on which this Agreement would have come to an end and until such later date being herein called the "Extended Contract Period"). During the Extended Contract Period, the provisions of this Agreement (including, inter alia, the provisions of ‎Article 9) shall continue to apply, except that any Carry Forward Aggregate which has accrued under this Agreement prior to the commencement of the Extended Contract Period shall be cancelled and shall not serve to reduce the Annual Take or Pay Quantity attributable to the Extended Contract Period.

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2.1.3 Conditionality: This Agreement is conditional upon (i) the Buyer and the Sellers obtaining the Anti-trust Consent or waiving such condition; (ii) the Buyer obtaining the Governmental Approval or waiving such condition; and (iii) the Buyer obtaining the PUA Approval or waiving such condition.

2.1.4 Anti-Trust Consent: The Sellers and the Buyer together shall diligently pursue the application for the Anti-trust Consent and shall make reasonable endeavors to obtain the Anti-trust Consent as soon as possible but in any event before the Approval Date. The Parties shall keep each other informed as to progress made towards obtaining the Anti-trust Consent on at least a weekly basis and shall co-operate with each other and provide reasonable assistance to each other to obtain the Anti-trust Consent.

If the Anti-trust Consent is not obtained before the Approval Date, or such condition is not waived by both Parties:

(a) the Parties shall meet as soon as possible, and in any event within seven (7) days after the Approval Date, to discuss the prospects for obtaining the Anti-trust Consent; and

(b) promptly after the date of such meeting or seven (7) days after the Approval Date (whichever is the later) either Party may, provided that it has complied with its obligations under this Article ‎2.1.4(a), terminate this Agreement on not less than seven (7) days prior written notice and upon the expiration of such notice period this Agreement will terminate, except if, before the termination date as specified in the notice, the Anti-trust Consent is obtained, then notwithstanding the notice of termination, this Agreement shall not terminate but shall continue in force.

2.1.5 Governmental Approval: The Buyer shall diligently pursue the Governmental Approval and shall make reasonable endeavors to obtain the Governmental Approval as soon as possible but in any event prior to the Approval Date. Buyer shall keep the Sellers informed as to progress made towards obtaining the Governmental Approval.

If the Governmental Approval is not obtained before the Approval Date, or such condition precedent is not waived by the Buyer:

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(a) the Parties shall meet as soon as possible, and in any event within seven (7) days after the Approval Date, to discuss the prospects for obtaining the Governmental Approval;

(b) promptly after the date of such meeting or seven (7) days after the Approval Date (whichever is the later) the Sellers may terminate this Agreement on not less than seven (7) days prior written notice and upon the expiration of such notice period this Agreement will terminate except if, before the termination date as specified in the notice, the Government Approval is obtained, then notwithstanding the notice of termination, this Agreement shall not terminate but shall continue in force; and

(c) if the Government Approval is not obtained by September 30, 2012 the Buyer may, provided that it has complied with its obligations under Article ‎2.1.5, terminate this Agreement on not less than seven (7) days prior written notice and upon the expiration of such notice period this Agreement will terminate, except if, before the termination date as specified in the notice, the Government Approval is obtained, then notwithstanding the notice of termination, this Agreement shall not terminate but shall continue in force.

2.1.6 PUA Approval: The Buyer shall diligently pursue the PUA Approval and shall make reasonable endeavors to obtain the PUA Approval as soon as possible but in any event prior to the Approval Date. Buyer shall keep the Sellers informed as to progress made towards obtaining the PUA Approval.

If the PUA Approval is not obtained before the Approval Date, or such condition precedent is not waived by the Buyer:

(a) the Parties shall meet as soon as possible, and in any event within seven (7) days after the Approval Date, to discuss the prospects for obtaining the PUA Approval;

(b) immediately after the date of such meeting or seven (7) days after the Approval Date (whichever is the later) the Sellers may terminate this Agreement on not less than seven (7) days prior written notice and upon the expiration of such notice period this Agreement will terminate except if, before the termination date as specified in the notice, the PUA Approval is obtained, then notwithstanding the notice of termination, this Agreement shall not terminate but shall continue in force; and

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(c) if the PUA Approval is not obtained by September 30, 2012 the Buyer may, provided that it has complied with its obligations under Article ‎2.1.6, terminate this Agreement on not less than seven (7) days prior written notice and upon the expiration of such notice period this Agreement will terminate, except if, before the termination date as specified in the notice, the PUA Approval is obtained then notwithstanding the notice of termination, this Agreement shall not terminate but shall continue in force.

2.1.7 Effect of Conditionality: Articles 1, ‎2.1, ‎2.6, 4, ‎8.5, 18, 19, 21, 22 and 23 will take effect on and from the Effective Date.

2.2 Flow Date

2.2.1 The "Flow Date" is the date on which the Sellers’ Facilities are completed to the extent required in order to deliver Specification Gas from the Reservoir at the Delivery Point in accordance with the terms of this Agreement (**) for the purposes of commissioning and testing the Sellers’ Facilities. The Sellers shall provide the Buyer not less than fourteen (14) days notice prior to the occurrence of the Flow Date. It is the intention of the Sellers that the Flow Date shall occur by July 1, 2013.

2.3 Consequences of Delays in Flow Date

2.3.1 Construction of Sellers' Facilities: In accordance with the terms of this Agreement, Sellers shall construct the Sellers' Facilities in order to enable Sellers to deliver Specification Gas produced from the Reservoir at the Delivery Point in accordance with the terms of this Agreement by October 1, 2013.

2.3.2 Sellers' Delay Period: In the event that by January 1, 2014 the Flow Date has not occurred, then in respect of each Day from and after January 1, 2014 until the Flow Date (the "Sellers' Delay Period"), the Sellers shall make payments to the Buyer in accordance with the provisions of Article ‎2.3.3 subject to the Sellers' limitation of liability as set out in Article ‎17.4.7, and such payments shall be the Sellers' sole liability to the Buyer and Buyer's sole remedy in such circumstances. For the avoidance of doubt, the Sellers shall be entitled to claim relief by reason of Force Majeure in accordance with ‎Article 16 in respect of such delay and liability. All such payments shall be made monthly in respect of each Day and shall be set out in a statement to be sent by the Buyer to the Sellers in accordance, mutatis mutandis, with ‎Article 11.

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2.3.3 Sellers' Payments: With respect to each Day during the Sellers' Delay Period (except to the extent such delay was caused by an event of Force Majeure) the Sellers shall pay the Buyer a sum of money equal to (**) in lieu of Sellers' liability for Shortfall Gas under Article ‎17.1 and such payments shall be the limit of the Sellers' liability and Buyer's sole remedy in such circumstances.

2.3.4 Termination due to Sellers' Delay: In the event that Sellers' Delay Period continues for a period of more than six (6) Months (except to the extent such delay was caused by an event of Force Majeure), then Buyer and Sellers shall meet within seven (7) days after the end of such six (6) Month period, to discuss and seek to agree on appropriate arrangements that will enable delivery of Specification Gas in accordance with the terms of this Agreement until the occurrence of the Flow Date, and if no such agreement is reached within thirty (30) days after the end of such six (6) Month period, the Buyer may, at any time thereafter, by not less than sixty (60) days' prior written notice to the Sellers, terminate this Agreement, unless prior to the expiry of such notice period the Flow Date has occurred, and in such event, notwithstanding such notice of termination, this Agreement shall not terminate but shall continue in force.

2.4 Commissioning Period

2.4.1 The "Commissioning Period" shall be a period commencing on the Flow Date and ending on the earlier of (i) the date upon which the Sellers notify the Buyer that they have completed the commissioning of the Sellers' Facilities, and (ii) the date of expiry of ninety (90) days following the Flow Date.

2.4.2 The Sellers will provide to the Buyer not less than fourteen (14) days' prior notice of the commencement of the Commissioning Period. During the Commissioning Period the Sellers may carry out commissioning activities of the Sellers' Facilities.

2.4.3 During the Commissioning Period the Buyer shall use reasonable endeavors to nominate and take delivery of Specification Gas in such quantities and at such rates as may reasonably be requested by the Sellers to carry out the commissioning and testing of the Sellers’ Facilities. For the avoidance of doubt, the provisions of Articles ‎9.3 and ‎17.1 shall not apply during the Commissioning Period.

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2.4.4 The Sellers will notify the Buyer upon completion of the commissioning of the Sellers’ Facilities.

2.5 Information and Inspection

2.5.1 Within thirty (30) days after the Effective Date and once every three (3) months thereafter until the Flow Date, the Sellers and the Buyer shall meet and discuss the state of progress of the Sellers’ Facilities (including permitting) and the plans for the development and commissioning of the Sellers’ Facilities.

2.5.2 On the request of the Buyer, the Sellers shall allow for the inspection of the progress of the construction and installation of the Sellers’ Facilities, upon reasonable advance request by the Buyer, such inspection to occur during normal working hours and provided Buyer complies with Sellers' standard safety and security procedures.

2.5.3 It is acknowledged and agreed that nothing in this ‎Article 2 shall oblige either Party to do or omit to do anything which would:

(a) breach or otherwise adversely affect any bona fide commitment of confidentiality owed to any Person; or

(b) procure or allow any rights of access or inspection in excess of or contrary to such rights as may be available to and exercisable by one Party in favor of the other.

2.6 Termination

2.6.1 Without prejudice to any other rights that the Sellers may have under this Agreement or pursuant to applicable law, the Sellers may terminate this Agreement in circumstances where the Buyer commits an Act of Insolvency that may reasonably be expected to materially adversely affect the performance by the Buyer of its obligations under this Agreement, by giving the Buyer not less than one hundred and twenty (120) days written notice

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2.6.2 Without prejudice to any other rights that the Buyer may have under this Agreement or pursuant to applicable law, the Buyer may terminate this Agreement in circumstances where any or all of the Sellers commit an Act of Insolvency that may reasonably be expected to materially adversely affect the performance by all of the Sellers of their obligations under this Agreement, by giving the Sellers not less than one hundred and twenty (120) days written notice.

2.6.3 The Sellers and the Buyer agree that they will not exercise any termination rights, except in relation to significant or continuing breaches by the other Party of a material provision of this Agreement and only after giving the breaching Party a period of one hundred and twenty (120) days (unless a shorter period is determined under this Agreement) in which to remedy the breach.

2.6.4 Any termination of this Agreement shall not affect any rights or obligations, which may have accrued prior to such termination.

2.6.5 Any notice of termination of this Agreement by the Sellers, shall be given by the Sellers to the Buyer as a single notice binding on all the Sellers on the same terms and being expressed to terminate this Agreement in respect of each of the Seller's Percentages and in respect of the Sellers' Interest.

2.6.6 Any notice of termination of this Agreement by the Buyer, shall be given by the Buyer to the Sellers jointly binding on all the Sellers on the same terms and being expressed to terminate this Agreement in respect of the Sellers’ Interest and in respect of each of the Sellers in relation to its respective Seller's Percentage, except that in circumstances where the grounds for any such notice of termination are given only in respect of Article ‎2.6.2 and are applicable to any one or more of the Sellers, but not all the Sellers, then such notice shall not have effect if, before its expiry, the Seller (or Sellers) in respect of which such notice has been served shall have signed an agreement or deed providing for the transfer of the relevant Seller’s Percentage (or as the case may be respective Sellers’ Percentages) under this Agreement to another Seller or Sellers or to other transferees in compliance with the provisions of ‎Article 18.

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ARTICLE 3

Agreement for Sale and Purchase

3.1 Agreement

Subject to the terms of this Agreement, the Sellers agree to deliver and sell and the Buyer agrees to take and pay for or, if not taken, pay for Gas, in such quantities, at such times and in such manner as shall from time to time be provided for under this Agreement.

3.2 Uses and Sources

3.2.1 The Buyer shall not be limited or restricted in the use of the Specification Gas purchased under this Agreement or in the purpose for which such Specification Gas is purchased by the Buyer.

3.2.2 Without derogating from the Sellers’ obligations in relation to the Sellers' Facilities under this Agreement, the Sellers shall not be limited or restricted in their sources of Natural Gas (whether from Israel or imported from elsewhere) for the purposes of delivering Specification Gas to the Buyer under this Agreement.

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ARTICLE 4

Warranties, Covenants and Taxes

4.1 Sellers' Warranties and Title

4.1.1 Without prejudice to any obligation of the Sellers under this Agreement, each of the Sellers (as to its Seller’s Percentage) warrants to the Buyer as of the Effective Date, as follows:

(a) title to all Gas sold and delivered by such Seller under this Agreement and that all Gas delivered by such Seller shall, upon delivery, be free from all liens, charges, encumbrances and adverse interests of any and every kind;

(b) the Sellers' Petroleum Rights are valid and subsisting and are free from all liens, charges, encumbrances and adverse interests of any and every kind, other than the charges listed in Schedule 4 hereto;

(c) under the Sellers' Petroleum Rights, the Sellers have discovered accumulations of Natural Gas currently estimated to be in excess of two hundred and fifty (250) BCM (Proved and Probable Reserves) within the Reservoir and have, subject to receiving all permits required under law, the right to produce, sell and deliver Natural Gas from the Reservoir in accordance with the terms of this Agreement for the whole of the Contract Period;

(d) the Sellers together are the owners of the Sellers' Petroleum Rights and are parties to the Sellers’ Agreements and, subject to receiving all permits required under law and entering into the Yam-Tethys Agreements as required by Article ‎4.2.1(b), it has no knowledge of any matter which might prevent it from producing Natural Gas from the Reservoir or from transporting, processing, delivering and selling Specification Gas to the Buyer at the Delivery Point through the Sellers’ Facilities in accordance with the terms of this Agreement for the duration of the Contract Period;

(e) it has received no notification of any claims and knows of no grounds for any claim which may be adverse to or inconsistent with the ownership and other rights specified in Article ‎4.1.1‎(c) whether from holders of interests adjoining the Reservoir or otherwise;

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(f) it is duly organized and validly existing under the laws of the jurisdiction of its formation and it has the legal right, power and authority to conduct its business and execute and deliver this Agreement and observe and perform its obligations under this Agreement;

(g) the entry by it into and performance of this Agreement is within its power and has been duly authorized by all necessary action on its part and shall not breach any law or determination or provision applicable to its governing documents;

(h) the Seller and any director, officer, employee or affiliated company of such Seller has not made, offered, or authorized and will not make, offer, or authorize with respect to the matters which are the subject of this Agreement, any payment, gift, promise or other advantage, whether directly or through any other person or entity, to or for the use or benefit of any public official (i.e., any person holding a legislative, administrative or judicial office, including any person employed by or acting on behalf of a public agency, a public enterprise or a public international organization) or any political party or political party official or candidate for office, where such payment, gift, promise or advantage would violate (i) the applicable laws of Israel or the United States of America (including, without limitation, the Foreign Corrupt Practices Act of 1977, as amended, U.S.C. §78dd-1, et seq.); (ii) the principles described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed in Paris on December 17, 1997, which entered into force on February 15, 1999, and the Convention’s Commentaries; or (iii) the principles described in the United Nations Convention Against Corruption, which entered into force on December 14, 2005. Each Seller shall defend, indemnify and hold the other Parties harmless from and against any and all claims, damages, losses, penalties, costs and expenses arising from or related to, any breach by such Seller of such warranty. Such indemnity obligation shall survive termination or expiration of this Agreement. Each Seller shall in good time (i) respond in reasonable detail to any notice from any other Party reasonably connected with the above-stated warranty; (ii) furnish applicable documentary support for such response upon request from such other Party; (iii) maintain adequate internal controls, properly record and report all transactions; and (iv) comply with the laws applicable to it. Each Seller acknowledges and confirms that: (i) each Party must rely on the other Parties’ system of internal controls, and on the adequacy of full disclosure of the facts, and of financial and other data regarding action undertaken under this Agreement; (ii) No Party is in any way authorized to take any action on behalf of another Party that would result in an inadequate or inaccurate recording and reporting of assets, liabilities or any other transaction, or which would put such Party in violation of its obligations under the laws applicable to the operations under this Agreement;

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(i) this Agreement constitutes a legal valid and binding act and obligation enforceable against such Seller in accordance with the terms of this Agreement.

4.2 Sellers' Covenants

4.2.1 Each of the Sellers (as to its Seller's Percentage) covenants with the Buyer that throughout the Contract Period:

(a) except in conjunction with a permitted assignment, creation of security or charge or encumbrance made under the provisions of ‎Article 18, its Seller’s Percentage and its rights under this Agreement shall be maintained and preserved free and clear (save as aforesaid) from any assignment, security, charge or encumbrance;

(b) prior to the Commencement Date it shall enter into the Yam-Tethys Agreements on terms which provide for the transportation of Specification Gas to the Delivery Point so as to enable it to comply with its obligations under this Agreement;

(c) it shall not agree to or (to the extent that it is within its power to prevent) permit any amendment or modification of the Sellers' Agreements or the Sellers' Petroleum Rights or the Yam-Tethys Agreements, whereby the Sellers' ability to perform its obligations under this Agreement are likely to be prevented or materially adversely affected and shall observe and perform all terms thereof and exercise its rights thereunder in such manner as to secure that the terms and provisions of this Agreement shall be performed;

(d) (**); and

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(e) it shall obtain all and any necessary consents or approvals required from time to time to permit the performance of the Sellers' obligations hereunder.

4.3 Buyer's Warranties and Covenants

4.3.1 The Buyer warrants to the Sellers as of the Effective Date as follows:

(a) it has the right for the whole of the Contract Period to purchase Specification Gas from the Sellers in accordance with the terms of this Agreement;

(b) it is duly organized and validly existing under the laws of the jurisdiction of its formation and it has the legal right, power and authority to conduct its business and execute and deliver this Agreement and observe and perform its obligations under this Agreement;

(c) its entry into and performance of this Agreement is within its power and has been duly authorized by all necessary action on its part and shall not breach any law or determination or provision applicable to its governing documents;

(d) it has entered into the Transportation Agreement with the Transporter providing for the transportation of Specification Gas from the Delivery Point through the Downstream System to the Buyer’s Stations for the duration of the Contract Period;

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(e) the Buyer and any director, officer, or employee of the Buyer or any affiliated company has not made, offered, or authorized and will not make, offer, or authorize with respect to the matters which are the subject of this Agreement, any payment, gift, promise or other advantage, whether directly or through any other person or entity, to or for the use or benefit of any public official (i.e., any person holding a legislative, administrative or judicial office, including any person employed by or acting on behalf of a public agency, a public enterprise or a public international organization) or any political party or political party official or candidate for office, where such payment, gift, promise or advantage would violate (i) the applicable laws of Israel or the United States of America (including, without limitation, the Foreign Corrupt Practices Act of 1977, as amended, U.S.C. §78dd-1, et seq.); (ii) the principles described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed in Paris on December 17, 1997, which entered into force on February 15, 1999, and the Convention’s Commentaries; or (iii) the principles described in the United Nations Convention Against Corruption, which entered into force on December 14, 2005. The Buyer shall defend, indemnify and hold the other Parties harmless from and against any and all claims, damages, losses, penalties, costs and expenses arising from or related to, any breach by the Buyer of such warranty. Such indemnity obligation shall survive termination or expiration of this Agreement. The Buyer shall in good time (i) respond in reasonable detail to any notice from any other Party reasonably connected with the above-stated warranty; (ii) furnish applicable documentary support for such response upon request from such other Party; (iii) maintain adequate internal controls, properly record and report all transactions; and (iv) comply with the laws applicable to it. Buyer acknowledges and confirms that: (i) each Party must rely on the other Parties’ system of internal controls, and on the adequacy of full disclosure of the facts, and of financial and other data regarding action undertaken under this Agreement; (ii) No Party is in any way authorized to take any action on behalf of another Party that would result in an inadequate or inaccurate recording and reporting of assets, liabilities or any other transaction, or which would put such Party in violation of its obligations under the laws applicable to the operations under this Agreement;

(f) this Agreement constitutes a legal, valid and binding act and obligation enforceable against it in accordance with the terms of this Agreement.

4.3.2 The Buyer covenants with the Sellers that throughout the Contract Period, the Buyer shall:

(a) not agree to or (to the extent that it is within its power to prevent) permit any amendment or modification of the Transportation Agreement whereby the Buyer's ability to perform its obligations under this Agreement are likely to be prevented or materially adversely affected and shall observe and perform all terms thereof and exercise its rights thereunder in such manner as to secure that the terms and provisions of this Agreement shall be performed; and

(b) obtain all and any necessary consents or approvals required to permit the performance of the Buyer's obligations hereunder.

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4.4 Taxes and Royalties

4.4.1 Each of the Sellers as to its Seller's Percentage shall pay or cause to be paid all royalties, taxes, duties, levies and other sums arising in respect of production, transportation, gathering, processing and handling of Natural Gas before delivery by such Seller to the Buyer at the Delivery Point.

4.4.2 The Buyer shall pay or cause to be paid all taxes, duties, levies and other sums arising in respect of receipt, processing, handling and transportation of Natural Gas after delivery to the Buyer by each of the Sellers at the Delivery Point.

4.4.3 All and any royalties, taxes, duties, levies or other sums arising at the Delivery Point shall be borne by the Parties as specified in the applicable legislation or other charging provisions.

4.4.4 Notwithstanding the above, the Buyer shall also bear and pay or (as the case may be) timely reimburse each of the Sellers in respect of any:

(a) Value Added Tax payable pursuant to Israeli Law in relation to Gas sold by such Seller to the Buyer under this Agreement;

(b) Excise Duty payable pursuant to the Excise Law on Fuels-1958 and Purchase Tax payable pursuant to the Purchase Tax Law- 1952, as applicable, and any other similar law, in relation to Gas sold by such Seller to the Buyer under this Agreement; and

(c) Any new tax, duty or levy imposed pursuant to Israeli Law on Natural Gas in relation to Gas sold by such Seller to the Buyer under this Agreement, provided (**).

4.5 Indemnities and Acknowledgements

4.5.1 Each of the Sellers as to its Seller’s Percentage shall indemnify and hold harmless the Buyer against any and all loss, damage and expense of every kind on account of:

(a) adverse claims relating to such Seller’s title to any or all Gas delivered to the Buyer hereunder; or

(b) any and all royalties, taxes, duties, levies or other sums which the Sellers are obligated to bear and pay pursuant to Article ‎4.4 above.

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4.5.2 The Buyer shall indemnify and hold harmless each of the Sellers as to its Sellers’ Percentage against any and all loss, damage and expense of every kind on account of taxes, duties, levies and other sums which the Buyer is obligated to bear and pay pursuant to Article ‎4.4 above.

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ARTICLE 5

Sellers’ Rights / Commingling and Unitization

5.1 Sellers’ Rights

Nothing in this ‎Article 5 shall be construed as relieving Sellers from any of their specific obligations pursuant to this Agreement, including without limitation the requirement to comply with the pressure and quality requirements provided in this Agreement. Without derogating from the above, Sellers shall be entitled to:

5.1.1 Determine the manner in which they conduct their physical operations;

5.1.2 Supply Natural Gas for delivery under this Agreement from sources other than the Reservoir at their sole discretion;

5.1.3 Commingle Natural Gas produced pursuant to the Sellers’ Petroleum Rights with Natural Gas produced from any other source or sources subject specifically to: (a) the pressure and quality requirements provided in this Agreement; (b) such arrangements as would be made by a Reasonable and Prudent Operator regarding allocation, attribution and measurement procedures in respect of Natural Gas produced at the Reservoir and all Natural Gas delivered at the Delivery Point;

5.1.4 Pool, combine or unitize all or any part of the Sellers’ Interest with interests in any other licenses or leases and in such event this Agreement shall extend and apply to the interest of the Sellers in such unit to the extent that such interest is derived from the Sellers’ Interest; and

5.1.5 Enter into agreements to supply third parties with Natural Gas from the Reservoir or elsewhere; (**).

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ARTICLE 6

Quantities and Nominations

6.1 The ACQ

6.1.1 For each Contract Year the "Annual Contract Quantity" (or "ACQ") shall be the aggregate of the respective DCQs applicable on each Day during that Contract Year.

6.2 The DCQ

6.2.1 Except as otherwise provided for in this Agreement, the "Daily Contract Quantity" or "DCQ" shall be as follows:

(a) In respect of each Day of the Commissioning Period, the DCQ shall be zero (0);

(b) In respect of each Day of the period commencing on the Commencement Date and ending on the Day immediately prior to the fifth (5th) anniversary of the Commencement Date, the DCQ shall be (**) MMBTU;

(c) In respect of each Day of the period commencing on the fifth (5th) anniversary of the Commencement Date (provided such date falls within the First Period) and ending on the last Day of the First Period, the DCQ shall be (**) MMBTU; and

(d) Notwithstanding the above, in respect of each Day of the Second Period (if applicable), the DCQ shall be (**) MMBTU.

6.3 Hourly Quantities

Except as otherwise provided for in this Agreement, the "Maximum Hourly Quantity" (or "MaxHQ") shall be as follows:

6.3.1 In respect of each Day of the Commissioning Period, the MaxHQ is not applicable.

6.3.2 In respect of each Day of the First Period, the MaxHQ shall be equal to the lower of: (i) (**) MMBTU and (ii) (**).

6.3.3 In respect of each Day of the Second Period (if applicable), the MaxHQ shall be equal to the lower of: (i) (**) MMBTU; and (ii) (**).

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6.4 Increased Quantities and Additional Facilities

6.4.1 Subject to the provisions of this Article ‎6.4, upon the Buyer serving on the Sellers the Increase Notice, the Sellers will be obliged to seek to fulfill certain conditions to obtain approvals, permits and rights to the effect that, subject to the fulfillment of such conditions (or their waiver by the Sellers), the Sellers will be obliged to construct, install, maintain and operate such additional Sellers' Facilities as may be required to increase the MaxHQ to (**) MMBTU.

With effect from the Additional Flow Date to be established in accordance with this Article ‎6.4, (but subject to any intervening occurrence of a Price Control Event) the MaxHQ will be so increased to (**) MMBTU together with the corresponding increase of the DCQ to (**) MMBTU), all in accordance with and subject to the provisions of this Article ‎6.4.

6.4.2 Buyer's Notice to Increase Quantities: The Buyer shall have the right to exercise the Increase Option by written notice to be delivered to the Sellers (the "Increase Notice") by the earlier of:

(a) April 2, 2013; or

(b) in the event that prior to February 1, 2013 the Sellers notify the Buyer in writing that the Sanction of the Additional Development has occurred (the "Sanction Notice"), by the later of: (i) December 31, 2012 (if Sellers' notification was delivered before October 15, 2012); and (ii) forty five (45) Days after the Sanction Notice.

6.4.3 Additional Flow Date: Following receipt of the Increase Notice, the Sellers shall be obliged to seek to satisfy the Sellers' Additional Conditions with the aim that the Additional Flow Date will occur within forty eight (48) Months after the Sellers' Additional Conditions Date.

6.4.4 Sellers' Additional Conditions: The Increase Option will be subject to the following conditions (the "Sellers' Additional Conditions"):

(a) the obtaining by the Sellers of the approval of the Ministry of Energy and Water Resources for the Sellers' Additional Development Plan in a form and on terms reasonably acceptable to the Sellers;

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(b) the obtaining by the Sellers of the rights to land on shore in Israel as may be required to construct the facilities contemplated in Sellers' Additional Development Plan, in a form and on terms reasonably acceptable to the Sellers; and

(c) the obtaining of the building permits and the approvals required for the construction and operation of the facilities contemplated in Sellers' Additional Development Plan.

6.4.5 Satisfaction of Sellers' Additional Conditions: The Sellers shall employ reasonable endeavors to procure that the Sellers' Additional Conditions are satisfied within six (6) months after Sellers receive the Increase Notice (or such later date as may be mutually agreed to in writing by the Parties). The Sellers shall keep the Buyer informed on a periodical basis and on reasonable request as to progress made towards achieving Sellers' Additional Conditions.

6.4.6 Termination due to Non-Satisfaction of Sellers' Additional Conditions: In the event that Sellers' Additional Conditions have not been satisfied or were not waived by the Sellers within twelve (12) Months after Sellers receive the Increase Notice (or such later date as may be mutually agreed to in writing by the Parties), the Buyer may terminate the Increase Option by not less than fourteen (14) days written notice and the provisions of Article ‎6.4.8 will apply. In the event that Sellers' Additional Conditions have not been satisfied or were not waived by the Sellers within eighteen (18) Months after Sellers received the Increase Notice or such later date as may be mutually agreed to in writing by the Parties, and the Increase Option has not been terminated by the Buyer, then the Sellers, provided they have sought to obtain the Sellers' Additional Conditions, shall also have the right to terminate the Increase Option by not less than fourteen (14) days written notice and the provisions of Article ‎6.4.8 will apply.

6.4.7 Termination due to Price Control: Notwithstanding the provisions of Articles ‎6.4.1 to ‎6.4.6, in the event that prior to the Increase Date a Price Control Event occurs, the Sellers shall have the right, at their sole and absolute discretion, to terminate the Increase Option by ninety (90) days' notice to the Buyer and the provisions of Article ‎6.4.8 will apply.

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6.4.8 Effect of Termination: Upon expiry of a termination notice pursuant to Articles ‎6.4.6, ‎6.4.7 or ‎6.4.12, the Increase Notice shall be null and void ab initio, the Sellers will be relieved from their obligations under Article ‎6.4, and the Increase of the MaxHQ, DCQ and TCQshall not become effective.

6.4.9 The Twelve Month Window: The Sellers shall use reasonable endeavors to ensure that the Additional Flow Date occurs within a twelve (12) month period, such period to commence no earlier than twenty four (24) Months after the Sellers' Additional Conditions Date; and end no later than forty eight (48) Months after the Sellers' Additional Conditions Date (such 12 month period, the "Twelve Month Window"). The Sellers will inform the Buyer of the commencement date of the Twelve Month Window within six (6) Months after the Sellers' Additional Conditions Date.

6.4.10 The Three Month Window: At least ninety (90) days prior to the first day of the Twelve Month Window, the Sellers will notify Buyer of a ninety (90) Day period in which they anticipate the Additional Flow Date to occur, such period to be within the Twelve Month Window (the "Three Month Window"). Within thirty (30) days after receipt of Sellers' notice specifying the Three Month Window, the Buyer will notify Sellers whether it has elected that the Increase Date will be the Actual Increase Date or the Deemed Increase Date. If Buyer fails to give such notice, the Increase Date will be the Actual Increase Date.

6.4.11 Additional Delay Period: If Buyer notified Sellers in accordance with Article ‎6.4.10 that the Increase Date will be the Actual Increase Date and the Additional Flow Date has not occurred (except due to circumstances in which the Sellers were relieved from liability for reasons of Force Majeure or Article ‎6.4.8) by the earlier of:

(i) the fourth (4th) anniversary of the Sellers' Additional Conditions Date; or (ii) the last day of the Three Month Window (such earlier date, the "Target Completion Date"), then in respect of each Day from the Target Completion Date (as such date may be postponed due to an event of Force Majeure) until the Additional Flow Date (the "Additional Delay Period"), the Buyer will have the right to nominate Gas under this Agreement as if the Increase Date had occurred and the Sellers shall make reasonable endeavors to make deliveries in accordance with Buyer's Proper Nominations and any quantities of Gas not delivered by the Sellers shall be deemed to constitute Shortfall Gas in accordance with the provisions of ‎Article 17, and the delivery of Gas by Sellers in reduction of such quantity of Shortfall Gas from the Shortfall Aggregate shall be the Sellers' sole liability to the Buyer and Buyer's sole remedy in such circumstances.

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6.4.12 Termination due to Delays: In the event that the Additional Delay Period continues for a period of more than twelve (12) Months (except to the extent such delay was caused by an event of Force Majeure), Buyer and Sellers shall meet within seven (7) days from such date, to discuss and seek to agree on appropriate arrangements that will enable delivery of such part of the Buyer's Proper Nominations that is attributable to such Increase Notice. If no such agreement is reached within thirty (30) days after such meeting, the Buyer may, at any time after the expiry of such period, by written notice to the Sellers, terminate the Increase Option effective sixty (60) days after the giving of such notice, unless prior to the expiry of such notice period the Additional Flow Date has occurred, in which event, the Increase Option is not terminated but is effective. On termination of the Increase Option as above the provisions of Article ‎6.4.8 will apply.

6.4.13 Available Capacity: Without derogating from the provisions of Articles ‎6.4.1 to ‎6.4.8, if by December 31, 2012 the Increase Notice has not been given, then at Buyer's request the Sellers shall advise the Buyer whether they have available uncontracted capacity in the Sellers' Facilities and are able to increase the MaxHQ and DCQ under this Agreement using the existing Sellers' Facilities. In the event the Sellers advise the Buyer that they do have available capacity as aforesaid and within thirty (30) days thereafter the Buyer notifies the Sellers that it would like to increase the MaxHQ and the DCQ hereunder, the Buyer and Sellers shall meet within fourteen (14) days from the date of Buyer's notice in order to discuss such increase.

6.4.14 Commissioning of Sellers' Facilities: Following the Additional Flow Date, the Sellers shall be entitled to carry out commissioning activities and the provisions of Articles ‎2.4 and ‎2.5, will apply, mutatis mutandis, in relation to the commissioning of such facilities.

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6.5 (**)

6.6 Deliveries

6.6.1 In respect of each Hour during the Commissioning Period, the Sellers shall use reasonable endeavors to deliver at the Delivery Point the quantities of Specification Gas nominated by the Buyer for delivery in respect of such Hour in accordance with the provisions of Article ‎2.4.

6.6.2 In respect of each Hour from the Commencement Date, the Sellers shall tender for delivery at the Delivery Point the quantities of Specification Gas Properly Nominated by the Buyer in respect of such Hour.

6.6.3 Subject to applicable law and unless otherwise instructed by any governmental authority, (**).

6.7 Operational Delivery Tolerances

6.7.1 The Parties agree that the following operational tolerances will apply in respect of deliveries that fall short of or exceed the quantity Properly Nominated for delivery at the Delivery Point ("Delivery Tolerances"):

(a) (**);

(b) (**); and

(c) (**).

6.8 Notification of Requirements

6.8.1 Not later than 1500 on the Wednesday immediately preceding the beginning of each Month, the Buyer shall give notice to the Sellers of the quantity of Specification Gas it then forecasts to be required in respect of each Day of that Month. This forecast is indicative and non-binding.

6.8.2 Not later than 1500 on the Wednesday immediately preceding each Week, the Buyer shall give notice to the Sellers of the quantity of Specification Gas it then forecasts to be required in respect of each Hour of that Week. This forecast is indicative and non-binding.

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6.8.3 Not later than 1500 each Day, the Buyer shall give notice to the Sellers nominating the quantity of Specification Gas it requires to be delivered at the Delivery Point in respect of each Hour of the immediately following Day. This nomination will be binding and final, subject to variations in accordance with Articles ‎6.8.5 and ‎6.8.6.

6.8.4 No later than 1600 on each Day, the Sellers shall inform the Buyer of their ability to meet the Buyer’s nominations, fully or partially in respect of any Hour of the immediately following Day. The above shall not derogate from nor add to the Sellers’ obligations and liabilities to deliver quantities of Gas under Article ‎6.8.3 above.

6.8.5 The Buyer shall be entitled by notice to the Sellers at any time to vary the quantities of Specification Gas so nominated pursuant to Article ‎6.8.3 provided that such notice is given not less than fourteen (14) Hours before the Hour to which it relates and provided such variation complies with Article ‎6.9.2.

6.8.6 The Buyer may at any time before any Hour request any variation in the Proper Nomination at shorter notice than is prescribed in Article ‎6.8.5, provided such variation complies with Article ‎6.9.2 and the Sellers shall use reasonable endeavors to comply fully with the variation so requested, it being specifically agreed that:

(a) the Sellers’ failure to comply with the variation so requested shall not constitute Shortfall Gas; and

(b) any such request to increase the Proper Nomination shall not affect the Sellers’ obligations in relation to the delivery of the quantity as previously nominated under Article ‎6.8.3 (or as varied under Article ‎6.8.5) in respect of such Hour.

6.8.7 In the event that the Buyer does not make a Proper Nomination in respect of any Hour pursuant to this Article ‎6.8, the Buyer shall be deemed to have nominated a quantity equal to the quantity Properly Nominated for that Hour in the preceding Day.

6.8.8 If due to an event of Force Majeure Buyer is unable to take, or if for any reason Sellers are unable to deliver, the quantities Properly Nominated by the Buyer, then for the duration of the Day covered by the then current Proper Nomination, the Properly Nominated quantity for each Hour in such Day shall continue to be the quantity specified in such Proper Nomination, and if such inability continues after the end of the Day covered by the then current Proper Nomination, then thereafter for the continuation of such inability the Properly Nominated quantity for each Hour during such period shall be deemed to be the average Properly Nominated quantity for that same Hour of the same Day of the Week with respect to the three (3) previous Weeks.

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6.8.9 Notwithstanding Article ‎6.8.3, any nomination of zero (0) by the Buyer in respect of any Hour shall be subject to the Buyer giving of not less than seven (7) Days' prior notice.

6.8.10 Notwithstanding the above, in the event that nomination procedures are imposed on the Parties by the Transporter which are inconsistent with the nomination procedures specified in this Article ‎6.8, the Parties shall revise the nomination procedures set out in this Article ‎6.8 so as to make them consistent with those imposed by the Transporter provided that the Sellers shall not be required to agree to procedures which are more onerous on the Sellers than the procedures specified in Article ‎6.8.5. In default of agreement between the Parties on such revisions, either Party may, by notice to the other, require the matter to be referred for determination by the Expert pursuant to Article ‎19.3.

6.9 Proper Nominations

6.9.1 For the purposes of this Agreement, "Proper Nomination" means a nomination which has been made in accordance with the requirements of Articles ‎6.8.3, ‎6.8.5, ‎6.8.7 or ‎6.8.9 and Article ‎6.9.2 and "Properly Nominated" means in relation to a quantity of Gas in respect of an Hour, the Proper Nomination.

6.9.2 A Proper Nomination made by the Buyer in respect of any Hour:

(a) shall not exceed the applicable MaxHQ;

(b) during the First Period, shall not exceed the quantity of Specification Gas Properly Nominated in respect of the immediately preceding Hour by more than:

(i) (**) MMBTU if the Proper Nomination for the preceding Hour was equal to or lower than (**) MMBTU; and

(ii) (**) MMBTU if the Proper Nomination for the preceding Hour was higher than (**) MMBTU;

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(c) during the Second Period (if applicable), shall not exceed the quantity of Specification Gas Properly Nominated in respect of the immediately preceding Hour by more than:

(i) (**) MMBTU if the Proper Nomination for the preceding Hour was equal to or lower than five thousand (5,000) MMBTU; and

(ii) (**) MMBTU if the Proper Nomination for the preceding Hour was higher than five thousand (5,000) MMBTU;

(d) (**).

(e) shall not be less than (**).

(f) shall not, together with the aggregate hourly quantity nominated by the Buyer under the YT GSPA (to the extent applicable), exceed (**) MMBTU during the First Period and (**) MMBTU during the Second Period.

(g) during the Maintenance Period shall not exceed the MaxHQ specified in the notice provided pursuant to Article ‎6.11.7.

6.9.3 Without derogating from the provisions of Article ‎6.9.2(a), during the First Period, Buyer may at any time nominate additional volumes of up to (**) MMBTU above the applicable MaxHQ ("Excess Gas") and Sellers shall make reasonable endeavors to comply with such nomination of additional volumes. For the avoidance of doubt, Excess Gas nominated by the Buyer in accordance with this Article ‎6.9.3 shall not be considered a Proper Nomination.

6.9.4 Without derogating from the provisions of Article ‎6.9.2(b) the Sellers will use reasonable endeavors, (**).

6.9.5 Without derogating from the provisions of Article ‎6.9.2(f), in the event that in any Hour, Buyer's nomination, together with the aggregate hourly quantity nominated by the Buyer under the YT GSPA (to the extent applicable) exceed (**) MMBTU, then the Sellers may, at their sole and absolute discretion, elect whether to comply with such nomination.

6.9.6 Subject to the provisions regarding Proper Nominations as above and without derogating from the provisions of Article ‎6.10, the Buyer is entitled to nominate every Hour, a quantity of Specification Gas between zero (0) and the MaxHQ, provided however that the Buyer will not nominate for any Hour a quantity of gas that is less than its pro-rata share of the Technical MinHQ, such share to be calculated based on the ratio between the ACQ in this Agreement and the cumulative annual contract quantities in all the gas sales agreements of the Sellers pursuant to which the Sellers will be delivering Natural Gas from the Reservoir at such date.

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6.9.7 All nominations or notifications of quantities of Specification Gas under this Agreement shall (except where the context otherwise requires) be made in MMBTU.

6.9.8 The Buyer shall use reasonable endeavors to take at the Delivery Point the quantities of Specification Gas Properly Nominated by the Buyer and tendered for delivery by the Sellers in respect of such Hour.

6.10 Over Deliveries

For the avoidance of doubt, it is confirmed that the Buyer shall not be obliged to take amounts of Specification Gas tendered for delivery by the Sellers in excess of the amount Properly Nominated ("Over Deliveries").

6.11 Planned Maintenance

6.11.1 If the Sellers have reason in any Contract Year to expect that the necessities of maintenance, repair, modification, installation of new equipment, or replacement of the Sellers’ Facilities ("Maintenance") would require a reduction in the ability to deliver Specification Gas to the Buyer under this Agreement, the Sellers shall, by not less than six (6) months' notice to the Buyer and subject to reasonable endeavors to coordinate with the Yam Tethys Partners (to the extent the Sellers are delivering gas hereunder through the Yam Tethys Facilities) and the Buyer, specify a period ("Maintenance Period") during which the Sellers intend to conduct such Maintenance.

6.11.2 Any Maintenance Period specified by the Sellers pursuant to Article ‎6.11.1 may not exceed fourteen (14) consecutive days and thirty (30) Days in aggregate in any two (2) consecutive Contract Years.

6.11.3 The Sellers shall periodically update the Buyer in accordance with the table below as to the estimated start date and duration of the Maintenance Period and as to the level to which the MaxHQ will be reduced.

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(**)	(**)	(**)
(**)	(**)	(**)
(**)	(**)	(**)
(**)	(**)	(**)
(**)	(**)	(**)

6.11.4 Sellers will use reasonable endeavors to schedule Maintenance Periods during the spring and autumn months.

6.11.5 The Parties agree that the provisions of Articles ‎6.11.3 and ‎6.11.4 above will not apply to Maintenance involving off-shore activities, provided however that the Sellers will keep the Buyer fully informed on an ongoing basis of any changes in relation to the Sellers' maintenance schedule.

6.11.6 The Sellers will specify by notice to the Buyer not less than one (1) month prior to the beginning of the Maintenance Period, as to the duration of the period during which the  MaxHQ will be reduced as above, provided that such period may not exceed the Maintenance Period.

6.11.7 During the Maintenance Period specified in this Article ‎6.11:

(a) the Sellers may carry out the Maintenance; and

(b) the MaxHQ for each Day during the Maintenance Period shall be reduced to the levels specified in the notice given by the Sellers to the Buyer, and the DCQ shall be reduced proportionately.

6.11.8 The Buyer shall make nominations in respect of each Day during the Maintenance Period by reference to such reduced MaxHQ specified in Article ‎6.11.7 above.

6.11.9 Without derogating from the provisions of Article ‎6.11, it is the intention of the Parties to use reasonable endeavors to minimize the Maintenance Periods required by them and the consequential reduction of the MaxHQ during such period.

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ARTICLE 7

Facilities

7.1 Sellers' Facilities

The Sellers shall throughout the Contract Period:

7.1.1 Construct and install the Sellers' Facilities in accordance with the standard of a Reasonable and Prudent Operator;

7.1.2 Maintain and repair the Sellers' Facilities and all replacements thereto in good working order and condition in accordance with the standard of a Reasonable and Prudent Operator; and

7.1.3 Operate the Sellers' Facilities in accordance with the standard of a Reasonable and Prudent Operator.

7.2 Buyer's Facilities

The Buyer shall throughout the Contract Period:

7.2.1 Construct and install the Buyer's Facilities in accordance with the standard of a Reasonable and Prudent Operator;

7.2.2 Maintain and repair the Buyer's Facilities and all replacements thereto in good working order and condition in accordance with the standard of a Reasonable and Prudent Operator; and

7.2.3 Operate the Buyer’s Facilities in accordance with the standard of a Reasonable and Prudent Operator.

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ARTICLE 8

Exchange of Information

8.1 Disclosure of Information

8.1.1 The Sellers and the Buyer shall throughout the Contract Period respectively provide to the other all such information as may be necessary or otherwise reasonably required to enable the other Party to carry out its obligations under this Agreement.

8.1.2 Without prejudice to the generality of the foregoing and to other provisions of this Agreement concerning the provision of information, the Sellers shall also provide a written program of proposed operations for each Month during the following Contract Year, which shall include details of any proposed maintenance programs in accordance with Article ‎6.11.

8.1.3 For the avoidance of any doubt, nothing in this Agreement shall be construed as granting the Sellers or the Buyer, whether directly or indirectly, access to any data or information relating to competitors of the Buyer or the Sellers (as applicable), or the methods of any such competitor, other than technical data or the data to be provided by the Sellers to the Buyer under Article ‎9.4 which is not likely to have an effect on the competition in the market.

8.2 Forecasts

8.2.1 The Sellers shall provide the Buyer, during each Month of October during the Contract Period, a written forecast of availability of Specification Gas during the next three (3) succeeding Contract Years and the Sellers' estimate of the uncontracted available capacity in Sellers' Facilities for the Contract Year following the date of such forecast.

8.2.2 The Buyer shall (subject to having received Sellers program and forecasts) provide to the Sellers, during each Month of November during the Contract Period, a written forecast of the quantities of Specification Gas, which it reasonably expects to nominate during the next three (3) succeeding Contract Years.

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8.3 Liability and Expense

8.3.1 All information, estimates and forecasts to be provided under this Agreement shall be provided in good faith, but neither Party shall be liable for the accuracy of any estimate or forecast made under this Article nor shall any such forecast vary the respective rights and obligations of the Parties hereunder.

8.3.2 All information, estimates and forecasts given or work undertaken under this Article shall be at the expense of the providing Party.

8.3.3 It is agreed that the provisions of this Agreement granting the Sellers, directly or indirectly, rights to receive information from the Buyer, access, visit, monitoring and inspection or to any other source of information, will not grant the Sellers access to information regarding the competitors of the Sellers or their mode of operation.

8.3.4 It is agreed that the provisions in this Agreement granting the Buyer, directly or indirectly, rights to receive information from Sellers, access, visit, monitoring and inspection or to any other source of information, will not grant the Buyer access to information regarding the competitors of the Buyer or their mode of operation.

8.4 Information and Access

8.4.1 It is acknowledged and agreed that nothing in this ‎Article 8 shall oblige either Party to do or omit to do anything which would:

(a) breach or otherwise adversely affect any bona fide commitment of confidentiality owed to any Party; or

(b) procure or allow any rights of access or inspection in excess of or contrary to such rights as may be legally available to and exercisable by one Party in favor of the other.

8.4.2 Notwithstanding the provisions of Article ‎8.5, it is agreed that all information, forecasts and estimates provided pursuant to Article ‎8.1 and Article ‎8.2 shall be kept confidential by the receiving Party and shall not be disclosed to any Person without the prior written consent of the providing Party.

8.5 Confidentiality

8.5.1 The terms and conditions of this Agreement and all information disclosed hereunder (including any disclosures made during any arbitration or Expert determination) shall until three (3) years after this Agreement has terminated be treated as confidential. Except as provided in Article ‎8.5.2, such terms and conditions shall not be disclosed in whole or in part by either Party and such information shall not be disclosed in whole or in part by the Party receiving the same to any other Person without the prior consent of the disclosing Party (such terms and conditions and such information being herein called "Disclosed Information").

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The expression Disclosed Information shall not include any information which (when used or disclosed) has been made public other than through a breach of this Agreement or has been or could have been lawfully acquired (other than pursuant to the provisions of this Article ‎8.5) by the Party or Person using the same or to whom disclosure is made.

8.5.2 Notwithstanding the provisions of Article ‎8.5.1, neither Party shall be required to obtain the prior consent of the other in respect of disclosure of Disclosed Information:

(a) to directors or employees of a Party and of Affiliates of such Party, provided that the Buyer or the Sellers (as the case may be) shall use reasonable endeavors to ensure that such Persons keep the Disclosed Information confidential on the same terms as are provided in this Article ‎8.5;

(b) to Persons professionally engaged by or on behalf of such Party, provided that such Persons shall be required by such Party to undertake to keep such information confidential and be bound by confidentiality provisions substantially the same as those contained in this Article ‎8.5;

(c) to any government department or any governmental or regulatory agency or body having jurisdiction over such Party, including the anti-trust commissioner and the petroleum commissioner, but only to the extent that such Party is legally compelled to make such disclosure;

(d) to any lending or other financial institution (including rating agencies) or to any bona fide intending assignee of the whole or any part of the rights and interests in such Party or of such Party under this Agreement; but (in either case) only to the extent required in connection with obtaining such finance or in respect of such proposed assignment and subject to such institution or intending assignee first agreeing with such Party to be bound by confidentiality provisions substantially the same as those contained in this Article ‎8.5;

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(e) to the extent required by any applicable laws, rules and regulations of any recognized stock exchange or to the extent required by any lawful subpoena or other process in connection with any judicial, arbitral, or administrative proceeding;

(f) to the Transporter, but only to the extent such disclosure is required;

provided, that in respect of Article ‎8.5.2, the disclosing Party: (i) shall keep the disclosure of Disclosed Information limited to the extent reasonably necessary for the purpose for which it is disclosed, (ii) shall wherever practicable and permissible, in advance of such disclosure (or if this is not practicable or permissible as soon as reasonably practicable or permissible thereafter), notify the other of such disclosure (and the extent thereof) and the identity of the Person(s) to whom disclosure was made, and (iii) shall so far as practicable minimize the further disclosure of the Disclosed Information.

8.5.3 Subject to Article ‎8.5.2 above, neither the Buyer nor the Sellers shall make any public representations, statements or announcements relating to this Agreement without the prior written approval of the other, such approval not to be unreasonably withheld.

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ARTICLE 9

Take or Pay

9.1 The Adjusted ACQ and Minimum Bill Quantity

9.1.1 For each Contract Year during the Take or Pay Period (or that part of the first Contract Year commencing on the first Day of the Take or Pay Period and ending at the end of such Contract Year), the "Adjusted Annual Contract Quantity" and the "Minimum Bill Quantity" shall be calculated in accordance with the following provisions.

9.1.2 The Adjusted Annual Contract Quantity (or "Adjusted ACQ") shall be a quantity of Specification Gas equal to the ACQ applicable for the relevant Contract Year less the sum of the following:

(a) the aggregate of the quantities of Specification Gas Properly Nominated by the Buyer for delivery during the relevant Contract Year which the Sellers did not for any reason deliver (including without limitation the Sellers' failure to deliver as a result of Force Majeure) but excluding any quantities that the Sellers failed to deliver in the circumstances of Article ‎11.5.2 and any failure by the Buyer to take delivery of Specification Gas properly tendered for delivery in accordance with this Agreement); and

(b) the aggregate of the quantities of Specification Gas Properly Nominated by the Buyer for delivery during the relevant Contract Year which the Buyer did not take for reasons for which it was excused from liability under ‎Article 16 or as a result of the Buyer’s exercise of any right to refuse to take delivery under Article ‎11.5.2 and ‎Article 12.

9.1.3 The "Minimum Bill Quantity" or "MBQ" shall be a quantity of Gas equal to (**) of the Adjusted ACQ for each such Contract Year.

9.2 Carry Forward Aggregate

9.2.1 If and to the extent that in any Contract Year during the Take or Pay Period the aggregate of the quantities of Gas taken and paid for by the Buyer under this Agreement (excluding any quantity of Gas in respect of which the Buyer shall receive a credit pursuant to Article ‎9.5) exceeds: (i) in respect of the period commencing on the Commencement Date and ending on the fifth (5th) anniversary of the Commencement Date – (**) MMBTU; (ii) in respect of the period commencing on the fifth (5th) anniversary of the Commencement Date until the end of the First Period – (**) MMBTU; and (iii) for the Second Period (if applicable) – (**) MMBTU; then such amount shall be classified as "Carry Forward" in respect of such Contract Year.

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9.2.2 Any quantity so classified as Carry Forward in respect of any Contract Year together with any Carry Forward so classified in respect of the (**), up to a maximum amount of (**) MMBTU and (**) MMBTU, shall (save to the extent of any use thereof pursuant to Article ‎9.3) be known as the "Carry Forward Aggregate" in force at any time or from time to time.

9.3 Take or Pay

9.3.1 In respect of each Contract Year during the Take or Pay Period or that part of the first Contract Year commencing on the first Day of the Take or Pay Period and ending at the end of such Contract Year, the amount of the Minimum Bill Quantity which has not been taken by the Buyer in such Contract Year under this Agreement shall be known as the "Annual Take or Pay Quantity" for such Contract Year.

9.3.2 In respect of any Contract Year for which there arises an Annual Take or Pay Quantity, such quantity shall be reduced by a quantity of Carry Forward Aggregate not exceeding (**) MMBTU during (**) MMBTU during (**), and:

(a) any remaining amount of such Annual Take or Pay Quantity shall be known as the "Net Annual TOP Quantity"; and

(b) such use of Carry Forward Aggregate shall be deemed to be a recovery of Carry Forward Aggregate by the Buyer to the extent of such use and the outstanding balance (if any) of Carry Forward Aggregate shall be reduced commensurately.

9.3.3 In respect of any Contract Year for which there arises a Net Annual TOP Quantity, the Buyer shall make payment to the Sellers, in accordance with the provisions of ‎Article 11 at the Contract Price applicable in respect of such Contract Year, for any such Net Annual TOP Quantity.

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9.3.4 The Net Annual TOP Quantity in respect of such Contract Year together with the Net Annual TOP Quantity in respect of the (**) not already recovered pursuant to the provisions of Article ‎9.5, shall be known as "Make-Up Aggregate".

9.4 (**)

9.5 Recovery of Make-up Aggregate

9.5.1 In relation to each Contract Year at the commencement of which any Make-Up Aggregate exists, the Buyer shall receive a quantity credit (in MMBTU) in respect of any Specification Gas taken and paid for by the Buyer in excess of the (**) in the relevant Contract Year up to the balance of the then outstanding Make-Up Aggregate.

9.5.2 The quantities to be used in so reducing the Make-Up Aggregate shall be established by (**).

9.5.3 The quantity credit mentioned in Article ‎9.5.1 shall be converted to a monetary credit by multiplying such quantity with a price equal to the Contract Price applicable in respect of the Contract Year in which such Make-Up Aggregate is recovered, together with interest thereon at the rate of LIBOR plus one (1) percentage point from the day (or if applicable, from each of the days) on which the Buyer made payment in respect of Gas taken by the Buyer in excess of the Minimum Bill Quantity in the relevant Contract Year (which is subsequently deducted from the Make-Up Aggregate), until payment of the relevant credit amount.

9.5.4 The monetary credit calculated in accordance with Article ‎9.5.3 shall be taken into account in the Annual Reconciliation Statement in respect of such Contract Year.

9.5.5 Any such credit to the Buyer shall be deemed to be a recovery of Make-Up Aggregate by the Buyer to the extent of the quantity corresponding to such credit and the outstanding balance (if any) of Make-Up Aggregate shall be reduced commensurately.

9.5.6 Notwithstanding the foregoing provisions of this Article ‎9.5, if at what would otherwise be the end of the Contract Period there is any Make-Up Aggregate outstanding, then:

(a) If such outstanding Make-Up Aggregate exceeds (**) MMBTU, then this Agreement shall not terminate on that date but shall continue in full force and effect for a number of Days equal to the Make-Up Aggregate divided by the DCQ or twelve (12) months, whichever is later so as to enable the Buyer to recover the outstanding Make-UP Aggregate in accordance with the terms of this Agreement. During this period, the provisions of this Agreement will continue to apply mutatis mutandis. In order to avoid any doubt, Article ‎9.3 will not apply; or

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(b) If such outstanding Make-Up Aggregate does not exceed (**) MMBTU, then on the fifteenth (15th) Business Day of the month immediately following the month in which such termination occurs the Sellers shall pay to the Buyer a sum of money equal to such outstanding Make-Up Aggregate multiplied by the Contract Price in force at the end of the Contract Year in which the termination occurred.

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ARTICLE 10

Price,  Price Review and Adjustment

10.1 Calculation of Contract Price

10.1.1 In the Month of December preceding each Price Period (each such Month being herein called a "Review Month"), the Sellers shall calculate the Contract Price for the Price Period in US Dollars per MMBTU in accordance with Articles ‎10.1.2 and ‎10.1.3 and such price so calculated shall be submitted to the Buyer for agreement as soon as practicable but in no event later than the last Day of the Review Month.

10.1.2 The Contract Price for the Price Period of 2011 (P2011) isfive point zero four two US Dollars (US$5.042) per MMBTU.

10.1.3 The Contract Price for each subsequent Price Period following 2011 shall be calculated in accordance with the following formula:

(**)

Where:

"(**)"is (**).

"(**)" is (**).

"(**)" is (**).

"(**)" is (**).

"(**)" is (**):

For the Price Periods commencing on January 1, 2012 and ending on December 31, 2019 (i.e.: The Price Periods for the Calendar Years 2012 through 2019):

(**)

For the Price Periods from January 1, 2020 (i.e.: The Price Periods for the Calendar Years 2020 until the end of the Contract Period):

(**)

Where:

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"CPI"means the U.S. Consumer Price Index for all Urban Consumers (CPI-U), U.S. City Average, All Items, Not Seasonally Adjusted (Index 1982-1984 = 100) (Series ID: CUUR0000SA0), as published by the United States Department of Labor, Bureau of Labor Statistics (on the Effective Date the CPI was published at the following web site: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt);

"CPIn" is the arithmetic average of the monthly values of the CPI for (**);

"(**)" is (**).

10.1.4 Example: (**)

10.1.5 The Parties agree that the Contract Price determined under this Agreement is appropriate for the selling to, and buying by, an anchor buyer of Gas in the Israeli market for use in Israel at the Effective Date.

10.1.6 All calculations to ascertain the Contract Price under this Agreement shall be made to five (5) places of decimals, without rounding and the final product shall then be rounded to the fourth decimal. A figure of five (5), or more, in the fifth place of decimals shall cause a rounding up of the fourth decimal.

10.1.7 All prices calculated in accordance with this ‎Article 10 are exclusive of all taxes and duties, and shall be payable in accordance with ‎Article 11.

10.2 Figures for Calculation of CPIn

In the application of the formula set out in Article ‎10.1.2, the latest figures for the relevant period needed to calculate CPIn which are available on the last day of the Review Month shall be used (whether the same are published in final or in provisional form) and the values so obtained shall not be adjusted consequent upon such figures being subsequently published in amended form except only:

10.2.1 in those specified circumstances and in the manner set out in Articles ‎10.4 and Article ‎10.6;

10.2.2 in the event that figures which are then published in provisional form are subsequently published in final form within two (2) months after the end of the Review Month.

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10.3 Change in Base of CPI

10.3.1 If in the Review Month it is found that during the relevant three (3) Month period used in the application of the formula to obtain the Contract Price (CP) in Article ‎10.1.2 the CPI has been rebased to a different period then, subject to the provisions of Article ‎10.2: the new CPI, with respect to the period from and after such rebasing will be multiplied by a conversion factor calculated by dividing the value of the CPI for the Month of the rebasing using the base in effect prior to the rebasing, by the value of the CPI for the Month of the rebasing using the new base in effect following such rebasing.

For example: if with respect to the Month the rebasing became effective the CPI is equal to 190 and the new value of the CPI for such Month calculated in accordance with the base in effect from the rebasing is equal to 100, then the conversion factor will be equal to 1.9 (190/100) and each new CPI published under the new base will be multiplied by a factor equal to 1.9.

10.3.2 For the purposes of this Article ‎10.3, the expression "CPI" shall be construed as including any successor thereto agreed or determined pursuant to this ‎Article 10.

10.4 Unavailability or Change in Basis of or Error in the CPIn

10.4.1 If during the Review Month, in the opinion of either Party, the CPIn:

(a) is permanently not available (or the Parties are unable to agree whether it is only temporarily unavailable);

(b) contains an error in any of the relevant figures required to calculate the CPIn; or

(c) is so changed in the basis of calculation as to affect materially the validity of price comparison or index comparison over time;

then either Party may, not later than the end of the Review Month, give notice to the other of such opinion and the Parties shall jointly endeavor to agree upon whether such opinion is valid and if so to agree upon an appropriate amendment to or replacement of the CPIn.

10.4.2 To the extent that the Parties have been able to agree upon an amendment to or replacement of the relevant CPIn, it shall be used in the calculation of the Contract Price for the relevant Price Period and subsequent Price Periods and shall not subsequently be amended in respect of the Price Periods for which it is used, even though the relevant CPIn subsequently becomes available or is corrected.

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10.4.3 If the Parties are unable within thirty (30) days from the date of the notice given under Article ‎10.4.1, to agree whether the CPIn is so unavailable, erroneous or has been changed, the matter shall (at the request of either Party) be referred for determination to an Expert pursuant to Article ‎19.3.

10.4.4 If for any of the reasons specified in Article ‎10.4.1 the Contract Price cannot be calculated when required, then a Provisional Contract Price shall be calculated in accordance with the provisions of Article ‎10.6.

10.4.5 It is agreed that a change of name of the CPIn shall not in itself be taken to be a reason for reference to an Expert under this Article ‎10.4.

10.5 Expert Determination

In any determination to be made by reference to the Expert under Article ‎10.4.3:

10.5.1 If the issue referred to the Expert is the establishment of an appropriate replacement of the CPIn pursuant to Article ‎10.4.1(a), the Expert shall provide a replacement CPIn (being an index price or series of prices or combination of indices as close as possible in type and use to the CPIn required to be replaced, with such adjustments only thereto as may be necessary to reflect more closely the movements of such CPIn and shall in the same manner (if required) provide an appropriate value to be used as a substitute CPI0.

10.5.2 If it is agreed or determined that the circumstances set out in Article ‎10.4.1(b) have occurred and the Expert is requested to make an appropriate amendment or replacement, the Expert shall provide a determination to correct the error including a substitute CPI0 if applicable.

10.5.3 If it is agreed or determined that the circumstances set out in Article ‎10.4.1(c) have occurred and the Expert is requested to make an appropriate amendment or replacement, the Expert shall make such adjustments to the CPIn (and if appropriate its substitute CPI0) as may be required to restore the validity of price or index comparison over time or, if this is not possible, the Expert may substitute an alternative CPIn together with an appropriate value to be used as the CPI0 in the manner described in Article ‎10.5.1.

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10.5.4 If the Expert is of the opinion that the CPIn is only temporarily unavailable as described in Article ‎10.4.1(a), then Article ‎10.4.4 shall apply as if the Parties had agreed the same and, if the Expert is of the opinion that the CPIn has not been computed in error or has not materially changed as described in Articles ‎10.4.1(b) and ‎10.4.1(c), then the Contract Price for the Price Period in respect of which the reference to the Expert has been made shall be calculated in accordance with Article ‎10.1 as if no reference to the Expert had been made whereupon no subsequent reference to the Expert under Article ‎10.4 may be made in respect of such Price Period by such Party.

10.5.5 The Expert shall have no power to change the formula set out in Article ‎10.1.2.

10.6 Provisional Contract Price

10.6.1 If due to the unavailability of information, Sellers are unable to calculate the CPIn, or if the Buyer has notified the Sellers that it does not agree with the Sellers’ calculation of the Contract Price within fourteen (14) Days of receipt of the Sellers’ calculation pursuant to Article ‎10.1.1 then:

(a) a price (herein referred to as the "Provisional Contract Price") shall be calculated as provided in Article ‎10.6.2; and

(b) if for any reason the Provisional Contract Price cannot be calculated as mentioned in Article ‎10.6.1‎(a), then the Contract Price for the immediately preceding Price Period shall be used as the Provisional Contract Price for the current Price Period;

and until the Contract Price can be calculated and subject to retrospective adjustment as hereinafter provided, the Provisional Contract Price for such Price Period shall be deemed to be the Contract Price for such Price Period for all purposes of this Agreement.

10.6.2 The Provisional Contract Price shall be calculated in the same manner as the Contract Price pursuant to this ‎Article 10, but using in respect of any figure used to calculate the CPIn for use in the said formula which is not available or is the subject of dispute under this ‎Article 10, the latest undisputed figure from the specified publication or same authority which was available prior to the disputed figure.

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10.6.3 Once the CPIn and figures required to calculate the Contract Price for any Price Period have all become available and any dispute in respect thereof has been finally settled, the Contract Price shall be calculated for such Price Period and shall take effect retrospectively from the commencement of such Price Period and any overpayment or underpayment by the Buyer hereunder made due to the application of the Provisional Contract Price shall be shown in the next Monthly statement following calculation of the Contract Price and shall be credited to or paid by the Buyer with interest calculated at the rate of LIBOR (**) from the date of any overpayment or underpayment to the date of credit or payment (as applicable) applying the agreed or determined Contract Price for such Price Period.

10.7 Review of Contract Price

The Contract Price shall be subject to review and adjustment pursuant to the terms of this Article ‎10.7:

10.7.1 By not later than thirty (30) days after each of the following dates:

(a) the eighth (8th) anniversary of the Commencement Date (the "First Price Adjustment Date"); and

(b) the eleventh (11th) anniversary of the Commencement Date (the "Second Price Adjustment Date");

either Party shall be entitled, by written Notice to the other Party (the "Price Adjustment Notice") to request a review of the Contract Price in accordance with the terms of this Article ‎10.7 (the "Price Adjustment") if, in its opinion, the Contract Price as at the respective Price Adjustment Date does not represent the price appropriate for the selling to, and buying by, (**).

10.7.2 A Party that requests a Price Adjustment shall specify in its Price Adjustment Notice the change it is requesting, including a reasonably detailed explanation of how such opinion was reached and all reasonably available non-confidential information that supports its opinion.

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10.7.3 The Parties shall discuss the Price Adjustment diligently and in good faith in order to conclude and reach a mutually acceptable agreement at the earliest reasonable time of a revised Contract Price that represents the price appropriate for the selling to, and buying by, (**).

10.7.4 If the Parties fail to reach an agreement on the Price Adjustment within ninety (90) days after the Price Adjustment Notice was delivered (or by a later date as may be agreed in writing by the Parties), either Party may refer the matter to Arbitration pursuant to Article ‎19.4.

10.7.5 The Price Adjustment made pursuant to Article ‎10.7.1(a) if made, whether agreed upon between the Parties pursuant to Article ‎10.7.3, or determined in Arbitration pursuant to the provisions of Article ‎19.4, shall be referred to in this Agreement as the "First Price Adjustment". The Contract Price following the First Price Adjustment shall apply from the First Price Adjustment Date until the end of that Price Period.

10.7.6 The Price Adjustment made pursuant to Article ‎10.7.1(b), if made, whether agreed upon between the Parties pursuant to Article ‎10.7.3, or determined in Arbitration pursuant to the provisions of Article ‎19.4, shall be referred to in this Agreement as the "Second Price Adjustment". The Contract Price following the Second Price Adjustment shall apply from the Second Price Adjustment Date until the end of that Price Period

10.7.7 The Price Adjustment shall be made by way of a factor by which the Contract Price will be multiplied in accordance with the following formula:

For the First Price Adjustment:

For the Second Price Adjustment:

Where:

"PA1" is the First Price Adjustment factor.

"PA2" is the Second Price Adjustment factor.

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10.7.8 The First Price Adjustment (PA1) shall not increase or decrease the Contract Price as at the First Price Adjustment Date by more than twenty five percent (25%) (i.e. 0.75 ≤ PA1 ≥ 1.25).

10.7.9 The Second Price Adjustment (PA2) shall not increase or decrease the Contract Price as at the Second Price Adjustment Date by more than ten percent (10%) (i.e. 0.90 ≤ PA2 ≥  1.10).

10.7.10 In the event that either Party requests a Price Adjustment, then with respect to the period as of the respective Price Adjustment Date and until the establishing of the Price Adjustment (whether as agreed by the Parties pursuant to Article ‎10.7.3, or as determined in Arbitration pursuant to the provisions of Article ‎19.4) the Contract Price shall continue to be calculated as if there was no Price Adjustment. Once the Price Adjustment has been agreed upon between the Parties pursuant to Article ‎10.7.3, or determined in Arbitration pursuant to the provisions of Article ‎19.4, the Contract Price shall be adjusted and shall take effect retrospectively from the respective Price Adjustment Date and any overpayment or underpayment by the Buyer in respect of the period from the Price Adjustment Date shall be shown in the next Monthly statement following calculation of the Contract Price based on the Price Adjustment, and shall be credited to or paid by the Buyer with interest calculated at the rate of LIBOR (**) from the date of any overpayment or underpayment to the date of credit or payment (as applicable) applying the adjusted Contract Price for such Price Period.

10.7.11 Example: (**)

10.8 Prices

10.8.1 Gas delivered under the terms of this Agreement shall be paid for at the Contract Price unless specified otherwise under this Agreement.

10.8.2 The Contract Price will include the amounts due to the Sellers for delivery of the Gas and providing the associated services as described in this Agreement, including the price of the energy content of the Gas, fees for capacity, processing, treatment, transportation, pressure reduction and measurement of the Gas prior to its delivery at the Delivery Point, and for the nomination procedures described in ‎Article 6.

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10.8.3 Gas delivered in reduction of the Shortfall Aggregate under the provisions of ‎Article 17 shall be paid for at a price (herein called the "Shortfall Price"), that is (**).

10.8.4 Excess Gas nominated by the Buyer and delivered under the provisions of Article ‎6.9.3 shall be paid for at a price that is equal to (**).

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ARTICLE 11

Billing and Payment

11.1 Monthly Statements

11.1.1 Not later than the fifth Business Day in the Month immediately following the earlier of September 2013 and the Flow Date and each Month thereafter, the Sellers shall render to the Buyer a statement ("Monthly Statement") which shall show for the preceding Month (inter alia) the information specified in Article ‎11.1.2.

11.1.2 The information referred to in Article ‎11.1.1 is:

(a) In respect of each Hour of that Month: the quantity of Gas expressed in MMBTU (calculated in accordance with its Higher Heating Value) delivered to the Buyer at the Delivery Point and the Proper Nomination for such Hour, and to the extent Sellers' deliveries fell short of Buyer's Proper Nomination in excess of the Delivery Tolerance, (**);

(b) Any reductions to the DCQ which are to be made in respect of any Day or Days in that Month (**);

(c) The balance of any Shortfall Aggregate (**) outstanding at the end of that Month;

(d) Any sum due and owing to the Buyer under the provisions of ‎Article 12 at the end of that Month;

(e) The sum due and owing to the Sellers (obtained in accordance with all relevant provisions of this Agreement) in respect of Gas delivered hereunder at the Delivery Point during that Month showing the respective apportionment (if applicable) of such sum at the respective prices applicable pursuant to the terms of this Agreement;

(f) Any sum due and owing to the Sellers under the provisions of Article ‎9.5 at the end of that Month;

(g) Any other sum or sums due and owing at the end of that Month from either Party to the other under this Agreement;

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(h) The net sums payable by the Buyer to each of the Sellers or by each of the Sellers to the Buyer after taking account of all the foregoing matters set out in this Article ‎11.1;

(i) The applicable taxes including value added tax and excise tax, if any, that are billable to Buyer or Sellers (as applicable) pursuant to applicable legislation or to this Agreement. Value Added Tax and excise tax (if any) will be expressed and paid by the Buyer to the Sellers in Israeli currency calculated in accordance with the Representative Rate known on the date of the tax invoice; and

(j) (**).

11.2 Annual Reconciliation Statements

11.2.1 As soon as practicable after each Contract Year but no more than sixty (60) days after the end of the Contract Year, the Sellers shall render to the Buyer a statement (herein called the "Annual Reconciliation Statement") which shall show for the preceding Contract Year (inter alia) the information specified in Article ‎11.2.2.

11.2.2 The information referred to in Article ‎11.2.1 is:

(a) The total quantity of Gas Properly Nominated by the Buyer in that Contract Year and the total quantity of Gas expressed in MMBTU delivered hereunder to the Delivery Point in that Contract Year;

(b) The Adjusted ACQ for that Contract Year showing in detail the reductions made from the ACQ in conformity with the terms of this Agreement to arrive at the Adjusted ACQ;

(c) The quantities of Gas for which the Buyer should have paid at the prices prescribed therefor and the quantities for which it has in fact paid at such prices;

(d) The balance of Make-Up Aggregate from previous Contract Years (showing the Contract Year or Contract Years in respect of which all parts of such Make-Up Aggregate first arose and showing in detail all reductions therefrom made in respect of such preceding Contract Year) together with a statement of the balance of Make-Up Aggregate (if any) to be carried forward;

(e) The balance of Carry Forward Aggregate remaining at the end of that Contract Year;

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(f) The Minimum Bill Quantity, the Annual Take or Pay Quantity and the Net Annual TOP Quantity for that Contract Year, if any;

(g) All and any sums due and owing from either Party to the other in respect of that Contract Year or any previous Contract Year;

(h) The net sums (if any) payable by the Buyer to each of the Sellers or by each of the Sellers to the Buyer as at the end of that Contract Year after taking account of all the foregoing matters set out in this Article ‎11.2; and

(i) (**).

11.2.3 If the Sellers have not rendered such Annual Reconciliation Statement within sixty (60) days from the end of the relevant Contract Year, then the Buyer shall be entitled to do so within sixty (60) days thereafter and such statement shall be deemed the Annual Reconciliation Statement.

11.3 Payment Dates

11.3.1 On the fifteenth (15th) Business Day after the Buyer has received the Sellers' Monthly Statement for the preceding Month, the Buyer shall pay to each of the Sellers, or each of the Sellers shall pay to the Buyer (as the case may be), in funds available to the recipient on the day of payment, the sum set out in such Monthly Statement, excluding amounts payable on account of Value Added Tax, which shall be paid in accordance with the provisions of Article ‎11.4.5.

11.3.2 On the last day of February in each Contract Year or within thirty (30) Business Days following the receipt of the Annual Reconciliation Statement, whichever is the later, the Buyer shall pay to each of the Sellers or each of the Sellers shall pay to the Buyer (as the case may be), in funds available to the recipient on the day of payment, the sum (if any) set out therein for the preceding Contract Year.

11.4 Payments

11.4.1 Payments under this Agreement shall be made in US Dollars by direct bank transfer or equivalent instantaneous transfer of funds to each of the Sellers or Buyer (as applicable) at such place in the US, Europe or Israel as the recipient may request or such other place as may be agreed (such agreement not to be unreasonably withheld).

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11.4.2 In the event any Seller requests that any payments to be made by the Buyer to such Seller hereunder be made in Israeli currency it shall submit its invoice in Israeli currency calculated in accordance with the Representative Rate known at the date of the invoice and Buyer shall comply with such request and make such payment in Israeli currency.

11.4.3 If the due date as specified above is not a banking day (i.e. a day on which banks are open for business) at the place of payment or place of receipt, then the due date shall be deferred to the next banking day.

11.4.4 Subject to the timely provision to the paying Party (which for the purposes of this Article will include the Buyer or each of the Sellers, as applicable) of appropriate withholding tax exemptions approvals, all payments made under this Agreement shall be made without withholding or deduction for, or on account of any taxes, duties, assessments or governmental charges of any nature imposed or levied by or on behalf of any authority having power to tax, unless such withholding or deduction is required by law.

11.4.5 In the event that any payments due to be paid by a Party hereunder are subject to Value Added Tax under Israeli Law, such Value Added Tax will be paid by such Party to the other Party at the prevailing legal rate, against procurement of a tax invoice (heshbonit mas) as required by Israeli law, by no later than one (1) Business Day prior to the date on which such Value Added Tax must be paid to the taxation authorities under the applicable law.

11.5 Failure to Pay

11.5.1 Should either the Buyer or any of the Sellers fail to make payment to the other of any sum due hereunder, interest thereon shall accrue at the rate per annum equal to LIBOR (**) (compounded annually) from the date when such payment is due hereunder until the same is made.

11.5.2 In the event of failure to pay any sum due pursuant to this Agreement which is not the subject of a dispute under Article ‎11.6.1 for seven (7) days from the applicable due date, then the Party to whom the same is due and owing may on fourteen (14) days prior notice to the other Party of the intention so to do, suspend delivery or receipt, as the case may be, of Specification Gas hereunder, and if such failure to pay continues for one hundred and twenty (120) days from the applicable due date, the Party to whom the same is due and owing may also, on fourteen (14) days prior notice to the other Party, terminate this Agreement, but the exercise of such right shall not constitute a waiver of, nor in any way prejudice, other remedies available to such Party.

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11.6 Disputed Amounts

11.6.1 In the event that the Buyer disputes any matter or sum set out in any Monthly Statement or any Annual Reconciliation Statement or the Sellers dispute any matter or sum set out in any Annual Reconciliation Statement prepared by the Buyer in accordance with Article ‎11.2.3, the Party disputing such matter or sum shall no later than three (3) Business Days before the due date for payment give notice to the other Party of the nature and extent of such dispute and of its election pursuant to Article ‎11.6.2 and the disputing Party shall (**).

11.6.2 The disputing Party shall be entitled (**).

11.6.3 Within fourteen (14) days after such payment due date, the Parties shall meet to seek to resolve such dispute, but if within thirty (30) days after such payment due date the Parties have not resolved such dispute, then either Party may refer such dispute to Arbitration in accordance with ‎Article 19.

11.6.4 Within seven (7) Business Days after such dispute is agreed or determined, the corresponding payment or repayment (as the case may be) due from one Party to the other shall be made together with interest at the rate set out in Article ‎11.5 from the applicable due date to the date of such payment or repayment.

11.7 Examination

The Parties shall each have the right, upon reasonable notice and at reasonable hours, to examine the books, records and charts of the other Party relevant to this Agreement to the extent necessary to verify the accuracy of any accounting statement, charge, calculation, determination or claim made pursuant to any of the provisions of this Agreement subject to the following:

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11.7.1 Such books, records and charts need not be preserved longer than a period of twenty-four (24) Months after the end of the Contract Year to which such books records or charts refer unless they relate to an outstanding bona fide dispute.

11.7.2 If any such verification involves the examination of confidential documents not solely relating to the sale of Specification Gas hereunder, the requesting Party shall have the right to require the auditors of the other Party to provide a certified extract of the documents excluding such non-relating matters and the costs of preparing such extract shall be borne by the requesting Party unless it is established that there was an error in any such accounting statement, charge, computation or claim in which event the cost thereof shall be borne by the other Party.

11.7.3 If any such examination reveals any inaccuracy in any invoice or financial statement theretofore rendered, the Party to whom the resulting payment or repayment is due shall within seven (7) Business Days after the date that such inaccuracy is discovered but not later than two (2) years after the date of the relevant statement or invoice, submit to the other Party a statement showing all necessary adjustments to the former bill or financial statement. Within fourteen (14) Business Days after the amount due is established (by agreement or determination by Arbitration in accordance with ‎Article 19) the Party from whom payment is due shall make payment or repayment (in accordance, mutatis mutandis, with the provisions of Articles ‎11.4 and ‎11.5 above) of the sum so due.

11.7.4 Such right to examine must be exercised within twenty-four (24) Months after the end of the Contract Year to which the books, records or charts being examined refer.

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ARTICLE 12

Quality

12.1 Specification

12.1.1 Natural Gas tendered for delivery under this Agreement shall at the Delivery Point be in accordance with the specification set out in part 1 of Schedule 5 ("Specification").

12.1.2 If Natural Gas tendered for delivery hereunder forms part of a commingled stream, which at the Delivery Point fails to conform to the Specification, then whatever may be the reason for such failure, the Natural Gas tendered for delivery hereunder shall be deemed not to conform to the Specification.

12.2 Failure to Conform

12.2.1 If at any time the Natural Gas tendered for delivery at the Delivery Point is Off-Spec Gas, any Party that becomes aware that such Natural Gas is Off-Spec Gas shall promptly notify the Transporter and the other Party in accordance with Article ‎12.3. The Buyer shall have the right to accept or reject such Off-Spec Gas subject to the following provisions of this Article ‎12.2.

12.2.2 Upon becoming aware that the Natural Gas tendered for delivery at the Delivery Point is Off-Spec Gas, the Sellers shall promptly use reasonable endeavors to remedy such failure so as to make available Specification Gas.

12.2.3 The Buyer may refuse to take all or any part of the Off-Spec Gas until the deficiency has been remedied, but any such refusal shall not constitute a waiver of nor affect any other rights or remedies of the Buyer in respect of such failure on the part of the Sellers to deliver Specification Gas.

12.2.4 If the Buyer knowingly takes Off-Spec Gas (i.e. after having being notified by the Sellers or the Transporter that it is Off-Spec Gas) (**):

(a) (**);

(b) (**);

provided however, that the Sellers’ total liability with regard to any and all costs and expenses with respect to the circumstances set out in Article ‎12.2.4, shall be limited to (**).

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12.2.5 If the Buyer:

(a) takes Off-Spec Gas not being aware that it is Off-Spec Gas; or

(b) (**),

then, (**).

12.3 Notifications

The Sellers shall notify the Buyer as soon as reasonably practicable after becoming aware of any failure or anticipated failure in the quality of the Natural Gas giving details of the cause of the failure (including the type and degree of such non-conformance) and an estimate of the probable duration of the failure.

12.4 Determination

12.4.1 Any difference between the Parties, which may arise in respect of the quality of the Natural Gas, shall (at the request of either Party) be referred to the Expert for determination in accordance with Article ‎19.3.

12.4.2 Any difference between the Parties, which may arise in respect of any liabilities, costs, claims and expenses incurred under Article ‎12.2, shall (at the request of either Party) be referred for determination in accordance with Article ‎19.4.

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ARTICLE 13

Delivery Point

13.1 Delivery Point

13.1.1 "Delivery Point" means the Ashdod Delivery Point or the Additional Delivery Point as applicable.

13.1.2 The "Ashdod Delivery Point" is the point at the flange between the receiving terminal operated by the Yam-Tethys Partners in Ashdod and the Transporter’s receiving terminal in Ashdod (being the entry point to the Downstream System) as identified in the diagram set out in Schedule 9.

13.1.3 In addition to the Ashdod Delivery Point, the Sellers will have the right to designate additional Delivery Points which will be the point at the flange between a suppliers' receiving terminal and the Transporter’s receiving terminal near Ashkelon (being an entry point to the Downstream System) or at any such other entry points to the Downstream System as may be agreed by the Parties (each an "Additional Delivery Point").

13.1.4 In the event there is more than one Delivery Point, the Sellers will have the right to deliver Gas hereunder at any one or more Delivery Points at their discretion and the term Delivery Point shall be construed to mean any Delivery Point.

13.1.5 Specification Gas to be delivered under the terms of this Agreement shall be tendered for delivery by the Sellers to the Buyer at the Delivery Point.

13.2 Property and Risk

Title to Specification Gas and risk of loss of or damage to Specification Gas delivered in accordance with the terms of this Agreement shall pass from the Sellers to the Buyer at the Delivery Point and any liability in respect of such Specification Gas shall also pass at the Delivery Point.

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ARTICLE 14

Pressure

14.1 Delivery Pressure

14.1.1 The "Delivery Pressure" shall be a pressure sufficient to allow Natural Gas Properly Nominated by Buyer to enter the Downstream System, it being agreed that the pressure in the Downstream System will not exceed a Gauge maximum pressure of eighty (80) Bar.

14.1.2 The Sellers shall deliver Specification Gas at the Delivery Point at the Delivery Pressure.

14.1.3 For the avoidance of doubt, if the Sellers, acting as a Reasonable and Prudent Operator, tender the quantity of Specification Gas Properly Nominated for delivery in accordance with Article ‎14.1.2 above and that quantity is not delivered because the pressure downstream of the Delivery Point was higher than eighty (80) Bar (or such higher pressure agreed to by Sellers), then this event will be included in the circumstances of Buyer’s failure to take delivery of Specification Gas and the Sellers shall have no liability for such failure to deliver the quantity Properly Nominated.

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ARTICLE 15

Measurement

15.1 General

Buyer and Sellers agree to determine measurement procedures in consultation with the relevant Transporter procedures and application of good oil and gas industry practices in accordance with the American Gas Association (or European equivalent) codes and specifications and in accordance with part 2 of Schedule 5.

15.2 Measurement Devices

Sellers shall supply, operate and maintain, or cause to be supplied, operated and maintained, suitable gas volume, pressure and temperature measuring devices, and sampling systems and analytical equipment required for collecting samples and for determining quality and composition of the Natural Gas. Such metering station will be located at or near the Delivery Point. If the Sellers supply such measuring devices, they shall do so in accordance with the American Gas Association (or European equivalent) codes and specifications and in accordance with part 2 of Schedule 5.

15.3 Disputes

In the event of any dispute concerning the subject matter of this ‎Article 15, including but not limited to, disputes over the accuracy of measuring devices, their calibration, the result of a measurement, sampling, analysis, computation or method of calculation, such dispute shall be settled in good faith as mutually agreed between the Parties and in consultation with the Transporter, if appropriate. In the absence of such agreement the dispute shall be submitted to the Expert for determination pursuant to Article ‎19.3.

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15.4 Costs and Expenses of Test and Verification

All costs and expenses for testing and verifying Sellers’ measurement devices shall be borne by Sellers, provided that if Buyer requests testing or verification of measurement devices, the costs for such action shall be borne by Buyer unless such devices are found to be outside tolerance limits. When the services of a competent impartial authority are required and selected by mutual agreement, then the fees and charges of such authority shall be borne equally by Sellers and Buyer.

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ARTICLE 16

Force Majeure

16.1 Definition

The expression "Force Majeure" means any event or circumstance (including (**)), which is beyond the control of the Buyer or the Sellers (as the case may be) (acting and having acted as a Reasonable and Prudent Operator) resulting in or causing:

16.1.1 the failure or inability by the Buyer or the Sellers (as the case may be) to perform any one or more of their respective obligations (including obligations of reasonable endeavors) under this Agreement; or

16.1.2 in the case of the Buyer, the occurrence of all or any of the circumstances specified in Article ‎16.4.2(d),

and which failure, inability or occurrence (as applicable) could not have been prevented or overcome by the exercise by the Buyer or the Sellers (as the case may be) of such action as would have been taken by a Reasonable and Prudent Operator.

For the avoidance of doubt, changes in market conditions, including changes that directly or indirectly affect the demand for or price of electricity and/or Gas, including inter alia, loss of customers, shall not constitute a Force Majeure event.

16.2 Exclusions

Notwithstanding anything in Article ‎16.1 (and without prejudice to the generality thereof):

16.2.1 The Sellers shall not be entitled to claim relief through Force Majeure for any failure to perform their obligations hereunder to the extent that such failure was caused by a (**).

16.2.2 The Buyer shall not be entitled to claim relief through Force Majeure in the event of any failure to perform its obligations hereunder to the extent that such failure was caused by any one or more of the following events or circumstances:

(a) The failure to renew, extend or obtain any of Buyer’s Generation Licenses; or

(b) Any requirement pursuant to Section 92 of the Israel Natural Gas Sector Law, 2002, to purchase Natural Gas from other producers or sources.

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16.3 Payments

Notwithstanding anything in Article ‎16.1 (and without prejudice to the generality thereof) failure by either the Buyer or the Sellers (as the case may be) to pay money which is due shall not be treated as being Force Majeure or caused thereby unless such failure was due to Force Majeure affecting all reasonable means of payment in which event upon the cessation of such Force Majeure the Buyer or the Sellers (as the case may be) shall pay in addition to the above, interest on any amounts due hereunder at the rate of LIBOR (**) calculated from the due date to the date of payment.

16.4 Nature of Relief

The Buyer or the Sellers (as the case may be) shall, subject to Article ‎16.5 and Article ‎16.6, be relieved from liability under this Agreement as follows:

16.4.1 In the case of the Sellers, to the extent that by reason of Force Majeure, the Sellers:

(a) fail to deliver the quantities of Specification Gas Properly Nominated for delivery under this Agreement;

(b) fail to perform any of their other obligations under this Agreement; or

(c) are otherwise in breach of any covenant under this Agreement.

16.4.2 In the case of the Buyer, to the extent that by reason of Force Majeure, the Buyer:

(a) fails to take delivery of Specification Gas Properly Nominated for delivery and properly tendered for delivery under this Agreement;

(b) fails to perform any of its other obligations under this Agreement;

(c) is otherwise in breach of any covenant under this Agreement; or

(d) is unable to:

(i) accept Natural Gas at Buyer's Facilities and/or use Natural Gas to generate electricity at and/or transmit electricity from any of the Buyer’s Facilities; or

(ii) transport or have transported in the Downstream System to any of Buyer’s Facilities the whole or any part of the Natural Gas which was to have been transported therein (pursuant to the Transportation Agreement) owing to the inoperability of the Downstream System caused by an event or circumstance beyond the control of the Transporter (acting and having acted as a Reasonable and Prudent Operator) and which could not have been prevented or overcome by the exercise by the Transporter of the standard of a Reasonable and Prudent Operator.

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16.4.3 In the event that either the Buyer or the Sellers shall exercise their respective rights (pursuant to Article ‎23.1) to perform any obligations under this Agreement by procuring that such obligations are performed by a third party, then the Buyer or the Sellers (as the case may be) shall only be entitled to be relieved from liability for reasons of Force Majeure to the extent that they acted as a Reasonable and Prudent Operator in appointing such third party and such third party would have been so entitled to such relief if such third party had been the Buyer or the Sellers (as the case may be) under this Agreement. For the avoidance of doubt, any Force Majeure event relating to the Yam-Tethys Facilities shall constitute a Force Majeure event under this Agreement provided that the inoperability of the Yam-Tethys Facilities would have entitled the Yam-Tethys Partners to such relief if Yam-Tethys Partners had been the Sellers under this Agreement.

16.5 Notice and Reports

Relief under Article ‎16.4 shall not be given to the Buyer or the Sellers unless such Party has:

16.5.1 By notice to the other Party (served as soon as reasonably possible and in no event later than seven (7) Days after becoming aware of the failure, inability or occurrence) that it intends to claim relief (and such notice shall contain such relevant information relating to such failure, inability or occurrence as is available including (without limitation) (**); and

16.5.2 Given (as soon as reasonably possible after the service of the notice under Article ‎16.5.1 but in any event not later than fifteen (15) Days thereafter) (**).

16.6 Remedial Steps

As soon as practicable after the occurrence of an event of Force Majeure, the Party claiming relief shall take all reasonable steps necessary in the applicable circumstances to remedy the failure, inability or occurrence. Relief under this ‎Article 16 shall cease to be available if the Party claiming relief (or, as applicable, such third party) fails to so take all necessary steps in the applicable circumstances to remedy the failure, inability or occurrence but such Party claiming relief shall not be obliged to settle any labor dispute except, in such manner as it shall in its own judgment consider fit.

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16.7 Access

Upon request from the other, the Party claiming relief shall as soon as reasonably possible to the extent it is entitled to do so give or procure access or if it is not so entitled shall use reasonable endeavors to procure access (subject in each case to operational constraints) for a reasonable number of representatives of the other Party to examine the scene (if any) of the event or circumstance causing the failure, inability or occurrence (such access to be at the sole risk and cost of the Party seeking access).

16.8 Extended Force Majeure

If by reason of an event of Force Majeure any Party ("Affected Party") is unable to perform any material obligation required to be performed under this Agreement and such inability to perform continues for a period of (**), the other Party may terminate this Agreement by giving at least ninety (90) days' notice in writing to the Affected Party at the expiry of which this Agreement will terminate without prejudice to any rights of the Parties that have accrued prior to the date of termination.

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ARTICLE 17

Default

17.1 Shortfall Gas

17.1.1 With effect from the later of the Commencement Date and October 1, 2013, if the Sellers fail in respect of any Hour to deliver the quantity of Specification Gas Properly Nominated for delivery for any reason other than the Buyer's failure to take Specification Gas otherwise properly tendered for delivery in accordance with this Agreement, such amount will be "Shortfall Gas", provided however that (**).

17.1.2 Notwithstanding the above, for the purposes of calculating Shortfall Gas, a Proper Nomination in respect of any Hour shall not include any quantity of Specification Gas:

(a) which exceeds the quantity taken by the Buyer in respect of the immediately preceding Hour (other than by reason of Sellers’ failure to tender for delivery Properly Nominated Gas in such preceding Hour) by more than: (i) (**) MMBTU if the quantity taken by the Buyer in the preceding Hour was equal to or lower than (**) MMBTU; (ii) (**) MMBTU if the quantity taken by the Buyer in the preceding Hour was higher than (**) MMBTU (**) or (**) MMBTU if the quantity taken by the Buyer in the preceding Hour was higher than (**) MMBTU (**).

(b) (**);

(c) which exceeds zero (0) during the first three (3) Hours after a Cold Start (**); or

(d) which exceeds (**) during the first (**) Hours after any Hour in which the Buyer and others nominated a total quantity of less than (**) MMBTU for delivery from the Reservoir to the Delivery Point or from the fourth Hour after such Hour quantities which exceeds the rates as set out in Article ‎17.1.2‎(a) above.

17.1.3 If any correction of quantities delivered in any Hour is made under the provisions of ‎Article 15, then the actual amount of any Shortfall Gas accrued shall be adjusted when the corrected amounts are available under the provisions of ‎Article 15 and the appropriate adjustments shall be made for the purposes of Article ‎17.2.

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17.1.4 In order to avoid any doubt, Shortfall Gas shall not include any quantity for which the Sellers are relieved from liability in accordance with ‎Article 16.

17.1.5 It is agreed that the provisions of Article ‎17.1 shall not apply in circumstances where in any Hour, the quantity of Gas delivered by the Sellers in respect of that Hour, is within the (**).

17.1.6 In respect of each Day and each Week, if the aggregate quantity of Gas delivered by the Sellers in respect of such periods, is not within the (**), respectively, then the extent to which the aggregate delivery falls short of the aggregate Proper Nominations for the applicable period ("Period Shortfall") will be Shortfall Gas in respect of the Month in which such period falls. It is agreed that each such quantity of Period Shortfall will be reduced by any quantities of Shortfall Gas already taken into account in respect of any Hour or Day falling within any longer aforesaid period. For the purposes of calculating the Week periods in any Month, there shall be included only those whole Weeks which end in that Month.

17.2 Monthly Shortfall Aggregate

17.2.1 The total of Shortfall Gas, in respect of any Month shall be aggregated as at the end of that Month (such aggregate amount together with any additions thereto pursuant to Article ‎17.2.3 being herein referred to as the "Shortfall Aggregate").

17.2.2 The first Specification Gas delivered after the end of that Month under this Agreement up to an amount equal to the Shortfall Aggregate which would otherwise be paid for by the Buyer at the Contract Price, shall be paid for at the Shortfall Price. The Shortfall Aggregate shall be reduced by the amount of Specification Gas which is paid for at the Shortfall Price.

17.2.3 To the extent that at the end of any Month the Shortfall Aggregate exceeds the amount of Specification Gas which is delivered in the next succeeding Month and paid for at the Shortfall Price, the balance shall be carried forward and be added to the Shortfall Aggregate for the next succeeding Month or Months (as the case may require).

17.2.4 If at any time or from time to time during the Contract Period the aggregate money value of the product of the Shortfall Aggregate and the difference between the applicable Shortfall Price and the Contract Price exceeds (**), then the Buyer may by notice to the Sellers elect that, subject to the limitations of liability under Article ‎17.4.8, the Sellers shall pay to the Buyer a sum of money equal to such aggregate money value and the Shortfall Aggregate shall be adjusted accordingly.

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17.2.5 If at the end of the Contract Period there is any quantity of Shortfall Aggregate which has not been discharged then, subject to the limitations of liability under Article ‎17.4.8, the Sellers shall pay to the Buyer at such date of termination a sum of money equal to the product of the Shortfall Aggregate and the difference between the applicable Shortfall Price and the Contract Price at the end of the final Contract Year of the Contract Period.

17.3 (**)

17.4 Limitations of Liability

17.4.1 The payment by the Buyer to the Sellers for a quantity of Specification Gas equal to the Minimum Bill Quantity for each Contract Year of the Take or Pay Period shall be the exclusive remedy and the limit of all and any liability of the Buyer in respect of any failure to take Specification Gas in that Contract Year, and shall be in full satisfaction of all rights, costs, claims, and damages (whether direct, indirect, consequential or otherwise and howsoever arising) of the Sellers in respect thereof, including as a result of a breach of Article ‎7.2.

17.4.2 Subject to the provisions of Article ‎17.4.1 above, Buyer’s total liability for any breach of any of its other undertakings and obligations under this Agreement shall not exceed an amount equal to (**) in any Contract Year, excluding the final Contract Year, and a total amount equal to (**) for the whole Contract Period (including the final Contract Year). This limitation of liability shall not apply to (**).

17.4.3 The Buyer shall not be liable to the Sellers and the Sellers shall not be liable to the Buyer for any indirect (which includes loss of profit and business interruption claims), consequential, exemplary or punitive losses or damages. To the extent any damages are required to be paid hereunder are liquidated, the Parties hereby acknowledge and agree that the liquidated damages constitute an adequate compensation and shall be the exclusive remedy in such circumstances.

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17.4.4 The delivery by the Sellers of a quantity of Specification Gas to be paid for by the Buyer at the Shortfall Price or payments made according to the provisions of Article ‎17.2.4 and ‎17.2.5 (if applicable), shall be the exclusive remedy and the limit of and the sole damages to which the Buyer may be entitled from the Sellers (whether direct, indirect, consequential or otherwise and howsoever arising) in respect of Sellers’ failure to deliver Properly Nominated Specification Gas to the Buyer in any Hour, including as a result of a breach of Articles ‎6.5, ‎6.6.3, and ‎7.1.

17.4.5 The delivery by the Sellers of a quantity of Specification Gas to be paid for by the Buyer at the applicable Shortfall Price, shall be the exclusive remedy and the limit of and the sole damages to which the Buyer may be entitled from the Sellers (whether direct, indirect, consequential or otherwise and howsoever arising) in respect of Sellers’ failure to deliver Properly Nominated Specification Gas to the Buyer in any Hour in the circumstances described in Article ‎17.3 and the Sellers failure to comply with the provisions of Article ‎6.4.11. Notwithstanding the aforesaid, in the event that the Sellers are in breach of their undertakings under Article ‎6.6.3, the Buyer shall have the right to seek specific performance of such undertakings.

17.4.6 The Payment of any amount due pursuant to ‎Article 12, shall be the sole damages to which the Buyer may be entitled from the Sellers (whether direct, indirect, consequential or otherwise and howsoever arising) in respect of Sellers’ failure to deliver Properly Nominated Specification Gas to the Buyer in any Hour (in the circumstances of ‎Article 12).

17.4.7 The payment by Sellers to Buyer of the amounts to which Buyer may be entitled under Article ‎2.3 up to a maximum of (**) shall be the limit of Sellers' liability and Buyer’s exclusive remedy in such circumstances, other than termination rights pursuant to Article ‎2.3.4.

17.4.8 Notwithstanding anything to the contrary in this Agreement, Sellers total liability for any failure to deliver Specification Gas and all other breaches of any or all of their undertakings and obligations under this Agreement, including as a result of a breach of Articles (**), and ‎7.1, shall not exceed an amount equal to (**), and a total amount equal to (**) for the whole Contract Period (including the final Contract Year).

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(a) The limitation of liability under Article ‎17.4.8 above shall not apply to (**).

(b) For the avoidance of doubt, the limitation of liability set out in this Article ‎17.4.8 will apply in respect of (**).

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ARTICLE 18

Assignment and Security Interests

18.1 General

18.1.1 For the purposes of this ‎Article 18, the expression "Party" means the Buyer of the one part and each of the Sellers of the other part, as appropriate.

18.1.2 No Party shall assign or transfer its rights and/or obligations under this Agreement or any part thereof except in accordance with the provisions of this ‎Article 18. Any assignment or transfer made without fulfilling the provisions of this ‎Article 18 shall be of no effect.

18.2 Transfer Among Sellers or to Affiliates

18.2.1 The Buyer and each of the Sellers may assign or transfer all or any portion of its rights and obligations under this Agreement (in this ‎Article 18 "transfer") to an Affiliate without the consent of the other Party, subject to the following:

(a) Prior to such transfer, the transferring Party shall provide to the other Party details of the rights and obligations to be transferred and the name of the Affiliate (or if a transfer between Sellers, the name of the Seller to which the interest is to be transferred); and

(b) At the time of such transfer, the transferring Party shall:

(i) if the transferring Party is a Seller, transfer to the transferee a corresponding portion of the Seller’s Percentage;

(ii) obligate the transferee to observe and perform the obligations under this Agreement transferred to it, including in the case of a transfer by a Seller, the obligation by the transferee to assume liability (commensurate with the interest transferred) in respect of all and any Make-Up Aggregate, Carry Forward Aggregate and Shortfall Aggregates accrued at the time of such transfer.

(iii) if the transferring Party is a Seller, replace the Credit Cover provided to the Buyer pursuant to ‎Article 20 with a new Credit Cover on the same terms (mutatis mutandis) as the existing Credit Cover;

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(c) Within seven (7) days after such transfer, the transferring Party shall give to the other Party notice of such transfer together with documentation regarding fulfillment of the provisions of Article ‎18.2.1‎(a) and ‎(b) above.

18.2.2 It is agreed that in the event of a transfer in accordance with the provisions of Article ‎18.2.1 above, the transferring Party shall remain fully liable to the other Party for the performance by the transferee of its obligations and discharge of its liabilities under this Agreement, except where the transferee has fulfilled the additional provisions of Article ‎18.4.1, in which case the transferring Party will be relieved of liability upon fulfillment of such provisions.

18.2.3 The provisions of Article ‎18.2.1 and ‎18.2.2 above will also apply to the transfer of rights and obligations from any of the Sellers to another Seller. Notwithstanding the provisions of Article ‎18.2.2, in the event of a transfer from any of the Sellers to another Seller, the transferring Seller will be relieved from liability to the Buyer for the performance of its obligations and discharge of its liabilities under this Agreement provided the transfer does not exceed in aggregate (**) of the transferring Seller’s Percentage.

18.3 Buyer's Structural Reform

18.3.1 Notwithstanding the provisions of Article ‎18.1 above, Buyer may transfer all of its rights and obligations under this Agreement to an Affiliate, without the prior consent of the Sellers, subject to; (i) such Affiliate providing to Sellers a written undertaking to be bound by all the terms and conditions of this Agreement, such undertaking to be in a form reasonably satisfactory to Sellers; and (ii) the Buyer remaining fully liable to Sellers for the performance by the Affiliate of its obligations and discharge of its liabilities under this Agreement.

18.3.2 Buyer shall be entitled to transfer Buyer’s rights and obligations under this Agreement to an Affiliate pursuant to the Electricity Sector Act 1996, the Government Companies Act 1975 and/or an Israeli Government decision to carry out with respect to Buyer any solvent re-organization, merger or de-merger, privatization or other structural reform provided that any such proposed transfer shall be subject to the provisions of Article ‎18.2 or ‎18.4 (as the case may be).

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18.4 Transfer Generally

18.4.1 Any transfer by the Buyer, or by each of the Sellers to a third party (other than to an Affiliate or among Sellers as set out in Article ‎18.2), may only be made if the transferring Party shall:

(a) reasonably satisfy the other Party that such proposed transferee has the financial and the technical status and ability to observe and perform the obligations to be transferred (regardless of any comparison with the corresponding status and ability of the transferring Party), and the Party wishing to transfer has given notice to that effect to the other and with such notice has given any necessary information to show such financial and technical status and ability of the proposed transferee. In such event, unless the Party to whom the notice has been given has within thirty (30) days given notice that it is not satisfied (stating the reasons therefore), it shall be deemed to be satisfied; and

(i) where the transferring Party is the Buyer, the other Party (acting reasonably) will also be entitled to require from the transferee appropriate financial securities or guarantees and appropriate technical assurances in connection with such transfer and that the transfer be made together with a transfer to the transferee of a corresponding portion of Buyer’s rights in the generating units at Buyer’s Facilities (such portion to be determined by the Expert pursuant to Article ‎19.3, in the event of disagreement between Parties regarding the portion to be transferred); and

(ii) (**).

(b) provide to the other Party, details of the rights and obligations to be transferred;

(c) if and to the extent applicable, provide to the other Party a new Credit Cover to replace the Credit Cover provided pursuant to ‎Article 20, in respect of the obligations to be transferred to the proposed transferee on the same terms (mutatis mutandis) as the existing Credit Cover;

(d) if the transferring Party is a Seller, transfer to the transferee a corresponding portion of the Seller’s Percentage; and

(e) obligate the transferee to observe and perform all the obligations of this Agreement transferred to it, including in the case of a transfer by a Seller, the obligation by the transferee to assume liability (commensurate with the interest transferred) in respect of all and any Make-Up Aggregate, Carry Forward Aggregate and Shortfall Aggregates accrued at the effective date of such transfer.

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18.4.2 In the event that the Sellers' Lenders, acting reasonably, do not approve Buyer's proposed transferee, the Buyer will be deemed not to have reasonably satisfied the Sellers in accordance with the provisions of Article ‎18.4.1.

18.4.3 With effect from the effective date of a transfer pursuant to this Article ‎18.4, the transferring Party shall, to the extent that it has transferred its obligations under this Agreement, be relieved from its obligations hereunder, but (except for the obligations assumed by the transferee of a Seller pursuant to Article ‎18.4.1(e)) no such transfer shall operate to relieve the transferring Party of any liability accrued under or pursuant to the terms of this Agreement prior to the effective date of such transfer.

18.4.4 Within seven (7) Days after such transfer, the transferring Party, jointly with the transferee, shall give to the other Party notice of such transfer.

18.5 Sellers' Percentage

18.5.1 The Seller’s Percentage of each of the Sellers as of the date hereof is set out in Schedule 2.

18.5.2 A Seller shall not transfer its Seller’s Percentage (or any part thereof) unless at the same time it (**).

18.5.3 (**).

18.6 Security for Financing

18.6.1 Notwithstanding the foregoing, a Seller may at any time (upon giving the Buyer not less than thirty (30) days prior notice thereof) assign its rights to the receipt of any monies due or to become due from the Buyer to it under this Agreement to or in favor of banks, bona fide financial entities or other lenders (in this Article ‎18.6 together called "Banks") as security for any financing, provided that the Buyer shall not be required or entitled to act on such assignment and make payment to the Banks unless:

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(a) the assignment contains an acknowledgement from the Banks that their rights to receive monies under the assignment are subject to the terms of this Agreement; and

(b) the Seller has provided the Buyer with a certified copy of an extract (referring to the above acknowledgement) from such assignment; and

(c) the Seller has confirmed to the Buyer that the Buyer shall be entitled to rely on the receipt by such Banks of any monies paid by the Buyer to such Banks pursuant to such assignment as being due payment to the Seller hereunder.

18.6.2 The authority given by the Seller to the Buyer (consequent upon an assignment which has been made under the provisions of Article ‎18.6.1) to make payment of monies due hereunder to the Banks may be revoked by a notice given to the Buyer by the Seller which complies with the provisions of Article ‎11.4 and which expressly revokes such authority.

18.6.3 Notwithstanding the foregoing, a Seller may at any time (upon giving the Buyer not less than thirty (30) day prior notice thereof) create, subject to the terms of this Article ‎18.6.3, any security over all or any of its rights under this Agreement (the "Charged Assets") (except for the creation of security in respect of its rights hereunder to receive monies in respect of which rights the terms of Article ‎18.6.1 apply in relation to creation of security), the Seller’s Interest, the Seller’s Percentage of the Sellers’ Agreements and/or its interest in the Sellers’ Facilities in favor of Banks as security for any financing, but the creation of such security over the Charged Assets shall only be permitted and be effective against the Buyer if at the time of the creation of the security over the Charged Assets, such Banks shall covenant directly with the Buyer (i) to procure that upon the enforcement of such security, they or any receiver appointed pursuant to the instrument creating the security or other Person enforcing the security or having control over the Charged Assets or any purchaser of the Charged Assets, shall accept and comply with the obligations and covenants of the Seller in relation to the Charged Assets contained in this Agreement; and (ii) not to sell the Charged Assets to any purchaser, unless there shall simultaneously be an assignment of all the rights and obligations of the Seller in relation to the Charged Assets under this Agreement to such purchaser in accordance (mutatis mutandis) with the provisions of Article ‎18.4.

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18.6.4 The Buyer agrees, if required by any Lender of any Seller (individually and collectively referred to as "Sellers' Lenders"), to provide Sellers' Lenders with acknowledgments evidencing its consent to creating a security interest over the Charged Assets which shall include reasonable terms and conditions customary for an acknowledgement of this type, substantially in the form attached as Schedule 10 hereto.

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ARTICLE 19

Governing Law and Dispute Resolution

19.1 Governing Law

This Agreement shall be governed by and construed in accordance with the substantive laws of Israel. In resolving any Dispute, the Expert or the arbitrator(s) shall take into account international petroleum industry practices.

19.2 Dispute Resolution

Any dispute, claim, or controversy arising out of or relating to this Agreement, including without limitation any issue regarding the existence, validity, enforceability, interpretation, application, performance, breach, formation or termination of this Agreement (each a "Dispute"), shall be resolved exclusively and finally in accordance with the provisions of this ‎Article 19.

19.2.1 Disputes that are to be submitted to Expert determination in accordance with Articles ‎6.8.10, ‎9.4.3, ‎10.4.3, ‎12.4.1, ‎15.3, ‎17.3.3(d) and ‎18.4.1(a)(i) shall be resolved by Expert Determination in accordance with the provisions of Article ‎19.3; and

19.2.2 Any Dispute (other than those referred to in Article ‎19.2.1 but including any Dispute regarding the conduct, interpretation, enforcement or application of the Expert Determination), shall be resolved by Arbitration in accordance with the provisions of Article ‎19.4.

19.3 Expert Determination

19.3.1 Procedure for Appointment

The procedure for the appointment of the Expert shall be as follows:

(a) The Party initiating Expert Determination shall give written notice to that effect to the other Party and with such notice shall give specific details of the Dispute to be resolved by the Expert.

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(b) The Parties shall endeavor to agree on a Person to act as the Expert to whom the Dispute shall be referred for determination.

(c) Notwithstanding the provisions of Article ‎19.3.1(b), if within fourteen (14) days from the delivery of the notice initiating the Expert Determination, the Parties have failed to agree upon the Expert to be appointed pursuant to Article ‎19.3.1(b), then the LCIA shall serve as appointing authority to appoint the Expert. Either Party may submit a written application to the LCIA, with a copy to the other Party, detailing the nature of the Dispute and the issues to be determined, setting out any matters the applicant may wish to bring to the attention of the LCIA for the purposes of making the appointment. Within ten (10) days of the submission of the Application to the LCIA, the other Party shall submit to the LCIA a reply to the Application. Within fourteen (14) days from the time of the reply to the application, the LCIA shall appoint a person to act as Expert, and in so doing the LCIA may take such independent advice as it thinks fit.

(d) The Expert Determination shall be administered by the LCIA, which shall act as appointing authority and determine any challenges brought to the Expert. The LCIA's charges shall be in accordance with its schedule of arbitration fees and costs (Schedule of Fees) as in effect at the time the Expert Determination proceeding is initiated.

(e) Prior to his appointment, the Expert shall provide the LCIA with a resumé of his experience, qualifications, and prior and present professional positions; shall agree in writing to a fee rate in accordance with the LCIA Schedule of Costs as then in effect; and shall sign a declaration to the effect that there are no circumstances known to him likely to give rise to any reasonable doubt regarding his independence and impartiality. The expert shall undertake a continuing obligation to disclose to the LCIA and the Parties any circumstances which may give rise to any reasonable doubt regarding his independence and impartiality after his appointment and before the conclusion of the Expert Determination.

(f) If circumstances exist giving rise to justifiable doubts about the Expert’s independence or impartiality, a Party may challenge the appointment or continued service of the Expert by giving written notice to the LCIA within thirty (30) days of the appointment or within thirty (30) days of the challenging Party becoming aware of the circumstances giving rise to such doubts. Unless the challenged Expert withdraws or the other Parties agree to the challenge, the LCIA shall, within thirty (30) days, decide the challenge. If the challenge is sustained, the LCIA shall thereafter appoint a replacement Expert.

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(g) If the Expert is either unwilling or unable to accept such appointment or has not confirmed his willingness and ability to accept such appointment within the said period of fourteen (14) days, then either Party may request the LCIA to appoint another Person as the Expert and the process shall be repeated until an Expert is found who accepts appointment.

(h) The Parties shall cooperate with each other to ensure that the terms and conditions of the contract of appointment of the Expert are agreed with such Person as soon as possible.

19.3.2 Nature of Proceeding, Qualifications, and Confidentiality

(a) The Expert shall act as an expert and not as an arbitrator. The law relating to arbitration shall not apply to the Expert or his determination or the procedure by which he reaches his determination.

(b) The Expert Determination proceedings shall be conducted in the English language.

(c) The failure of any Party to participate in the Expert Determination or to comply with any of the requirements of this Article shall not prevent the Expert Determination from proceeding or impair the validity and enforceability of the Expert Determination.

(d) The determination of the Expert shall be final and binding upon the Parties, save in the event of fraud or manifest error.

(e) No Person shall be appointed as the Expert unless such Person shall be qualified by education, experience, and training to determine the Dispute.

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(f) No Person shall be appointed as the Expert who at the time of appointment is (or within two (2) Calendar Years before such appointment has been) a director, office holder or an employee of, or directly or indirectly retained as consultant to, either Party or any Affiliate of either Party or is the holder of shares directly or indirectly in a Party.

(g) Any Person appointed as the Expert shall not be entitled to act as the Expert and shall promptly resign, if, at the time of the appointment or at any time before giving any determination under such appointment, such Person has or may have some interest or duty which materially conflicts or may materially conflict with such Person’s function under such appointment.

(h) All information, data or documentation disclosed or delivered to the Expert in consequence of or in connection with the Expert’s appointment hereunder, shall be treated as confidential. Except for disclosure to technical or professional advisors under Article ‎19.3.3(a)(iii), the Expert shall not disclose to any Person any such information, data or documentation and all such information data and documentation shall remain the property of the Party disclosing or delivering the same and all copies thereof shall be returned on completion of the Expert's work.

(i) Copies of all submissions and communications shall be provided to the LCIA, and once appointed, to the Expert, and to all other Parties.

(j) The terms of appointment of the Expert shall contain an obligation on the part of the Expert to comply with such obligations as aforesaid.

19.3.3 Terms of Reference of the Expert

(a) The terms of reference of the Expert shall contain (inter alia) provisions that:

(i) the Expert shall not later than twenty-one (21) days after his appointment call the Parties to a meeting in Israel or such other place as the Parties may agree at which he shall raise any matters requiring clarification (whether arising out of his contract of appointment, the Dispute, or otherwise) and lay down the timetable and procedural rules to be applied, which timetable and rules shall not be inconsistent with the terms of this Article;

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(ii) the Parties shall be entitled and required to supply data, documentation, and information and make written submissions to the Expert as the Expert deems necessary and appropriate for determining the Dispute;

(iii) the Expert shall be entitled to obtain such independent professional and/or technical advice as he may reasonably require;

(iv) any and all communications between and submissions made by either of the Parties and the Expert shall be made in English in writing and a copy thereof provided simultaneously to the other Party. The Expert shall not engage in any ex parte communications with any of the Parties. No meeting between the Expert and the Parties or either of them shall take place unless both Parties have a reasonable opportunity to attend any such meeting;

(v) the Expert may adopt such procedures and may conduct the Expert Determination in such manner as he deems appropriate, consistent with the provisions of this Article. The Expert may hold an evidentiary hearing and require the Parties to attend and present evidence if he deems it reasonably necessary for the determination of the Dispute;

(vi) the Expert shall issue his Determination within ninety (90) days of his appointment, or as soon thereafter as reasonably practicable or the Parties may agree in writing. The Expert’s Determination shall be in writing and shall state the reasons therefore. The Expert shall provide to the Parties a draft of his proposed Determination in respect of which both Parties shall be entitled to respond and make representations to the Expert within twenty-one (21) days after receipt of the draft Determination; and

(vii) as soon as possible after the twenty-one (21) day period referred to in Article ‎19.3.3(a)‎(v), the Expert shall issue his final Determination.

(b) If the Expert fails or refuses to comply with the terms of reference or to timely issue the Determination, then the Dispute shall be submitted to arbitration as provided in Article ‎19.4.

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(c) Each Party shall bear the costs of providing all data, information and submissions given by it and the costs and expenses of all witnesses and Persons retained by it. The costs and expenses of the Expert and any independent advisers to the Expert shall be borne in the manner determined by the Expert and, failing such determination, one half by the Buyer and one half by the Sellers.

(d) Unless otherwise agreed by the Parties or as determined by the Expert, all meetings and hearings with the Expert shall be held in Israel.

19.4 Arbitration

19.4.1 Except as referred to an Expert as set forth in Articles ‎19.2 and ‎19.3, any Dispute shall be referred to and finally and exclusively resolved by arbitration in accordance with this Article ‎19.4.

19.4.2 Disputes relating to matters with an amount in controversy of less than (**) shall be determined by a single arbitrator, in accordance with the Rules of Arbitration of the Israeli Institute of Commercial Arbitration. The seat of the arbitration shall be (**).If the Parties do not agree that the amount in controversy does not exceed (**), or if the Dispute involves a claim for relief other than monetary relief, then the arbitration shall be heard and determined by a tribunal of three (3) arbitrators in accordance with the provisions of Article ‎19.4.3 or ‎19.4.4 (as applicable).

19.4.3 Disputes relating to matters with an amount in controversy of (**) or more, but less than (**) shall be heard and determined by a tribunal of three (3) arbitrators. The arbitration shall be conducted pursuant to the Rules of Arbitration of the London Court of International Arbitration ("LCIA Rules"). The seat of the arbitration shall be (**). If the Parties do not agree that the amount in controversy is less than (**), then the arbitration shall be heard and determined by a tribunal of three (3) arbitrators in accordance with the provisions of Article ‎19.4.4.

19.4.4 Disputes relating to matters with an amount in controversy of (**) or more shall be heard and determined by a tribunal of three (3) arbitrators. The arbitration shall be conducted pursuant to the LCIA Rules. The seat of arbitration shall be London, England.

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19.4.5 With respect to any Dispute, the amount in controversy shall be based upon the amount claimed in the proceeding in all claims in the aggregate, but with claims and counterclaims being counted separately, exclusive of interest or attorneys’ fees, and including the actual or potential value to the Parties of any matters for which a declaration of the meaning, effect, or application of any terms, rights, or obligations arising out of or relating to this Agreement is requested, or for which other non-monetary relief is sought.

19.4.6 If a single arbitrator is to determine the Dispute, the Parties shall endeavour to agree on the arbitrator. If the Parties are unable to agree on the arbitrator within thirty (30) days of the date for the Respondent’s Response to the request for arbitration, then the arbitrator shall be appointed by the Israeli Institute of Commercial Arbitration in accordance with its Rules. The arbitrator shall be qualified by experience and education to determine matters in the nature of the Dispute.

19.4.7 If the Dispute is to be determined by a tribunal of three (3) arbitrators, the Claimant(s) and Respondent(s) shall each nominate a person to serve as arbitrator as provided in the LCIA Rules. The two arbitrators so appointed and confirmed shall, within thirty (30) days of their confirmation or such other time as the Parties may agree in writing, nominate a third person as arbitrator, who upon confirmation shall serve as the Chair of the Tribunal. The arbitrators so appointed shall be qualified by education and experience to determine matters in the nature of the Dispute.

19.4.8 No person shall be appointed as an arbitrator under this Agreement if at the time of appointment he is (or within three (3) years before such appointment has been) a director, office holder, or an employee of, or directly or indirectly retained as consultant to, either Party or any Affiliate of either Party or is the holder of shares directly or indirectly in a Party.

19.4.9 Any person appointed as an arbitrator shall not be entitled to act as an arbitrator if, at the time of the appointment or at any time before giving the award under the arbitration, such person has or may have some interest or duty which materially conflicts or may materially conflict with his function under such appointment.

19.4.10 The arbitration proceedings shall be held as promptly as possible at such place in Israel or England (as applicable) (or other place agreed to by both Parties) and at such time as the arbitrator(s) shall determine.

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19.4.11 The Parties hereby waive any reference to the courts under Sections 45 and 69 of the Arbitration Act 1996, and under Sections 21A and 29B of the Israeli Arbitration Law – 1968 and the first supplement thereto.

19.4.12 All arbitration proceedings shall be conducted in and all awards rendered in the English language.

19.4.13 The arbitrator(s) shall not be bound by the rules of evidence and civil procedure. The arbitrators shall not act as amiable compositeur or ex aequo et bono.

19.4.14 The Award shall be final and binding upon the Parties, and shall be without right of appeal. Judgment on the award may be entered in any court having jurisdiction.

19.4.15 The Arbitral Tribunal has the power and authority to award actual money damages, and to award declaratory, injunctive, or mandatory relief, including ordering specific performance. Any award of monetary damages shall be made in U.S. dollars, and shall include interest thereon from the date of breach until paid. The arbitrators shall have no power to award, and the Award shall not include consequential, punitive, or other special damages.

19.4.16 The fees of the arbitrator(s) and costs incidental to arbitration proceedings, including legal expenses of the Parties, shall be borne in accordance with the determination of the arbitrator(s).

19.4.17 The Parties shall conduct the arbitration proceedings in a fair, efficient and expeditious manner.

19.4.18 Any arbitration rendered pursuant to this ‎Article 19 is an international arbitration for the purposes of Israeli law, English law, United States law, and the New York Convention on the Recognition and Enforcement of Foreign Arbitral Awards, 1958.

19.4.19 This Article constitutes an arbitration agreement between the Parties as defined in the Israeli Arbitration Law-1968.

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19.5 Jurisdiction

19.5.1 Subject to the above mentioned dispute resolution mechanism and the arbitration provisions set forth above in this Article, non-exclusive jurisdiction in respect of any matter relating to this Agreement shall be vested: (i) with respect to any Dispute pursuant to Articles ‎19.4.2 and ‎19.4.3 - in the competent courts of Tel Aviv – Jaffa; and (ii) with respect to any Dispute pursuant to Article ‎19.4.4 - in the courts of London, England.

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ARTICLE 20

Security and Credit Cover

20.1 Sellers’ Security

Dor Gas Exploration Limited Partnership (in this ‎Article 20, "Dor") shall provide and maintain Credit Cover for the benefit of the Buyer, as follows:

20.1.1 Dor shall, by October 1, 2013, provide the Buyer with a Credit Cover in the total amount of (**), which shall be maintained in force for the First Period to be increased within 30 Days from the commencement of the Second Period (if applicable) to an amount of (**), to be maintained until the end of the entire Contract Period.

20.1.2 In the event that Dor provides the Buyer with a Corporate Guarantee as its Credit Cover in any Contract Year, Buyer will be entitled to instruct Dor in respect of the following Contract Year, to replace the Corporate Guarantee with another type of Credit Cover (Bank Guarantee or Letter of Credit, at Dor's discretion) by written notice to Dor at least thirty (30) days prior to the latest date on which Credit Cover must be provided in respect of the following Contract Year in accordance with Article ‎20.1.1. Buyer's right to so instruct Dor will only apply in the following circumstances: (i) the guarantor under the Corporate Guarantee defaulted on any payment due under the Corporate Guarantee; or (ii) where there has been an adverse material change in the financial standing of the guarantor under such Corporate Guarantee which may reasonably be expected to impair such guarantor’s ability to make all payments under the Corporate Guarantee.

20.1.3 The Buyer shall be entitled to call on and draw down against the Credit Cover which is in the form of a Corporate Guarantee to the extent that, and at such time as, Dor has failed to meet its payment obligations in respect of all amounts which Dor owes to Buyer pursuant to this Agreement. The Buyer shall give Dor notice of not less than fourteen (14) days of its intention to call on and draw down against the Credit Cover (any such Corporate Guarantee) provided by Dor.

20.1.4 Dor may at anytime during the Contract Period choose to replace the Corporate Guarantee with any other type of Credit Cover (Bank Guarantee or Letter of Credit, at Dor's sole discretion) by written notice to the Buyer at least 30 (thirty days) prior to the latest date on which Credit Cover must be provided in respect of following Contract Year.

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20.1.5 The Buyer shall be entitled to draw down against Credit Cover which is in the form of a bank guarantee or a letter of credit to the extent that, and at such time as, Dor has failed to meet its payment obligations in respect of undisputed amounts or amounts determined under ‎Article 19 (whether in whole or in part) under this Agreement. The Buyer shall give to Dor a notice of not less than seven (7) days of its intention to draw down against any such Credit Cover provided by Dor.

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ARTICLE 21

Relationship and Sellers’ Coordinator

21.1 Relationship of Sellers

21.1.1 The Sellers are acting jointly in relation to matters such as the development of the Reservoir, the Sellers’ Facilities and the production, transportation and delivery of Specification Gas under this Agreement (and acting through the Sellers’ Coordinator in the circumstances set out in Article ‎21.2), but it is acknowledged by the Buyer (notwithstanding that this Agreement is entered into by all the Sellers with the Buyer) that nothing in this Agreement shall be deemed to constitute as between the Sellers any joint liability and each of the Sellers shall be liable to the Buyer only in respect of its Seller’s Percentage of such liability of Sellers as may arise under this Agreement.

21.1.2 Notwithstanding that the Buyer may make nominations for the delivery of Specification Gas under this Agreement in an aggregate nomination in a single notice delivered to the Sellers’ Coordinator pursuant to Article ‎21.2.1, the quantity deemed to have been nominated for delivery by each Seller shall be its respective Seller’s Percentage of the aggregate quantity so nominated.

21.1.3 The quantity of Specification Gas deemed to have been delivered at the Delivery Point by each of the Sellers in respect of each Hour shall be its respective Seller’s Percentage of the aggregate quantity of Specification Gas delivered by the Sellers at the Delivery Point in response to the Buyer’s nomination. To the extent that such aggregate quantity falls short of the Proper Nomination, such shortfall shall be attributed to each of the Sellers in proportion to its respective Seller’s Percentage.

21.2 Sellers’ Coordinator

21.2.1 The Sellers hereby appoint Noble Energy Mediterranean Ltd. as their representative (herein called the "Sellers' Coordinator", which expression shall include any successor appointed as provided herein) who shall be authorized to and shall act as the representative for the Sellers under this Agreement for the following purposes (provided that the authority hereby given to the Sellers' Coordinator relating to the giving of notices, nominations, statements and estimates shall not preclude the Sellers from giving any notices, nominations, statements and estimates which are within the scope of such authority):

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(a) the giving and receiving of all notices, nominations, estimates, and requests, provided that such authority shall not extend to a notice of termination of this Agreement;

(b) the giving and receiving of all financial and other statements, reports and information hereunder;

(c) the making and witnessing of the measurement and testing of Specification Gas delivered to the Buyer under this Agreement and of the measuring equipment and adjustments to such equipment; and

(d) the settling with the Buyer of all disputes or differences between the Parties hereunder:

(i) in relation to the applicable DCQ;

(ii) arising under ‎Article 15 or in relation to the volume and/or Higher Heating Value of Gas delivered in any Hour to the Buyer hereunder;

(iii) arising under ‎Article 12; and

(iv) as to whether the Sellers are entitled to relief under ‎Article 16 in respect of any underdelivery of Gas to the Buyer in any Hour.

21.2.2 The Sellers agree that the Buyer shall be entitled to act upon any or all acts or things done or performed or nominations, notices or statements given or received or agreements made from time to time in respect of the above matters or within the scope of its authority by the Sellers' Coordinator as fully and effectively as though the Sellers had themselves done or performed the same.

21.2.3 The Sellers may at any time change the Sellers' Coordinator provided that at all times during the Contract Period a Sellers' Coordinator is appointed. The Sellers shall notify the Buyer of any change of the Sellers' Coordinator.

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21.2.4 In the event that the Buyer considers the Sellers to be in breach of this Agreement as a result of an alleged failure of the Sellers' Coordinator to perform its duties described in this Agreement, the Buyer shall give the Sellers notice thereof and also give the Sellers a period of sixty (60) days to enable the Sellers to rectify or cause to be rectified the alleged breach before the Buyer institutes any legal proceedings in respect thereof.

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ARTICLE 22

Immunity

22.1 Immunity

Each of the Parties is subject to civil and commercial law with respect to its obligations under this Agreement, and the signing and performance of this Agreement by such Party constitute private and commercial acts rather than governmental and public acts. Each of the Parties irrevocably represents, warrants and agrees that this Agreement is a commercial rather than a public or governmental activity and that each such Party is not entitled to claim immunity from legal proceedings with respect to itself or any of its assets on the grounds of sovereignty or otherwise under any law or in any jurisdiction where an action may be brought for the enforcement of any of the obligations arising under or relating to this Agreement. To the extent that any of the Parties or any of their assets has or hereafter may acquire any right to immunity from set-off, legal proceedings, attachment prior to judgment, other attachment or execution of judgment on the grounds of sovereignty or otherwise, such Party irrevocably waives such rights to immunity in respect of its obligations arising under or relating to this Agreement.

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ARTICLE 23

Miscellaneous Provisions

23.1 Performance of Obligations

Each Party shall be entitled to perform any of its obligations under this Agreement by procuring that such obligations are performed on its behalf by a third party, but such Party shall remain responsible to the other for the due performance of such obligations and for any failure or non-performance of such third party or any operator agents contractors or employees of such third party, as if such Party itself had failed to fulfill the relevant obligations.

23.2 Waiver

No waiver by any Party of any default or defaults by the other in the performance of any of the provisions of this Agreement shall operate or be construed as a waiver of any other or further default or defaults, whether of a like or different character.

23.3 Successors

This Agreement shall bind and inure to the benefit of the Buyer and each of the Sellers and their respective successors and permitted assigns.

23.4 Notices

23.4.1 Any notice to be given by one Party to another under this Agreement shall be in writing and shall be delivered by hand to the Party in question or sent to such Party by registered delivery, letter or facsimile or electronic transmission addressed to that Party at such address (or as the case may be, such facsimile transmission number or electronic mail address) as the Party in question may from time to time designate by written notice.

23.4.2 Until such notice shall be given, the addresses of the Parties shall be those which appear in this Agreement.

23.4.3 All notices delivered by recorded delivery or hand or sent by facsimile or electronic transmission shall be deemed to be effective when received at the recipient's address as aforesaid.

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23.4.4 Any notice (other than routine notices and communications) given or facsimile or electronic transmission shall, unless already acknowledged, be subsequently confirmed by letter sent by registered delivery or delivered by hand, but without prejudice to the validity of the original notice, if received.

23.5 Entirety

This Agreement shall constitute the entire agreement between the Parties as to the matters addressed herein and shall supersede and take the place of all documents, minutes of meetings, letters or notes which may be in existence at the date hereof, and of all written or oral statements, representations and warranties which may have been made by or on behalf of the Parties as to such matters.

23.6 Survival

The provisions of Article ‎8.5, ‎Article 11 (to the extent necessary to finalize accounts) and ‎Article 19 shall survive the termination of this Agreement.

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IN WITNESS of their agreement, each of the Parties have caused their respective duly authorized representative to sign this instrument in Tel Aviv, on March 14, 2012.

THE ISRAEL ELECTRIC CORPORATION LIMITED Name: Eli Glickman Title: President & CEO /s/ Eli Glickman Name: Harel Blinde Title: Senior Vice President & CFO /s/ Harel Blinde	NOBLE ENERGY MEDITERRANEAN LTD. Name: Lawson Freeman Title: Vice President /s/ Lawson Freeman
AVNER OIL EXPLORATION LIMITED PARTNERSHIP Avner Oil and Gas Limited, General Partner Name: Gideon Tadmor Title: CEO & Director /s/ Gideon Tadmor Name: Gabriel Last Title: Director /s/ Gabriel Last	DELEK DRILLING LIMITED PARTNERSHIP Delek Drilling Management (1993) Ltd., General Par­­­tner Name: Gideon Tadmor Title: Chairman /s/ Gideon Tadmor Name: Yossi Abu Title: CEO /s/ Yossi Abu
ISRAMCO NEGEV-2 LIMITED PARTNERSHIP Isramco Oil and Gas Ltd., General Partner Name: Avi Geffen Title: CEO /s/ Avi Geffen	DOR GAS EXPLORATION LIMITED PARTNERSHIP Alon Gas Exploration Management Ltd. General Partner Name: Eli Misgav Title: CEO /s/ Eli Misgav Name: Zvi Greenfeld /s/ Zvi Greenfeld

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SCHEDULE 1

Sellers' Petroleum Rights

Petroleum Lease I/12 "Tamar" granted on December 2, 2009 pursuant to section 26 of the Petroleum Law, 5712-1952.

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SCHEDULE 2

Seller’s Percentages and Sellers’ Interest

Noble Energy Mediterranean Ltd.	36.000	%
Delek Drilling Limited Partnership	15.625	%
Avner Oil Exploration Limited Partnership	15.625	%
Isramco Negev2 Limited Partnership	28.750	%
Dor Gas Exploration Limited Partnership	4.000	%
Total	100.000	%

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SCHEDULE 3

Sellers' Agreements

Joint Operating Agreement dated November 16, 1999, as amended, governing Sellers' Petroleum Rights

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SCHEDULE 4

List of Charges on Sellers' Petroleum Rights

1. Delek Drilling Limited Partnership hereby warrants and represents to the Buyer that as of the Effective Date, (**).

2. Avner Oil Exploration Limited Partnership hereby warrants and represents to the Buyer that as of the Effective Date, (**).

3. Dor Gas Exploration Limited Partnership hereby warrants and represents to the Buyer that as of the Effective Date, (**).

4. Isramco Negev-2 Limited Partnership hereby warrants and represents to the Buyer that as of the Effective Date, (**).

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SCHEDULE 5

Part 1

Specification for Gas Quality

Natural Gas tendered for delivery under this Agreement shall at the Delivery Point comply with the following requirements and the requirements of the Transporter as at the date of this Agreement.

1. Gas made available for transport shall be free from odors, foreign materials, dust or other solid and liquids, waxes, gums and gum forming constituents. The Sellers shall furnish, install, maintain and operate such drips, separators, heaters and other devices as the Seller may deem necessary or desirable to effect compliance with this requirement

2. For the avoidance of doubt, it is agreed that the Sellers may (acting as a Reasonable and Prudent Operator) inject substances while processing the Natural Gas provided that the Sellers are able to and do, in fact, remove all of such substances prior to the Delivery Point until the gas meets the current specification. On Buyer's request, the list of treatment substances shall be made available to the Buyer. If the Sellers fail to so comply, the Buyer may at any time require the Sellers to cease injection of such substances.

3. Without prejudice to the generality of the provisions of Paragraph 1 & 2 above, gas at the Delivery Point shall conform to the parameters of Table 1.

4. Sampling: Sampling of natural gas for continuous automatic and periodic laboratory analysis shall be in accordance with ISO 10715.

No material may be added to the stream being tested which will alter the tests results or cause the test to be non-representative of the moisture or liquefiable hydrocarbon content of the stream being tested.

5. Gas Chromatography, Energy Calculations & Reports: Natural gas composition shall be continuously monitored using a gas-chromatograph measuring up to at least C6-plus and compatible with ISO 6974-5. Gas analysis shall be used for further calculations of gas mixture molecular weight, Higher Heating value, density, compressibility, energy & Wobbe Index at reference conditions and at actual line conditions (according to relevancy). Physical properties used to configure chromatographs and perform calorific value and relative density calculations shall be derived from the latest version of GPA Standard 2145/ISO 6976

Gas analysis shall be used for further calculations at the Metering Line Flow Computer:

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· Gas density at Standard Conditions shall be calculated in accordance with AGA Report No.8:1994/ISO-12213-1:1997

· Gas density at Line Conditions shall be calculated in accordance with AGA Report No.8:1994/ISO-12213-1:1997

6. The heating value of C6 shall be applied for all C6-plus compounds as long as laboratory measurements justify this simplicity. The Buyer shall be notified at any change.

7. Calorific value in MJ/m3 units shall be reported to the 2nd decimal. A factor of 1055.056 MJ/MMBTU shall be used for unit conversion (AGA Report No. 8 & GPA 2172). Values in MMBTU/m3 shall be reported to the 5th decimal figure. (Wobbe index shall be reported accordingly). Compression factor, density and relative density shall be reported (If required) to the 4th decimal figure.

8. Average values of continuously measured parameters in Table 1 shall be reported daily. Intermittent measurements shall be reported after completion.

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Table 1: Parameters limits

Parameter	Requirement	Units	Methods & Remarks
Water Dew Point (WDP) At any pressure up to and including 80 bar (g)	≤ 0 (Zero)	( oC )	(a)
Hydrocarbon Dew Point (HCDP) At any pressure up to and including 80 bar(g)	≤ 5	( oC )	(b)
Total Sulphur (as S)	< 100	(ppm Weight)	(c)
Hydrogen Sulphide (as H2S)	< 5	(ppm Volume)	(d)
Carbon Dioxide	≤ 3.0	(Mole percent)	(e)
Total Inerts [N2+CO2+Ar]	≤ 5.0	(Mole percent)	(f)
Oxygen	≤ 0.01	(Mole percent)	(g)
Methane	≥ 92	(Mole percent)	(h)
Glycol	No free liquid to be present in gas at Delivery Point	--	(i)
Methanol	≤ 100	(ppm volume)	(j)

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Table 1 (cont.): Parameters limits

Parameter	Requirement	Units	Methods & Remarks
Higher Heating Value @ 15/15 oC & 101.325 Kpa	0.03460 - 0.03950	MMBTU/Cubic Meter	(k)
Wobbe Index @ 15/15 oC & 101.325 Kpa	0.04620 - 0.05090	MMBTU/Cubic Meter	(l)
Supplied gas temperature	5 – 38 But at least 10.0 oC above the actual WDP at least 5.0 oC above the actual HCDP and at least 10.0 oC at the PRMS Eshkol inlet	( oC )	--
Pressure	60-80 Seller shall supply sufficient pressure to allow nominated gas volumes to enter the INGL, transportation system, subject to the maximum pressure not exceeding 80 bar at the Delivery Point.	bar(a)	--

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Methods & Remarks

a) Water Dew Point (WDP)

Moisture shall be measured continuously according to ASTM D 5454 - using a water concentration analyzer. The sensor should operate at a fixed controlled temperature greater than the maximum gas stream temperature. The gas sample stream should operate at a controlled pressure no greater than 3 bar (g). Calculation of WDP from the measured water concentration shall be based on equations (or commercial calculators) which produce results that are in agreement with the data given in table C.1 of appendix C to ISO 18543:2004; Natural gas — Correlation between water content and water dew point. Direct measurement of WDP according to ISO 6327-1981 (E) is permitted. Manual measurement according to ASTM D 1142 (chilled mirror) shall be the reference method.

b) Hydrocarbon Dew Point (HCDP)

HCDP shall be measured continuously by a chilled mirror instrument working in pressure ranges of 28 ± 3 bar(g), capable of measuring HCDP up to +20 deg C. Manual measurement according to ASTM D 1142 shall be the reference method.

Gas chromatographic laboratory analysis complying with ISO 23874 (and measuring until C12) may serve for research purposes.

c) Total Sulfur and Sulfur species.

Total Sulfur shall be analyzed quarterly in a certified laboratory during the first year of supply. Sulfur species concentrations shall be identified and compared with the concentration of total sulfur. After typical values are determined and no corrosive sulfur is present - then the frequency can be lowered (twice a year in the second year and annually afterwards).

If, however, concentrations greater than 6 mg/m3 of COS or RHS or any corrosive sulfur species (as S) shall be found at any time then total Sulfur shall be measured continuously using an ASTM standard (ASTM D7493 or ASTM D7165 – 10).

A full laboratory Sulfur species analysis shall be performed with any significant change of gas quality.

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d) Hydrogen Sulphide

H2S shall be continuously monitored by automatic instruments complying with ASTM D4084 (Lead acetate reaction rate method).

 e, f & g) Oxygen and Total Inerts (N2+CO2+Ar)

N2, O2, Ar & CO2 shall be continuously measured by a GC with a lower detection limit not greater 0.005 % mole, using Helium as a carrier and a suitable column to split N2 and O2.

The limiting value for Oxygen in Table 1 is required during normal operations. Higher values are allowed during commissioning of new pipelines. Such values and durations of irregularity shall be agreed upon by all parties before commissioning.

h) Methane

Methane (and all typical natural gas components) shall be continuously monitored by GC according to ISO 6974-5. The limiting values of Table 1 are valid for the normal routine.

i) Glycol

No free liquid glycol shall be detected while determining the water and/or hydrocarbon dew point using the Bureau of Mines/chilled mirror device.

j) Methanol

Analysis for methanol content will only be required during periods when methanol is being injected for operational reasons. Buyer will be advised when used. Methanol content will be determined using a mutually agreed procedure. .

k) Higher Heating Value

Higher Heating Value - means the superior calorific value calculated as described in ISO: 6976:1995 (E) of one Cubic Meter of Natural Gas at the reference condition of 15/15 Degrees Celsius and 1.01325 Bar(a) for the actual natural gas in the real state. Full precision, definitive mode shall be used.

l) Wobbe Index

Wobbe Index shall be calculated according to ISO: 6976:1995(E) at the reference condition of 15/15 Degrees Celsius and 1.01325 Bar (a) for the actual natural gas in the real state.

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SCHEDULE 5

Part 2

Specification for Measurement

Measurements Codes & Specifications

Measuring devices shall be installed in accordance with the latest edition (at the time of installation) of American Gas Association standards AGA 7, AGA 8, AGA 9, AGA 10, and API 21.1. Chemical analyses shall be performed in accordance with ASTM, GPA or ISO/European equivalent mentioned in this document.

Measurement System

1. The measurement system shall be designed with sufficient redundancy (3x50 %) such that the failure of a single meter run does not shut down the whole measurement system. Each of these meter runs shall incorporate a single turbine meter and a single multipath ultrasonic meter in series in full compliance with above listed standards.

Double block and bleed valves shall be provided upstream and downstream of each meter run to allow switching from one run to another without compromising measurement performance and to ensure no gas bypasses the intended meter runs.

2. Each custody transfer meter run shall also include adequate flow conditioning meeting manufacturers' recommendations and the recommendations of the appropriate AGA standard. Flow conditioning must also eliminate the possibility of one meter affecting the performance of the other meter in series.

3. Each measurement system shall include an on-stream analyzer (gas chromatograph) and its associated sampling, calibration and carrier gas equipment. Where significant ultrasonic noise exists, “U” shaped piping shall be included upstream and downstream of the ultrasonic meter to isolate the meter from the noise.

 “Significant” noise shall be as defined in AGA Report No. 9, meaning noise levels sufficient to degrade meter performance significantly.

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4. The primary components of the metering system, turbine meter, and ultrasonic meter, flow computer and gas chromatograph, should have approval for custody transfer by Nederlands Meetinstituut (NMi) or equivalent

5 The entire system must meet appropriate standards reflecting the area classification for the skid location, but Class 1 Group D Division II at a minimum.

6. The meters should be operated within the manufacturers recommended specific flow range and operating conditions to achieve the desired accuracy and normal life time.

7. The Sellers shall submit lists of selected equipment, drawings, standards and certifications of the selected equipment for measuring at the delivery points.

8. Seller shall nominate which volume metering device is to be utilised as the primary device (for custody transfer) and which device is to be utilised as the secondary (check) device.

9. Total measurement uncertainty of energy shall be +/-1% and shall be calculated according to ISO 5168.

The seller shall demonstrate that the metering system meets the agreed upon total uncertainty and the individual total uncertainties of the separate components.

Calibration

1. Each meter shall be flow certified prior to final delivery to Israel by an internationally recognized flow facility. During certification, the entire engineered meter run assembly shall be certified, at high pressure, in the exact configuration as the final installed configuration.

The Sellers shall invite the Buyer and the Transporter to witness onsite calibrations and/or verification of measurements by giving seven days notice, and shall make necessary arrangements for the participation of the Buyer/ Transporter or their formal representative.Buyer and Transporter will be responsible for all costs associated with the attendance of their personnel or representatives.

2. Once in normal operation, turbine meters will need to be recertified whenever their performance is suspect, whenever they fail spin tests or whenever they have been repaired. Ultrasonic meters are not generally recertified unless internal physical dimensions or transducer types are altered.

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3. The results of the flow certifications and instrument calibrations shall be available upon request, together with a statement of conditions under which the calibration took place.

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Calibration Intervals

Ultrasonic meters	Not required unless internal dimensions and/or transducer type changes
Spin tests for turbine meters	Not required unless the comparison between the Ultrasonic and Turbine meters exceeds ½% and no other solution can be identified.
Turbine meters proving	Not required when in series with USM
Flow tests at traceable flow labs (turbine meters)	Every 16 years
Flow computers	Quarterly
Pressure and Temperature Measuring Device	Quarterly
Difference between ultrasonic meter and the turbine meter in series	Collected continuously & reported quarterly. Difference of greater than 1/2% shall be reported within 7 days, differences greater than 1% will also require a plan for remediation to be submitted by the Seller’
Gas chromatographs	Daily - By local automatic reference gas mixture. Quarterly - By analysis of a reference gas mixture (not in current use as calibration). All reference gas mixtures shall be certified by an accredited calibration laboratory.
Moisture analyzer	Monthly
HCDP analyzer	Monthly
H2S analyzer	Monthly

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4. Calibration procedures shall be updated for new installation and transmitted to the Buyer and the Transporter. A report shall be sent to the Buyer and the Transporter following every calibration.

Requirements for Off-Line measurements

1. Verification of the accuracy of online chemical parameter measurements (from which physical property are determined) shall be carried out according to the instructions of the instrument's manufacturers. Where such instructions are missing or where they are found to be not sufficient, then by means of laboratory analysis of samples taken at appropriate time intervals and at least Quarterly (and where statutory requirements exist according to such requirements). In the event of discrepancy between the online facilities and the laboratory analysis, the measurement equipment shall be recalibrated. Shippers, Sellers and Transporters shall be notified should the discrepancy force a change in future or previous calculations of +/- 1/4% or greater.

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SCHEDULE 6

CORPORATE GUARANTEE

(date)

The Israel Electric Corporation Limited

…………………………………………

…………………………………………

1. At the request of [Dor Gas Exploration Limited Partnership] ("Debtor") we Alon Natural Gas Exploration Ltd. ("the Guarantor") hereby unconditionally and irrevocably guarantee the payment to the Israel Electric Corporation Limited ("IEC") of all amounts which the Debtor owes to IEC pursuant to the Gas Sale and Purchase Agreement dated [insert date] between the Debtor and others and IEC ("GSPA"), up to the total sum of [insert amount] in the aggregate (“Guarantee Amount") including without limitation amounts payable pursuant to the GSPA as damages in the event of a breach by the Debtor of any obligation under the GSPA. We confirm that we are familiar with the terms of the GSPA.

2. Accordingly, we hereby undertake to pay IEC within seven (7) banking days any amount, not exceeding in the aggregate the Guarantee Amount, due to IEC from the Debtor pursuant to the GSPA which IEC claims from us from time to time, but prior to the Expiry Time, by written demand substantially in the form set out in Appendix A ("Payment Demand"). Except for the Payment Demand, IEC will not be required to provide any proof or other justification to its claim hereunder or to substantiate its demand in any way nor will it be required to first seek payment of the amount claimed from the Debtor or any other person.

3. The obligations and liability of the Guarantor hereunder shall in no way be discharged, impaired or otherwise affected by the following (without limitation):

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a. any amendment to the GSPA, or any compromise, variation, total or partial release, discharge or waiver of any obligations under the GSPA (save, for the removal of doubt, the right to assert any defense which may be available to Debtor);

b. failure to make prior demand on the Debtor or any other guarantors or to proceed against the Debtor in any legal, judicial or arbitral forum or failure to enforce or seek to enforce any other security taken in respect of the Debtor’s obligations under the GSPA, before proceeding against the Guarantor to enforce or collect under this Guarantee;

c. bankruptcy, insolvency, merger, administration, reorganization, liquidation, arrangement with creditors or any similar act, event or proceedings affecting the Debtor, or any change in Debtor’s status, function, control or ownership;

d. arrangements entered into between IEC and any other creditors of the Debtor;

e. failure by IEC to give notice to the Guarantor of the occurrence of any of the events detailed in this clause 3; or

f. any failure to realize or fully to realize the value of, or any release, discharge, exchange or substitution of, any security taken in respect of Debtor’s obligations under the GSPA.

4. Without derogating from any other provisions of this guarantee which exclude the application of, or constitute a waiver by the Guarantor, of certain defenses or rights under the Israel Guarantee Law, 1967 (“the Guarantee Law”) (which defenses or rights would, but for such provision, have been available to the Guarantor), the Guarantor hereby waives all rights and defenses under the Guarantee Law (save, for the removal of doubt, the right to assert any defense which may be available to Debtor under the GSPA) and confirms that the provisions of the Guarantee Law affording such rights or defenses to a guarantor shall not apply to this guarantee.

Notwithstanding anything to the contrary or otherwise contained in this Guaranty, it is hereby expressly stipulated that the Guarantor's total liability hereunder shall be subject to the limitations of liabilities applicable to the Debtor included in Article ‎Article 17 of the GSPA.

129

5. This Guarantee shall not be terminated by the dissolution, merger, reorganization or consolidation of the Guarantor, or the sale of any assets of the Guarantor, but shall be binding upon it and its successors and shall inure to the benefit of IEC and its successors.

6. The Guarantor represents and undertakes that:

a. the execution, delivery and performance of this Guarantee by the Guarantor will not cause the Guarantor to be in breach of or default under any law it is subject to, or under any agreement binding on it or any of its assets and no material litigation or administrative proceeding before, by or of any court or governmental authority is pending or (so far as the Guarantor is aware) threatened against it or any of its assets;

b. the Guarantor is a company limited by shares, duly incorporated under the laws of the State of Israel with power to enter into this Guarantee and to exercise its rights and perform its obligations hereunder and all corporate and other actions required to authorize its execution of this Guarantee and the performance by it of its obligations hereunder have duly been taken;

c. the obligations of the Guarantor under this Guarantee are legal and valid obligations binding on the Guarantor and enforceable in accordance with the terms hereof;

d. the entering into of this Guarantee by the Guarantor and the exercise of the Guarantor’s rights and performance of the Guarantor’s obligations hereunder do not and will not: (a) conflict with any agreement, charge or other instrument or document to which it is a party or which is binding upon it or any of its assets, (b) conflict with its documents of incorporation or constitutive documents, or (c) conflict with any applicable law, regulation or official judicial order;

130

7. This Guarantee is not assignable or transferable by Guarantor or IEC except together with an assignment of the GSPA and in accordance with its terms. In the event of Assignment of Buyer's rights and obligations in accordance with the provisions of the GSPA, this Guarantee will inure to the benefit of said permitted assignees of Buyer.

8 This Guarantee shall be binding upon and inure solely to the benefit of IEC or its assignees under section 7 above, and nothing in this Guarantee, express or implied, is intended to or shall confer upon any other person any right, benefit or remedy of any nature whatsoever under or by reason of this Guarantee.

9. This Guarantee shall be governed by Israeli Law and the courts of Israel shall have exclusive jurisdiction in all matters arising therefrom and the Guarantor hereby submits irrevocably to the jurisdiction of the said courts.

10. This Guarantee constitutes the entire agreement between the parties and supersedes and replaces any prior written or oral agreement, representations or undertaking between them relating to the subject matter of this Guarantee. Any addition or amendment to this Guarantee shall not be effective unless in writing and signed by the Parties’ authorized signatories.

11. This Guarantee shall remain in force from the date hereof until noon on [--] ("Expiry Time"), whereupon this Guarantee shall expire and become null and void and have no further force or effect. Any Payment Demand must be delivered to Guarantor at the above address of our branch, by not later than the Expiry Time. Any Payment Demand submitted to us after the Expiry Time will not be entertained. For the removal of doubt, notwithstanding anything to the contrary in this Article 11, in event that a Payment Demand is submitted prior to the Expiry Time, this guarantee shall remain in full force and effect in respect of such Payment Demand.

IN WITNESS WHEREOF, Signed in ____ this __ day of _____ in the year ______

(parent)

131

Appendix A

Form of Payment Demand

THE ISRAEL ELECTRIC CORPORATION LIMITED

Messrs.

………..[the Guarantor]……..

…………………………

Re: Payment Demand pursuant to your Guarantee

No. …..……… (the "Guarantee") dated ………………

I THE UNDERSIGNED the Chief Executive Officer [or Chief Financial Officer], of Israel Electric Corporation Limited (“IEC”) hereby demand payment on behalf of IEC of the sum of ___________ US Dollars (US$ _________) under the above Guarantee.

I hereby confirm and certify that –

(i) the above amount claimed by IEC in this Payment Demand is due and payable to IEC by the Debtor under the Gas Sale and Purchase Agreement dated [--] between the Debtor and others and IEC (the “GSPA”); and

(ii) IEC has given the Debtor not less than fourteen (14) days written notice of its intention to demand payment of the above amount under the Guarantee in accordance with Article 20.1.3 of the GSPA.

SIGNED, this ____ day of _________, in the year _________

By: _____________________________________________

CEO / CFO of the Israel Electric Corporation Limited

132

SCHEDULE 7

Form of Bank Guarantee

           (bank)

          (date)

The Israel Electric Corporation Limited

…………………………………………

…………………………………………

Gentlemen:

Bank Guarantee No. ………………….

1.           At the request of [[Dor Gas Exploration Limited Partnership] ("Debtor") we hereby unconditionally and irrevocably guarantee the payment to The Israel Electric Corporation Limited ("IEC") of all amounts which the Debtor owes to IEC pursuant to the Gas Sale and Purchase Agreement dated [insert Date] between the Debtor and others and IEC ("GSPA"), up to the total sum of [insert Amount] in the aggregate (“Guarantee Amount").

2.           Accordingly, we hereby undertake to pay IEC within [seven (7)] banking days any amount, not exceeding in the aggregate the Guarantee Amount, which IEC claims from us from time to time, but prior to the Expiry Time, by written demand substantially in the form set out in Appendix A ("Payment Demand"). Except for the Payment Demand, IEC will not be required to provide any proof or other justification to its claim hereunder or to substantiate its demand in any way nor will it be required to first seek payment of the amount claimed from the Debtor or any other person.

3.           This Guarantee is not assignable or transferable.

133

4.           This Guarantee shall be governed by Israeli Law and the courts of Israel shall have exclusive jurisdiction in all matters arising therefrom.

5.           This Guarantee shall remain in force from the date hereof until noon on [_________] ("Expiry Time"), whereupon this Guarantee shall expire and become null and void and have no further force or effect. Any Payment Demand must be delivered to us at the above address of our branch, by not later than the Expiry Time. Any Payment Demand submitted to us after the Expiry Time will not be entertained.

IN WITNESS WHEREOF, Signed in ____ this __ day of _____ in the year ______

(bank)

134

Appendix A

Form of Payment Demand

THE ISRAEL ELECTRIC CORPORATION LIMITED

Messrs.

………..[the bank]……..

…………………………

Re:  Payment Demand pursuant to your Bank Guarantee

No. …..……… (the "Guarantee") dated ………………

I THE UNDERSIGNED the Chief Executive Officer [or Chief Financial Officer], of Israel Electric Corporation Limited (“IEC”) hereby demand payment on behalf of IEC of the sum of ___________ US Dollars (US$ _________) under the above Guarantee.

I hereby confirm and certify that –

(i)           the above amount claimed by IEC in this Payment Demand is undisputed and is due and payable to IEC by the Debtor under the Gas Sale and Purchase Agreement dated [Insert Date] between the Debtor and others and IEC (the “GSPA”), or has been determined as due to IEC pursuant to Article 19 of the GSPA, and is unpaid as of the time that this Payment Demand is delivered to you; and

(ii)           IEC has given the Debtor not less than seven (7) days written notice of its intention to demand payment of the above amount under the Guarantee in accordance with Article 20.1.5 of the GSPA.

SIGNED, this ____ day of _________, in the year _________

      By: _____________________________________________

CEO / CFO of The Israel Electric Corporation Limited

135

SCHEDULE 8

Form of Letter of Credit

SAMPLE

THE ISRAEL ELECTRIC CORPORATION LIMITED

(full address)

DEAR SIRS,

RE: IRREVOCABLE STANDBY LETTER OF CREDIT NO. (insert number)

AT THE REQUEST OF [DOR GAS EXPLORATION LIMITED PARTNERSHIP] (“DEBTOR”) WE, (full name and address of issuing bank), HEREBY ISSUE OUR IRREVOCABLE STANDBY LETTER OF CREDIT NO……. IN YOUR FAVOUR TO GUARANTEE THE PAYMENT TO THE ISRAEL ELECTRIC CORPORATION LIMITED (‘IEC”) OF ALL AMOUNTS WHICH THE DEBTOR OWES TO IEC PURSUANT TO THE GAS SALE AND PURCHASE AGREEMENT DATED [insert date] BETWEEN THE DEBTOR AND OTHERS AND IEC (“GSPA”), UP TO THE TOTAL SUM OF [USD ___________] (US DOLLARS _________ MILLION) IN THE AGGREGATE (“GUARANTEE AMOUNT”).

ACCORDINGLY, WE (full name of issuing bank), HEREBY UNDERTAKE TO PAY IEC WITHIN FOURTEEN (14) BANKING DAYS ANY AMOUNT, NOT EXCEEDING IN THE AGGREGATE THE GUARANTEE AMOUNT, WHICH IEC CLAIMS FROM US FROM TIME TO TIME, BUT PRIOR TO THE EXPIRY TIME, BY WRITTEN DEMAND AS FOLLOWS:

QUOTE

THE ISRAEL ELECTRIC CORPORATION LIMITED

SRS.

___________(Full name and address of the issuing bank)

136

RE: PAYMENY DEMAND PURSUANT TO YOUR STANDBY LETTER OF

       CREDIT NO…  DATED…

I THE UNDERSIGNED THE CHIEF EXECUTIVE OFFICER (OR CHIEF FINANCIAL OFFICER), OF THE ISRAEL ELECTRIC CORPORATION LIMITED (“IEC”) HEREBY DEMAND PAYMENT ON BEHALF OF IEC OF THE SUM OF US DOLLARS (US $……………….) UNDER THE ABOVE STANDBY LETTER OF CREDIT.

I HEREBY CONFIRM AND CERTIFY THAT –

(I)           THE ABOVE AMOUNT CLAIMED BY IEC IN THIS PAYMENT DEMAND IS UNDISPUTED AND IS DUE AND PAYABLE TO IEC BY [DOR GAS EXPLORATION LIMITED PARTNERSHIP] (the “DEBTOR”) UNDER THE GAS SALE AND PURCHASE AGREEMENT DATED [insert date] BETWEEN THE DEBTOR AND OTHERS AND IEC (“GSPA”), OR HAS BEEN DETERMINED AS DUE TO IEC PURSUANT TO ARTICLE 19 OF THE GSPA, AND IS UNPAID AS OF THE TIME THAT THIS PAYMENT DEMAND IS DELIVERED TO YOU; AND THAT

(II)           IEC HAS GIVEN THE DEBTOR NOT LESS THAN SEVEN (7) DAYS WRITTEN NOTICE OF ITS INTENTION TO DEMAND PAYMENT OF THE ABOVE AMOUNT UNDER THE STANDBY LETTER OF CREDIT IN ACCORDANCE WITH ARTICLE 20.1.5 OF THE GSPA.

SIGNED, THIS_____ DAY OF_____, IN THE YEAR_____

BY: __________________________________________________________

      CEO/CFO OF THE ISRAEL ELECTRIC CORPORATION LIMITED

END QUOTE

137

EXCEPT FOR THE PAYMENT DEMAND IEC WILL NOT BE REQUIRED TO PROVIDE ANY PROOF OR OTHER JUSTIFICATION TO ITS CLAIM HEREUNDER OR TO SUBSTANTIATE ITS DEMAND IN ANY WAY NOR WILL IT BE REQUIRED TO FIRST SEEK PAYMENT OF THE AMOUNT CLAIMED FROM THE DEBTOR OR ANY OTHER PERSON.

THIS STANDBY LETTER OF CREDIT IS NEITHER ASSIGNABLE NOR TRANSFERABLE.

THIS STANDBY LETTER OF CREDIT IS SUBJECT TO UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS (1993 REVISION) INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 500.

THIS STANDBY LETTER OF CREDIT IS AVAILABLE WITH US AND SHALL REMAIN IN FORCE FROM THE DATE HEREOF UNTIL NOON ON (insert validity date) (“EXPIRY TIME”), WHEREUPON THIS STANDBY LETTER OF CREDIT SHALL EXPIRE AND BECOME NULL AND VOID AND HAVE NO FURTHER FORCE OR EFFECT WHETHER OR NOT THIS INSTRUMENT HAS BEEN RETURNED TO US FOR CANCELLATION. ANY PAYMENT DEMAND MUST BE DELIVERED TO US AT THE ABOVE ADDRESS OF OUR BRANCH, BY NOT LATER THAN THE EXPIRY TIME. ANY PAYMENT DEMAND SUBMITTED TO US AFTER THE EXPIRY TIME WILL NOT BE ENTERTAINED.

138

SCHEDULE 9

ASHDOD DELIVERY POINT DIAGRAM

(**)

139

SCHEDULE 10

FORM OF BUYER'S CONSENT

(**)

140

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 the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 26, 2012
/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 the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 26, 2012
/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 March 31, 2012 (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:	April 26, 2012	/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 March 31, 2012 (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:	April 26, 2012	/s/ Kenneth M. Fisher
		Kenneth M. Fisher
		Chief Financial Officer

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Income Taxes [Abstract]
Current	$ 79	$ 12
Deferred	32	11
Total Income Tax Provision	111	23
Effective Tax Rate (in hundredths)	30.00%	62.00%
Increase in the valuation allowance		$ 11
US [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2008
Equatorial Guinea [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2007
Israel [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2008
UK [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2010
Netherlands [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2009
China [Member]
Income Tax Examination [Line Items]
Earliest years remaining open to examinations	2006

XML

Debt (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Debt	$ 4,484,000,000		$ 4,495,000,000
Unamortized Discount	(23,000,000)		(26,000,000)
Total Debt, Net of Discount	4,461,000,000		4,469,000,000
Long-term Debt Due After One Year	4,088,000,000		4,100,000,000
Revolving credit facility	3,000,000,000		3,000,000,000
Credit Facility due October 14, 2016 [Member]
Debt Instrument [Line Items]
Debt	0	[1]	0	[1]
Interest Rate (in hundredths)	0.00%	[1]	0.00%	[1]
Debt instrument, maturity date	Oct. 14, 2016	[1]	Oct. 14, 2016	[1]
CONSOL Installment Payments, due September 30, 2012 and 2013 [Member]
Debt Instrument [Line Items]
Debt	656,000,000		656,000,000
Interest Rate (in hundredths)	1.76%	[2]	1.76%	[2]
Debt instrument, maturity dates	September 30. 2012 and 2013		September 30, 2012 and 2013
Less Amounts Due Within One Year	(325,000,000)		(324,000,000)
FPSO Lease Obligation [Member]
Debt Instrument [Line Items]
Debt	344,000,000		355,000,000
Interest Rate (in hundredths)	0.00%		0.00%
Less Amounts Due Within One Year	(48,000,000)		(45,000,000)
Senior Notes, due April 15, 2014 [Member]
Debt Instrument [Line Items]
Debt	200,000,000		200,000,000
Interest Rate (in hundredths)	5.25%		5.25%
Debt instrument, maturity date	Apr. 15, 2014		Apr. 15, 2014
Senior Notes, due March 1, 2019 [Member]
Debt Instrument [Line Items]
Debt	1,000,000,000		1,000,000,000
Interest Rate (in hundredths)	8.25%		8.25%
Debt instrument, maturity date	Mar. 01, 2019		Mar. 01, 2019
Senior Notes, due December 15, 2021 [Member]
Debt Instrument [Line Items]
Debt	1,000,000,000		1,000,000,000
Interest Rate (in hundredths)	4.15%		4.15%
Debt instrument, maturity date	Dec. 15, 2021		Dec. 15, 2021
Senior Notes, due October 15, 2023 [Member]
Debt Instrument [Line Items]
Debt	100,000,000		100,000,000
Interest Rate (in hundredths)	7.25%		7.25%
Debt instrument, maturity date	Oct. 15, 2023		Oct. 15, 2023
Senior Notes, due April 1, 2027 [Member]
Debt Instrument [Line Items]
Debt	250,000,000		250,000,000
Interest Rate (in hundredths)	8.00%		8.00%
Debt instrument, maturity date	Apr. 01, 2027		Apr. 01, 2027
Senior Notes, due March 1, 2041 [Member]
Debt Instrument [Line Items]
Debt	850,000,000		850,000,000
Interest Rate (in hundredths)	6.00%		6.00%
Debt instrument, maturity date	Mar. 01, 2041		Mar. 01, 2041
Senior Debentures, due August 1, 2097
Debt Instrument [Line Items]
Debt	$ 84,000,000		$ 84,000,000
Interest Rate (in hundredths)	7.25%		7.25%
Debt instrument, maturity date	Aug. 01, 2097		Aug. 01, 2097

[1] Our Credit Agreement provides for a $3.0 billion unsecured five-year revolving credit facility. The Credit Facility is available for general corporate purposes

[2] Imputed rate.

XML

Fair Value Measurements and Disclosures (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements and Disclosures [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)
March 31, 2012
Financial Assets
Mutual Fund Investments	$	108		$	-		$	-	$	-		$	108
Commodity Derivative Instruments		-			105			-		(66	)		39
Financial Liabilities
Commodity Derivative Instruments		-			(214	)		-		66			(148	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(172	)		-			-		-			(172	)
December 31, 2011
Financial Assets
Mutual Fund Investments	$	99		$	-		$	-	$	-		$	99
Commodity Derivative Instruments		-			99			-		(52	)		47
Financial Liabilities
Commodity Derivative Instruments		-			(135	)		-		52			(83	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(162	)		-			-		-			(162	)

(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.

Additional fair value disclosures

Fair value information regarding our debt is as follows:

	March 31,				December 31,
	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	4,117	$	4,606	$	4,114	$	4,733

(1) Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2012 or December 31, 2011. See Note 4. Debt.

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations, Beginning Balance	$ 377	$ 253
Liabilities Incurred	6	1
Liabilities Settled	(2)	(9)
Revision of Estimate	3	4
Accretion Expense	7	5
Asset Retirement Obligations, Ending Balance	$ 391	$ 254

XML

Organization and Nature of Operations

3 Months Ended

Mar. 31, 2012

Organization and Nature of Operations [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 core operating areas are onshore in the U.S., 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)

3 Months Ended

Mar. 31, 2012

Income Taxes [Abstract]

Income Tax Provision (Benefit)

The income tax provision consists of the following:

	Three Months Ended March 31,
	2012			2011
(millions)
Current	$	79		$	12
Deferred		32			11
Total Income Tax Provision	$	111		$	23
Effective Tax Rate		30	%		62	%

XML

Basic and Diluted Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

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 March 31,
	2012		2011
(millions, except per share amounts)
Net Income	$	263	$	14
Weighted Average Number of Shares Outstanding, Basic		177		176
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock		3		2
Weighted Average Number of Shares Outstanding, Diluted		180		178
Earnings Per Share, Basic	$	1.48	$	0.08
Earnings Per Share, Diluted		1.47		0.08
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above		2		2

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2012

Segment Information [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/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (in first quarter 2011), and new ventures.

	Consolidated		United States			West Africa		Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended March 31, 2012
Revenues from Third Parties	$	1,112	$	554		$	383	$	44	$	75	$	56
Income from Equity Method Investees		53		2			51		-		-		-
Total Revenues		1,165		556			434		44		75		56
DD&A		312		198			73		5		18		18
(Gain) Loss on Commodity Derivative Instruments		96		(9	)		105		-		-		-
Income (Loss) Before Income Taxes		374		193			227		32		40		(118	)
Three Months Ended March 31, 2011
Revenues from Third Parties	$	851	$	505		$	130	$	52	$	114	$	50
Income from Equity Method Investees		48		-			48		-		-		-
Total Revenues		899		505			178		52		114		50
DD&A		221		167			10		4		28		12
Loss on Commodity Derivative Instruments		286		192			94		-		-		-
Income (Loss)  Before Income Taxes		37		(37	)		74		39		68		(107	)
March 31, 2012
Goodwill	$	696	$	696		$	-	$	-	$	-	$	-
Total Assets		17,064		11,220			2,948		2,107		458		331
December 31, 2011
Goodwill		696		696			-		-		-		-
Total Assets		16,444		11,201			2,728		1,751		544		220

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Basis of Presentation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011		Dec. 31, 2011
Other Revenues [Abstract]
Other Revenues	$ 0	[1]	$ 21	[1]
Production Expense
Lease Operating Expense	118		92
Production and Ad Valorem Taxes	38		32
Transportation and Gathering Expense	23		18
Total	179		142
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense	0	[2]	18	[2]
Electricity Generation Expense	0	[1]	17	[1]
Other, Net	12		1
Total	12		36
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense	3	[3]	10	[3]
Interest Income	0		(3)
Other (Income) Expense, Net	(4)		1
Total	(1)		8
Accounts Receivable, Net
Commodity Sales	467				356
Joint Interest Billings	344				313
Other	117				123
Allowance for Doubtful Accounts	(9)				(9)
Total	919				783
Other Current Assets
Inventories, Current	77				78
Commodity Derivative Assets, Current	17				10
Deferred Income Taxes, Net, Current	159	[4]			41	[4]
Probable Insurance Claims	22	[5]			15	[5]
Prepaid Expenses and Other Assets, Current	55				36
Total	330				180
Other Noncurrent Assets
Equity Method Investments	376				329
Mutual Fund Investments	108				99
Commodity Derivative Assets, Noncurrent	22				37
Other Assets, Noncurrent	86				83
Total	592				548
Other Current Liabilities
Production and Ad Valorem Taxes	123				121
Commodity Derivative Liabilities, Current	119				76
Income Taxes Payable	131				127
Asset Retirement Obligations, Current	41				33
Interest Payable	41				56
CONSOL Installment Payment	325	[6]			324	[6]
Current Portion of FPSO Lease Obligation	48				45
Other	123				143
Total	951				925
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	237				222
Asset Retirement Obligations, Noncurrent	350				344
Accrued Benefit Costs, Noncurrent	90				88
Commodity Derivative Liabilities, Noncurrent	29				7
Other	113				91
Total	$ 819				$ 752
Common stock, shares authorized (in shares)	250,000,000				250,000,000
Common stock, shares authorized after April 24th, 2012 (in shares)	500,000,000
Common stock, par value per share (in dollars per share)	$ 3.333				$ 3.333
Common stock, par value per share after April 24th, 2012 (in dollars per share)	$ 0.01

[1] Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

[2] Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011.

[3] Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.

[4] Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.

[5] Amounts represent the costs incurred to date of the Leviathan-2 well in excess of the insurance deductible and insurance proceeds received to date.

[6] See Note 3. Acquisitions and Note 4. Debt.

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Consolidated Statements of Shareholders' Equity (unaudited) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Statements of Shareholders' Equity (unaudited) (Parenthetical) [Abstract]
Cash dividends per share (in dollars per share)	$ 0.22	$ 0.18

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Acquisitions (Details) (USD $)	3 Months Ended		9 Months Ended
	Mar. 31, 2012		Sep. 30, 2011
Total Purchase Price [Abstract]
Unproved Oil and Gas Properties	$ 853,000,000
Proved Oil and Gas Properties	386,000,000
Investment in CONE Gathering LLC	69,000,000
Total Assets Acquired	1,308,000,000	[1]
Ratio of funding on share of future drilling and completion costs	one-third
Interest in joint venture partnership (in hundredths)			50.00%
Undeveloped acres purchased (in acres)			628,000
Approximate purchase price of joint venture partnership			1,300,000,000
Cash paid to joint venture partnership	596,000,000
Remaining annual installments to purchase joint venture partnership	2
Calendar year funding of future drilling and completion costs, maximum (per year)	400,000,000
Future drilling and completion costs, maximum	2,100,000,000
Cost Obligation expected term, minimum (in years)	8 years
Natural gas price agreed upon benchmark, average (in MMBtu)	4.00
Imputed discount on CONSOL installment payments	$ 17,000,000

[1] Total reflects impact of $17 million imputed discount on CONSOL installment payments.

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Revenues from Third Parties	$ 1,112	$ 851
Income from Equity Method Investees	53	48
Total Revenues	1,165	899
DD&A	312	221
(Gain) Loss on Commodity Derivative Instruments	96	286
Income (Loss) Before Income Taxes	374	37
Goodwill	696		696
Total Assets	17,064		16,444
United States [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	554	505
Income from Equity Method Investees	2	0
Total Revenues	556	505
DD&A	198	167
(Gain) Loss on Commodity Derivative Instruments	(9)	192
Income (Loss) Before Income Taxes	193	(37)
Goodwill	696		696
Total Assets	11,220		11,201
West Africa [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	383	130
Income from Equity Method Investees	51	48
Total Revenues	434	178
DD&A	73	10
(Gain) Loss on Commodity Derivative Instruments	105	94
Income (Loss) Before Income Taxes	227	74
Goodwill	0		0
Total Assets	2,948		2,728
Eastern Mediterranean [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	44	52
Income from Equity Method Investees	0	0
Total Revenues	44	52
DD&A	5	4
(Gain) Loss on Commodity Derivative Instruments	0	0
Income (Loss) Before Income Taxes	32	39
Goodwill	0		0
Total Assets	2,107		1,751
North Sea [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	75	114
Income from Equity Method Investees	0	0
Total Revenues	75	114
DD&A	18	28
(Gain) Loss on Commodity Derivative Instruments	0	0
Income (Loss) Before Income Taxes	40	68
Goodwill	0		0
Total Assets	458		544
Other International And Corporate [Member]
Segment Reporting Information [Line Items]
Revenues from Third Parties	56	50
Income from Equity Method Investees	0	0
Total Revenues	56	50
DD&A	18	12
(Gain) Loss on Commodity Derivative Instruments	0	0
Income (Loss) Before Income Taxes	(118)	(107)
Goodwill	0		0
Total Assets	$ 331		$ 220

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Consolidated Statements of Operations (unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Revenues
Oil, Gas and NGL Sales	$ 1,112		$ 830
Income from Equity Method Investees	53		48
Other Revenues	0	[1]	21	[1]
Total	1,165		899
Costs and Expenses
Production Expense	179		142
Exploration Expense	63		70
Depreciation, Depletion and Amortization	312		221
General and Administrative	98		83
Other Operating (Income) Expense, Net	12		36
Total	664		552
Operating Income	501		347
Other (Income) Expense
Loss on Commodity Derivative Instruments	96		286
Interest, Net of Amount Capitalized	32		16
Other Non-Operating (Income) Expense, Net	(1)		8
Total	127		310
Income Before Income Taxes	374		37
Income Tax Provision	111		23
Net Income	$ 263		$ 14
Earnings Per Share, Basic (in dollars per share)	$ 1.48		$ 0.08
Earnings Per Share, Diluted (in dollars per share)	$ 1.47		$ 0.08
Weighted Average Number of Shares Outstanding, Basic (in shares)	177		176
Weighted Average Number of Shares Outstanding, Diluted (in shares)	180		178

[1] Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

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Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flows From Operating Activities
Net Income	$ 263	$ 14
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization	312	221
Dry Hole Cost	1	22
Deferred Income Taxes	32	11
Dividends (Income) from Equity Method Investees, Net	(29)	(23)
Unrealized (Gain) Loss on Commodity Derivative Instruments	73	303
Other Adjustments for Noncash Items Included in Income	30	36
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable	(135)	(9)
(Increase) in Other Current Assets	(5)	(17)
Increase in Accounts Payable	190	28
Increase (Decrease) in Current Income Taxes Payable	5	(71)
(Decrease) in Other Current Liabilities	(26)	(54)
Other Operating Assets and Liabilities, Net	30	23
Net Cash Provided by Operating Activities	741	484
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(1,018)	(578)
Additions to Equity Method Investments	(14)	0
Proceeds from Divestitures	0	3
Net Cash Used in Investing Activities	(1,032)	(575)
Cash Flows From Financing Activities
Exercise of Stock Options	27	23
Excess Tax Benefits from Stock-Based Awards	12	8
Dividends Paid, Common Stock	(39)	(32)
Purchase of Treasury Stock	(13)	(16)
Proceeds from Credit Facilities	0	120
Repayment of Credit Facilities	0	(470)
Proceeds from Issuance of Senior Long-Term Debt, Net	0	836
Settlement of Interest Rate Derivative Instrument	0	(40)
Repayment of Capital Lease Obligation	(8)	0
Net Cash Provided By (Used In) Financing Activities	(21)	429
Increase (Decrease) in Cash and Cash Equivalents	(312)	338
Cash and Cash Equivalents at Beginning of Period	1,455	1,081
Cash and Cash Equivalents at End of Period	$ 1,143	$ 1,419

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Fair Value Measurements and Disclosures (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	$ 108		$ 99
Commodity Derivative Instruments	39		47
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	(148)		(83)
Portion of Deferred Compensation Liability Measured at Fair Value	(172)		(162)
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Net of Unamortized Discount	4,117	[1]	4,114	[1]
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Net of Unamortized Discount	4,606	[1]	4,733	[1]
Quoted Prices in Active Markets (Level 1) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	108	[2]	99	[2]
Commodity Derivative Instruments	0	[2]	0	[2]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	0	[2]	0	[2]
Portion of Deferred Compensation Liability Measured at Fair Value	(172)	[2]	(162)	[2]
Significant Other Observable Inputs (Level 2) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[3]	0	[3]
Commodity Derivative Instruments	105	[3]	99	[3]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	(214)	[3]	(135)	[3]
Portion of Deferred Compensation Liability Measured at Fair Value	0	[3]	0	[3]
Significant Unobservable Inputs (Level 3) [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[4]	0	[4]
Commodity Derivative Instruments	0	[4]	0	[4]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	0	[4]	0	[4]
Portion of Deferred Compensation Liability Measured at Fair Value	0	[4]	0	[4]
Fair Value Inputs Adjustment [Member]
Financial Assets Measured at Fair Value on a Recurring Basis [Abstract]
Mutual Fund Investments	0	[5]	0	[5]
Commodity Derivative Instruments	(66)	[5]	(52)	[5]
Financial Liabilities Measured at Fair Value on a Recurring Basis [Abstract]
Commodity Derivative Instruments	66	[5]	52	[5]
Portion of Deferred Compensation Liability Measured at Fair Value	$ 0	[5]	$ 0	[5]

[1] Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2012 or December 31, 2011. See Note 5. Debt

[2] 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.

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

[4] Level 3 measurements are fair value measurements which use unobservable inputs.

[5] Amount represents the impact of master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.

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Acquisitions (Tables)

3 Months Ended

Mar. 31, 2012

Acquisitions [Abstract]

Purchase Price Allocation of Acquisition

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

	March 31,
	2012
(millions)
Unproved Oil and Gas Properties	$	853
Proved Oil and Gas Properties		386
Investment in CONE Gathering LLC		69
Total Assets Acquired (1)	$	1,308

(1) Total reflects impact of $17 million imputed discount on CONSOL installment payments.

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Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs, Beginning of Period	$ 696
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	93
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves	0
Capitalized Exploratory Well Costs Charged to Expense	0
Capitalized Exploratory Well Costs, Balance at End of Period	789
Exploratory Well Costs Capitalized for a Period of One Year or Less	345	318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	444	378
Capitalized Exploratory Well Costs	789
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a period Greater Than One Year Since Commencement of Drilling	10	9
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	261
Suspended since 2010	116
Suspended Since 2011	67
Total	444	378
Blocks O And I Offshore Equatorial Guinea [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	114
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	106
Suspended since 2010	6
Suspended Since 2011	2
Total	114
YoYo Offshore Cameron [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	41
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	38
Suspended since 2010	2
Suspended Since 2011	1
Total	41
Leviathan Offshore Israel [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	86
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	0
Suspended since 2010	41
Suspended Since 2011	45
Total	86
Dalit Offshore Israel [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	22
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	21
Suspended since 2010	1
Suspended Since 2011	0
Total	22
Gunflint Deepwater Gulf Of Mexico [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	70
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	56
Suspended since 2010	3
Suspended Since 2011	11
Total	70
Deep Blue Gulf of Mexico [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	75
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	19
Suspended since 2010	54
Suspended Since 2011	2
Total	75
Selkirk North Sea [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	22
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	21
Suspended since 2010	1
Suspended Since 2011	0
Total	22
Other - 3 Projects of $10 million or less [Member]
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement	14
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items]
Suspended since 2009 & prior	0
Suspended since 2010	8
Suspended Since 2011	6
Total	$ 14

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities [Abstract]

Unsettled Derivative Instruments

Unsettled Derivative Instruments   As of March 31, 2012, we had entered into the following crude oil derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	Bbls Per Day		Weighted Average Fixed Price		Weighted Average  Short Put  Price		Weighted Average Floor Price		Weighted Average  Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX WTI  (1)		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	Two-Way Collars	NYMEX WTI		5,000		-		-		95.00		115.00
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		26,000		-		82.88		100.86		127.32
2014	Swaps	Dated Brent		3,000		107.15		-		-		-
2014	Three-Way Collars	Dated Brent		10,000		-		85.00		98.50		129.24

(1) West Texas Intermediate

As of March 31, 2012, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day		Weighted Average Fixed Price		Weighted Average Short Put  Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX HH (1)		30,000	$	5.10	$	-	$	-	$	-
2012	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2013	Three-Way Collars	NYMEX HH		100,000		-		3.88		4.75		5.63

(1) Henry Hub

As of March 31, 2012, we had entered into the following natural gas basis swaps:

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

(1) Colorado Interstate Gas – Northern System

Fair Value of Derivative Instruments

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
	March 31,			December 31,			March 31,			December 31,
	2012			2011			2012			2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
(millions)
Commodity Derivative Instruments	Current Assets	$	17	Current Assets	$	10	Current Liabilities	$	119	Current Liabilities	$	76
	Noncurrent Assets		22	Noncurrent Assets		37	Noncurrent Liabilities		29	Noncurrent Liabilities		7
Total		$	39		$	47		$	148		$	83

Effect of derivative instruments on consolidated statement of operations

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

	Three Months Ended March 31,
	2012		2011
(millions)
Realized Mark-to-Market (Gain) Loss	$	23	$	(17	)
Unrealized Mark-to-Market Loss		73		303
Total Loss on Commodity Derivative Instruments	$	96	$	286

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Consolidated Statements of Shareholders' Equity (unaudited) (USD $) In Millions	Common Stock [Member]	Additional Paid in Capital [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock at Cost [Member]	Retained Earnings [Member]	Total
Balance at Beginning of Period at Dec. 31, 2010	$ 651	$ 2,385	$ (104)	$ (624)	$ 4,540	$ 6,848
Net Income	0	0	0	0	14	14
Stock-based Compensation	0	14	0	0	0	14
Exercise of Stock Options	2	21	0	0	0	23
Tax Benefits Related to Exercise of Stock Options	0	8	0	0	0	8
Restricted Stock Awards, Net	1	(1)	0	0	0	0
Dividends	0	0	0	0	(32)	(32)
Changes in Treasury Stock, Net	0	0	0	(16)	0	(16)
Unrealized Change in Fair Value	0	0	15	0	0	15
Net Change in Other	0	0	2	0	0	2
Balance at End of Period at Mar. 31, 2011	654	2,427	(87)	(640)	4,522	6,876
Balance at Beginning of Period at Dec. 31, 2011	656	2,497	(100)	(638)	4,850	7,265
Net Income	0	0	0	0	263	263
Stock-based Compensation	0	16	0	0	0	16
Exercise of Stock Options	2	25	0	0	0	27
Tax Benefits Related to Exercise of Stock Options	0	12	0	0	0	12
Restricted Stock Awards, Net	1	(1)	0	0	0	0
Dividends	0	0	0	0	(39)	(39)
Changes in Treasury Stock, Net	0	0	0	(13)	0	(13)
Net Change in Other	0	0	2	0	0	2
Balance at End of Period at Mar. 31, 2012	$ 659	$ 2,549	$ (98)	$ (651)	$ 5,074	$ 7,533

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Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Statements of Comprehensive Income (unaudited) [Abstract]
Net Income	$ 263	$ 14
Unrealized Change in Fair Value	0	23
Less Tax Provision	0	(8)
Net Change in Other	2	2
Other Comprehensive Income	2	17
Comprehensive Income	$ 265	$ 31

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Basic and Diluted Earnings Per Share

3 Months Ended

Mar. 31, 2012

Basic and Diluted Earnings Per Share [Abstract]

Basic and Diluted Earnings Per Share

Note 9.  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 include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share:

	Three Months Ended March 31,
	2012		2011
(millions, except per share amounts)
Net Income	$	263	$	14
Weighted Average Number of Shares Outstanding, Basic		177		176
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock		3		2
Weighted Average Number of Shares Outstanding, Diluted		180		178
Earnings Per Share, Basic	$	1.48	$	0.08
Earnings Per Share, Diluted		1.47		0.08
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above		2		2

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Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Apr. 06, 2012	Jun. 30, 2011
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			$ 15.6
Entity Common Stock, Shares Outstanding		177,787,421
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012

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Income Taxes

3 Months Ended

Mar. 31, 2012

Income Taxes [Abstract]

Income Taxes

Note 10.  Income Taxes

The income tax provision consists of the following:

	Three Months Ended March 31,
	2012			2011
(millions)
Current	$	79		$	12
Deferred		32			11
Total Income Tax Provision	$	111		$	23
Effective Tax Rate		30	%		62	%

Our effective tax rate decreased for the first quarter of 2012 as compared with the first quarter of 2011. During the first quarter of 2011, we increased the valuation allowance against our deferred tax asset for foreign tax credits by $11 million resulting in a corresponding increase in income tax expense, which was primarily responsible for the difference in the quarterly effective tax rates.

Years Remaining Open to Examination   In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2008, Equatorial Guinea – 2007, Israel – 2008, UK – 2010, the Netherlands – 2009, and China – 2006.

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Consolidated Balance Sheets (unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Current Assets
Cash and Cash Equivalents	$ 1,143	$ 1,455
Accounts Receivable, Net	919	783
Other Current Assets	330	180
Total Current Assets	2,392	2,418
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)	18,527	17,703
Property, Plant and Equipment, Other	317	294
Total Property, Plant and Equipment, Gross	18,844	17,997
Accumulated Depreciation, Depletion and Amortization	(5,460)	(5,215)
Total Property, Plant and Equipment, Net	13,384	12,782
Goodwill	696	696
Other Noncurrent Assets	592	548
Total Assets	17,064	16,444
Current Liabilities
Accounts Payable - Trade	1,457	1,343
Other Current Liabilities	951	925
Total Current Liabilities	2,408	2,268
Long-Term Debt	4,088	4,100
Deferred Income Taxes, Noncurrent	2,216	2,059
Other Noncurrent Liabilities	819	752
Total Liabilities	9,531	9,179
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; 198 Million and 197 Million Shares Issued, Respectively	659	656
Additional Paid in Capital	2,549	2,497
Accumulated Other Comprehensive Loss	(98)	(100)
Treasury Stock, at Cost; 19 Million Shares	(651)	(638)
Retained Earnings	5,074	4,850
Total Shareholders' Equity	7,533	7,265
Total Liabilities and Shareholders' Equity	$ 17,064	$ 16,444

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Debt

3 Months Ended

Mar. 31, 2012

Debt [Abstract]

Debt

Note 4. Debt

Our debt consists of the following:

	March 31,						December 31,
	2012						2011
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due October 14, 2016 (1)	$	-			-		$	-			-
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	% (2)		656			1.76	% (2)
FPSO Lease Obligation		344			-			355			-
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	%
4.15% Senior Notes, due December 15, 2021		1,000			4.15	%		1,000			4.15	%
7¼% Senior 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	%		850			6.00	%
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		4,484						4,495
Unamortized Discount		(23	)					(26	)
Total Debt, Net of Discount		4,461						4,469
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(325	)					(324	)
FPSO Lease Obligation		(48	)					(45	)
Long-Term Debt Due After One Year	$	4,088					$	4,100

(1) Our Credit Agreement provides for a $3.0 billion unsecured five-year revolving credit facility. The Credit Facility is available for general corporate purposes.

(2) Imputed rate.

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

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Acquisitions

3 Months Ended

Mar. 31, 2012

Acquisitions [Abstract]

Acquisitions

Note 3.   Acquisitions

Marcellus Shale Joint Venture   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 a 50% interest in approximately 628,000 net undeveloped acres, certain producing properties, and existing infrastructure, such as pipeline and gathering facilities, for approximately $1.3 billion, including post-closing adjustments. We and CONSOL also formed CONE Gathering LLC (CONE) to own and operate the existing and future infrastructure. We have paid a total of $596 million as of March 31, 2012, and, other than post-closing adjustments, the remainder will be paid in two annual installments. See Note 4. Debt.

As part of the joint venture transaction, we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation), which is expected to be paid out over approximately eight years or more. The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and will remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices.

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

	March 31,
	2012
(millions)
Unproved Oil and Gas Properties	$	853
Proved Oil and Gas Properties		386
Investment in CONE Gathering LLC		69
Total Assets Acquired (1)	$	1,308

(1) Total reflects impact of $17 million imputed discount on CONSOL installment payments.

We used an income approach to estimate the fair value of the proved oil and gas properties as of the acquisition date. 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 reserves 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 for proved oil and gas properties 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.

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Debt (Tables)

6 Months Ended

Jun. 30, 2011

Debt [Abstract]

Debt

Our debt consists of the following:

	March 31,						December 31,
	2012						2011
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility, due October 14, 2016 (1)	$	-			-		$	-			-
CONSOL Installment Payments, due September 30, 2012 and 2013		656			1.76	% (2)		656			1.76	% (2)
FPSO Lease Obligation		344			-			355			-
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	%
4.15% Senior Notes, due December 15, 2021		1,000			4.15	%		1,000			4.15	%
7¼% Senior 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	%		850			6.00	%
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
Total		4,484						4,495
Unamortized Discount		(23	)					(26	)
Total Debt, Net of Discount		4,461						4,469
Less Amounts Due Within One Year
CONSOL Installment Payment, due September 30, 2012, net of discount		(325	)					(324	)
FPSO Lease Obligation		(48	)					(45	)
Long-Term Debt Due After One Year	$	4,088					$	4,100

(1) Our Credit Agreement provides for a $3.0 billion unsecured five-year revolving credit facility. The Credit Facility is available for general corporate purposes.

(2) Imputed rate.

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Segment Information

3 Months Ended

Mar. 31, 2012

Segment Information [Abstract]

Segment Information

Note 11.  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/Guinea-Bissau); Eastern Mediterranean (Israel and Cyprus); the North Sea (UK and the Netherlands); and Other International and Corporate. Other International includes China, Ecuador (in first quarter 2011), and new ventures.

	Consolidated		United States			West Africa		Eastern Mediter- ranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended March 31, 2012
Revenues from Third Parties	$	1,112	$	554		$	383	$	44	$	75	$	56
Income from Equity Method Investees		53		2			51		-		-		-
Total Revenues		1,165		556			434		44		75		56
DD&A		312		198			73		5		18		18
(Gain) Loss on Commodity Derivative Instruments		96		(9	)		105		-		-		-
Income (Loss) Before Income Taxes		374		193			227		32		40		(118	)
Three Months Ended March 31, 2011
Revenues from Third Parties	$	851	$	505		$	130	$	52	$	114	$	50
Income from Equity Method Investees		48		-			48		-		-		-
Total Revenues		899		505			178		52		114		50
DD&A		221		167			10		4		28		12
Loss on Commodity Derivative Instruments		286		192			94		-		-		-
Income (Loss)  Before Income Taxes		37		(37	)		74		39		68		(107	)
March 31, 2012
Goodwill	$	696	$	696		$	-	$	-	$	-	$	-
Total Assets		17,064		11,220			2,948		2,107		458		331
December 31, 2011
Goodwill		696		696			-		-		-		-
Total Assets		16,444		11,201			2,728		1,751		544		220

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Capitalized Exploratory Well Costs

3 Months Ended

Mar. 31, 2012

Capitalized Exploratory Well Costs [Abstract]

Capitalized Exploratory Well Costs

Note 7.  Capitalized Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense.

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

		Three Months Ended March 31, 2012
(millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	696
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		93
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		-
Capitalized Exploratory Well Costs Charged to Expense		-
Capitalized Exploratory Well Costs, End of Period	$	789

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

	March 31,		December 31,
	2012		2011
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	345	$	318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling		444		378
Balance at End of Period	$	789	$	696
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement 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 commencement of drilling as of March 31, 2012:

			Suspended Since
	Total		2011		2010		2009 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	114	$	2	$	6	$	106
Offshore Cameroon
YoYo		41		1		2		38
Offshore Israel
Leviathan		86		45		41		-
Dalit		22		-		1		21
Deepwater Gulf of Mexico
Gunflint		70		11		3		56
Deep Blue		75		2		54		19
North Sea
Selkirk		22		-		1		21
Other
3 projects of $10 million or less each		14		6		8		-
Total	$	444	$	67	$	116	$	261

Blocks O and I   Blocks O and I are crude oil, natural gas and natural gas condensate discoveries.  During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.

YoYo   YoYo is a 2007 natural gas and condensate discovery. During 2011 we acquired and processed additional 3-D seismic information and are continuing evaluations for future drilling potential.

Leviathan   Leviathan is a 2010 natural gas discovery. We are continuing to evaluate the discovery with the successful drilling of the Leviathan-3 appraisal well. We will require an additional one or two appraisal wells to further define Leviathan's natural gas areal extent in order to determine the best development option including subsea tieback to existing shallow water platform, semi-submersible platform, FPSO, or LNG. 

In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests are expected during the second quarter of 2012.

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

Gunflint   Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery. We are currently drilling the first of up to three appraisal wells that we anticipate drilling to fully evaluate the extent of the reservoir. We are also reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility.

Deep Blue   Deep Blue (Green Canyon Block 723) was a significant test well which began drilling in 2009. When the Deepwater Moratorium was announced in May 2010, we were required to suspend side track drilling activities. We resumed drilling activities and found additional hydrocarbons in high quality reservoirs in 2011. We have completed the analysis of the data obtained from the side track well and are working with our existing and potential new partners regarding their participation in an appraisal well.

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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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 5.  Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   In order to mitigate the effect of 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.

We also may enter into forward contracts to hedge anticipated exposure to interest rate risk associated with public debt financing.

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 6. 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 March 2011 debt issuance. During first quarter 2011, the fair value of the swap increased and we recognized a gain of $23 million, net of tax, in AOCL. On February 15, 2011 we settled the interest rate swap, which had a net liability position of $40 million at the time of settlement. 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 notes. The ineffective portion of the interest rate swap was de minimis.

Unsettled Derivative Instruments   As of March 31, 2012, we had entered into the following crude oil derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	Bbls Per Day		Weighted Average Fixed Price		Weighted Average  Short Put  Price		Weighted Average Floor Price		Weighted Average  Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX WTI  (1)		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	Two-Way Collars	NYMEX WTI		5,000		-		-		95.00		115.00
2013	Three-Way Collars	NYMEX WTI		5,000		-		65.00		85.00		113.63
2013	Three-Way Collars	Dated Brent		26,000		-		82.88		100.86		127.32
2014	Swaps	Dated Brent		3,000		107.15		-		-		-
2014	Three-Way Collars	Dated Brent		10,000		-		85.00		98.50		129.24

(1) West Texas Intermediate

As of March 31, 2012, we had entered into the following natural gas derivative instruments:

					Swaps		Collars
Settlement Period	Type of Contract	Index	MMBtu Per Day		Weighted Average Fixed Price		Weighted Average Short Put  Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Instruments Entered Into as of March 31, 2012
2012	Swaps	NYMEX HH (1)		30,000	$	5.10	$	-	$	-	$	-
2012	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2012	Three-Way Collars	NYMEX HH		110,000		-		4.44		5.25		6.66
2013	Swaps	NYMEX HH		30,000		5.25		-		-		-
2013	Two-Way Collars	NYMEX HH		40,000		-		-		3.25		5.14
2013	Three-Way Collars	NYMEX HH		100,000		-		3.88		4.75		5.63

(1) Henry Hub

As of March 31, 2012, we had entered into the following natural gas basis swaps:

Settlement Period	Index	Index Less Differential	MMBtu Per Day		Weighted Average Differential
2012	IFERC CIG (1)	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
	March 31,			December 31,			March 31,			December 31,
	2012			2011			2012			2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair  Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
(millions)
Commodity Derivative Instruments	Current Assets	$	17	Current Assets	$	10	Current Liabilities	$	119	Current Liabilities	$	76
	Noncurrent Assets		22	Noncurrent Assets		37	Noncurrent Liabilities		29	Noncurrent Liabilities		7
Total		$	39		$	47		$	148		$	83

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

	Three Months Ended March 31,
	2012		2011
(millions)
Realized Mark-to-Market (Gain) Loss	$	23	$	(17	)
Unrealized Mark-to-Market Loss		73		303
Total Loss on Commodity Derivative Instruments	$	96	$	286

AOCL at March 31, 2012 included deferred losses of $26 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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Fair Value Measurements and Disclosures

3 Months Ended

Mar. 31, 2012

Fair Value Measurements and Disclosures [Abstract]

Fair Value Measurements and Disclosures

Note 6.  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 5. Derivative Instruments and Hedging Activities.

Deferred Compensation Liability   The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments above.

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

	Fair Value Measurements Using
	Quoted Prices in  Active Markets (Level 1) (1)			Significant Other Observable Inputs (Level 2) (2)			Significant Unobservable Inputs (Level 3) (3)		Adjustment (4)			Fair Value Measurement
(millions)
March 31, 2012
Financial Assets
Mutual Fund Investments	$	108		$	-		$	-	$	-		$	108
Commodity Derivative Instruments		-			105			-		(66	)		39
Financial Liabilities
Commodity Derivative Instruments		-			(214	)		-		66			(148	)
Portion of Deferred Compensation
Liability Measured at Fair Value		(172	)		-			-		-			(172	)
December 31, 2011
Financial Assets
Mutual Fund Investments	$	99		$	-		$	-	$	-		$	99
Commodity Derivative Instruments		-			99			-		(52	)		47
Financial Liabilities
Commodity Derivative Instruments		-			(135	)		-		52			(83	)
Portion of Deferred Compensation Liability
Measured at Fair Value		(162	)		-			-		-			(162	)

(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.

Additional Fair Value Disclosures

Debt   The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a level 1 measurement on the fair value hierarchy.  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. As such, we consider the fair value of our floating-rate debt and CONSOL installment payments to be level 2 measurements on the fair value hierarchy. See Note 4. Debt. Fair value information regarding our debt is as follows:

	March 31,				December 31,
	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	4,117	$	4,606	$	4,114	$	4,733

(1) Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at March 31, 2012 or December 31, 2011. See Note 4. Debt.

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 8.  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:

	Three Months Ended March 31,
	2012			2011
(millions)
Asset Retirement Obligations, Beginning Balance	$	377		$	253
Liabilities Incurred		6			1
Liabilities Settled		(2	)		(9	)
Revision of Estimate		3			4
Accretion Expense		7			5
Asset Retirement Obligations, Ending Balance	$	391		$	254

Liabilities settled in 2011 related primarily to Deepwater Gulf of Mexico and Gulf of Mexico shelf properties.

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

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Derivative Instruments and Hedging Activities (Details) (USD $)	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011	Dec. 31, 2011	Feb. 15, 2011
Derivative Instruments and Hedging Activities [Abstract]
Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss			$ (23,000,000)
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
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	39,000,000			47,000,000
Derivative Liability, Fair Value	148,000,000			83,000,000
Realized Mark-to-Market (Gain) Loss	23,000,000		(17,000,000)
Unrealized (Gain) Loss on Commodity Derivative Instruments	73,000,000		303,000,000
Loss on Commodity Derivative Instruments	96,000,000		286,000,000
Amount of Deferred Losses Related to Interest Rate Derivative Instruments to be Amortized to Interest Expense Over the Life of the Related Debt Issuance	26,000,000
Amount of Deferred Losses Related to Interest Rate Derivative Instruments Currently Being Reclassified Into Earnings	2,000,000
Commodity derivative instruments [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	17,000,000			10,000,000
Commodity derivative instruments [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	22,000,000			37,000,000
Commodity derivative instruments [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	119,000,000			76,000,000
Commodity derivative instruments [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	29,000,000			7,000,000
Crude Oil Commodity Contract [Member] | Two Way Collar 1 [Member]
Derivative [Line Items]
Period	2013
Index	NYMEX WTI	[1]
Volume Per Day	5,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 95.00
Weighted Average Ceiling Price	$ 115.00
Crude Oil Commodity Contract [Member] | Three Way Collars 1 [Member]
Derivative [Line Items]
Period	2012
Index	NYMEX WTI	[1]
Volume Per Day	23,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 61.09
Weighted Average Floor Price	$ 83.04
Weighted Average Ceiling Price	$ 101.66
Crude Oil Commodity Contract [Member] | Swaps 1 [Member]
Derivative [Line Items]
Period	2012
Index	NYMEX WTI	[1]
Volume Per Day	5,000
Weighted Average Fixed Price	$ 91.84
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Crude Oil Commodity Contract [Member] | Swaps 2 [Member]
Derivative [Line Items]
Period	2012
Index	Dated Brent
Volume Per Day	8,000
Weighted Average Fixed Price	$ 89.06
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Crude Oil Commodity Contract [Member] | Three Way Collars 2 [Member]
Derivative [Line Items]
Period	2012
Index	Dated Brent
Volume Per Day	3,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 70.00
Weighted Average Floor Price	$ 95.83
Weighted Average Ceiling Price	$ 105.00
Crude Oil Commodity Contract [Member] | Basis Swaps 1 [Member]
Derivative [Line Items]
Period	2013
Index	Dated Brent
Volume Per Day	3,000
Weighted Average Fixed Price	$ 98.03
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Crude Oil Commodity Contract [Member] | Three Way Collars 3 [Member]
Derivative [Line Items]
Period	2013
Index	NYMEX WTI	[1]
Volume Per Day	5,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 65.00
Weighted Average Floor Price	$ 85.00
Weighted Average Ceiling Price	$ 113.63
Crude Oil Commodity Contract [Member] | Swaps 4 [Member]
Derivative [Line Items]
Period	2014
Index	Dated Brent
Volume Per Day	3,000
Weighted Average Fixed Price	$ 107.15
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Crude Oil Commodity Contract [Member] | Three Way Collars 4 [Member]
Derivative [Line Items]
Period	2013
Index	Dated Brent
Volume Per Day	26,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 82.88
Weighted Average Floor Price	$ 100.86
Weighted Average Ceiling Price	$ 127.32
Crude Oil Commodity Contract [Member] | Three Way Collars 5 [Member]
Derivative [Line Items]
Period	2014
Index	Dated Brent
Volume Per Day	10,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 85.00
Weighted Average Floor Price	$ 98.50
Weighted Average Ceiling Price	$ 129.24
Natural Gas Commodity Contract [Member] | Two Way Collar 1 [Member]
Derivative [Line Items]
Period	2012
Index	NYMEX HH	[2]
Volume Per Day	40,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 3.25
Weighted Average Ceiling Price	$ 5.14
Natural Gas Commodity Contract [Member] | Three Way Collars 1 [Member]
Derivative [Line Items]
Period	2012
Index	NYMEX HH	[2]
Volume Per Day	110,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 4.44
Weighted Average Floor Price	$ 5.25
Weighted Average Ceiling Price	$ 6.66
Natural Gas Commodity Contract [Member] | Swaps 1 [Member]
Derivative [Line Items]
Period	2012
Index	NYMEX HH	[2]
Volume Per Day	30,000
Weighted Average Fixed Price	$ 5.10
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Natural Gas Commodity Contract [Member] | Swaps 2 [Member]
Derivative [Line Items]
Period	2013
Index	NYMEX HH	[2]
Volume Per Day	30,000
Weighted Average Fixed Price	$ 5.25
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 0
Weighted Average Ceiling Price	$ 0
Natural Gas Commodity Contract [Member] | Three Way Collars 2 [Member]
Derivative [Line Items]
Period	2013
Index	NYMEX HH	[2]
Volume Per Day	100,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 3.88
Weighted Average Floor Price	$ 4.75
Weighted Average Ceiling Price	$ 5.63
Natural Gas Commodity Contract [Member] | Basis Swaps 1 [Member]
Derivative [Line Items]
Period	2012
Index	IFERC CIG
Index Less Differential	NYMEX HH
Volume Per Day	150,000
Weighted Average Differential	$ (0.52)
Natural Gas Commodity Contract [Member] | Two Way Collar 2 [Member]
Derivative [Line Items]
Period	2013
Index	NYMEX HH	[2]
Volume Per Day	40,000
Weighted Average Fixed Price	$ 0
Weighted Average Short Put Price	$ 0
Weighted Average Floor Price	$ 3.25
Weighted Average Ceiling Price	$ 5.14

[1] West Texas Intermediate

[2] Henry Hub

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Basis of Presentation (Tables)

3 Months Ended

Mar. 31, 2012

Basis of Presentation [Abstract]

Statement of Operations Information

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

	Three Months Ended March 31,
	2012			2011
(millions)
Other Revenues (1)	$	-		$	21
Production Expense
Lease Operating Expense	$	118		$	92
Production and Ad Valorem Taxes		38			32
Transportation and Gathering Expense		23			18
Total	$	179		$	142
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	-		$	18
Electricity Generation Expense (1)		-			17
Other, Net		12			1
Total	$	12		$	36
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense (3)	$	3		$	10
Interest Income		-			(3	)
Other (Income) Expense, Net		(4	)		1
Total	$	(1	)	$	8

(1) Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

(2) Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011. 

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

Balance Sheet Information Table

Balance Sheet Information   Other balance sheet information is as follows:

	March 31,			December 31,
	2012			2011
(millions)
Accounts Receivable, Net
Commodity Sales	$	467		$	356
Joint Interest Billings		344			313
Other		117			123
Allowance for Doubtful Accounts		(9	)		(9	)
Total	$	919		$	783
Other Current Assets
Inventories, Current	$	77		$	78
Commodity Derivative Assets, Current		17			10
Deferred Income Taxes, Net, Current (1)		159			41
Probable Insurance Claims (2)		22			15
Prepaid Expenses and Other Current Assets, Current		55			36
Total	$	330		$	180
Other Noncurrent Assets
Equity Method Investments	$	376		$	329
Mutual Fund Investments		108			99
Commodity Derivative Assets, Noncurrent		22			37
Other Assets, Noncurrent		86			83
Total	$	592		$	548
Other Current Liabilities
Production and Ad Valorem Taxes	$	123		$	121
Commodity Derivative Liabilities, Current		119			76
Income Taxes Payable		131			127
Asset Retirement Obligations, Current		41			33
Interest Payable		41			56
CONSOL Installment Payment (3)		325			324
Current Portion of FPSO Lease Obligation		48			45
Other		123			143
Total	$	951		$	925
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	237		$	222
Asset Retirement Obligations, Noncurrent		350			344
Accrued Benefit Costs, Noncurrent		90			88
Commodity Derivative Liabilities, Noncurrent		29			7
Other		113			91
Total	$	819		$	752

 (1) Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.

 (2) Amounts represent the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible and insurance proceeds received to date.

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

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Capitalized Exploratory Well Costs (Tables)

3 Months Ended

Mar. 31, 2012

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:

		Three Months Ended March 31, 2012
(millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	696
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		93
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		-
Capitalized Exploratory Well Costs Charged to Expense		-
Capitalized Exploratory Well Costs, End of Period	$	789

Aging of Capitalized Well Costs

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

	March 31,		December 31,
	2012		2011
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	345	$	318
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling		444		378
Balance at End of Period	$	789	$	696
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement 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 commencement of drilling as of March 31, 2012:

			Suspended Since
	Total		2011		2010		2009 & Prior
(millions)
Country/Project
Offshore Equatorial Guinea
Blocks O and I	$	114	$	2	$	6	$	106
Offshore Cameroon
YoYo		41		1		2		38
Offshore Israel
Leviathan		86		45		41		-
Dalit		22		-		1		21
Deepwater Gulf of Mexico
Gunflint		70		11		3		56
Deep Blue		75		2		54		19
North Sea
Selkirk		22		-		1		21
Other
3 projects of $10 million or less each		14		6		8		-
Total	$	444	$	67	$	116	$	261

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Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Consolidated Balance Sheets (unaudited) [Abstract]
Preferred stock, par value per share (in dollars per share)	$ 1.00	$ 1.00
Preferred stock, shares authorized (in shares)	4,000,000	4,000,000
Common stock, par value per share (in dollars per share)	$ 3.333	$ 3.333
Common stock, shares authorized (in shares)	250,000,000	250,000,000
Common stock, shares issued (in shares)	198,000,000	197,000,000
Treasury stock, shares (in shares)	19,000,000	19,000,000

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Basis of Presentation

3 Months Ended

Mar. 31, 2012

Basis of Presentation [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 March 31, 2012 and December 31, 2011 and for the three months ended March 31, 2012 and 2011 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 months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. 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, 2011.

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 March 31,
	2012			2011
(millions)
Other Revenues (1)	$	-		$	21
Production Expense
Lease Operating Expense	$	118		$	92
Production and Ad Valorem Taxes		38			32
Transportation and Gathering Expense		23			18
Total	$	179		$	142
Other Operating (Income) Expense, Net
Deepwater Gulf of Mexico Moratorium Expense (2)	$	-		$	18
Electricity Generation Expense (1)		-			17
Other, Net		12			1
Total	$	12		$	36
Other Non-Operating (Income) Expense, Net
Deferred Compensation Expense (3)	$	3		$	10
Interest Income		-			(3	)
Other (Income) Expense, Net		(4	)		1
Total	$	(1	)	$	8

(1) Other revenues for first quarter 2011 consist of electricity sales from the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

(2) Amount relates to rig stand-by expense incurred prior to receiving a permit to resume drilling activities in the deepwater Gulf of Mexico in 2011. 

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

Balance Sheet Information   Other balance sheet information is as follows:

	March 31,			December 31,
	2012			2011
(millions)
Accounts Receivable, Net
Commodity Sales	$	467		$	356
Joint Interest Billings		344			313
Other		117			123
Allowance for Doubtful Accounts		(9	)		(9	)
Total	$	919		$	783
Other Current Assets
Inventories, Current	$	77		$	78
Commodity Derivative Assets, Current		17			10
Deferred Income Taxes, Net, Current (1)		159			41
Probable Insurance Claims (2)		22			15
Prepaid Expenses and Other Current Assets, Current		55			36
Total	$	330		$	180
Other Noncurrent Assets
Equity Method Investments	$	376		$	329
Mutual Fund Investments		108			99
Commodity Derivative Assets, Noncurrent		22			37
Other Assets, Noncurrent		86			83
Total	$	592		$	548
Other Current Liabilities
Production and Ad Valorem Taxes	$	123		$	121
Commodity Derivative Liabilities, Current		119			76
Income Taxes Payable		131			127
Asset Retirement Obligations, Current		41			33
Interest Payable		41			56
CONSOL Installment Payment (3)		325			324
Current Portion of FPSO Lease Obligation		48			45
Other		123			143
Total	$	951		$	925
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	237		$	222
Asset Retirement Obligations, Noncurrent		350			344
Accrued Benefit Costs, Noncurrent		90			88
Commodity Derivative Liabilities, Noncurrent		29			7
Other		113			91
Total	$	819		$	752

 (1) Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2012 and 2013.

 (2) Amounts represent the costs incurred to date of the Leviathan-2 appraisal well in excess of the insurance deductible and insurance proceeds received to date.

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

Changes in Shareholders' Equity   On April 24, 2012, our shareholders voted to approve an amendment to the Company's Certificate of Incorporation to (i) increase the number of authorized shares of our common stock from 250 million to 500 million shares and (ii) reduce the par value of the Company's common stock from $3.331/3 per share to $0.01 per share.

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 and interim periods beginning after December 15, 2011. As of March 31, 2012, we have adopted the provisions of ASU 2011-04, which did not impact our consolidated financial statements. The only impact was to our fair value disclosures.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position and results of operations.

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

Changes in Asset Retirement Obligations

Changes in asset retirement obligations were as follows:

	Three Months Ended March 31,
	2012			2011
(millions)
Asset Retirement Obligations, Beginning Balance	$	377		$	253
Liabilities Incurred		6			1
Liabilities Settled		(2	)		(9	)
Revision of Estimate		3			4
Accretion Expense		7			5
Asset Retirement Obligations, Ending Balance	$	391		$	254

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Basic and Diluted Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Basic and Diluted Earnings Per Share [Abstract]
Net Income	$ 263	$ 14
Weighted Average Number of Shares Outstanding, Basic (in shares)	177	176
Incremental Shares from Assumed Conversion of Dilutive Stock Options and Restricted Stock (in shares)	3	2
Weighted Average Number of Shares Outstanding, Diluted (in shares)	180	178
Earnings Per Share, Basic (in dollars per share)	$ 1.48	$ 0.08
Earnings Per Share, Diluted (in dollars per share)	$ 1.47	$ 0.08
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above	2	2

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 12.  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.